e10vk
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
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(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1933
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For the fiscal year ended
December 31, 2006
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or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number 1-32599
Williams Partners
L.P.
(Exact name of Registrant as
Specified in Its Charter)
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Delaware
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20-2485124
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(State or Other Jurisdiction
of
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(IRS Employer
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Incorporation or
Organization)
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Identification No.)
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One Williams Center, Tulsa,
Oklahoma
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74172-0172
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(Address of Principal Executive
Offices)
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(Zip
Code)
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918-573-2000
(Registrants Telephone
Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Units
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
(Title of Class)
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant: (1) has
filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2
of the Exchange Act.
Large accelerated
filer o Accelerated
filer þ Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
The aggregate market value of the registrants common units
held by non-affiliates based on the closing sale price of such
units as reported on the New York Stock Exchange, as of the last
business day of the registrants most recently completed
second quarter was approximately $417,974,414. This figure
excludes common units beneficially owned by the directors and
executive officers of Williams Partners GP LLC, our general
partner.
The registrant had 25,553,306 common units, 6,805,492
Class B units and 7,000,000 subordinated units outstanding
as of February 27, 2007.
DOCUMENTS INCORPORATED BY REFERENCE
None
WILLIAMS
PARTNERS L.P.
FORM 10-K
TABLE OF CONTENTS
DEFINITIONS
We use the following oil and gas measurements and industry terms
in this report:
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.
British Thermal Units (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.
BBtu/d: One billion Btus per day.
¢/MMBtu: Cents per one million Btus.
MMBtu: One million Btus.
MMBtu/d: One million Btus per day.
MMcf: One million cubic feet. (Volumes of
natural gas are generally reported in terms of cubic feet).
MMcf/d: One million cubic feet per day.
NGLs: Natural gas liquids.
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.
Throughput: The volume of product transported
or passing through a pipeline, plant, terminal or other facility.
Workover: Operations on a completed production
well to clean, repair and maintain the well for the purposes of
increasing or restoring production.
WILLIAMS
PARTNERS L.P.
FORM 10-K
PART I
Items 1
and 2. Business and Properties
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, in which we
own a 40% interest. Discovery consists of Discovery
Producer Services LLC and its wholly owned subsidiary, Discovery
Gas Transmission LLC. When we refer to Discovery by name, we are
referring exclusively to its businesses and operations.
WEBSITE
ACCESS TO REPORTS AND OTHER INFORMATION
We file our annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and other documents electronically with the U.S. Securities
and Exchange Commission (SEC) under the Securities
Exchange Act of 1934, as amended. From
time-to-time,
we may also file registration and related statements pertaining
to equity or debt offerings. You may read and copy any materials
that we file with the SEC at the SECs Public Reference
Room at 100 F Street, N.E., Washington, DC 20549. You may obtain
information on the operation of the Public Reference Room by
calling the SEC at
1-800-SEC-0330.
You may also obtain such reports from the SECs Internet
website at http://www.sec.gov.
We make available free of charge on or through our Internet
website at http://www.williamslp.com, our annual report
on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Exchange Act as soon as
reasonably practicable after we electronically file such
material with, or furnish it to, the SEC. Our Corporate
Governance Guidelines, Code of Business Conduct and Ethics and
the charter of the audit committee of our general partners
board of directors are also available on our Internet website.
We will also provide, free of charge, a copy of any of our
governance documents listed above upon written request to our
general partners secretary at Williams Partners L.P., One
Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
Our principal executive offices are located at One Williams
Center, Tulsa, Oklahoma 74172. Our telephone number is
918-573-2000.
GENERAL
We are a publicly traded 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, processing and treating
natural gas and the fractionating and storing of 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.
Operations of our businesses are located in the United States.
We manage our business and analyze our results of operations on
a segment basis. Our operations are divided into three business
segments:
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Gathering and Processing West. Our
Gathering and Processing West segment includes
Williams Four Corners LLC, or Four Corners, which 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. These assets generate revenues by providing natural gas
gathering, transporting, processing and treating services to
customers under a range of contractual arrangements.
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Gathering and Processing Gulf. Our
Gathering and Processing Gulf segment includes our
equity investment in Discovery and the Carbonate Trend gathering
pipeline. We own a 40% interest in
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Discovery, which is operated by Williams. 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 a natural gas liquids
fractionator in Louisiana. Our Carbonate Trend gathering
pipeline is an unregulated sour gas gathering pipeline
consisting of approximately 34 miles of pipeline off the
coast of Alabama. These assets generate revenues by providing
natural gas gathering, transporting and processing services and
integrated natural gas fractionating services to customers under
a range of contractual arrangements.
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NGL Services. Our NGL Services segment
includes three integrated natural gas liquids storage facilities
and a 50% undivided interest in a natural gas liquids
fractionator near Conway, Kansas. These assets generate revenues
by providing stand-alone natural gas liquids fractionation and
storage services using various fee-based contractual
arrangements where we receive a fee or fees based on actual or
contracted volumetric measures.
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We account for our 40% interest in Discovery as an equity
investment and, therefore, do not consolidate its financial
results.
Our assets were owned by Williams prior to the initial public
offering (IPO) of our common units in August 2005
and our acquisition of Four Corners in 2006. Williams indirectly
owns an approximate 21% limited partnership interest in us and
all of our 2% general partner interest.
Williams is an integrated energy company with 2006 revenues in
excess of $11.8 billion that trades on the New York Stock
Exchange 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 NGL industry for more than
20 years.
RECENT
EVENTS
Acquisition of Four Corners. In 2006, in two
separate transactions, we acquired 100% of Four Corners from
Williams. On June 20, 2006, we acquired a 25.1% membership
interest in Four Corners for aggregate consideration of
$360.0 million. On December 13, 2006, we acquired the
remaining 74.9% membership interest for aggregate consideration
of $1.223 billion. These two transactions were financed
with the following debt and equity issuances.
Issuance of Common Units. On June 20 and
December 13, 2006, respectively, we sold 7,590,000 and
8,050,000 common units (including 990,000 and 1,050,000 common
units pursuant to the underwriters over-allotment purchase
option) in public offerings. We received net proceeds of
approximately $227.1 million and $293.7 million,
respectively, from the sale of the common units after deducting
underwriting discounts but before estimated offering expenses.
Issuance of Common Units and Class B units in a Private
Placement. On December 13, 2006, we sold
2,905,030 common units and 6,805,492 unregistered Class B
units in a private placement. We received net proceeds of
approximately $346.5 million after deducting placement fees
but before estimated offering expenses. The Class B units
are convertible into common units on a
one-for-one
basis upon the approval of a majority of the votes cast by
common unitholders, provided that the total number of votes cast
is at least a majority of common units eligible to vote
(excluding common units held by Williams and its affiliates).
Issuance of Senior Unsecured Notes. On June 20
and December 13, 2006, respectively, we issued
$150.0 million and $600.0 million aggregate principal
amount of 7.5% and 7.25% senior unsecured notes due 2011
and 2017, respectively. We received net proceeds of
approximately $146.8 million and $590.0 million,
respectively, from the sale of the senior unsecured notes after
deducting initial purchaser discounts and estimated offering
expenses.
Williams New Credit Facility. In May
2006, Williams replaced its $1.275 billion secured credit
facility with a $1.5 billion unsecured credit agreement.
The new facility contains 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 $75.0 million for general partnership
purposes, including acquisitions, but only to the
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extent that sufficient amounts remain unborrowed by Williams and
its other subsidiaries. Please read Financial
Condition and Liquidity Credit Facilities for
more information.
FINANCIAL
INFORMATION ABOUT SEGMENTS
See Part II, Item 8 Financial Statements
and Supplementary Data.
NARRATIVE
DESCRIPTION OF BUSINESS
Operations of our businesses are located in the United States
and are organized into three reporting segments:
(1) Gathering and Processing West,
(2) Gathering and Processing Gulf and
(3) NGL Services.
Gathering
and Processing West
Our Gathering and Processing West segment is
comprised of our Four Corners assets, which include:
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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.
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Our Four Corners customers are primarily natural gas
producers in the San Juan Basin. We provide our customers
with a full range of gathering, processing and treating
services. Fee-based gathering, processing and treating services
accounted for approximately 72% of our Gathering and
Processing West segments total revenue less
its product cost and shrink replacement costs and expenses for
the year ended December 31, 2006. The remaining 28% of the
segments total revenues less product cost and shrink replacement
for the year ended December 31, 2006 was derived from the
sale of NGLs received by Four Corners as consideration for
processing services.
For the twelve months ended December 31, 2006, our Four
Corners gathering system gathered 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 our Four Corners pipeline system in the
San Juan Basin is produced from conventional reservoirs
with approximately 60% coming from coal bed reservoirs. We are
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 topographically challenging
terrain, we have gathering pipelines throughout most of the
San Juan Basin.
Four
Corners Natural Gas Gathering System
Our 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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Over 400,000 horsepower of compression comprised of distributed
gathering compression, major gathering station compression and
plant compression. A substantial portion of this compression is
operated by a third-party.
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We generally charge a fee on the volume of natural gas gathered
on our Four Corners pipeline system. We do not, however, take
title to the natural gas gathered on the system other than
natural gas we retain for fuel and purchases for shrinkage.
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Four
Corners Processing and Treating Plants
Natural
Gas Processing Plants
Our Gathering and Processing West segment includes
three natural gas processing plants with a combined processing
capacity of 760 MMcf/d and combined NGL production capacity
of 41,000 bpd. We own and operate these three plants.
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
Mid-America
Pipeline (MAPL) system to Gulf Coast markets, but
some NGLs we retain are 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 we retain 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.
Treating
Plants
Coal bed methane sources typically contain high levels of carbon
dioxide that must be reduced to 2% or less for transportation
through pipelines to end markets. Our Gathering and
Processing West segment includes two natural gas
treating plants, the Milagro and Esperanza plants, which are
located in New Mexico and have a combined carbon dioxide
treating capacity of 750 MMcf/d. We own and operate these
two plants. The Milagro treating plant can deliver natural gas
to the El Paso Natural Gas, Transwestern, Southern Trails
and PNM pipelines. The Esperanza treating plant treats coal bed
methane volumes and removes carbon dioxide from the gas stream
upstream of the Milagro plant.
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
Customers. ConocoPhillips fee-based
gathering and processing revenue accounted for approximately 24%
of this segments total revenues. Total revenues are
comprised of product sales and fee-based gathering and
processing revenues. In any given period, our product sales
revenues can vary significantly depending on commodity prices
and the extent to which we purchase third-party processing
customers NGLs. ConocoPhillips fee-based gathering
and processing revenue accounted for 50% of this segments
total fee-based gathering and processing revenues, including
revenues attributable to Burlington Resources prior to its
acquisition by ConocoPhillips on March 31, 2006.
Additionally, product sales to a subsidiary of Williams, to
which Four Corners sells substantially all of the NGLs it
retains under its keep-whole and
percent-of-liquids
contracts, accounted for approximately 45% of the segments
total revenues for the year ended December 31, 2006. This
amount includes NGL sales related to third-party processing
customers NGLs that Four Corners purchases.
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Contracts. We provide our Four Corners
customers with a full range of gathering, processing and
treating services. These services are usually provided to each
customer under long-term contracts with applicable acreage
dedications, reserve dedications, or both, for the life of the
contract. Our portfolio of Four Corners natural gas
processing agreements includes the following types of contracts:
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Keep-whole. Under keep-whole contracts, we
(1) process natural gas produced by customers,
(2) retain some or all of the extracted NGLs as
compensation for our services, (3) replace the Btu content
of the retained NGLs that were separated during processing with
natural gas purchases, also known as shrink replacement gas, and
(4) deliver an equivalent Btu content of natural gas to
customers at the plant outlet. We, in turn, sell the retained
NGLs to a subsidiary of Williams, which serves as a purchaser
for those NGLs at market prices. For the year ended
December 31, 2006, 38% of our Gathering and
Processing West segments processing volumes
were under keep-whole contracts.
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Percent-of -liquids. Under
percent-of-liquids processing contracts, we (1) process
natural gas produced by customers, (2) deliver to customers
an
agreed-upon
percentage of the extracted NGLs, (3) retain a portion of
the extracted NGLs as compensation for our services and
(4) deliver natural gas to customers at the plant outlet.
Under this type of contract, we are not required to replace the
Btu content of the retained NGLs that were extracted during
processing. We sell the retained NGLs to a subsidiary of
Williams, which serves as a purchaser for those NGLs at market
prices. For the year ended December 31, 2006, 12% of the
segments processing volumes were under percent-of-liquids
contracts.
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Fee-based. Under fee-based contracts, we
receive revenue based on the volume of natural gas processed and
the per-unit
fee charged, and retain none of the extracted NGLs. For the year
ended December 31, 2006, 14% of the segments
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, 2006, 36% of the segments
processing volumes were under these fee-based and keep-whole
contracts.
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Competition
Our Four Corners pipeline system competes with other delivery
options available to producers in the San Juan Basin. We
generally compete with other gathering systems and
interconnecting gas processing and treating facilities, some of
which may have the same owner. The Enterprise system is
comprised of approximately 5,500 miles of gathering lines
and one processing plant. Enterprise owns and operates primarily
conventional natural gas gathering and processing facilities in
the San Juan Basin. The Red Cedar system consists of
approximately 900 miles of gathering lines, and is a joint
venture between the Southern Ute Indian tribe and Kinder Morgan
Energy Partners. The TEPPCO system consists of 400 miles of
gathering lines. Red Cedar and TEPPCO own and operate primarily
coal bed methane gathering and treating facilities in the
San Juan Basin.
Gas
Supply
All of our 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 our Four Corners system for
the life of the contract. Those contracts also contain
provisions requiring the connection of newly drilled wells
within dedicated areas to our Four Corners system. 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 9% of our
total revenues for the year ended December 31, 2006. We
anticipate that additional well connects, together with
sustained drilling activity, other expansion opportunities and
production enhancement activities by producers, will
substantially offset the impact of normal decline in gathered
and processed volumes or even temporarily
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increase these volumes. We have also, on occasion, successfully
pursued customers connected to competing gathering systems when
the customers contract with the competing gathering system
expired.
Gathering
and Processing Gulf
Our Gathering and Processing Gulf segment is
comprised of our 40% interest in Discovery and the Carbonate
Trend gathering pipeline.
Discovery
General
We own a 40% interest in Discovery, which in turn owns:
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a 283-mile
natural gas gathering and transportation pipeline system,
located primarily off the coast of Louisiana in the Gulf of
Mexico, with a mainline capacity, certified by the
U.S. Federal Energy Regulatory Commission (the
FERC), of approximately 600 MMcf/d with six
delivery points connected to major interstate and intrastate
pipeline systems;
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a cryogenic natural gas processing plant in Larose, Louisiana;
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a fractionator in Paradis, Louisiana; and
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a 22-mile
mixed NGL pipeline connecting the gas processing plant to the
fractionator.
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Additionally, Discovery has signed definitive agreements with
Chevron, Total 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 first gas flowing
in the first half of 2008.
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
our Gathering and Processing Gulf segment.
Discovery
Natural Gas Pipeline System
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 and located in the offshore
Louisiana Outer Continental Shelf at Ewing Bank 873. It 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 acres (nine square miles). The
mainline has a FERC-certificated capacity of approximately
600 MMcf/d.
The Discovery system connects to six natural gas pipeline
systems, two of which provide 1.6 Bcf/d of takeaway
capacity: the Bridgeline system, which serves southern Louisiana
and connects to the Henry Hub natural gas market point, the
Texas Eastern Pipeline system, which serves markets from Texas
to the northeastern United States and Gulfsouth, which provides
gas markets to the entire gulf coast region. Additionally,
Discovery completed a market expansion project in June 2005 that
connects Discovery to three additional pipeline systems:
Tennessee Gas Pipeline, Columbia Gulf Transmission and
Transcontinental Gas Pipe Line, or 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 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.
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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. The
FERC regulates 60 miles of Discoverys 90 miles
of shallow water laterals;
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a fixed-leg shelf production handling facility installed at
Grand Isle 115. The platform facility allows for the injection
of gas and 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. The FERC does
not regulate this lateral.
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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 has 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. The FERC does not regulate any of
Discoverys deepwater laterals.
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.
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%. 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 handling facilities and upon separation and
stabilization, to a third partys oil gathering pipeline
and barge facility. Discovery also provides compression services
for a third partys onshore gathering system that connects
to Discoverys onshore lateral.
Paradis
Fractionation Facility
The fractionator is located onshore near Paradis, Louisiana. The
fractionator and mixed NGL pipeline went into 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. The Paradis
fractionator is designed to fractionate 32,000 bpd of mixed
NGLs and is expandable to 42,000 bpd. In 2006, Discovery
fractionated an average of 15,139 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.
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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
Management
Currently, Discovery is owned 40% by us, 20% by Williams and 40%
by DCP Midstream, LLC (DCP). 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.
Discovery
Customers and Contracts
Customers. Product sales to a subsidiary of
Williams, which purchases substantially all of the NGLs and
excess natural gas to which Discovery takes title, accounted for
approximately 75.3% of Discoverys revenues for the year
ended December 31, 2006. This amount includes NGL sales
related to third-party processing customers elections to
have Discovery purchase their NGLs. In any given period, these
product sales revenues can vary significantly depending on
commodity prices and the extent to which third-party processing
customers elect to have Discovery purchase their NGLs.
Texas Eastern Transmission Company (TETCO) accounted
for approximately 25% of Discoverys fee-based,
transportation, gathering and processing, fractionation and
related revenues. TETCOs revenues related to the open
seasons, which provided outlets for natural gas that was
stranded following damage to third-party facilities during
hurricanes Katrina and Rita. In October 2006, Discovery signed a
one-year contract with TETCO. Discoverys other 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.
Contracts. Discoverys wholly owned
subsidiary, Discovery Gas Transmission, owns the mainline and
the FERC-regulated laterals, which generate revenues through a
tariff on file with the FERC for several types of service:
traditional firm transportation service with reservation fees
(although no current shippers have elected this service); firm
transportation service on a commodity basis with reserve
dedication; and interruptible transportation service. In
addition, for any of these general services, Discovery Gas
Transmission has the authority to negotiate a specific rate
arrangement with an individual shipper and has several of these
arrangements currently in effect.
Discoverys maximum regulated rate for mainline
transportation is scheduled to decrease in 2008. At that time,
Discovery may be required to reduce the mainline transportation
portion of the rate on any 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 the FERC to alter this scheduled reduction. However, if
filed, a rate case may not be successful in even partially
preventing the scheduled rate reduction. Please read
FERC Regulation.
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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
per-unit fee
charged.
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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 a
subsidiary of Williams at market prices. Some of
Discoverys contracts have a bypass option,
which is explained below under Operation and
Contract Optimization.
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Operation
and Contract Optimization
Long-haul natural gas pipelines, generally interstate pipelines
that serve end use 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. 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.
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.
Competition
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.
Gas
Supply
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, Apaches Tarantula
discovery and ATPs Gomez discovery. Additionally,
Discovery has signed definitive agreements
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with Chevron, Total 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 described above. Furthermore, in areas
that we believe are accessible to the Discovery pipeline system,
approximately 600 deepwater blocks are currently 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.
Third-Party
Pipeline Supply
Last years emergency connections to TETCO and Tennessee
Gas Pipeline (TGP) have continued to flow gas
throughout 2006. Discovery signed a one-year processing contract
with TETCO, effective October 2006, for a minimum volume of 100
BBtu/d and a maximum of 300 BBtu/d while the Venice gas plant is
being rebuilt. Additionally, Discovery is competing for
additional gas throughput from TETCO and TGP.
Carbonate
Trend Pipeline General
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, 2006, our average transportation volume was
approximately 29 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.
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.
Carbonate
Trend Customers and Contracts
Customers. Our primary customer on the
Carbonate Trend pipeline is Chevron, which, together with
Coldren Resources L.P. (Coldren), who purchased
Noble Energys interest, have large lease positions in the
Carbonate Trend area. Chevron and Coldren own an interest in
more than seven federal leases in the Carbonate Trend area and
Chevron is the operator for the majority of these leases. For
the year ended December 31, 2006, volumes from these
Chevron leases represented approximately 70% of Carbonate
Trends total throughput and 77% of Carbonate Trends
total revenue with volumes from Coldren constituting the
remainder.
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Contracts. We have long-term transportation
agreements with Chevron and Coldren. Pursuant to these
agreements, Chevron and Coldren have agreed to transport on our
pipeline all gas produced on their seven 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 Coldren expire or the
underlying reserves are depleted, Chevron and Coldren 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 Coldren may make an annual election
to utilize capacity along a segment of Transco. When Chevron or
Coldren utilize this capacity, our
per-unit
gathering fee is determined by subtracting the 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.
Competition
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.
Gas
Supply
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.
NGL
Services
Our NGL Services segment is comprised of our Conway, Kansas
businesses which consist of:
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three integrated NGL storage facilities; and
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a 50% interest in an NGL fractionator.
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Our Conway assets are strategically located at one of the two
major NGL trading hubs in the continental United States.
Conway
Storage Assets
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.
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 Valero 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
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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.
Competition
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 with 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.
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 Valero
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 or our rail
loading and unloading facility.
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 and forward purchase and sales contracts.
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.
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Historically, we completed these product sales and purchases
with third parties. However, in December of 2004, we began to
complete 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.
The
Conway Fractionation Facility
The Conway fractionation facility is strategically located at
the junction of the south, east and west legs of MAPL and has
interconnections with the BP Wattenberg pipeline and the
ConocoPhillips Chisholm pipeline, each of which transports mixed
NGLs to our facility. The Conway fractionation facility has a
total design capacity of 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 wholly
owned subsidiary of Williams at a price not to exceed a
specified price to satisfy our fuel requirements under this
fractionation contract.
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.
Competition
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 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.
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Mixed
NGL Sources
Based on Energy Information Administration 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 BP 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.
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.
Customers
and Contracts
Customers. Our NGL Services segment customers
include NGL producers, NGL pipeline operators, NGL service
providers and NGL end-users. Our three largest customers
accounted for 37% of our segment revenues in 2006.
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. We also
have several long-term contracts for terms that expire between
2009 and 2018. Each of these long-term contracts is based on a
percentage of our published price of storage in our Conway
facilities, which we adjust annually. Our storage revenues are
not generally affected by seasonality because our customers
generally pay for storage capacity, not injected or withdrawn
volumes.
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 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.
One such long-term fractionation contract expires on
January 1, 2008. Another long-term fractionation contract
expires in 2009. We generally enter into fractionation contracts
that cover a portion of our remaining capacity at the Conway
facility for periods of one year or less.
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
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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 $0.8 million between 2007 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.
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 the 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 to undertake certain restoration activities to
repair the partial erosion of the pipeline overburden caused by
Hurricane Ivan in September 2004 and Hurricane Katrina in August
2005. We estimate that these restoration activities could be
completed by the end of 2007. During these repairs, the pipeline
would be shutdown for approximately 40 days, which would
decrease our cash flows from operations by approximately
$0.3 million. We would fund these repairs with cash flows
from operations and seek reimbursement from our insurance
carrier
and/or
contractual counterparties. Additionally, in the omnibus
agreement, Williams agreed to reimburse us for the cost of the
restoration activities related to Hurricane Ivan to the extent
that we are not reimbursed by our insurance carrier and subject
to an overall limitation of $14.0 million for all
indemnified environmental and related expenditures generally for
a period of three years that ends in August 2008. We are
assessing our options for meeting our obligations with respect
to these restoration activities.
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
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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
Discovery
The Discovery
105-mile
mainline, approximately 60 miles of laterals and its market
expansion project are subject to regulation by the 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, the FERC has
authority over the construction, operation and expansion of
interstate pipeline facilities, as well as the rates, 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, the FERC
has issued rules that allow regulated pipelines to obtain
blanket authorizations that obviate the need for prior specific
FERC approvals for initiating and abandoning service. Commencing
in 1992, the FERC issued a series of orders (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 the 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 the
FERC, state regulators, or federal and state legislators may
take in the future.
In 2000, the 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.
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In addition, the 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 the 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, the 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
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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 6, 2005
requesting a limited waiver to permit three DCP employees to be
shared between Discovery and DCP and to provide information
necessary for DCP to carry out its responsibilities as an owner
of Discovery. The FERC has not yet acted on this filing.
However, on November 17, 2006, the United States Court of
Appeals for the District of Columbia Circuit vacated and
remanded Order No. 2004 as applied to interstate natural
gas pipelines and their affiliates. On January 9, 2007, the
FERC issued an interim rule. The Interim Rule re-promulgates, on
an interim basis, the standards of conduct that were not
challenged before the Court. The Interim Rule applies to the
relationship between interstate natural gas pipelines and their
marketing and brokering affiliates, but not necessarily to their
other affiliates, such as gatherers, processors or exploration
and production companies. On January 18, 2007, the FERC
issued a Notice of Proposed Rulemaking to propose permanent
regulations regarding the standards of conduct. A comment period
will ensue through April 4, 2007, after which the FERC may
enact a final rule. At this stage, it cannot be determined how a
final rule may or may not affect Discovery.
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
January 2008 to
$0.08/MMBtu.
At that time, Discovery may be required to reduce the mainline
transportation portion of the rate on any 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 the FERC seeking to alter this scheduled
reduction. However, if filed, a rate case may not 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.
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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, the 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 the FERCs decision
applying the Lakehead policy. In its Lakehead
decision, the 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, the
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 pipelines owners have such actual
or potential income tax liability will be reviewed by the 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, the FERC issued its first case-specific oil
pipeline review of the income tax allowance issue in the SFPP
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proceeding, reaffirming its new income tax allowance policy and
directing SFPP to provide certain evidence necessary to
determine its income allowance. The FERCs BP West Coast
remand decision and the new tax allowance policy have been
appealed to the D.C. Circuit, and rehearing requests have been
filed with respect to the December 2005 order. Therefore, the
ultimate outcome of these proceedings is not certain and could
result in changes to the FERCs treatment of income tax
allowances in cost of service. If the 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 the FERC or a shipper initiated a complaint proceeding.
However, we do not believe that it is likely that a current
shipper will challenge Discoverys rates that would
materially affect its revenues or cash flows.
Additional proposals and proceedings that might affect the
natural gas industry are pending before Congress, the FERC and
the courts. The natural gas industry historically has been
heavily regulated.
Other
The Carbonate Trend pipeline and the Four Corners system are
gathering pipelines, and are not subject to the FERCs
jurisdiction under the Natural Gas Act.
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. The 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 the FERC.
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.
Environmental
Regulation
General
Our operation of pipelines, plants and other facilities for
gathering, transporting, processing and 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.
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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.
In the omnibus agreement executed in connection with our IPO,
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.
Air
Emissions
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.
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.
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We currently own or lease, and our predecessor has in the past
owned or leased, properties where hydrocarbons are being or have
been handled for many years. Although we have utilized operating
and disposal practices that were standard in the industry at the
time, hydrocarbons or other wastes may have been disposed of or
released on or under the properties owned or leased by us or on
or under 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.
We are a participant in certain hydrocarbon removal and
groundwater monitoring activities at Four Corners associated
with 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.
Water
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.
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.
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
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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 35 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 $1.2 million per year to
install a double liner on a brine pond. 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. 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 unitholders.
We are currently in discussions with the Jicarilla Apache Nation
regarding
rights-of-way
that expired at the end of 2006 for a segment of Four
Corners gathering system which flows less than 10% of the
systems gathered volumes. We continue to operate our
assets on these reservation lands pursuant to a three-month
agreement while we conduct further discussions that could result
in renewal of our rights of way, sale of the gathering assets on
reservation land or other options that might be in the mutual
interest of both parties.
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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 our general partner or its affiliates employed
approximately 304 people, as of December 31, 2006, who
will spend at least a majority of their time operating the Four
Corners, Conway and Carbonate Trend facilities and approximately
110 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. For further information, please
read Directors and Executive Officers of the
Registrant Reimbursement of Expenses of our General
Partner and Certain Relationships and Related
Transactions.
FINANCIAL
INFORMATION ABOUT GEOGRAPHIC AREAS
We have no revenue or segment profit/loss attributable to
international activities.
Item 1A. Risk
Factors
FORWARD-LOOKING
STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT
Certain matters contained in this report include
forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as
amended. These statements discuss our expected future results
based on current and pending business operations.
All statements, other than statements of historical facts,
included in this report which address activities, events or
developments that we expect, believe or anticipate will exist or
may occur in the future, are forward-looking statements.
Forward-looking statements can be identified by various forms of
words such as anticipates, believes,
could, may, should,
continues, estimates,
expects, forecasts, might,
planned, potential,
projects, scheduled or similar
expressions. These forward-looking statements include, among
others, statements regarding:
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amounts and nature of future capital expenditures;
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expansion and growth of our business and operations;
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business strategy;
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cash flow from operations;
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seasonality of certain business segments; and
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natural gas liquids and gas prices and demand.
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Forward-looking statements are based on numerous assumptions,
uncertainties and risks that could cause future events or
results to be materially different from those stated or implied
in this document. 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. The reader should carefully consider the risk factors
discussed below in addition to the other information in this
annual report. 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
and the trading price of our common units could decline and
unitholders could lose all or part of their investment. Many of
the factors that could adversely affect our business, results of
operations and financial condition are beyond our ability to
control or predict. Specific factors which could cause actual
results to differ from those in the forward-looking statements
include:
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We may not have sufficient cash from operations to enable us to
pay the minimum 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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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 future financial and operating flexibility may be adversely
affected by restrictions in our indentures and by our leverage.
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Our partnership agreement limits our general partners
fiduciary duties to unitholders and restricts the remedies
available to unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
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Williams revolving credit facility 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 currently have little
ability to remove our general partner without its consent.
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Unitholders may be required to pay taxes on their share of our
income even if they 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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Given the uncertainties and risk factors that could cause our
actual results to differ materially from those contained in any
forward-looking statement, we caution investors not to unduly
rely on our forward-looking statements. We disclaim any
obligations to and do not intend to update the above list or to
announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or
developments.
In addition to causing our actual results to differ, the factors
listed above and referred to below may cause our intentions to
change from those statements of intention set forth in this
report. Such changes in our intentions may also cause our
results to differ. We may change our intentions, at any time and
without notice, based upon changes in such factors, our
assumptions, or otherwise.
23
Because forward-looking statements involve risks and
uncertainties, we caution that there are important factors, in
addition to those listed above, that may cause actual results to
differ materially from those contained in the forward-looking
statements. These factors include the following:
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:
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the prices we obtain for our services;
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the prices of, level of production of, and demand for, natural
gas and NGLs;
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the volumes of natural gas we gather, transport, process and
treat and the volumes of NGLs we fractionate and store;
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the level of our operating costs, including payments to our
general partner; and
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prevailing economic conditions.
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In addition, the actual amount of cash we will have available
for distribution will depend on other factors such as:
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the level of capital expenditures we make;
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the restrictions contained in our and Williams debt
agreements and our debt service requirements;
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the cost of acquisitions, if any;
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fluctuations in our working capital needs;
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our ability to borrow for working capital or other purposes;
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the amount, if any, of cash reserves established by our general
partner;
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the amount of cash that Discovery distributes to us; and
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reimbursement payments to us by, and credits from, Williams
under the omnibus agreement.
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Unitholders 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.
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. Our 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 our 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
24
maintain or increase throughput levels on these pipelines and
the utilization rate of Discoverys natural gas processing
plant and fractionator and our Four Corners processing plants
and treating plants, we and Discovery 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 and
Discoverys ability to successfully complete lateral
expansion projects to connect to new wells.
We do not have 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 the first half of 2008.
The level of drilling activity in the fields served by our and
Discoverys pipelines and our 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 our 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 unitholders.
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 our 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 our
unitholders.
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
capacity;
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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.
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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 largest customer for the year ended
December 31, 2006, other than a subsidiary of Williams that
purchases NGLs, is ConocoPhillips which accounted for
approximately 24% of the Gathering and Processing
West segments total revenues, including revenues
attributable to Burlington Resources prior to its acquisition by
ConocoPhillips on March 31, 2006.
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 9%
of our total revenues for the year ended December 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, could have a
material adverse effect on our business, results of operations,
financial condition and our ability to make cash distributions
to unitholders, 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.
26
MAPL also provides the only liquids pipeline access to multiple
end markets for NGL products that are recovered from our 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,
we would be unable to deliver a substantial portion of the NGLs
recovered at our Four Corners processing plants. This would have
an immediate impact on our ability to sell or deliver NGL
products recovered at our Four Corners processing plants. In
addition, the five pipeline systems that move natural gas to end
markets from the San Juan Basin connect to our 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, our
customers would be unable to deliver natural gas to end markets.
This would reduce the volumes of natural gas processed or
treated at our 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 unitholders.
Any temporary or permanent interruption in operations at MAPL 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 unitholders.
Williams
revolving credit facility 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 $75.0 million of
indebtedness under Williams $1.5 billion revolving
credit facility. However, this $75.0 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 could restrict
our access to credit. As of December 31, 2006, letters of
credit totaling $29.0 million had been issued on behalf of
Williams by the participating institutions under the facility
and no revolving credit loans were 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 $75.0 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 revolving credit
facility, 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 would 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 Liquidity and
Capital Resources.
Due to our relationship with Williams, our ability to obtain
credit will be affected by Williams credit ratings. Any
future down grading of a Williams credit rating would
likely also result in a down grading of our 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.
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Our
future financial and operating flexibility may be adversely
affected by restrictions in our indentures and by our
leverage.
In June 2006, we issued $150.0 million of senior unsecured
notes and in December 2006, we issued an additional
$600.0 million of senior unsecured notes, both of which
caused our leverage to increase. Our total outstanding long-term
debt as of December 31, 2006 was $750.0 million,
representing approximately 85% of our total book capitalization.
Our debt service obligations and restrictive covenants in the
indentures governing our senior unsecured notes could have
important consequences. For example, they could:
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make it more difficult for us to satisfy our obligations with
respect to our senior unsecured notes and our other
indebtedness, which could in turn result in an event of default
on such other indebtedness or our outstanding notes;
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impair our ability to obtain additional financing in the future
for working capital, capital expenditures, acquisitions, general
corporate purposes or other purposes;
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adversely affect our ability to pay cash distributions to
unitholders;
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diminish our ability to withstand a downturn in our business or
the economy generally;
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require us to dedicate a substantial portion of our cash flow
from operations to debt service payments, thereby reducing the
availability of cash for working capital, capital expenditures,
acquisitions, general corporate purposes or other purposes;
limit our flexibility in planning for, or reacting to, changes
in our business and the industry in which we operate; and
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place us at a competitive disadvantage compared to our
competitors that have proportionately less debt.
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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. If we are unable to meet our debt service obligations,
we could be forced to restructure or refinance our indebtedness,
seek additional equity capital or sell assets. We may be unable
to obtain financing or sell assets on satisfactory terms, or at
all.
We are not prohibited under our indentures from incurring
additional indebtedness. Our incurrence of significant
additional indebtedness would exacerbate the negative
consequences mentioned above, and could adversely affect our
ability to repay our senior notes.
Discovery
is not prohibited from incurring indebtedness, which may affect
our ability to make distributions to unitholders.
Discovery is not prohibited by the terms of its limited
liability company agreement from incurring indebtedness. If
Discovery was to incur significant amounts of indebtedness, it
may inhibit its ability to make distributions to us. An
inability by Discovery to make distributions to us would
materially and adversely affect our ability to make
distributions to unitholders because we expect distributions we
receive from Discovery to represent a significant portion of the
cash we distribute to unitholders.
We do
not own all of the interests in the Conway fractionator or
Discovery, 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 or
Discovery, 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
unitholders.
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Discovery
may reduce its 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. Discoverys available cash includes
cash on hand less any reserves that may be appropriate for
operating its business. As a result, reserves established by
Discovery, including those for working capital, will reduce the
amount of available cash. The amount of Discoverys
quarterly distributions, including the amount of cash reserves
not distributed, is determined by the members of its management
committee 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:
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the Carbonate Trend pipeline, which is operated by Chevron;
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our Conway fractionator and storage facilities, which we
operate; and
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most of our Four Corners field compression, excluding major
turbine compressor stations, which is operated by Hanover.
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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, our reliance
on Hanover 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 unitholders.
Hanover operates our Four Corners field compression pursuant to
agreements that are on a
month-to-month
status and can be terminated by Hanover at any time by providing
notice thirty days before the termination. If Hanover terminates
the agreements, we would need to find another operator for the
field compression. A change in operators could result in a
significant interruption of service.
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.
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Our Conway fractionation facility competes for volumes of mixed
NGLs with fractionators 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
unitholders.
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 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.
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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 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.
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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
unitholders. Further, if we issue additional common units in
connection with future acquisitions, unitholders interest
in the partnership will be diluted and distributions to
unitholders 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 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
FERC lowers the tariff rates Discovery is permitted to charge
its customers, on its own initiative, or as a result of
challenges raised by Discoverys customers or third
parties, the FERC could require refunds of amounts collected
under rates which it finds unlawful. An adverse decision by the
FERC in approving Discoverys regulated rates could
adversely affect our cash flows. Although the 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.
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 the 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
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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.
Pursuant to an order on and remand of a decision by the
U.S. Court of Appeals for the District of Columbia Circuit
in BP West Coast Products, LLC v. FERC and a policy
statement regarding income tax allowances issued by the FERC, 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 the FERC on a
case-by-case
basis. Both the FERCs income tax allowance policy and its
initial application in an individual pipeline rate proceeding
are, however, currently being challenged in the court of
appeals. As a result, the ultimate outcome of these proceedings
is not certain and could result in a reversal of the FERCs
policy or other changes to the FERCs treatment of income
tax allowances in cost-of -service. Under the FERCs
current policy, 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
the FERC were to disallow a substantial portion of
Discoverys income tax allowance, it may be more difficult
for Discovery to justify its rates.
On November 17, 2006, the U.S. Court of Appeals for
the District of Columbia Circuit vacated and remanded the
FERCs Order No. 2004, which adopted standards of
conduct governing interstate pipelines interactions with
their energy affiliates. Discovery had previously received
certain waivers from compliance with portions of Order
No. 2004. It is uncertain what action, if any, the FERC
will take in response to the remand. If the FERC issues new
standards of conduct, Discovery may incur additional compliance
costs.
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.
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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. Also, Hurricanes Ivan and
Katrina in 2004 and 2005, respectively, eroded part of the
overburden covering our Carbonate Trend Pipeline. During the
repair, it would be shutdown for approximately 40 days,
which would decrease our cash flows from operations by
approximately $0.3 million. We expect that the cost of the
repair would be recoverable from insurance.
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
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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
unitholders.
The
only pipeline that provides NGL transportation capacity in the
San Juan Basin has filed at the FERC to increase certain of
its tariff rates. If the requested increase is granted, our
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 the FERC to increase
certain of its tariff rates. If the FERC grants this request to
increase those tariff rates, we estimate that our 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 unitholders.
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 in high consequence areas where a leak or
rupture could do the most harm. 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.
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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 facilities and replaced three sections of brine systems
at a cost of $0.7 million. We have completed approximately
one-third of the testing and expect to complete the remainder of
the testing in 2007 and 2008. The results of these testing
programs will be analyzed, and 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 unitholders.
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.
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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. 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 unitholders. For
example, portions of our Four Corners gathering system are
located on Native American
rights-of-way.
Four Corners is currently in discussions with the Jicarilla
Apache Nation regarding
rights-of-way
that expired at the end of 2006 for a segment of the gathering
system which flows less than 10% of Four Corners gathered
volumes.
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, some of which may be material,
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.
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 materially increase
our compliance costs and the cost of any remediation that may
become necessary.
For example, 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 promulgated more
stringent
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regulations regarding safety and integrity of brine ponds and
storage caverns. 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, we may have to make capital expenditures to muffle
noise from our 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 our revenues and cash
flows.
The New Mexico state legislature has previously called for
hearings to take place to examine the regulation of natural gas
gathering systems in the state. It is unclear if further
discussions or hearings will occur, but they could result in
gathering regulation that would affect the fees that we could
collect for gathering services. This type of regulation could
adversely impact our revenues and cash flow.
Risks
Inherent in an Investment in Us
We
have a holding company structure in which our subsidiaries
conduct our operations and own our operating assets, which may
affect our ability to make payments on our outstanding notes and
distributions on our common units.
We have a holding company structure, and our subsidiaries
conduct all of our operations and own all of our operating
assets. Williams Partners L.P. has no significant assets other
than the ownership interests in its subsidiaries. As a result,
our ability to make required payments on our outstanding notes
and distributions on our common units depends on the performance
of our subsidiaries and their ability to distribute funds to us.
The ability of our subsidiaries to make distributions to us may
be restricted by, among other things, applicable state
partnership and limited liability company laws and other laws
and regulations. If we are unable to obtain the funds necessary
to pay the principal amount at maturity of our outstanding
notes, or to repurchase our outstanding notes upon the
occurrence of a change of control, or make distributions on our
common units we may be required to adopt one or more
alternatives, such as a refinancing of our outstanding notes or
borrowing funds to make distributions on our common units. We
cannot assure our notes holders that we would be able to
refinance our outstanding notes or that we will be able to
borrow funds to make distributions on our common units.
Common
units held by Williams eligible for future sale may have adverse
effects on the price of our common units.
As of December 31, 2006, Williams held 1,250,000 common
units and 7,000,000 subordinated units, representing a 21%
limited partnership interest in us. Williams may, from time to
time, sell all or a portion of its 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.
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If we
fail to obtain the approval of the unitholders for the
conversion of the Class B units to common units, the
minimum quarterly distribution payable in respect of the
Class B units will increase, which will reduce the amount
of cash available for distribution on our common
units.
If conversion of our Class B units is not approved by our
unitholders within six months of the closing of the issuance of
the Class B units, which is June 11, 2007, the holders
of the Class B units will be entitled to receive an
increased quarterly distribution equal to 115% of the quarterly
distribution and distributions on liquidation payable on each
common unit, but in each case the holders of the Class B
units will remain subordinated to the holders of common units
with respect to quarterly distributions and any arrearages
thereon. Based on our current quarterly distribution of
$0.47 per unit, this increase would result in an aggregate
of approximately $0.5 million of additional quarterly
distributions on Class B units. If we become obligated to
pay an increased quarterly distribution on the Class B
units, our cash on hand will be reduced and we may not have
sufficient cash available to pay distributions on our common
units.
Potential
changes in accounting standards might cause us to revise our
financial results and disclosures 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 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 unitholders.
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 unitholders.
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 unitholders.
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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.
Williams owns the 2% general partner interest and a 21% limited
partner interest in us and owns and controls 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 our unitholders;
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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.
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Our
partnership agreement limits our general partners
fiduciary duties to unitholders and restricts the remedies
available to unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
Our partnership agreement contains provisions that reduce the
standards to which our general partner would otherwise be held
by state fiduciary duty law. For example, our partnership
agreement:
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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 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.
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By purchasing a common unit, a common unitholder will be bound
by the provisions in the partnership agreement, including the
provisions discussed above.
Even
if unitholders are dissatisfied, they have little ability to
remove our general partner without its consent.
Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our
business and, therefore, limited ability to influence
managements decisions regarding our business. Unitholders
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 our unitholders are dissatisfied with the
performance of our general partner, they 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.
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
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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 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 unitholder approval, which
would dilute unitholder 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.
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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.
Our
general partner has a limited call right that may require
unitholders to sell their 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,
non-affiliated unitholders may be required to sell their common
units at
39
an undesirable time or price and may not receive any return on
their investment. Such unitholders may also incur a tax
liability upon a sale of their 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.
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, 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
unitholders.
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. 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 unitholders.
Unitholders
may not have limited liability if a court finds that unitholder
action constitutes control of our business. Unitholders may also
have liability to repay distributions.
As a limited partner in a partnership organized under Delaware
law, unitholders could be held liable for our obligations to the
same extent as a general partner if they 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.
Tax
Risks
Our
tax treatment depends on our status as a partnership for federal
income tax purposes, as well as our not being subject to
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 unitholders would be substantially
reduced.
The anticipated after-tax benefit of an investment in the common
units depends largely on our being treated as a partnership for
federal income tax purposes. We have not requested, and do not
plan to request, a ruling from the IRS on this or any other
matter affecting us.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our income at the
corporate tax rate, which is currently a maximum of 35%.
Distributions to unitholders would generally be taxed again as
corporate distributions, and no income, gains, losses,
deductions or credits would flow through to unitholders. Because
a tax would be imposed upon us as a corporation, our cash
available to
40
pay distributions to unitholders 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 unitholders, 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 unitholders
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. 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.
Unitholders
may be required to pay taxes on their share of our income even
if unitholders do not receive any cash distributions from
us.
Unitholders are required to pay federal income taxes and, in
some cases, state and local income taxes on their share of our
taxable income, whether or not they receive cash distributions
from us. Unitholders may not receive cash distributions from us
equal to their share of our taxable income or even equal to the
actual tax liability that results from their share of our
taxable income.
The
tax gain or loss on the disposition of our common units could be
different than expected.
If a unitholder sell its common units, it will recognize gain or
loss equal to the difference between the amount realized and its
tax basis in those common units. Prior distributions to a
unitholder in excess of the total net taxable income it was
allocated for a common unit, which decreased its tax basis in
that common unit, will, in effect, become taxable income to the
unitholder if the common unit is sold at a price greater than
its tax basis in that common unit, even if the price the
unitholder receives is less than its original cost. A
substantial portion of the amount realized, whether or not
representing gain, may be ordinary income to the unitholder.
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.
41
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 will all aspects of existing Treasury
regulations. A successful IRS challenge to those positions could
adversely affect the amount of tax benefits available to
unitholders. It also could affect the timing of these tax
benefits or the amount of gain from the sale of common units and
could have a negative impact on the value of our common units or
result in audit adjustments to unitholder tax returns.
Unitholders
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, unitholders 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. Unitholders 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, unitholders may be subject to penalties
for failure to comply with those requirements. We own property
and conduct business in Kansas, Louisiana, Colorado and New
Mexico. We may own property or conduct business in other states
or foreign countries in the future. It is the unitholders
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.
The
sale or exchange of 50% or more of our capital and profits
interests will result in the termination of our partnership for
federal income tax purposes.
We will be considered to have terminated for federal income tax
purposes if there is a sale or exchange of 50% or more of the
total interests in our capital and profits within a
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.
|
|
Item 1B.
|
Unresolved
Staff Comments
|
None.
|
|
Item 3.
|
Legal
Proceedings
|
The information called for by this item is provided in
Note 14, Commitments and Contingencies included in the
Notes to Consolidated Financial Statements of this report, which
information is incorporated into this Item 3 by reference.
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
None.
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities.
|
Market
Information, Holders and Distributions
Our common units are listed on the New York Stock Exchange under
the symbol WPZ. At the close of business on
February 20, 2007, there were 25,553,306 common units
outstanding, held by approximately 13,238 holders, including
common units held in street name and by affiliates of Williams.
42
As of February 26, 2007, there were 7,000,000 subordinated
units outstanding held by four subsidiaries of Williams. The
subordinated units are not publicly traded.
As of February 26, 2007, there were 6,805,492 Class B
units outstanding, held by 22 holders. The Class B units
were issued in December 2006 and 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 New York Stock Exchange Composite Transactions Tape, and
quarterly cash distributions paid to our unitholders.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Distribution
|
|
|
High
|
|
Low
|
|
per Unit(a)
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
$
|
40.80
|
|
|
$
|
35.04
|
|
|
$
|
0.4700
|
|
Third Quarter
|
|
|
36.00
|
|
|
|
29.25
|
|
|
|
0.4500
|
|
Second Quarter
|
|
|
35.55
|
|
|
|
30.30
|
|
|
|
0.4250
|
|
First Quarter
|
|
|
33.92
|
|
|
|
31.00
|
|
|
|
0.3800
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
$
|
34.26
|
|
|
$
|
29.75
|
|
|
|
0.3500
|
|
Third Quarter(b)
|
|
|
32.75
|
|
|
|
24.89
|
|
|
|
0.1484
|
(c)
|
|
|
|
(a) |
|
Represents cash distributions attributable to the quarter and
declared and paid or to be paid within 45 days after
quarter end. We paid cash distributions to our general partner
with respect to its 2% general partner interest that totaled
$0.1 million for the period from August 23, 2005
through December 31, 2005. We declared cash distributions
to our general partner with respect to its 2% general partner
interest and incentive distribution rights that totaled
$1.8 million for the 2006 period. No Class B units
were outstanding until December 2006 and therefore did not
participate in cash distributions prior to the cash distribution
for the fourth quarter of 2006. |
|
(b) |
|
For the period from August 18, 2005 through
September 30, 2005. |
|
(c) |
|
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
Within 45 days after the end of each quarter we will
distribute all of our available cash, as defined in our
partnership agreement, to unitholders of record on the
applicable record date. Available cash generally means, for each
fiscal quarter all cash on hand at the end of the quarter:
|
|
|
|
|
less the amount of cash reserves established by our general
partner to:
|
|
|
|
|
|
provide for the proper conduct of our business (including
reserves for future capital expenditures and for our anticipated
credit needs);
|
|
|
|
comply with applicable law, any of our debt instruments or other
agreements; or
|
|
|
|
provide funds for distribution to our unitholders and to our
general partner for any one or more of the next four quarters;
|
|
|
|
|
|
plus all cash on hand on the date of determination of available
cash for the quarter resulting from working capital borrowings
made after the end of the quarter 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.
|
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 quarter,
43
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. In addition, as described in
more detail below, the Class B units rank junior to common
units in their right to receive distributions but senior of the
subordinated units. The Class B units, if any remain
outstanding, would continue to rank junior to the common units
even after the expiration of the 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:
|
|
|
|
|
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;
|
|
|
|
the adjusted operating surplus (as defined in our
partnership agreement) 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 general partner
interest during those periods; and
|
|
|
|
there are no arrearages in payment of the minimum quarterly
distribution on the common units.
|
In addition, the subordination period may terminate before
June 30, 2008 if the following tests are met:
|
|
|
|
|
distributions of available cash from operating surplus on each
of the outstanding common units and subordinated units equaled
or exceeded $2.10 (150% of the annualized minimum quarterly
distribution) for the immediately preceding four-quarter period;
|
|
|
|
the adjusted operating surplus generated during such
four-quarter period equaled or exceeded $2.10 (150% of the
annualized minimum quarterly distribution) on all of the
outstanding common units and subordinated units during such
four-quarter period on a fully diluted basis and the related
distribution on the general partner interest during such
four-quarter period; and
|
|
|
|
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 also end before June 30, 2008.
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:
|
|
|
|
|
the subordination period will end and each subordinated unit
will immediately convert into one common unit;
|
|
|
|
any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
|
|
|
|
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.
|
We will make distributions of available cash from operating
surplus for any quarter during any subordination period in the
following manner:
|
|
|
|
|
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;
|
44
|
|
|
|
|
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;
|
|
|
|
third, if any Class B units remain outstanding, 98%
to the Class B unitholders, pro rata, and 2% to our general
partner, until we distribute for each outstanding Class B
unit an amount equal to the minimum quarterly distribution for
that quarter;
|
|
|
|
fourth, if any Class B units remain outstanding, 98%
to the Class B unitholders, pro rata, and 2% to our general
partner, until we distribute for each outstanding Class B
unit an amount equal to any arrearages in payment of the minimum
quarterly distribution on the Class B units for any prior
quarters;
|
|
|
|
fifth, if any subordinated units remain outstanding, 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
|
|
|
|
thereafter, cash in excess of the minimum quarterly
distributions is distributed to the unitholders and the general
partner based on the incentive percentages below.
|
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. In
addition, the description of distributions payable on the
Class B units above reflect the distributions payable on
the Class B units within 180 days of their issuance on
December 13, 2006. The Class B units will convert into
common units on a
one-for-one
basis upon the approval of a majority of the votes cast by
common unitholders provided that the total number of votes cast
is at least a majority of common units eligible to vote
(excluding common units held by Williams and its affiliates). We
are required to seek such approval as promptly as practicable
and not later than 180 days from December 13, 2006. If
we have not obtained the requisite unitholder approval of the
conversion of the Class B units within 180 days from
December 13, 2006, the Class B units will be entitled
to receive 115% of the quarterly distribution and distributions
on liquidation payable on each common unit. We expect to call a
special meeting of common unitholders in the second quarter of
2007 to seek approval for the conversion of the Class B
units.
Our general partner is entitled to incentive distributions if
the amount we distribute with respect to any quarter exceeds
specified target levels shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marginal Percentage
|
|
|
|
Total Quarterly Distribution
|
|
Interest in Distributions
|
|
|
|
Target Amount
|
|
Unitholders
|
|
|
General Partner
|
|
|
Minimum Quarterly Distribution
|
|
$0.35
|
|
|
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
|
%
|
45
|
|
Item 6.
|
Selected
Financial and Operational Data
|
The following table shows selected financial and operating data
of Williams Partners L.P. and of Discovery Producer Services LLC
for the periods and as of the dates indicated. We derived the
financial data as of December 31, 2006 and 2005 and for the
years ended December 31, 2006, 2005 and 2004 in the
following table from, and that information should be read
together with, and is qualified in its entirety by reference to,
the consolidated financial statements and the accompanying notes
included elsewhere in this document. All other financial data
are derived from our financial records.
Because Four Corners was an affiliate of Williams at the time of
these acquisitions, these transactions were between entities
under common control, and have been accounted for at historical
cost. Accordingly, our consolidated financial statements and
notes have been restated to reflect the combined historical
results of Four Corners throughout the periods presented. These
acquisitions have no impact on historical earnings per unit as
pre-acquisition earnings were allocated to our general partner.
The table should also be read together with
Managements Discussion and Analysis of Financial
Condition and Results of Operations for information
concerning significant trends in the financial condition and
results of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
|
(Dollars in thousands, except per unit amounts)
|
|
|
Statement of Income
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
563,410
|
|
|
$
|
514,972
|
|
|
$
|
469,199
|
|
|
$
|
382,428
|
|
|
$
|
349,817
|
|
Costs and expenses
|
|
|
420,342
|
|
|
|
395,556
|
|
|
|
364,602
|
|
|
|
286,637
|
|
|
|
253,417
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
143,068
|
|
|
|
119,416
|
|
|
|
104,597
|
|
|
|
95,791
|
|
|
|
96,400
|
|
Equity earnings
Discovery
|
|
|
12,033
|
|
|
|
8,331
|
|
|
|
4,495
|
|
|
|
3,447
|
|
|
|
2,026
|
|
Impairment of investment in
Discovery
|
|
|
|
|
|
|
|
|
|
|
(13,484
|
)(a)
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(9,833
|
)
|
|
|
(8,238
|
)
|
|
|
(12,476
|
)
|
|
|
(4,176
|
)
|
|
|
(3,414
|
)
|
Interest income
|
|
|
1,600
|
|
|
|
165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting principle
|
|
$
|
146,868
|
|
|
$
|
119,674
|
|
|
$
|
83,132
|
|
|
$
|
95,062
|
|
|
$
|
95,012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income(b)
|
|
$
|
146,868
|
|
|
$
|
118,352
|
|
|
$
|
83,132
|
|
|
$
|
93,633
|
|
|
$
|
95,012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting principle per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unit
|
|
$
|
1.62
|
|
|
$
|
0.49
|
(d)
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
B unit
|
|
$
|
0.45
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Subordinated unit
|
|
$
|
1.62
|
|
|
$
|
0.49
|
(d)
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Net income per limited partner
unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unit
|
|
$
|
1.62
|
|
|
$
|
0.44
|
(d)
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
B unit
|
|
$
|
0.45
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Subordinated unit
|
|
$
|
1.62
|
|
|
$
|
0.44
|
(d)
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Balance Sheet Data (at period
end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
933,148
|
|
|
$
|
875,275
|
|
|
$
|
863,584
|
|
|
$
|
896,739
|
(c)
|
|
$
|
825,007
|
|
Property, plant and equipment, net
|
|
|
647,578
|
|
|
|
658,965
|
|
|
|
669,503
|
|
|
|
705,600
|
|
|
|
755,131
|
|
Investment in Discovery
|
|
|
147,493
|
|
|
|
150,260
|
|
|
|
147,281
|
(a)
|
|
|
156,269
|
(c)
|
|
|
49,323
|
|
Advances from affiliate
|
|
|
|
|
|
|
|
|
|
|
186,024
|
|
|
|
187,193
|
(c)
|
|
|
90,996
|
|
Partners capital
|
|
|
135,402
|
(e)
|
|
|
827,245
|
|
|
|
637,198
|
|
|
|
674,533
|
|
|
|
694,691
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
|
(Dollars in thousands, except per unit amounts)
|
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions declared per
unit
|
|
$
|
1.605
|
|
|
$
|
0.1484
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Cash distributions paid per unit
|
|
$
|
1.605
|
|
|
$
|
0.1484
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Operating
Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Four Corners gathered volumes
(MMBtu/d)
|
|
|
1,499,937
|
|
|
|
1,521,507
|
|
|
|
1,559,940
|
|
|
|
1,577,181
|
|
|
|
1,594,745
|
|
Four Corners processed volumes
(MMBtu/d)
|
|
|
875,600
|
|
|
|
863,693
|
|
|
|
900,194
|
|
|
|
900,356
|
|
|
|
917,613
|
|
Four Corners liquid sales
gallons(000s)
|
|
|
182,010
|
|
|
|
165,479
|
|
|
|
197,851
|
|
|
|
187,788
|
|
|
|
203,688
|
|
Four Corners net liquids margin
(¢/gallon)
|
|
|
47
|
¢
|
|
|
37
|
¢
|
|
|
29
|
¢
|
|
|
17
|
¢
|
|
|
15
|
¢
|
Conway storage revenues
|
|
$
|
25,237
|
|
|
$
|
20,290
|
|
|
$
|
15,318
|
|
|
$
|
11,649
|
|
|
$
|
10,854
|
|
Conway fractionation volumes
(bpd) our 50%
|
|
|
38,859
|
|
|
|
39,965
|
|
|
|
39,062
|
|
|
|
34,989
|
|
|
|
38,234
|
|
Carbonate Trend gathered volumes
(MMBtu/d)
|
|
|
29,323
|
|
|
|
35,605
|
|
|
|
49,981
|
|
|
|
67,638
|
|
|
|
57,060
|
|
Discovery Producer
Services 100%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathered volumes (MMBtu/d)
|
|
|
467,338
|
|
|
|
345,098
|
|
|
|
348,142
|
|
|
|
378,745
|
|
|
|
425,388
|
|
Gross processing margin
(¢/MMbtu)
|
|
|
23
|
¢
|
|
|
19
|
¢
|
|
|
17
|
¢
|
|
|
17
|
¢
|
|
|
12
|
¢
|
|
|
|
(a) |
|
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. |
|
(b) |
|
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. |
|
(c) |
|
In December 2003, we made a $101.6 million capital
contribution to Discovery, which Discovery subsequently used to
repay maturing debt. We funded this contribution with an advance
from Williams. Prior to the closing of our initial public
offering, Williams forgave the entire advances from affiliates
balance. |
|
(d) |
|
The period of August 23, 2005 through December 31,
2005. |
|
(e) |
|
Because Four Corners was an affiliate of Williams at the time of
its acquisition by us, the acquisition is accounted for as a
combination of entities under common control, whereby the assets
and liabilities of Four Corners are combined with Williams
Partners L.P. at their historical amounts for all periods
presented. This accounting causes a reduction of the capital
balance for the general partner for the difference between the
historical cost of the Four Corners assets and liabilities and
the aggregate consideration paid to the general partner. |
47
|
|
Item 7.
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
Please
read the following discussion of our financial condition and
results of operations in conjunction with the consolidated
financial statements and related notes included in Item 8
of this annual report.
Overview
We are principally engaged in the business of gathering,
transporting, processing and treating natural gas and
fractionating and storing NGLs. We manage our business and
analyze our results of operations on a segment basis. Our
operations are divided into three business segments:
|
|
|
|
|
Gathering and Processing West. Our
West segment includes Williams Four Corners LLC (Four
Corners). The Four Corners system gathers and processes or
treats 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.
|
|
|
|
Gathering and Processing Gulf. Our
Gulf segment includes (1) our 40% ownership interest in
Discovery and (2) the Carbonate Trend gathering pipeline
off the coast of Alabama. 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
In 2006, the two most important events for our business were the
June and December acquisitions of 25.1% and 74.9%, respectively,
of Four Corners from Williams. The combined value of these
transactions was approximately $1.6 billion, which is a
dramatic increase in size from the $100.2 million we raised
at our IPO in August of 2005. The acquisition of Four Corners
provides us with a large-scale gathering and processing system
with stable cash flows and a relatively high percentage of
fee-based revenues. The 2006 results of our Gathering and
Processing West segment, which includes Four
Corners, were exceptionally strong based on record commodity
margins for the NGLs it receives under certain processing
contracts. However, we also experienced significant increases in
operating costs in that segment. Discovery continued work on its
important Tahiti lateral expansion project, which remains on
schedule to receive initial throughput in the first half of
2008. Discovery also benefited from record commodity margins and
the continuation of processing volumes initially received
following damage to third-party facilities during Hurricanes
Katrina and Rita. In our NGL Services segment, we continued
storage cavern workovers and wellhead modifications at Conway
while generating increased storage revenues from higher average
storage volumes. We have increased distributions each quarter in
an aggregate amount of $0.12, or 34%, per unit since our IPO. We
believe that we have adequate cash reserves to finance our
working capital and maintenance capital requirements, and we
have had no borrowings under our revolving credit facilities.
Our capitalization and relationship with Williams has us
well-positioned to continue to grow through both internal
projects and acquisition transactions with Williams and other
third parties.
Recent
Events
Acquisition of Four Corners. In 2006, in two
separate transactions, we acquired 100% of Four Corners from
Williams. On June 20, 2006, we acquired a 25.1% membership
interest in Four Corners for aggregate consideration of
$360.0 million. On December 13, 2006, we acquired the
remaining 74.9% membership
48
interest for aggregate consideration of $1.223 billion.
These two transactions were financed with the following debt and
equity issuances.
Issuance of Common Units. On June 20 and
December 13, 2006, respectively, we sold 7,590,000 and
8,050,000 common units (including 990,000 and 1,050,000 common
units pursuant to the underwriters over-allotment purchase
option) in public offerings. We received net proceeds of
approximately $227.1 million and 293.7 million,
respectively, from the sale of the common units after deducting
underwriting discounts but before estimated offering expenses.
Issuance of Common Units and Class B units in a Private
Placement. On December 13, 2006, we sold
2,905,030 common units and 6,805,492 unregistered Class B
units in a private placement. We received net proceeds of
approximately $346.5 million after deducting placement fees
but before estimated offering expenses. The Class B units
are convertible into common units on a
one-for-one
basis upon the approval of a majority of the votes cast by
common unitholders, provided that the total number of votes cast
is at least a majority of common units eligible to vote
(excluding common units held by Williams and its affiliates).
Issuance of Senior Unsecured Notes. On June 20
and December 13, 2006, respectively, we issued
$150.0 million and $600.0 million aggregate principal
amount of 7.5% and 7.25% senior unsecured notes due 2011
and 2017. We received net proceeds of approximately
$146.8 million and $590.0 million from the sale of the
senior unsecured notes after deducting initial purchaser
discounts and estimated offering expenses.
Because Four Corners was an affiliate of Williams at the time of
these acquisitions, these transactions were between entities
under common control, and have been accounted for at historical
cost. Accordingly, our consolidated financial statements and
notes have been restated to include the historical results of
Four Corners throughout the periods presented. These two
acquisitions of a combined 100% membership interest in Four
Corners increased net income $142.7 million,
$113.5 million and $96.6 million for 2006, 2005 and
2004, respectively. These acquisitions have no impact on
historical earnings per unit as pre-acquisition earnings were
allocated to our general partner.
New Credit Facility with Williams. In May
2006, Williams replaced its $1.275 billion secured credit
facility with a $1.5 billion unsecured credit agreement.
The new facility contains 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 $75.0 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:
|
|
|
|
|
Four Corners gathering and processing volumes;
|
|
|
|
Four Corners net liquids margin;
|
|
|
|
Discoverys and Carbonate Trends pipeline throughput
volumes;
|
|
|
|
Discoverys gross processing margins;
|
|
|
|
Conways fractionation volumes;
|
|
|
|
Conways storage revenues; and
|
|
|
|
operating and maintenance expenses.
|
Four
Corners
Gathering and Processing Volumes. The
gathering volumes on our Four Corners system and volumes
processed at the Ignacio, Kutz and Lybrook natural gas
processing plants are important components of maximizing its
profitability. We gather approximately 37% of the San Juan
Basins natural gas production on
49
our Four Corners system at approximately 6,400 receipt points
under mostly fee-based contracts. Our gathering volumes from
existing wells connected to our pipeline will naturally decline
over time. Accordingly, to maintain or increase gathering
volumes we must continually obtain new supplies of natural gas.
Our Four Corners system processes natural gas under keep-whole,
percent-of-liquids, fee-based and fee-based and keep-whole
contracts. Our processing volumes are largely dependent on the
volume of natural gas gathered on our Four Corners system.
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 from
the revenue Four Corners receives from the sale of its NGLs.
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. Under certain agreement types, Four Corners
receives NGLs as compensation for processing services provided
to its customers. 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.
Discovery
and Carbonate Trend
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 obtain
new supplies of natural gas. Our ability to maintain existing
supplies of natural gas and obtain new supplies are impacted by
(1) the level of workovers or recompletions of existing
connected wells and successful drilling activity in areas
currently dedicated to our pipelines and (2) our ability to
compete for volumes from successful new wells in other areas. We
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 certain processing contracts
for Discoverys account and keep-whole contracts; 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 gross
processing margin. 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 the
FERC in 2004, we expect that Discovery will generate only
minimal revenues, if any, from the sale of excess natural gas in
the future. However, this rule has been vacated and remanded
back to the FERC because the courts found that the FERC offered
no evidence of abusive behavior to warrant such restriction.
Discoverys mix of processing contract types and its
operation and contract optimization activities are determinants
in processing revenues and gross margins.
Conway
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.
50
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 versus 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, leased compression
services, contract services, fuel, utilities, materials,
supplies, insurance and ad valorem taxes comprise the most
significant portion of operating and maintenance expenses. We
have experienced increased operating and maintenance expenses in
recent years due to the growth of the oil and gas industry,
which has increased competition for resources. Other than rented
compression services and fuel expense, 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. Leased compression services are
dependent upon the extent and amount of additional compression
needed to meet the needs of our Four Corners customers and
the cost at which compression can be purchased, leased and
operated. 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 Gulf 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 IPO, Williams agreed to provide
a five-year partial credit for general and administrative
expenses incurred on our behalf. The amount of the credit was
$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.
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. 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.
Accounting
for Asset Retirement Obligations
We record asset retirement obligations for legal 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, 2006, we have an accrued asset retirement
obligation liability of $4.5 million for estimated
retirement costs associated with the abandonment of Four
Corners gas processing and compression facilities located
on leased land, its wellhead connections on federal land and
Conways underground storage caverns and brine ponds in
accordance with KDHE regulations. Our recorded asset retirement
obligation is based on the assumption that the abandonment of
our Four Corners and Conway assets generally occurs in
approximately 50 years. If this assumption had been changed
to 30 years in 2006, the recorded asset retirement
obligation would have increased by approximately
$2.8 million. Our estimate utilizes judgments and
assumptions regarding the extent of our
51
obligations, the costs to abandon and the timing of abandonment.
Please read Note 8 of Notes to Consolidated Financial
Statements.
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
December 31, 2006, we have an accrual for estimated
environmental remediation obligations of $6.6 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
certain of our environmental liabilities. Please read
Environmental and Note 14 of Notes
to Consolidated Financial Statements for further information.
52
Results
of Operations
Consolidated
Overview
The following table and discussion is a summary of our
consolidated results of operations for the three years ended
December 31, 2006. The results of operations by segment are
discussed in further detail following this consolidated overview
discussion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Change
|
|
|
|
|
|
% Change
|
|
|
|
|
|
|
|
|
|
from
|
|
|
|
|
|
from
|
|
|
|
|
|
|
2006
|
|
|
2005(1)
|
|
|
2005
|
|
|
2004(1)
|
|
|
2004
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
563,410
|
|
|
|
+9
|
%
|
|
$
|
514,972
|
|
|
|
+10
|
%
|
|
$
|
469,199
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
175,508
|
|
|
|
+1
|
%
|
|
|
177,527
|
|
|
|
(16
|
)%
|
|
|
152,963
|
|
Operating and maintenance expense
|
|
|
155,214
|
|
|
|
(20
|
)%
|
|
|
129,759
|
|
|
|
(11
|
)%
|
|
|
116,446
|
|
Depreciation, amortization and
accretion
|
|
|
43,692
|
|
|
|
(3
|
)%
|
|
|
42,579
|
|
|
|
+4
|
%
|
|
|
44,361
|
|
General and administrative expense
|
|
|
39,440
|
|
|
|
(8
|
)%
|
|
|
36,615
|
|
|
|
(14
|
)%
|
|
|
32,179
|
|
Taxes other than income
|
|
|
8,961
|
|
|
|
(6
|
)%
|
|
|
8,446
|
|
|
|
(13
|
)%
|
|
|
7,506
|
|
Other (income) expense, net
|
|
|
(2,473
|
)
|
|
|
NM
|
|
|
|
630
|
|
|
|
+94
|
%
|
|
|
11,147
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
420,342
|
|
|
|
(6
|
)%
|
|
|
395,556
|
|
|
|
(8
|
)%
|
|
|
364,602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
143,068
|
|
|
|
+20
|
%
|
|
|
119,416
|
|
|
|
+14
|
%
|
|
|
104,597
|
|
Equity earnings
Discovery
|
|
|
12,033
|
|
|
|
+44
|
%
|
|
|
8,331
|
|
|
|
+85
|
%
|
|
|
4,495
|
|
Impairment of investment in
Discovery
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
+100
|
%
|
|
|
(13,484
|
)
|
Interest expense
|
|
|
(9,833
|
)
|
|
|
(19
|
)%
|
|
|
(8,238
|
)
|
|
|
+34
|
%
|
|
|
(12,476
|
)
|
Interest income
|
|
|
1,600
|
|
|
|
NM
|
|
|
|
165
|
|
|
|
NM
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting principle
|
|
|
146,868
|
|
|
|
+23
|
%
|
|
|
119,674
|
|
|
|
+44
|
%
|
|
|
83,132
|
|
Cumulative effect of change in
accounting principle
|
|
|
|
|
|
|
+100
|
%
|
|
|
(1,322
|
)
|
|
|
NM
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
146,868
|
|
|
|
+24
|
%
|
|
$
|
118,352
|
|
|
|
+42
|
%
|
|
$
|
83,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
+ = Favorable Change;− = Unfavorable Change; NM = A
percentage calculation is not meaningful due to change in signs,
a zero-value denominator or a percentage change greater than 200. |
2006 vs.
2005
Revenues increased $48.4 million, or 9%, due primarily to
higher revenues in our Gathering and Processing West
segment reflecting increased product sales and gathering and
processing revenues as well as increased storage revenues and
increased product sales revenues in our NGL Services segment.
These increases are discussed in detail in the
Results of Operations Gathering
and Processing West and
Results of Operations NGL
Services sections.
Operating and maintenance expense increased $25.5 million,
or 20%, due primarily to higher compression, maintenance and
labor costs in our Gathering and Processing West
segment. These increases are discussed in the
Results of Operations Gathering
and Processing West section.
53
Operating income increased $23.7 million, or 20%, due
primarily to higher net liquids margins and fee-based revenues,
partially offset by higher operating and maintenance expense.
Equity earnings from Discovery increased $3.7 million, or
44%, due primarily to Discoverys higher gross processing
margins partially offset by their higher operating and
maintenance expense. These increases are discussed in detail in
the Results of Operations
Gathering and Processing Gulf section.
Interest expense increased $1.6 million, or 19%, due
primarily to $8.3 million of interest on our
$750.0 million senior unsecured notes. We issued
$150.0 million in June 2006 and $600.0 million in
December 2006 to finance our acquisition of 100% of Four
Corners. This increase was partially offset by $7.4 million
lower interest following the forgiveness of advances from
Williams in conjunction with the closing of our IPO on
August 23, 2005.
Interest income increased $1.4 million due to interest
earned on our cash balances following our IPO on August 23,
2005.
2005 vs.
2004
Revenues increased $45.8 million, or 10%, due primarily to
higher product sales and gathering and processing revenues in
our Gathering and Processing West segment as well as
increased storage and product sales revenues in our NGL Services
segment.
Product cost and shrink replacement increased
$24.6 million, or 16%, directly related to the increase in
product sales volumes in our Gathering and
Processing West and NGL Services segments.
Operating and maintenance expense increased $13.3 million,
or 11%, due primarily to higher maintenance, fuel and power
costs in both our Gathering and Processing West and
NGL Services segments.
General and administrative expense increased $4.4 million,
or 14%, 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.
Other (income) expense, net improved $10.5 million, or 94%,
due primarily to the 2004 impairment of our Four Corners
LaMaquina carbon dioxide treating facility and other 2004 losses
on asset dispositions and materials and supplies inventory
adjustments.
Operating income increased $14.8 million, or 14%, due
primarily to higher fee-based revenues and net liquids margins
in our Gathering and Processing West segment and the
absence of a 2004 impairment charge, partially offset by higher
operating and maintenance expenses.
Equity earnings from Discovery increased $3.8 million due
primarily to Discoverys 2005 recognition of deferred gains
and higher revenues, partially offset by their increased
expenses. This increase is discussed in detail in the
Results of Operations Gathering and
Processing Gulf section.
The 2004 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 fair value of
our investment in Discovery.
Interest expense decreased $4.2 million, or 34%, due
primarily to the forgiveness of advances from Williams in
conjunction with the closing of the IPO on August 23, 2005.
The Cumulative effect of change in accounting principle of
$1.3 million in 2005 relates to our December 31, 2005
adoption of Financial Accounting Standards Board Interpretation
(FIN) No. 47. Please read Note 8 of Notes
to Consolidated Financial Statements.
54
Results
of operations Gathering and Processing
West
The Gathering and Processing West segment includes
our Four Corners natural gas gathering, processing and treating
assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Segment revenues
|
|
$
|
502,313
|
|
|
$
|
463,203
|
|
|
$
|
428,223
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
159,997
|
|
|
|
165,706
|
|
|
|
146,328
|
|
Operating and maintenance expense
|
|
|
124,763
|
|
|
|
104,648
|
|
|
|
97,070
|
|
Depreciation, amortization and
accretion
|
|
|
40,055
|
|
|
|
38,960
|
|
|
|
40,675
|
|
General and administrative
expense direct
|
|
|
11,920
|
|
|
|
12,230
|
|
|
|
8,500
|
|
Taxes other than income
|
|
|
8,245
|
|
|
|
7,746
|
|
|
|
6,790
|
|
Other (income) expense, net
|
|
|
(2,476
|
)
|
|
|
636
|
|
|
|
11,238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses,
including interest income
|
|
|
342,504
|
|
|
|
329,926
|
|
|
|
310,601
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
159,809
|
|
|
$
|
133,277
|
|
|
$
|
117,622
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 vs.
2005
Revenues increased $39.1 million, or 8%, due primarily to
$24.6 million higher product sales and $14.3 million
higher gathering and processing revenues. Product sales
increased due primarily to:
|
|
|
|
|
$14.9 million related to a 12% increase in NGL volumes that
we received under certain processing contracts. This increase
was related primarily to equipment outages in 2005 and reduced
ethane processing in the fourth quarter of 2005 caused by
sharply higher natural gas prices following the hurricanes of
2005;
|
|
|
|
$13.5 million related to a 10% increase in average NGL
sales prices realized on sales of NGLs which we received under
certain processing contracts. This increase resulted from
general increases in market prices for these commodities between
the two periods;
|
|
|
|
$4.1 million of higher condensate sales, which includes
$1.9 million resulting from the recognition of two
additional months of condensate revenue in 2006. Prior to 2006,
condensate revenue had been recognized two months in arrears. As
a result of more timely sales information now made available
from third parties, we have recorded these on a current basis
and thus have fully recognized this activity through
December 31, 2006. Our management concluded that the effect
of recording the additional two months was not material to our
results for 2006, prior periods or our trend of
earnings; and
|
|
|
|
$1.1 million of higher LNG sales related to an increase in
volumes sold.
|
These product sales increases were partially offset by
$9.0 million lower sales of NGLs on behalf of third party
producers for whom we purchase their NGLs for a fee under their
contracts. Under these arrangements, we purchase the NGLs from
the third party producers and sell them to an affiliate. This
decrease is offset by lower associated product costs of
$9.0 million discussed below.
The $14.3 million increase in fee-based gathering and
processing revenues is due primarily to $15.2 million
higher revenue from a 7% increase in the average gathering and
processing rates, partially offset by $0.9 million lower
revenue from a slight decrease in gathering and processing
volumes. The average gathering and processing rates increased in
2006 largely as a result of inflation-sensitive contractual
escalation clauses. One significant gathering agreement is
adjusted based on changes in the average price of natural gas.
55
Product cost and shrink replacement gas costs decreased
$5.7 million, or 3%, due primarily to:
|
|
|
|
|
a $9.0 million decrease from third party producers who
elected to have us purchase their NGLs which was offset by the
corresponding decrease in product sales discussed above; and
|
|
|
|
a $6.0 million decrease from 8% lower average natural gas
prices.
|
These decreases were partially offset by a $9.8 million
increase from 16% higher volumetric shrink requirements under
our Four Corners keep-whole processing contracts.
Operating and maintenance expense increased $20.1 million,
or 19%, due primarily to:
|
|
|
|
|
a $13.4 million increase in materials and supplies, outside
services and other operating expenses related primarily to
increased compression and maintenance costs;
|
|
|
|
a $4.7 million increase in labor and benefits caused by
higher Williams annual incentive program costs and the addition
of new personnel; and
|
|
|
|
a $2.0 million increase in non-shrink natural gas purchases
due primarily to higher volumetric gathering fuel requirements
and higher system losses.
|
Other (income) expense, net improved $3.1 million due
primarily to a $3.6 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.
Segment profit increased $26.5 million, or 20%, due
primarily to $24.7 million of higher net liquids margins
resulting primarily from increased
per-unit
margins on higher NGL sales volumes, $14.3 million of
higher fee-based gathering and processing revenues,
$5.2 million from higher condensate and LNG sales, and the
$3.5 million improvement in other (income) expense, net.
These increases were partially offset by $20.1 million
higher operating and maintenance expense.
2005 vs.
2004
Revenues increased $35.0 million, or 8%, due primarily to
$26.4 million higher product sales and $9.8 million
higher gathering and processing revenue. Product sales revenues
increased due primarily 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 us purchase 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 we received under our processing
contracts;
|
|
|
|
$3.0 million higher LNG sales; and
|
|
|
|
$2.9 million higher condensate sales.
|
These increases were partially offset by $22.1 million
related to 18% lower NGL volumes received under our 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 we 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
inflation-sensitive 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. Historically, we
have substantially offset the impact of production declines at
Four Corners 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 us purchase their NGLs and
56
$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 our 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;
|
|
|
|
$2.7 million of higher natural gas cost related to fuel and
system gains and losses; and
|
|
|
|
$1.8 million of higher compressor costs from
inflation-indexed escalation clauses in operating and
maintenance agreements and additional rental units.
|
These increases were partially offset by $2.0 million of
other various operating and maintenance expense decreases.
General and administrative direct expense increased
$3.7 million, or 44%, due primarily to including certain
management costs that were directly charged in 2005 and
allocated in 2004.
Other (income) expense, net improved $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;
|
|
|
|
$1.2 million loss on asset dispositions; and
|
|
|
|
$1.0 million for materials and supplies inventory
adjustments.
|
Segment profit increased $15.7 million, or 13%, due
primarily to $9.8 million higher gathering and processing
revenues, $7.0 million higher product sales margins on
lower NGL sales volumes and lower other expenses of
$10.6 million, partially offset by $7.6 million higher
operating and maintenance expenses and $3.7 million higher
general and administrative direct expenses.
Outlook
2007
Throughput volumes on our Four Corners gathering, processing and
treating system are an important component of maximizing its
profitability. Throughput volumes from existing wells connected
to its pipelines will naturally decline over time. Accordingly,
to maintain or increase throughput levels we must continually
obtain new supplies of natural gas.
|
|
|
|
|
In 2007, we anticipate that sustained drilling activity,
expansion opportunities and production enhancement activities by
existing customers should be sufficient to more than offset the
historical decline and increase gathered and processed volumes.
|
|
|
|
We have realized above average margins at our gas processing
plants in recent years due primarily to increasing prices for
NGLs. We expect
per-unit
margins in 2007 will remain higher in relation to five- year
historical averages but below the record levels realized in
2006. Additionally, we anticipate that our contract mix and
commodity management activities at Four Corners will continue to
allow us to realize greater margins relative to industry
benchmark averages.
|
|
|
|
We anticipate that operating costs, excluding compression, will
remain stable as compared to 2006. Compression cost increases
are dependent upon the extent and amount of additional
compression needed to meet the needs of our Four Corners
customers and the cost at which compression can be purchased,
leased and operated.
|
|
|
|
We are conducting negotiations with the Jicarilla Apache Nation
in Northern New Mexico for the renewal of certain rights of way
on reservation lands. The current right of way agreement, which
covers certain gathering system assets in Rio Arriba County, New
Mexico, expired on December 31, 2006. We continue to
operate our assets on these reservation lands pursuant to a
three-month agreement while we
|
57
|
|
|
|
|
conduct further discussions that could result in renewal of our
rights of way, sale of the gathering assets on reservation lands
or other options that might be in the mutual interest of both
parties.
|
Results
of operations Gathering and Processing
Gulf
The Gulf segment includes the Carbonate Trend gathering pipeline
and our 40% ownership interest in Discovery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Segment revenues
|
|
$
|
2,656
|
|
|
$
|
3,515
|
|
|
$
|
4,833
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
1,660
|
|
|
|
714
|
|
|
|
572
|
|
Depreciation
|
|
|
1,200
|
|
|
|
1,200
|
|
|
|
1,200
|
|
General and administrative
expense direct
|
|
|
1
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
2,861
|
|
|
|
1,916
|
|
|
|
1,772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss)
|
|
|
(205
|
)
|
|
|
1,599
|
|
|
|
3,061
|
|
Equity earnings
Discovery
|
|
|
12,033
|
|
|
|
8,331
|
|
|
|
4,495
|
|
Impairment of investment in
Discovery
|
|
|
|
|
|
|
|
|
|
|
(13,484
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit (loss)
|
|
$
|
11,828
|
|
|
$
|
9,930
|
|
|
$
|
(5,928
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carbonate
Trend
2006 vs.
2005
Segment operating income decreased $1.8 million from income
of $1.6 million in 2005 to a loss of $0.2 million in
2006 due to the $0.9 million increase in operating and
maintenance expense associated mainly with increased insurance
premiums resulting from hurricanes. Additionally, operating
income decreased due to the absence of $0.5 million in
revenues from the settlement of a contractual volume deficiency
payment recognized in 2005 and lower gathering revenues.
2005 vs.
2004
Segment operating income decreased $1.5 million, or 48%,
due primarily to lower gathering revenues and the absence of
$1.0 million of revenue from the settlement of a
contractual volume deficiency payment recognized in 2004,
partially offset by $0.5 million of revenue from the
settlement of a contractual volume deficiency payment recognized
in 2005.
58
Discovery
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 Statements of Income. The following discussion
addresses in greater detail the results of operations for 100%
of Discovery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Revenues
|
|
$
|
197,313
|
|
|
$
|
122,745
|
|
|
$
|
99,876
|
|
Costs and expenses, including
interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
119,552
|
|
|
|
64,467
|
|
|
|
45,355
|
|
Operating and maintenance expense
|
|
|
23,049
|
|
|
|
10,165
|
|
|
|
17,854
|
|
General and administrative expense
|
|
|
2,150
|
|
|
|
2,053
|
|
|
|
1,424
|
|
Depreciation and accretion
|
|
|
25,562
|
|
|
|
24,794
|
|
|
|
22,795
|
|
Interest income
|
|
|
(2,404
|
)
|
|
|
(1,685
|
)
|
|
|
(550
|
)
|
Other (income)expense, net
|
|
|
(679
|
)
|
|
|
2,123
|
|
|
|
1,328
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
167,230
|
|
|
|
101,917
|
|
|
|
88,206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative
effect of change in accounting principle
|
|
$
|
30,083
|
|
|
$
|
20,828
|
|
|
$
|
11,670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners 40%
interest
|
|
$
|
12,033
|
|
|
$
|
8,331
|
|
|
$
|
4,668
|
|
Capitalized interest amortization
|
|
|
|
|
|
|
|
|
|
|
(173
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings per our
Consolidated Statement of Income
|
|
$
|
12,033
|
|
|
$
|
8,331
|
|
|
$
|
4,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 vs.
2005
Revenues increased $74.6 million, or 61%, due primarily to
higher NGL product sales from the purchasing of customers
NGLs. In addition, the Tennessee Gas Pipeline (TGP)
and the Texas Eastern Transmission Company (TETCO)
open season agreements, which began in the last quarter of 2005,
contributed an increase of $7.5 million. The open seasons
provided outlets for natural gas that was stranded following
damage to third-party facilities during hurricanes Katrina and
Rita. TGPs open season contract came to an end in early
2006. TETCOs volumes continued throughout 2006, and in
October we signed a one-year contract, which is discussed
further in the Outlook section. The significant components of
the revenue increase are addressed more fully below.
|
|
|
|
|
Product sales increased $59.9 million for NGL sales related
to third-party processing customers elections to have
Discovery purchase their NGLs under an option in their
contracts. These sales were offset by higher associated product
costs of $59.9 million discussed below.
|
|
|
|
Product sales also increased $18.1 million due to a 54%
increase in NGL volumes that Discovery received under certain
processing contracts and $5.3 million due to 10% higher
average NGL sales prices related to these volumes. NGL sales
volumes in 2006 were higher due partly to the lack of
hurricane-related disruptions in 2006. In addition,
exceptionally strong commodity margins compelled our customers
to process their natural gas rather than by-pass, which led to
higher product sales revenues on our
percent-of-liquids
and keep-whole processing contracts.
|
|
|
|
Transportation revenues increased $3.1 million, including
$2.4 million in additional fee-based revenues related to
the TGP and TETCO open season agreements discussed above.
|
|
|
|
Fee-based processing and fractionation revenues increased
$2.7 million due primarily to $5.1 million in
additional fee-based revenues related to processing the TGP and
TETCO open seasons volumes discussed above, partially offset by
lower by-pass revenues.
|
59
Partially offsetting these increases were the following:
|
|
|
|
|
Product sales decreased $10.0 million due to the absence of
excess fuel and shrink replacement gas sales.
|
|
|
|
Gathering revenues decreased $3.8 million due primarily to
lower gathered volumes and rates and a $1.4 million
deficiency payment received in the first quarter of 2005.
|
Product cost and shrink replacement increased
$55.1 million, or 85%, due primarily to $59.9 million
higher product purchase costs for the processing customers who
elected to have Discovery purchase their NGLs and
$6.7 million higher costs related primarily to increased
processing volumes in 2006, partially offset by a
$10.0 million decrease due to the absence of excess fuel
and shrink replacement gas sales in 2006.
Operating and maintenance expense increased $12.9 million,
or 127%, due primarily to a $10.7 million credit recognized
in 2005 related to amounts previously deferred for net system
gains from 2002 through 2004. These deferred gains were
recognized following the acceptance in 2005 of a filing with the
FERC. Additionally, Discovery had higher fuel costs caused by
increased processing activity, $1.8 million higher property
insurance premiums related to the increased hurricane activity
in the Gulf Coast region in prior years, partially offset by
$1.0 million insurance deductible expensed in 2005.
Depreciation and accretion expense increased $0.7 million,
or 3%, due primarily to the market expansion project placed in
service in September 2005.
Interest income increased $0.7 million due primarily to
interest earned on funds restricted for use in the construction
of the Tahiti pipeline lateral expansion project.
Other (income) expense, net improved $2.8 million due
primarily to a net improvement of $3.1 million in foreign
currency transaction gains 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. We are required
to pay a significant portion of the construction costs in Euros.
Net income increased $9.3 million, or 44%, due primarily to
$18.1 million higher gross processing margins and
$7.5 million higher revenues from TGP and TETCO open
seasons, partially offset by $12.9 million higher operating
and maintenance and $3.8 million lower gathering revenues.
2005 vs.
2004
Revenues increased $22.9 million, or 23%, due primarily to
higher NGL product sales from purchasing 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 this increase include the following.
|
|
|
|
|
Product sales increased $31.6 million for the NGL sales
related to third-party processing customers election to
have Discovery purchase their NGLs 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 due primarily to $3.9 million in
additional volumes related to the TGP and TETCO open seasons
discussed previously, $2.9 million related to an 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.
|
60
Partially offsetting these increases were the following:
|
|
|
|
|
Product sales 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.
|
|
|
|
Product sales also 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 replacement gas in 2004
than 2005.
|
|
|
|
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 purchase
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 following Hurricanes Katrina and Rita; and
|
|
|
|
$4.9 million lower costs associated with sales of excess
fuel and shrink natural 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. These deferred gains were recognized following the
acceptance in 2005 of a filing with the FERC. Partially
offsetting this was $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 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
period 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 deferred gain recognition,
$8.9 million increased revenue from gathering, processing
and fractionation services and $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 higher other expense including the
foreign currency transaction loss.
61
Outlook
for 2007
Carbonate
Trend
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 to undertake certain restoration activities to repair
the partial erosion of the pipeline overburden caused by
Hurricane Ivan in September, 2004 and Hurricane Katrina in
August 2005. We estimate that these restoration activities could
be completed by the end of 2007. During these repairs, the
pipeline would be shut down for approximately 40 days,
which would decrease our cash flows from operations by
approximately $0.3 million. We would fund these repairs
with cash flows from operations and seek reimbursement from our
insurance carrier
and/or
contractual counterparties. Additionally, in the omnibus
agreement, Williams agreed to reimburse us for the cost of the
restoration activities related to Hurricane Ivan to the extent
that we are not reimbursed by our insurance carrier and subject
to an overall limitation of $14.0 million for all
indemnified environmental and related expenditures generally for
a period of three years that ends in August 2008. We are
assessing our options for meeting our obligations with respect
to these restoration activities.
Discovery
Throughput volumes on Discoverys pipeline system are an
important component of maximizing its profitability. Pipeline
throughput volumes from existing wells connected to its
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, Discovery must continually obtain new supplies of
natural gas.
|
|
|
|
|
The Tahiti pipeline lateral expansion project is currently on
schedule. We expect construction will be completed in the second
quarter of 2007 and anticipate initial throughput will begin in
the first half of 2008. We expect this agreement will have a
significant favorable impact on Discoverys revenues.
|
|
|
|
Discovery signed a one-year processing contract with TETCO
effective October 2006 for a minimum volume of 100 BBtu/d and a
maximum of 300 BBtu/d. Current flowing volume under this
contract is 160 BBtu/d.
|
|
|
|
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; currently
the rate is approximately 40 BBtu/d. We expect the rate to
increase from this level in the third quarter of 2007.
|
|
|
|
In October 2006 we signed an agreement with Walter Oil and Gas
Corp. which is producing approximately 25 BBtu/d.
|
|
|
|
In December 2006 we signed an agreement with Energy
Partners LTD, which will result in approximately 10 BBtu/d
of throughput beginning in the first quarter of 2007.
|
|
|
|
Insurance premiums have increased dramatically from
approximately $2.3 million in 2005 to the current level of
$4.9 million in 2006. We have no reason to expect premiums
to materially change from this amount in the near term.
|
62
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Segment revenues
|
|
$
|
58,441
|
|
|
$
|
48,254
|
|
|
$
|
36,143
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
28,791
|
|
|
|
24,397
|
|
|
|
18,804
|
|
Product cost
|
|
|
15,511
|
|
|
|
11,821
|
|
|
|
6,635
|
|
Depreciation and accretion
|
|
|
2,437
|
|
|
|
2,419
|
|
|
|
2,486
|
|
General and administrative
expense direct
|
|
|
1,149
|
|
|
|
1,068
|
|
|
|
535
|
|
Other, net
|
|
|
719
|
|
|
|
694
|
|
|
|
625
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
48,607
|
|
|
|
40,399
|
|
|
|
29,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
9,834
|
|
|
$
|
7,855
|
|
|
$
|
7,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 vs.
2005
Segment revenues increased $10.2 million, or 21%, due
primarily to higher storage, product sales and other revenues.
The significant components of these revenue increases are
addressed more fully below.
|
|
|
|
|
Storage revenues increased $4.9 million due primarily to
higher average storage volumes from additional short-term
storage leases caused by the reduced demand for propane during
the mild 2006 winter and storage customers who held their NGLs
in storage due to an inclining forward market.
|
|
|
|
Product sales were $2.6 million higher due primarily to the
sale of surplus volumes created through our product optimization
activities. This increase was more than offset by the related
increase in product cost discussed below.
|
|
|
|
Other revenues increased $1.7 million due primarily to
$1.3 million of fees charged for low sulfur natural
gasoline upgrades that began in 2006.
|
Operating and maintenance expense increased $4.4 million,
or 18%, due primarily to increased storage cavern workovers and
increases to Conways environmental remediation liability,
partially offset by favorable changes in product imbalance
adjustments.
Product cost increased $3.7 million, or 31%, due to the
higher product sales volumes discussed above as well as an
increase in
per-unit
costs of 21%.
Segment profit increased $2.0 million, or 25%, due
primarily to $10.2 million higher revenues, substantially
offset by $8.1 million higher product cost and operating
and maintenance expense.
2005 vs.
2004
Segment revenues increased $12.1 million, or 34%, due
primarily to higher product sales, storage and fractionation
revenues. The significant components of the increase include the
following:
|
|
|
|
|
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 discussed below.
|
|
|
|
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
and storage volumes.
|
63
|
|
|
|
|
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 higher volumes in 2005.
|
Operating and maintenance expense increased $5.6 million,
or 30%, due primarily to increased fuel and power costs, some of
which we are able to pass through to our customers, and
increased product imbalance valuation adjustments.
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, partially offset by $5.6 million
higher operating and maintenance expense.
Outlook
for 2007
|
|
|
|
|
In 2006 we experienced record physical storage volumes largely
related to increased demand for short-term storage leases. This
increase in short-term leases was caused primarily by reduced
demand for propane during the mild
2005-2006
winter and storage customers who held their NGLs in storage due
to an inclining forward market. In 2007, we expect demand for
our storage services to remain strong in relation to historic
averages but we do not expect to realize the same level of
short-term storage leases as experienced in 2006.
|
|
|
|
We continue to execute a large number of storage cavern
workovers and wellhead modifications to comply with KDHE
regulatory requirements. We expect outside service costs to
continue at current levels throughout 2007 and 2008 to ensure
that we meet the regulatory compliance requirement to complete
cavern wellhead modifications before the end of 2008. Our
forecast for 2007 is to workover approximately 59 caverns (both
complete and partial) compared to 51 cavern workovers (38
complete and 13 partial) in 2006.
|
Financial
Condition and Liquidity
We believe we have the financial resources and liquidity
necessary to meet future requirements for working capital,
capital and investment expenditures, debt service and quarterly
cash distributions. We anticipate our sources of liquidity for
2007 will include:
|
|
|
|
|
Cash and cash equivalents on hand;
|
|
|
|
Cash generated from operations, including cash distributions
from Discovery;
|
|
|
|
Insurance or other recoveries related to the Carbonate Trend
overburden restoration, which should be received, approximately,
as costs are incurred;
|
|
|
|
Capital contributions from Williams pursuant to an omnibus
agreement; and
|
|
|
|
Credit facilities, as needed.
|
Our cash and cash equivalents increased $16.5 million and
$19.2 million on June 20, 2006 and December 13,
2006, respectively, upon the completion of our acquisitions of
25.1% and 74.9% ownership interests in Four Corners. These
amounts represent excess net proceeds generated by our offerings
of common units and issuances of senior unsecured notes above
the consideration paid to Williams for the respective Four
Corners interests. We have retained this cash to be used for
general partnership purposes.
We anticipate our more significant cash requirements for 2007 to
be:
|
|
|
|
|
Maintenance capital expenditures for our Four Corners and Conway
assets;
|
|
|
|
Expansion capital expenditures for our Four Corners assets;
|
64
|
|
|
|
|
Carbonate Trend overburden restoration;
|
|
|
|
Interest on our long-term debt; and
|
|
|
|
Quarterly distributions to our unitholders.
|
Discovery
Discovery expects to make quarterly distributions of available
cash to its members pursuant to the terms of its limited
liability company agreement. Discovery made the following
2006-2007
distributions to its members (all amounts in thousands):
|
|
|
|
|
|
|
|
|
Date of Distribution
|
|
Total Distribution to Members
|
|
|
Our 40% Share
|
|
|
1/31/06
|
|
$
|
11,000
|
|
|
$
|
4,400
|
|
4/28/06
|
|
$
|
9,000
|
|
|
$
|
3,600
|
|
7/31/06
|
|
$
|
10,000
|
|
|
$
|
4,000
|
|
10/30/06
|
|
$
|
11,000
|
|
|
$
|
4,400
|
|
1/30/07
|
|
$
|
9,000
|
|
|
$
|
3,600
|
|
In 2005, Discovery sustained damages from Hurricane Katrina. The
estimated total cost for hurricane-related repairs is
approximately $26.0 million, including $24.5 million
in potentially reimbursable expenditures in excess of its
deductible. Of this amount, $17.5 million has been spent as of
December 31, 2006. Discovery is funding these repairs with
cash flows from operations and is seeking reimbursement from its
insurance carrier. As of December 31, 2006, Discovery has
received $4.9 million from the insurance carriers and has
an insurance receivable balance of $12.6 million.
We expect future cash requirements for Discovery relating to
working capital and maintenance capital expenditures to be
funded from its own internally generated cash flows from
operations. Growth or expansion capital expenditures for
Discovery will be funded either by 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 required under the omnibus
agreement consist of the following:
|
|
|
|
|
Indemnification of environmental and related expenditures, less
any related insurance recoveries, for a period of three years
(for certain of those expenditures) up to a cap of
$14 million. Amounts expected to be incurred in 2007
related to these indemnifications are as follows:
|
|
|
|
|
|
approximately $2.9 million for capital expenditures related
to KDHE-related cavern compliance at our Conway storage
facilities;
|
|
|
|
and approximately $1.2 million for our 40% share of
Discoverys costs for marshland restoration and repair or
replacement of Paradis emission-control flare.
|
In addition, should we undertake the repair, we would incur
repair costs related to the partial erosion of the Carbonate
Trend pipeline overburden by Hurricane Ivan in 2004. We expect
all costs related to this repair will be recoverable from
insurance, but to the extent they are not, we will seek
indemnification under the omnibus agreement. We are assessing
our options for meeting our obligations with respect to these
restoration activities. As of December 31, 2006 we have
received $2.5 million from Williams for indemnified items
since inception of the agreement in August 2005. Thus,
approximately $11.5 million remains for reimbursement of
our costs on these items.
|
|
|
|
|
An annual credit for general and administrative expenses of
$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. As of December 31, 2006 we have
received $1.6 million from Williams for this
indemnification.
|
65
Credit
Facilities
We may borrow up to $75.0 million under Williams
$1.5 billion revolving credit facility, which is available
for borrowings and letters of credit. Borrowings under this
facility mature on May 1, 2009. Our $75.0 million
borrowing limit under Williams revolving credit 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, 2006, letters of credit totaling
$29.0 million had been issued on behalf of Williams by the
participating institutions under this facility and no revolving
credit loans were outstanding.
We also have a $20.0 million revolving credit facility with
Williams as the lender. The facility was amended and restated on
August 7, 2006. The facility is available exclusively to
fund working capital borrowings. Borrowings under the amended
and restated facility will mature on June 29, 2009. We are
required to reduce all borrowings under this 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
December 31, 2006 we had no outstanding borrowings under
the working capital credit facility.
Capital
Requirements
The natural gas gathering, treating, 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 $11.0 million for 2007. Of
this amount, we estimate approximately $3.0 million may be
reimbursed by Williams subject to the omnibus agreement. We
expect to fund the remainder of these expenditures through cash
flows from operations. These expenditures relate primarily to
cavern workovers and wellhead modifications necessary to comply
with KDHE regulations.
We estimate that expansion capital expenditures for the Conway
assets will be approximately $2.0 million for 2007.
We estimate that maintenance capital expenditures for Four
Corners will be approximately $25.0 million for 2007. We
expect Four Corners will fund its maintenance capital
expenditures through its cash flows from operations. These
expenditures include approximately $13.0 million related to
well connections necessary to connect new sources of throughput
for the Four Corners system which serve to offset the
historical decline in throughput volumes.
We estimate that expansion capital expenditures for Four Corners
will be approximately $19.0 million for 2007. We expect
Four Corners will fund its expansion capital expenditures
through its cash flows from operations. These expenditures
include estimates of approximately $6.0 million for certain
well connections that we believe will increase throughput
volumes in 2007.
We estimate that maintenance capital expenditures for 100% of
Discovery will be approximately $7.0 million for 2007. Of
this amount, we estimate our 40% share of approximately
$3.0 million may be reimbursed by Williams subject to the
omnibus agreement. We expect Discovery will fund the remainder
of its maintenance capital expenditures through its cash flows
from operations. These maintenance capital expenditures relate
to numerous smaller projects.
66
We estimate that expansion capital expenditures for 100% of
Discovery will be approximately $39.0 million for 2007, of
which our 40% share is $16.0 million. Of the 100% amount,
approximately $33.0 million is for the ongoing construction
of the Tahiti pipeline lateral expansion project. Discovery will
fund these expenditures with amounts previously escrowed for
this project.
Carbonate
Trend Overburden Restoration
Should we undertake the repair, we would incur repair costs
related to the partial erosion of the Carbonate Trend pipeline
overburden by Hurricane Ivan in 2004 and Hurricane Katrina in
2005. We would fund these repairs with cash flows from
operations and then seek reimbursement from insurance
and/or
contractual counterparties. We are assessing our options for
meeting our obligations with respect to these restoration
activities.
Debt
Service Long-Term Debt
In June 2006, we and Williams Partners Finance Corporation
(Williams Partners Finance) issued
$150.0 million aggregate principal amount of senior
unsecured notes. Williams Partners Finance Corporation is our
wholly owned subsidiary organized for the sole purpose of
co-issuing our debt securities. The senior unsecured notes bear
interest at 7.5% per annum payable semi-annually in arrears
on June 15 and December 15 of each year. We made the first
payment on December 15, 2006. The senior notes mature on
June 15, 2011.
Additionally, on December 13, 2006, we and Williams
Partners Finance issued $600.0 million aggregate principal
of 7.25% senior unsecured notes in a private debt
placement. The maturity date of the notes is February 1,
2017. Interest is payable semi-annually in arrears on February 1
and August 1 of each year, beginning on August 1, 2007.
In connection with the issuance of the 7.5% and
7.25% senior unsecured notes, we entered into registration
rights agreements with the initial purchasers whereby we agreed
to conduct registered exchange offers of exchange notes in
exchange for the senior unsecured notes or cause to become
effective a shelf registration statement providing for resale of
the senior unsecured notes. If we fail to file a registration
statement with the SEC within 270 days of the respective
closing dates, we will be required to pay liquidated damages in
the form of additional cash interest to the holders of the
notes. Upon the occurrence of such a failure to comply, the
interest rate on the senior unsecured notes shall be increased
by 0.25% per annum during the
90-day
period immediately following the occurrence of such failure to
comply and shall increase by 0.25% per annum 90 days
thereafter until all defaults have been cured, but in no event
shall such aggregate additional interest exceed 0.50% per
annum.
Cash
Distributions to Unitholders
We paid quarterly distributions to common and subordinated
unitholders and our general partner interest after every quarter
since our IPO on August 23, 2005. Our most recent quarterly
distribution of $19.5 million was paid on February 14,
2007 to the general partner interest and common, Class B
and subordinated unitholders of record at the close of business
on February 7, 2007. This distribution included an
additional incentive distribution to our general partner of
approximately $0.6 million.
Results
of Operations Cash Flows
Williams
Partners L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Net cash provided by operating
activities
|
|
$
|
173,817
|
|
|
$
|
157,932
|
|
|
$
|
137,090
|
|
Net cash used by investing
activities
|
|
|
(628,580
|
)
|
|
|
(55,666
|
)
|
|
|
(15,454
|
)
|
Net cash provided (used) by
financing activities
|
|
|
505,465
|
|
|
|
(95,427
|
)
|
|
|
(121,636
|
)
|
67
The $15.9 million increase in net cash provided by
operating activities for 2006 as compared to 2005 is due
primarily to $24.1 million increase in operating income as
adjusted for non-cash items and a $16.4 million increase in
distributed earnings from Discovery, partially offset by a
$29.4 million increase in cash used for working capital.
The increase in cash used for working capital was caused
primarily by an increase in affiliate receivables as a result of
Four Corners transition from Williams cash
management program to our cash management program, and other
changes in accounts payable. The $20.8 million increase in
net cash provided by operating activities in 2005 as compared to
2004 is due primarily to $8.4 million higher operating
income, adjusted for non-cash items, and $8.1 million in
cash provided from changes in working capital related primarily
to a change in the shrink replacement gas imbalance.
Net cash used by investing activities in 2006 relates primarily
to the $608.3 million acquisition of Four Corners. Because
Four Corners was an affiliate of Williams at the time of these
acquisitions, these transactions are accounted for as a
combination of entities under common control and the acquisition
is recorded at historical cost rather than the actual
consideration paid to Williams. Net cash used by investing
activities in 2005 includes our capital contribution of
$24.4 million to Discovery for construction of the Tahiti
pipeline lateral expansion project. Capital expenditures for
Four Corners and Conway totaled $31.8 million,
$31.3 million and $15.6 million in 2006, 2005 and
2004, respectively.
Net cash provided by financing activities in 2006 includes:
|
|
|
|
|
$625.3 million of net proceeds from debt and equity
issuances related to our acquisition of Four Corners less the
related amounts distributed to Williams in excess of Four
Corners contributed basis;
|
|
|
|
distributions to unitholders and our general partner of
$30.0 million; and
|
|
|
|
contributions from our general partner to maintain their 2%
ownership following the issuances of equity and per the omnibus
agreement that totaled $25.5 million.
|
Net cash provided by financing activities in 2005 includes the
cash flows related to our IPO in August 2005. In addition, 2006,
2005 and 2004 included $114.5 million, $187.2 million
and $120.5 million, respectively, related to the pass
through of net cash flows to Williams under its cash management
program of Four Corners net cash flows and operations
prior to our IPO.
Discovery
100%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
Net cash provided by operating
activities
|
|
$
|
62,606
|
|
|
$
|
30,814
|
|
|
$
|
35,623
|
|
Net cash used by investing
activities
|
|
|
(16,312
|
)
|
|
|
(65,997
|
)
|
|
|
(39,115
|
)
|
Net cash provided (used) by
financing activities
|
|
|
(30,089
|
)
|
|
|
1,339
|
|
|
|
|
|
Net cash provided by operating activities increased
$31.8 million in 2006 as compared to 2005 due primarily to
an increase of $19.3 million in working capital and an
increase of $10.0 million in operating income as adjusted
for non-cash items. The 2006 cash provided related to working
capital was due to receipts on invoices that were outstanding at
the end of 2005 and the collection of hurricane-related
insurance receivables. 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 had not yet been reimbursed by
Discoverys insurance carrier.
Net cash used by investing activities included
$33.4 million of capital spending in 2006, primarily for
the Tahiti project, partially offset by the use of
$15.8 million of Tahiti-related 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.
68
Net cash used by financing activities in 2006 includes
$13.5 million of capital contributions compared to
$48.3 million in 2005. Both years contributions
related to the Tahiti pipeline lateral expansion. Additionally,
Discovery distributed $41.0 million to its members during
2006. During 2005, Discovery distributed $43.8 million
associated with its operations prior to our IPO and a
$3.2 million quarterly distribution to members in the
fourth quarter of 2005.
Contractual
Obligations
A summary of our contractual obligations as of December 31,
2006, is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008-2009
|
|
|
2010-2011
|
|
|
2012+
|
|
|
Total
|
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal
|
|
$
|
|
|
|
$
|
|
|
|
$
|
150,000
|
|
|
$
|
600,000
|
|
|
$
|
750,000
|
|
Interest
|
|
|
36,625
|
|
|
|
109,500
|
|
|
|
109,500
|
|
|
|
239,250
|
|
|
|
494,875
|
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
2,426
|
|
|
|
4,025
|
|
|
|
2,440
|
|
|
|
1,000
|
|
|
|
9,891
|
|
Purchase obligations
|
|
|
20,212
|
(a)
|
|
|
240
|
|
|
|
240
|
|
|
|
120
|
(b)
|
|
|
20,812
|
|
Other long term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
59,263
|
|
|
$
|
113,765
|
|
|
$
|
262,180
|
|
|
$
|
840,370
|
|
|
$
|
1,275,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes the open purchase orders as of
12/31/06 to
be paid in 2007. |
|
(b) |
|
Year 2012 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, 2006, is
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008-2009
|
|
|
2010-2011
|
|
|
2012+
|
|
|
Total
|
|
|
Notes payable/long-term debt
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
855
|
|
|
|
1,715
|
|
|
|
1,715
|
|
|
|
3,252
|
|
|
|
7,537
|
|
Purchase obligations(a)
|
|
|
33,279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33,279
|
|
Other long-term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
34,134
|
|
|
$
|
1,715
|
|
|
$
|
1,715
|
|
|
$
|
3,252
|
|
|
$
|
40,816
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
A majority of the amounts are Tahiti-related expenditures that
will be funded from the amounts that were escrowed for this
project in September 2005 and capital contributions from members
including us. Please read Financial Condition and
Liquidity. |
Effects
of Inflation
We have experienced increased costs in recent years due to the
effects of growth in the oil and gas industry, which has
increased competition for resources. Approximately 50% of Four
Corners gathering and processing revenues are from
contracts that include escalation clauses that provide for an
annual escalation based on an inflation-sensitive index. These
escalations, combined with increased fees where competition
permits for new and amended contracts, help to offset these
inflationary pressures; however, they may not always approximate
the actual inflation rate we experience due to geographic
and/or
industry-specific inflationary pressures on our costs and
expenses. We have significant annual capital expenditures
related to well connections and gathering system expansions
necessary to connect new sources of throughput to the Four
Corners system as throughput volumes from existing wells
will naturally decline over time.
69
Regulatory
Matters
Discoverys natural gas pipeline transportation is subject
to rate regulation by the FERC under the Natural Gas Act. For
more information on federal and state regulations affecting our
business, please read Risk Factors and FERC
Regulation elsewhere in this report.
Environmental
We are a participant in certain hydrocarbon removal and
groundwater monitoring activities associated with 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. As of
December 31, 2006, we had accrued liabilities totaling
$0.7 million for these environmental activities. 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. During 2006, we paid
approximately $0.2 million in construction with these
environmental activities.
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 35 salt caverns per year and install, on
average, a double liner on one brine pond every other year. The
incremental cost of these activities is approximately
$5.5 million per year to complete the workovers and
approximately $1.2 million per year to install a double
liner on a brine bond. 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.
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, of which $0.7 million has
been incurred to date from the onset of the policy. 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 closing date of August 23, 2005. 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
$0.2 million to $0.4 million per year following the
completion of the remediation work. At December 31, 2006
and 2005, we had accrued liabilities totaling $5.9 million
and $5.4 million, respectively, for these costs. 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.
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. Williams has posted
two letters of credit on our behalf in an aggregate amount of
70
$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
or are capable of meeting KDHE financial strength tests. After
our filing of this
Form 10-K,
we will request the state to accept a financial test in lieu of
the letters of credit.
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 $2.9 million.
|
|
Item 7A.
|
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 risks to which we
are exposed are commodity price risk and interest rate risk.
Commodity
Price Risk
Certain of our and 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 our and Discoverys services in
the future. Our Carbonate Trend pipeline 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 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. 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. This physical contract is a derivative. However,
we elected to account for this contract under the normal
purchases exemption to the fair value accounting that would
otherwise apply. We also have physical contracts for the
purchase of ethane and the sale of propane related to our
operating supply management activities at Conway. These physical
contracts are derivatives. However, we elected to account for
these contracts under the normal purchases exemption to the fair
value accounting that would otherwise apply. We and Discovery do
not currently use any other derivatives to manage the risks
associated with these price fluctuations.
Interest
Rate Risk
Our long-term senior unsecured notes have fixed interest rates.
Any borrowings under our credit agreements would be at a
variable interest rate and would expose us to the risk of
increasing interest rates. As of December 31, 2006 we did
not have borrowings under our credit agreements.
The table below provides information about our interest
rate-sensitive instruments as of December 31, 2006.
Long-term debt in the table represents principal cash flows by
expected maturity date. The fair value of our private debt is
valued based on the prices of similar securities with similar
terms and credit ratings.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2006
|
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
Fixed rate
|
|
$
|
150
|
|
|
$
|
156
|
|
Interest rate
|
|
|
7.5
|
%
|
|
|
|
|
Fixed rate
|
|
$
|
600
|
|
|
$
|
612
|
|
Interest rate
|
|
|
7.25
|
%
|
|
|
|
|
71
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
MANAGEMENTS
REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Our general partner is responsible for establishing and
maintaining adequate internal control over financial reporting
(as defined in
Rules 13a-15(f)
and
15d-15(f)
under the Securities Exchange Act of 1934) and for the
assessment of the effectiveness of internal control over
financial reporting. Our internal control system was designed to
provide reasonable assurance to our management and board of
directors regarding the preparation and fair presentation of
financial statements in accordance with accounting principles
generally accepted in the United States. Our internal control
over financial reporting includes those policies and procedures
that (i) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the
transactions and dispositions of our assets; (ii) provide
reasonable assurance that transactions are recorded as to permit
preparation of financial statements in accordance with generally
accepted accounting principles, and that our receipts and
expenditures are being made only in accordance with
authorization of our management and board of directors; and
(iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use or disposition
of our assets that could have a material effect on our financial
statements.
All internal control systems, no matter how well designed, have
inherent limitations. Therefore, even those systems determined
to be effective can provide only reasonable assurance with
respect to financial statement preparation and presentation.
Projections of any evaluation of effectiveness to future periods
are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
Our management assessed the effectiveness of Williams Partners
L.P.s internal control over financial reporting as of
December 31, 2006. In making this assessment, management
used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) in Internal
Control Integrated Framework. Managements
assessment included an evaluation of the design of our internal
control over financial reporting and testing of the operational
effectiveness of our internal control over financial reporting.
Based on our assessment we believe that, as of December 31,
2006, Williams Partners L.P.s internal control over
financial reporting is effective based on those criteria.
Ernst & Young, LLP, our independent registered public
accounting firm, has issued an audit report on our assessment of
the companys internal control over financial reporting. A
copy of this report is included in this Annual Report on
Form 10-K.
72
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors of Williams Partners GP LLC
General Partner of Williams Partners L.P.
and the Limited Partners of Williams Partners L.P.
We have audited managements assessment, included in the
accompanying Managements Report on Internal Control over
Financial Reporting, that Williams Partners L.P. maintained
effective internal control over financial reporting as of
December 31, 2006, based on criteria established in
Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (the
COSO criteria). Williams Partners L.P.s
management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our
responsibility is to express an opinion on managements
assessment and an opinion on the effectiveness of the
Companys internal control over financial reporting 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 effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, evaluating
managements assessment, testing and evaluating the design
and operating effectiveness of internal control, and performing
such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, managements assessment that Williams
Partners L.P. maintained effective internal control over
financial reporting as of December 31, 2006, is fairly
stated, in all material respects, based on the COSO criteria.
Also in our opinion, Williams Partners L.P. maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2006, based on the COSO
criteria.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Williams Partners L.P. as of
December 31, 2006 and 2005, and the related consolidated
statements of income, partners capital, and cash flows for
each of the three years in the period ended December 31,
2006, and our report dated February 22, 2007 expressed an
unqualified opinion thereon.
Tulsa, Oklahoma
February 22, 2007
73
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Williams Partners GP LLC
General Partner of Williams Partners L.P.
and the Limited Partners of Williams Partners L.P.
We have audited the accompanying consolidated balance sheets of
Williams Partners L.P. as of December 31, 2006 and 2005,
and the related consolidated statements of income,
partners capital, and cash flows for each of the three
years in the period ended December 31, 2006. 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 standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Williams Partners L.P. at
December 31, 2006 and 2005, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2006, in conformity with
U.S. generally accepted accounting principles.
As described in Note 8, effective December 31,
2005, Williams Partners L.P. adopted Financial Accounting
Standards Board Interpretation No. 47, Accounting for
Conditional Asset Retirement Obligations.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of Williams Partners L.P.s internal control
over financial reporting as of December 31, 2006, based on
criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 22, 2007,
expressed an unqualified opinion thereon.
Tulsa, Oklahoma
February 22, 2007
74
WILLIAMS
PARTNERS L.P.
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005*
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
57,541
|
|
|
$
|
6,839
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Trade
|
|
|
18,320
|
|
|
|
17,695
|
|
Affiliate
|
|
|
12,420
|
|
|
|
|
|
Other
|
|
|
3,991
|
|
|
|
3,472
|
|
Gas purchase contract
affiliate
|
|
|
4,754
|
|
|
|
5,320
|
|
Prepaid expenses
|
|
|
3,765
|
|
|
|
2,742
|
|
Other current assets
|
|
|
2,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
103,325
|
|
|
|
36,068
|
|
Investment in Discovery Producer
Services
|
|
|
147,493
|
|
|
|
150,260
|
|
Property, plant and equipment, net
|
|
|
647,578
|
|
|
|
658,965
|
|
Gas purchase contract
noncurrent affiliate
|
|
|
|
|
|
|
4,754
|
|
Other noncurrent assets
|
|
|
34,752
|
|
|
|
25,228
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
933,148
|
|
|
$
|
875,275
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS
CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
19,827
|
|
|
$
|
25,572
|
|
Affiliate
|
|
|
|
|
|
|
4,729
|
|
Product imbalance
|
|
|
651
|
|
|
|
1,765
|
|
Deferred revenue
|
|
|
3,382
|
|
|
|
3,552
|
|
Accrued liabilities
|
|
|
16,173
|
|
|
|
6,160
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
40,033
|
|
|
|
41,778
|
|
Long-term debt
|
|
|
750,000
|
|
|
|
|
|
Environmental remediation
liabilities
|
|
|
3,964
|
|
|
|
4,371
|
|
Other noncurrent liabilities
|
|
|
3,749
|
|
|
|
1,881
|
|
Commitments and contingent
liabilities (Note 14)
|
|
|
|
|
|
|
|
|
Partners capital:
|
|
|
|
|
|
|
|
|
Common unitholders (25,553,306 and
7,006,146 outstanding at December 31, 2006 and 2005)
|
|
|
733,878
|
|
|
|
108,526
|
|
Class B unitholders
(6,805,492 outstanding at December 31, 2006)
|
|
|
241,923
|
|
|
|
|
|
Subordinated unitholders
(7,000,000 outstanding at December 31, 2006 and 2005)
|
|
|
108,862
|
|
|
|
108,491
|
|
General partner
|
|
|
(949,261
|
)
|
|
|
610,228
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
135,402
|
|
|
|
827,245
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
partners capital
|
|
$
|
933,148
|
|
|
$
|
875,275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Restated as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
75
WILLIAMS
PARTNERS L.P.
CONSOLIDATED
STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005*
|
|
|
2004*
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and processing:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
42,228
|
|
|
$
|
36,755
|
|
|
$
|
30,990
|
|
Third-party
|
|
|
206,432
|
|
|
|
198,041
|
|
|
|
194,832
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
255,075
|
|
|
|
236,020
|
|
|
|
199,716
|
|
Third-party
|
|
|
16,919
|
|
|
|
8,728
|
|
|
|
13,605
|
|
Storage
|
|
|
25,237
|
|
|
|
20,290
|
|
|
|
15,318
|
|
Fractionation
|
|
|
11,698
|
|
|
|
10,770
|
|
|
|
9,070
|
|
Other
|
|
|
5,821
|
|
|
|
4,368
|
|
|
|
5,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
563,410
|
|
|
|
514,972
|
|
|
|
469,199
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
78,201
|
|
|
|
58,780
|
|
|
|
58,193
|
|
Third-party
|
|
|
97,307
|
|
|
|
118,747
|
|
|
|
94,770
|
|
Operating and maintenance expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
53,627
|
|
|
|
46,194
|
|
|
|
39,968
|
|
Third-party
|
|
|
101,587
|
|
|
|
83,565
|
|
|
|
76,478
|
|
Depreciation, amortization and
accretion
|
|
|
43,692
|
|
|
|
42,579
|
|
|
|
44,361
|
|
General and administrative expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
34,295
|
|
|
|
33,765
|
|
|
|
29,948
|
|
Third-party
|
|
|
5,145
|
|
|
|
2,850
|
|
|
|
2,231
|
|
Taxes other than income
|
|
|
8,961
|
|
|
|
8,446
|
|
|
|
7,506
|
|
Other (income) expense
net
|
|
|
(2,473
|
)
|
|
|
630
|
|
|
|
11,147
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
420,342
|
|
|
|
395,556
|
|
|
|
364,602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
143,068
|
|
|
|
119,416
|
|
|
|
104,597
|
|
Equity earnings
Discovery Producer Services
|
|
|
12,033
|
|
|
|
8,331
|
|
|
|
4,495
|
|
Impairment of investment in
Discovery Producer Services
|
|
|
|
|
|
|
|
|
|
|
(13,484
|
)
|
Interest expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
(89
|
)
|
|
|
(7,461
|
)
|
|
|
(11,980
|
)
|
Third-party
|
|
|
(9,744
|
)
|
|
|
(777
|
)
|
|
|
(496
|
)
|
Interest income
|
|
|
1,600
|
|
|
|
165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting principle
|
|
|
146,868
|
|
|
|
119,674
|
|
|
|
83,132
|
|
Cumulative effect of change in
accounting principle
|
|
|
|
|
|
|
(1,322
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
146,868
|
|
|
$
|
118,352
|
|
|
$
|
83,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income for
calculation of earnings per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
146,868
|
|
|
$
|
118,352
|
|
|
|
|
|
Net income applicable to
pre-partnership operations allocated to general partner
|
|
|
(116,450
|
)
|
|
|
(113,418
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to
partnership operations
|
|
|
30,418
|
|
|
|
4,934
|
|
|
|
|
|
Allocation of net loss to general
partner
|
|
|
(2,897
|
)
|
|
|
(1,273
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income to limited
partner
|
|
|
33,315
|
|
|
|
6,207
|
|
|
|
|
|
Basic and diluted earnings per
limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
1.62
|
|
|
$
|
0.49
|
|
|
|
|
|
Class B units
|
|
$
|
0.45
|
|
|
|
N/A
|
|
|
|
|
|
Subordinated units
|
|
$
|
1.62
|
|
|
$
|
0.49
|
|
|
|
|
|
Cumulative effect of change in
accounting principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
|
|
|
$
|
(0.05
|
)
|
|
|
|
|
Class B units
|
|
|
|
|
|
|
N/A
|
|
|
|
|
|
Subordinated units
|
|
|
|
|
|
$
|
(0.05
|
)
|
|
|
|
|
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
1.62
|
|
|
$
|
0.44
|
|
|
|
|
|
Class B units
|
|
$
|
0.45
|
|
|
|
N/A
|
|
|
|
|
|
Subordinated units
|
|
$
|
1.62
|
|
|
$
|
0.44
|
|
|
|
|
|
Weighted average number of units
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
11,632,110
|
|
|
|
7,001,366
|
|
|
|
|
|
Class B units
|
|
|
354,258
|
|
|
|
N/A
|
|
|
|
|
|
Subordinated units
|
|
|
7,000,000
|
|
|
|
7,000,000
|
|
|
|
|
|
|
|
|
* |
|
Restated as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
76
WILLIAMS
PARTNERS L.P.
CONSOLIDATED
STATEMENT OF PARTNERS CAPITAL*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-IPO
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Owners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity/
|
|
|
Total
|
|
|
|
|
|
|
Limited Partners
|
|
|
General
|
|
|
Partners
|
|
|
|
Common
|
|
|
Class B
|
|
|
Subordinated
|
|
|
Partner
|
|
|
Capital
|
|
|
|
(Dollars in thousands)
|
|
|
Balance
December 31, 2004
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
637,198
|
|
|
$
|
637,198
|
|
Accounts receivable not contributed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,640
|
)
|
|
|
(2,640
|
)
|
Contribution of net assets of
predecessor companies (2,000,000 common units; 7,000,000
subordinated units)
|
|
|
10,471
|
|
|
|
|
|
|
|
106,427
|
|
|
|
49,174
|
|
|
|
166,072
|
|
Net income 2005
|
|
|
3,104
|
|
|
|
|
|
|
|
3,103
|
|
|
|
112,145
|
|
|
|
118,352
|
|
Cash distributions
|
|
|
(1,039
|
)
|
|
|
|
|
|
|
(1,039
|
)
|
|
|
(42
|
)
|
|
|
(2,120
|
)
|
Issuance of units to public
(5,000,000 common units)
|
|
|
100,247
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100,247
|
|
Offering costs
|
|
|
(4,291
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,291
|
)
|
Issuance of common units (6,146
common units)
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
Distributions to The Williams
Companies, Inc. net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(187,217
|
)
|
|
|
(187,217
|
)
|
Contributions pursuant to the
omnibus agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,610
|
|
|
|
1,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
December 31, 2005
|
|
|
108,526
|
|
|
|
|
|
|
|
108,491
|
|
|
|
610,228
|
|
|
|
827,245
|
|
Net income 2006
|
|
|
21,181
|
|
|
|
655
|
|
|
|
11,606
|
|
|
|
113,426
|
|
|
|
146,868
|
|
Cash distributions
|
|
|
(17,887
|
)
|
|
|
|
|
|
|
(11,235
|
)
|
|
|
(872
|
)
|
|
|
(29,994
|
)
|
Issuance of units to public
(18,545,030 common units)
|
|
|
625,995
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
625,995
|
|
Issuance of Class B units
through Private placement (6,805,492 Class B units)
|
|
|
|
|
|
|
241,268
|
|
|
|
|
|
|
|
|
|
|
|
241,268
|
|
Offering costs
|
|
|
(4,168
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,168
|
)
|
Distributions to The Williams
Companies, Inc. net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(114,497
|
)
|
|
|
(114,497
|
)
|
Distributions to general partner
for purchase of Four Corners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,583,000
|
)
|
|
|
(1,583,000
|
)
|
Contributions pursuant to the
omnibus agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,840
|
|
|
|
6,840
|
|
Contributions from general partner
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,614
|
|
|
|
18,614
|
|
Other
|
|
|
231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
December 31, 2006
|
|
$
|
733,878
|
|
|
$
|
241,923
|
|
|
$
|
108,862
|
|
|
$
|
(949,261
|
)
|
|
$
|
135,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Restated as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
77
WILLIAMS
PARTNERS L.P.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005*
|
|
|
2004*
|
|
|
|
(In thousands)
|
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
146,868
|
|
|
$
|
118,352
|
|
|
$
|
83,132
|
|
Adjustments to reconcile to cash
provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in
accounting principle
|
|
|
|
|
|
|
1,322
|
|
|
|
|
|
Depreciation, amortization and
accretion
|
|
|
43,692
|
|
|
|
42,579
|
|
|
|
44,361
|
|
Provision for loss on property,
plant and equipment
|
|
|
|
|
|
|
917
|
|
|
|
7,636
|
|
(Gain)/loss on sale of property,
plant and equipment
|
|
|
(3,055
|
)
|
|
|
|
|
|
|
1,258
|
|
Impairment of investment in
Discovery Producer Services
|
|
|
|
|
|
|
|
|
|
|
13,484
|
|
Amortization of gas purchase
contract affiliate
|
|
|
5,320
|
|
|
|
2,033
|
|
|
|
|
|
Distributions in excess of
/(undistributed) equity Earnings of Discovery Producer Services
|
|
|
4,367
|
|
|
|
(7,051
|
)
|
|
|
(4,495
|
)
|
Cash provided (used) by changes in
assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(13,564
|
)
|
|
|
(4,419
|
)
|
|
|
1,559
|
|
Prepaid expenses
|
|
|
(1,023
|
)
|
|
|
(463
|
)
|
|
|
(362
|
)
|
Other current assets
|
|
|
(920
|
)
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
(10,600
|
)
|
|
|
8,801
|
|
|
|
12,146
|
|
Product imbalance
|
|
|
(1,114
|
)
|
|
|
8,243
|
|
|
|
(7,295
|
)
|
Accrued liabilities
|
|
|
6,395
|
|
|
|
(4,008
|
)
|
|
|
(5,464
|
)
|
Deferred revenue
|
|
|
(170
|
)
|
|
|
247
|
|
|
|
775
|
|
Other, including changes in
noncurrent assets and liabilities
|
|
|
(2,379
|
)
|
|
|
(8,621
|
)
|
|
|
(9,645
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
173,817
|
|
|
|
157,932
|
|
|
|
137,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of Four Corners
|
|
|
(607,545
|
)
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(32,270
|
)
|
|
|
(31,266
|
)
|
|
|
(15,603
|
)
|
Change in accrued
liabilities-capital expenditures
|
|
|
5,078
|
|
|
|
|
|
|
|
|
|
Contribution to Discovery Producer
Services
|
|
|
(1,600
|
)
|
|
|
(24,400
|
)
|
|
|
|
|
Proceeds from sales of property,
plant and equipment
|
|
|
7,757
|
|
|
|
|
|
|
|
149
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing
activities
|
|
|
(628,580
|
)
|
|
|
(55,666
|
)
|
|
|
(15,454
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sales of common units
|
|
|
867,263
|
|
|
|
100,247
|
|
|
|
|
|
Proceeds from debt issuances
|
|
|
750,000
|
|
|
|
|
|
|
|
|
|
Excess purchase price over the
contributed basis of Four Corners
|
|
|
(975,455
|
)
|
|
|
|
|
|
|
|
|
Payment of debt issuance costs
|
|
|
(13,138
|
)
|
|
|
|
|
|
|
|
|
Payment of equity offering costs
|
|
|
(4,168
|
)
|
|
|
(4,291
|
)
|
|
|
|
|
Distributions to The Williams
Companies, Inc.
|
|
|
(114,497
|
)
|
|
|
(187,217
|
)
|
|
|
(120,467
|
)
|
Changes in advances from
affiliates net
|
|
|
|
|
|
|
(3,656
|
)
|
|
|
(1,169
|
)
|
Distributions to unitholders and
general partner
|
|
|
(29,994
|
)
|
|
|
(2,120
|
)
|
|
|
|
|
General partner contributions
|
|
|
18,614
|
|
|
|
|
|
|
|
|
|
Contributions per omnibus agreement
|
|
|
6,840
|
|
|
|
1,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by
financing activities
|
|
|
505,465
|
|
|
|
(95,427
|
)
|
|
|
(121,636
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in cash and cash
equivalents
|
|
|
50,702
|
|
|
|
6,839
|
|
|
|
|
|
Cash and cash equivalents at
beginning of year
|
|
|
6,839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end
of year
|
|
$
|
57,541
|
|
|
$
|
6,839
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Restated as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
78
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%
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% 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% 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% 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 (OLLC), an operating limited liability
company (wholly owned by us), through which all our activities
are conducted.
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% 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%
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.
Acquisition
of Four Corners
On June 20, 2006, we acquired a 25.1% membership interest
in Williams Four Corners LLC (Four Corners) pursuant
to an agreement with Williams Energy Services, LLC
(WES), Williams Field Services Group LLC
(WFSG), Williams Field Services Company, LLC
(WFSC) and OLLC for aggregate consideration of
$360.0 million. Prior to closing, WFSC contributed to Four
Corners its natural gas gathering, processing and treating
assets in the San Juan Basin in New Mexico and Colorado. We
financed this acquisition with a combination of equity and debt.
On June 20, 2006, we issued 6,600,000 common units at a
price of $31.25 per unit. Additionally, at the closing, the
underwriters fully exercised their option to purchase
79
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
990,000 common units at a price of $31.25 per unit. This
offering yielded net proceeds of $227.1 million after
payment of underwriting discounts and commissions of
$10.1 million but before the payment of other offering
expenses. On June 20, 2006, we also issued
$150.0 million aggregate principal of unsecured
7.5% senior notes due 2011 under a private placement debt
agreement. Proceeds from this issuance totaled
$146.8 million (net of $3.2 million of related
expenses).
On December 13, 2006, we acquired the remaining 74.9%
membership interest in Four Corners pursuant to an agreement
with WES, WFSG, WFSC and OLLC for aggregate consideration of
$1.223 billion. We financed this acquisition with a
combination of equity and debt. On December 13, 2006, we
issued 7,000,000 common units at a price of $38.00.
Additionally, at the closing, the underwriters fully exercised
their option to purchase 1,050,000 common units at a price of
$38.00 per unit. This offering yielded net proceeds of
$293.7 million after payment of underwriting discounts and
commissions of $12.2 million but before the payment of
other offering expenses. On December 13, 2006, we received
$346.5 million in proceeds from the sale of 2,905,030
common units and 6,805,492 unregistered Class B units in a
private placement net of $3.5 million in placement agency
fees. On December 13, 2006, we also issued
$600.0 million aggregate principal of unsecured
7.25% senior notes due 2017 under a private placement debt
agreement. Proceeds from this issuance totaled
$590.0 million (net of $10.0 million of related
expenses).
Because Four Corners was an affiliate of Williams at the time of
these acquisitions, these transactions are accounted for as a
combination of entities under common control, similar to a
pooling of interests, whereby the assets and liabilities of Four
Corners are combined with Williams Partners L.P. at their
historical amounts for all periods presented. These two
acquisitions of a combined 100% membership interest in Four
Corners increased net income $113.5 million and
$96.6 million for 2005 and 2004, respectively. The
restatement to reflect these acquisitions does not impact
historical earnings per unit as pre-acquisition earnings were
allocated to our general partner.
|
|
Note 2.
|
Description
of Business
|
We are principally engaged in the business of gathering,
transporting, processing and treating natural gas and
fractionating and storing NGLs. Operations of our businesses are
located in the United States and are organized into three
reporting segments: (1) Gathering and Processing-West,
(2) Gathering and Processing-Gulf and (3) NGL
Services. Our Gathering and Processing-West segment includes the
Four Corners gathering and processing operations. Our Gathering
and Processing-Gulf segment includes the Carbonate Trend
gathering pipeline and our equity investment in Discovery. Our
NGL Services segment includes the Conway fractionation and
storage operations.
Gathering and Processing-West. Our Four
Corners natural gas gathering, processing and treating assets
consist of, among other things, (1) a
3,500-mile
natural gas gathering system in the San Juan Basin in New
Mexico and Colorado with a capacity of two billion cubic feet
per day, (2) 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 (MMcf/d) and
(3) the Milagro and Esperanza natural gas treating plants
in New Mexico, which have a combined carbon dioxide treating
capacity of 750 MMcf/d.
Gathering and Processing-Gulf . We own a 40%
interest in Discovery, which includes a wholly-owned subsidiary,
Discovery Gas Transmission LLC. Discovery owns (1) a
283-mile
natural gas gathering and transportation pipeline system,
located primarily off the coast of Louisiana in the Gulf of
Mexico, (2) a 600 MMcf/d 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) a
22-mile
mixed NGL pipeline connecting the gas processing plant to the
fractionator. Although Discovery includes fractionation
operations, which would normally fall within the NGL Services
segment, it is primarily engaged in gathering and processing and
is
80
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
managed as such. Hence, this equity investment is considered
part of the Gathering and Processing-Gulf 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% 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
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.
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:
|
|
|
|
|
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% 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 Income, 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.
81
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
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.
Investments. We account for our investment in
Discovery under the equity method since we do not control it. 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, 2006 and 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 Statements of 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.
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 are expensed
on a straight-line basis over the lease term.
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, in the course of providing gathering, processing,
treating, fractionation and storage services to our customers,
we realize gains and losses due to (1) the product blending
process at the Conway fractionator, (2) the periodic
emptying of storage caverns at Conway and (3) 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 Consolidated Statements of
Income. The sum of these items is reflected as product imbalance
receivables or payables on the Consolidated 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.
82
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Revenue Recognition. The nature of our
businesses result in various forms of revenue recognition. Our
Gathering and Processing segments recognize (1) revenue
from the gathering and processing of gas in the period the
service is provided based on contractual terms and the related
natural gas and liquid volumes and (2) product sales
revenue when the product has been delivered. 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.
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.
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. Capitalized interest
for the periods presented is immaterial.
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
aggregated 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.
83
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Earnings Per Unit. In accordance with
SFAS No. 128, Earnings Per Share, as
clarified by 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, Class B and subordinated units
outstanding. Basic and diluted earnings per unit are equivalent
as there are no dilutive securities outstanding.
Recent Accounting Standards. In January 2006,
Williams adopted the fair value recognition provisions of FASB
Statement No. 123(R), Share-Based Payment
(SFAS No. 123(R)), using the modified-prospective
method. 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. 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.
Our and Williams adoption of this Statement did not have a
material impact on our Consolidated Financial Statements.
In January 2006 we adopted SFAS No. 151,
Inventory Costs, an amendment of ARB No. 43,
Chapter 4. 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 was not
material.
In January 2006 we adopted SFAS No. 153,
Exchanges of Nonmonetary Assets, an amendment of APB
Opinion No. 29. 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.
The impact of this Statement on our Consolidated Financial
Statements was not material.
In September 2006, the Financial Accounting Standards Board
(FASB) issued SFAS No. 157, Fair
Value Measurements. This Statement establishes a framework
for fair value measurements in the financial statements by
providing a single definition of fair value, provides guidance
on the methods used to estimate fair value and increases
disclosures about estimates of fair value.
SFAS No. 157 is effective for fiscal years beginning
after November 15, 2007 and is generally applied
prospectively. We will assess the impact of this Statement on
our Consolidated Financial Statements.
In December 2006, the FASB issued FASB Staff Position (FSP) EITF
00-19-2,
Accounting for Registration Payment Arrangements.
This FSP specifies that the contingent obligation to make future
payments or otherwise transfer consideration under a
registration payment arrangement should be separately recognized
and measured in accordance with FASB Statement No. 5,
Accounting for Contingencies. This FSP is effective immediately
for registration payment arrangements and the financial
instruments subject to those arrangements that are entered into
or modified subsequent to December 21, 2006. For
registration payment arrangements and financial instruments
subject to those arrangements that were entered into prior to
December 21, 2006, the guidance in the FSP is effective for
fiscal years beginning after December 15, 2006. We do not
expect this FSP to have a material impact on our Consolidated
Financial Statements.
84
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 4.
|
Allocation
of Net Income and Distributions
|
The allocation of net income between our general partner and
limited partners, as reflected in the Consolidated Statement of
Partners Capital, for the years ended December 31,
2006 and 2005 are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Allocation of net income to
general partner:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
146,868
|
|
|
$
|
118,352
|
|
Net income applicable to
pre-partnership operations allocated to general partner
|
|
|
(116,450
|
)
|
|
|
(113,418
|
)
|
Charges allocated directly to
general partner:
|
|
|
|
|
|
|
|
|
Reimbursable general and
administrative costs
|
|
|
3,200
|
|
|
|
1,400
|
|
Core drilling indemnified costs
|
|
|
784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total charges allocated directly
to general partner
|
|
|
3,984
|
|
|
|
1,400
|
|
|
|
|
|
|
|
|
|
|
Income subject to 2% allocation of
general partner interest
|
|
|
34,402
|
|
|
|
6,334
|
|
General partners share of
net income
|
|
|
2.0
|
%
|
|
|
2.0
|
%
|
|
|
|
|
|
|
|
|
|
General partners allocated
share of net income before items directly allocable to general
partner interest
|
|
|
688
|
|
|
|
127
|
|
Incentive distributions paid to
general partner*
|
|
|
272
|
|
|
|
|
|
Charges allocated directly to
general partner
|
|
|
(3,984
|
)
|
|
|
(1,400
|
)
|
Pre-partnership net income
allocated to general partner interest
|
|
|
116,450
|
|
|
|
113,418
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to general
partner
|
|
$
|
113,426
|
|
|
$
|
112,145
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
146,868
|
|
|
$
|
118,352
|
|
Net income allocated to general
partner
|
|
|
113,426
|
|
|
|
112,145
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to limited
partners
|
|
$
|
33,442
|
|
|
$
|
6,207
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Under the two class method of computing earnings per
share, prescribed by SFAS No. 128, Earnings Per
Share, earnings are to be allocated to participating
securities as if all of the earnings for the period had been
distributed. As a result, the general partner receives an
additional allocation of income in quarterly periods where an
assumed incentive distribution, calculated as if all earnings
for the period had been distributed, exceeds the actual
incentive distribution. The assumed incentive distribution for
the twelve months ended December 31, 2006 is
$0.4 million. This results in an allocation of income for
the calculation of earnings per limited partner unit as follows: |
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Net income allocated to general
partner
|
|
$
|
113,553
|
|
|
$
|
112,145
|
|
Net income allocated to limited
partners
|
|
$
|
33,315
|
|
|
$
|
6,207
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
146,868
|
|
|
$
|
118,352
|
|
|
|
|
|
|
|
|
|
|
Pursuant to the partnership agreement, income allocations are
made on a quarterly basis; therefore, earnings per limited
partner unit for 2006 is calculated as the sum of the quarterly
earnings per limited partner unit for each of the four quarters
of 2006. Common, Class B and subordinated unitholders share
equally, on a
per-unit
basis, in the net income allocated to limited partners.
85
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The reimbursable general and administrative and core drilling
costs represent the 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
|
|
|
Class B
|
|
|
General
|
|
|
Total Cash
|
|
Payment Date
|
|
Distribution
|
|
|
Units
|
|
|
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
|
|
$
|
0.3800
|
|
|
$
|
2,662
|
|
|
$
|
2,660
|
|
|
|
|
|
|
$
|
109
|
|
|
$
|
5,431
|
|
8/14/2006(b)
|
|
$
|
0.4250
|
|
|
$
|
6,204
|
|
|
$
|
2,975
|
|
|
|
|
|
|
$
|
263
|
|
|
$
|
9,442
|
|
11/14/2006(c
)
|
|
$
|
0.4500
|
|
|
$
|
6,569
|
|
|
$
|
3,150
|
|
|
|
|
|
|
$
|
401
|
|
|
$
|
10,120
|
|
2/14/2007(d)
|
|
$
|
0.4700
|
|
|
$
|
12,010
|
|
|
$
|
3,290
|
|
|
$
|
3,198
|
|
|
$
|
993
|
|
|
$
|
19,491
|
|
|
|
|
(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) |
|
Includes $0.1 million incentive distribution rights payment
to the general partner. |
|
(c) |
|
Includes $0.2 million incentive distribution rights payment
to the general partner. |
|
(d) |
|
On February 14, 2007, we paid a cash distribution of
$0.47 per unit on our outstanding common, subordinated and
Class B units to unitholders of record on February 7, 2007.
This amount includes $0.6 million incentive distribution
rights payment to the general partner. |
|
|
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 the payroll costs associated
with the operations employees 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 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 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. Our share of these costs is reflected in General and
administrative expense Affiliate in the accompanying
Consolidated 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. 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.
86
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At December 31, 2006 and 2005 we have a contribution
receivable from our general partner of $0.4 million and
$0.3 million, respectively, which is netted against
Partners capital on the Consolidated Balance Sheets, for
amounts reimbursable to us under the omnibus agreement.
We purchase natural gas for shrink replacement and fuel for Four
Corners and the Conway fractionator, including fuel on behalf of
the Conway co-owners, from Williams Power Company
(Power), a wholly owned subsidiary of Williams.
Natural gas purchased for fuel is reflected in Operating and
maintenance expense Affiliate, and natural gas
purchased for shrink replacement is reflected in Product cost
and shrink replacement Affiliate in the accompanying
Consolidated Statements of Income. 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 Income. The carrying value of this
contract is reflected as Gas purchase contract
affiliate and Gas purchase contract
noncurrent affiliate on the Consolidated Balance
Sheets.
We purchase natural gas for delivery of waste heat from Power
that we use to generate steam at our Milagro treating plant. 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 expired in the fourth quarter of 2006 and were
replaced with new agreements. We expect that our Milagro natural
gas fuel costs will increase due to our expectation that future
market prices will exceed prices associated with the prior
agreements.
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, reduce expenses or increase profitability. 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 Power, at current market prices at each location and are
included in Product sales Affiliate and Product cost
and shrink replacement Affiliate on the Consolidated
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 sell the NGLs to which we take title on the Four Corners
system to Williams Midstream Marketing and Risk Management, LLC
(WMMRM), a wholly owned subsidiary of Williams.
Revenues associated with these activities are reflected as
Product sales Affiliate on the Consolidated
Statements of Income. These transactions are conducted at
current market prices for the products.
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 Affiliate on the Consolidated
Statements of Income.
In December 2004, we began selling Conways 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 Product
sales Affiliate on the Consolidated Statements of
Income. Correspondingly, we purchase ethane and other NGLs for
Conway from Power to replenish deficit product inventory
positions. The transactions conducted between us and Power are
transacted at current market prices for the products.
87
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands)
|
|
|
General and administrative
expenses, including amounts subsequently charged to co-owners:
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated
|
|
$
|
18,512
|
|
|
$
|
29,400
|
|
|
$
|
24,293
|
|
Directly charged
|
|
|
10,574
|
|
|
|
4,607
|
|
|
|
5,655
|
|
Operating and maintenance
expenses, including amounts subsequently charged to co-owners:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel purchases, including
amortization of gas contract
|
|
|
38,197
|
|
|
|
38,996
|
|
|
|
28,851
|
|
Salaries and benefits
|
|
|
26,860
|
|
|
|
21,812
|
|
|
|
21,657
|
|
NGL purchases
|
|
|
14,884
|
|
|
|
15,657
|
|
|
|
1,271
|
|
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
elected to utilize this capacity.
Prior to its acquisition by us, Four Corners participated in
Williams cash management program under an unsecured
promissory note agreement with Williams for both advances to and
from Williams. As of December 31, 2005 and 2004, Four
Corners net advances to Williams were classified as a
component of general partners capital because Williams has
not historically required repayment or repaid amounts owed us.
In addition, upon Four Corners acquisition by us, the
outstanding advances were distributed to Williams. Changes in
these advances to Williams are presented as distributions to
Williams in the Consolidated Statement of Partners Capital
and Consolidated Statements of Cash Flows.
For 2005 and 2004, 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. For 2006 and 2005, affiliate
interest expense also includes commitment fees on the working
capital credit facility (see Note 11). The interest rate on
the advances with Williams was 7.70% at December 31, 2005.
With the transition to a stand-alone cash management program,
amounts owed by us or to us by Williams or its subsidiaries are
shown as Accounts payable-Affiliate or Accounts
receivable-Affiliate in the accompanying Consolidated Balance
Sheets.
|
|
Note 6.
|
Investment
in Discovery Producer Services
|
Our 40% investment in Discovery is accounted for using the
equity method of accounting since we do not control it. At
December 31, 2006 and 2005, Williams owned an additional
20% ownership interest in Discovery through Energy.
In October, 2006 and September 2005, we made $1.6 million
and $24.4 million capital contributions, respectively, to
Discovery for a substantial portion of our share of the
estimated future capital expenditures for the Tahiti pipeline
lateral expansion project.
88
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 (1) Discovery purchases a portion of the natural gas
from Williams to meet its fuel and shrink replacement needs at
its processing plant and (2) Williams purchases 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.
During 2006 and 2005 we received total distributions of
$16.4 million and $1.3 million, respectively, from
Discovery.
The summarized financial position and results of operations for
100% of Discovery are presented below (in thousands).
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Current assets
|
|
$
|
73,841
|
|
|
$
|
70,525
|
|
Non-current restricted cash
|
|
|
28,773
|
|
|
|
44,559
|
|
Property, plant and equipment
|
|
|
355,304
|
|
|
|
344,743
|
|
Current liabilities
|
|
|
(40,559
|
)
|
|
|
(45,070
|
)
|
Non-current liabilities
|
|
|
(3,728
|
)
|
|
|
(1,121
|
)
|
|
|
|
|
|
|
|
|
|
Members capital
|
|
$
|
413,631
|
|
|
$
|
413,636
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
160,825
|
|
|
$
|
76,864
|
|
|
$
|
68,766
|
|
Third-party
|
|
|
36,488
|
|
|
|
45,881
|
|
|
|
31,110
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
74,316
|
|
|
|
24,895
|
|
|
|
4,945
|
|
Third-party
|
|
|
97,394
|
|
|
|
77,702
|
|
|
|
83,811
|
|
Interest income
|
|
|
(2,404
|
)
|
|
|
(1,685
|
)
|
|
|
(550
|
)
|
Foreign exchange (gain) loss
|
|
|
(2,076
|
)
|
|
|
1,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting principle
|
|
$
|
30,083
|
|
|
$
|
20,828
|
|
|
$
|
11,670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
30,083
|
|
|
$
|
20,652
|
|
|
$
|
11,670
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
89
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 7.
|
Other
Costs and Expenses Net
|
Other (income) expense net reflected on the
Consolidated Statements of Income consists of the following
items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Impairment of LaMaquina carbon
dioxide treating facility
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7,636
|
|
Gain on sale of LaMaquina carbon
dioxide treating facility
|
|
|
(3,619
|
)
|
|
|
|
|
|
|
|
|
Other
|
|
|
1,146
|
|
|
|
630
|
|
|
|
3,511
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(2,473
|
)
|
|
$
|
630
|
|
|
$
|
11,147
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LaMaquina Carbon Dioxide Treating
Facility. This Four Corners 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.
Other. In 2004, other expense included losses
from Four Corners asset dispositions and materials and supplies
inventory adjustments.
|
|
Note 8.
|
Property,
Plant and Equipment
|
Property, plant and equipment, at cost, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
|
December 31,
|
|
|
Depreciable
|
|
|
|
2006
|
|
|
2005
|
|
|
Lives
|
|
|
|
(In thousands)
|
|
|
|
|
|
Land and right of way
|
|
$
|
41,721
|
|
|
$
|
44,363
|
|
|
|
|
|
Gathering pipelines and related
equipment
|
|
|
821,478
|
|
|
|
801,385
|
|
|
|
20-30 years
|
|
Processing plants and related
equipment
|
|
|
147,241
|
|
|
|
164,257
|
|
|
|
30 years
|
|
Fractionation plant and related
equipment
|
|
|
16,697
|
|
|
|
16,646
|
|
|
|
30 years
|
|
Storage plant and related equipment
|
|
|
69,017
|
|
|
|
65,892
|
|
|
|
30 years
|
|
Buildings and other equipment
|
|
|
90,082
|
|
|
|
90,070
|
|
|
|
3-45 years
|
|
Construction work in progress
|
|
|
19,447
|
|
|
|
20,323
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
1,205,683
|
|
|
|
1,202,936
|
|
|
|
|
|
Accumulated depreciation
|
|
|
558,105
|
|
|
|
543,971
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
647,578
|
|
|
$
|
658,965
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 $1.4 million equal
to the present value of expected future asset retirement
obligations at December 31, 2005. The liabilities are
slightly offset
90
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
by a $0.1 million 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 $1.3 million reduction
to earnings is reflected as a cumulative effect of a change in
accounting principle for the year ended 2005. An additional
$0.1 million reduction of earnings is reflected as a
cumulative effect of a change in accounting principle for our
40% 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 2004, the impact to our income from
continuing operations and net income would have been immaterial.
The obligations relate to gas processing and compression
facilities located on leased land, wellhead connections on
federal land, underground storage caverns and the associated
brine ponds. 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 connections, 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 2006 and
2005 is presented below.
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Balance, January 1
|
|
$
|
1,880
|
|
|
$
|
1,090
|
|
Liabilities incurred during the
period
|
|
|
|
|
|
|
91
|
|
Liabilities settled during the
period
|
|
|
(510
|
)
|
|
|
(204
|
)
|
Accretion expense
|
|
|
86
|
|
|
|
1
|
|
Estimate revisions
|
|
|
2,943
|
|
|
|
(460
|
)
|
FIN No. 47 revisions
|
|
|
|
|
|
|
1,362
|
|
Loss on settlements
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31
|
|
$
|
4,476
|
|
|
$
|
1,880
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 9.
|
Accrued
Liabilities
|
Accrued liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Environmental
remediation current portion
|
|
$
|
2,636
|
|
|
$
|
1,752
|
|
Customer deposit for construction
|
|
|
5,078
|
|
|
|
|
|
Accrued interest
|
|
|
2,796
|
|
|
|
|
|
Taxes other than income
|
|
|
2,347
|
|
|
|
2,431
|
|
Other
|
|
|
3,316
|
|
|
|
1,977
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
16,173
|
|
|
$
|
6,160
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 10.
|
Major
Customers, Concentrations of Credit Risk and Financial
Instruments
|
Major
customers
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 43%, 46% and 42% of
revenues
91
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
in 2006, 2005 and 2004, respectively. The percentages for the
remaining two largest customers, both from our Gathering and
Processing West segment, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
ConocoPhillips
|
|
|
12
|
%
|
|
|
14
|
%
|
|
|
14
|
%
|
Burlington Resources
|
|
|
9
|
|
|
|
10
|
|
|
|
11
|
|
Burlington Resources was acquired by ConocoPhillips on
March 31, 2006.
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.
The following table summarizes the concentration of accounts
receivable by service and segment.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Gathering and
Processing West:
|
|
|
|
|
|
|
|
|
Natural gas gathering and
processing
|
|
$
|
16,709
|
|
|
$
|
15,855
|
|
Other
|
|
|
561
|
|
|
|
1,368
|
|
Gathering and
Processing Gulf:
|
|
|
|
|
|
|
|
|
Natural gas gathering
|
|
|
468
|
|
|
|
525
|
|
Other
|
|
|
1,343
|
|
|
|
|
|
NGL Services:
|
|
|
|
|
|
|
|
|
Fractionation services
|
|
|
320
|
|
|
|
532
|
|
Amounts due from fractionator
partners
|
|
|
1,833
|
|
|
|
1,834
|
|
Storage
|
|
|
825
|
|
|
|
793
|
|
Other
|
|
|
36
|
|
|
|
260
|
|
Accrued interest
|
|
|
216
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
22,311
|
|
|
$
|
21,167
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31, 2006 and 2005, a
substantial portion of our accounts receivable result from
product sales and gathering and processing services provided to
four of our customers. 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 conditions and credit worthiness are
evaluated regularly. Our credit policy and the relatively short
duration of receivables mitigate the risk of uncollectible
receivables.
Financial
Instruments
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.
92
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Long-term debt. The fair value of our private
long-term debt is based on the prices of similar securities with
similar terms and credit ratings.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
|
Amount
|
|
Value
|
|
Amount
|
|
Value
|
|
|
(In thousands)
|
|
Cash and cash equivalents
|
|
$
|
57,541
|
|
|
$
|
57,541
|
|
|
$
|
6,839
|
|
|
$
|
6,839
|
|
Long-term debt (see Note 11)
|
|
$
|
750,000
|
|
|
$
|
768,844
|
|
|
|
|
|
|
|
|
|
|
|
Note 11.
|
Long-Term
Debt, Credit Facilities and Leasing Activities
|
Long-Term
Debt
On December 13, 2006, we and Williams Partners Finance
Corporation issued $600.0 million aggregate principal of
7.25% senior unsecured notes in a private debt placement.
Williams Partners Finance Corporation is our wholly owned
subsidiary organized for the sole purpose of co-issuing our debt
securities. The maturity date of the notes is February 1,
2017. Interest is payable semi-annually in arrears on February 1
and August 1 of each year, beginning on August 1,
2007. Debt issuance costs associated with the notes totaled
$10.0 million and are being amortized over the life of the
notes.
On June 20, 2006, we and Williams Partners Finance
Corporation issued $150.0 million aggregate principal of
7.5% senior unsecured notes in a private debt placement.
The maturity date of the notes is June 15, 2011. Interest
is payable semi-annually in arrears on June 15 and December 15
of each year, with the first payment due on December 15,
2006. Debt issuance costs associated with the notes totaled
$3.1 million and are being amortized over the life of the
notes.
In connection with the issuance of the $600.0 million and
$150.0 million senior unsecured notes, sold in private debt
placements to qualified institutional buyers in accordance with
Rule 144A under the Securities Act and outside the United
States in accordance with Regulations under the Securities Act,
we entered into registration rights agreements with the initial
purchasers of the senior unsecured notes whereby we agreed to
conduct a registered exchange offer of exchange notes in
exchange for the senior unsecured notes or cause to become
effective a shelf registration statement providing for resale of
the senior unsecured notes. If we fail to file a registration
statement with the SEC within 270 days of the respective
closing dates, we will be required to pay liquidated damages in
the form of additional cash interest to the holders of the
senior unsecured notes. Upon the occurrence of such a failure to
comply, the interest rate on the senior unsecured notes shall be
increased by 0.25% per annum during the
90-day
period immediately following the occurrence of such failure to
comply and shall increase by 0.25% per annum 90 days
thereafter until all defaults have been cured, but in no event
shall such aggregate additional interest exceed 0.50% per
annum.
The terms of the senior unsecured notes are governed by an
indenture that contains affirmative and negative covenants that,
among other things, limit (1) our ability and the ability
of our subsidiaries to incur liens securing indebtedness,
(2) mergers, consolidations and transfers of all or
substantially all of our properties or assets, (3) Williams
Partners Finance Corporations ability to incur additional
indebtedness and (4) Williams Partners Finance
Corporations ability to engage in any business not related
to obtaining money or arranging financing for us or our other
subsidiaries. Our investment in Discovery will not be classified
as our subsidiary under the indenture so long as we continue to
own a minority interest in such entity. As a result, Discovery
will not be subject to the restrictive covenants in the
indenture. The indenture also contains customary events of
default, upon which the trustee or the holders of the senior
unsecured notes may declare all outstanding senior unsecured
notes to be due and payable immediately.
We may redeem the $600.0 million senior unsecured notes and
the $150.0 million senior unsecured notes at our option in
whole or in part at any time or from time to time prior to
February 1, 2017 and June 15,
93
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2011, respectively, at a redemption price per note equal to the
sum of (1) the then outstanding principal amount thereof,
plus (2) accrued and unpaid interest, if any, to the
redemption date (subject to the right of holders of record on
the relevant record date to receive interest due on an interest
payment date that is on or prior to the redemption date), plus
(3) a specified make-whole premium (as defined
in the indenture). Additionally, upon a change of control (as
defined in the indenture), each holder of the senior unsecured
notes will have the right to require us to repurchase all or any
part of such holders senior unsecured notes at a price
equal to 101% of the principal amount of the senior unsecured
notes plus accrued and unpaid interest, if any, to the date of
settlement. Except upon a change of control as described in the
prior sentence, we are not required to make mandatory redemption
or sinking fund payments with respect to the senior unsecured
notes or to repurchase the senior unsecured notes at the option
of the holders.
Pursuant to the indenture, we may issue additional notes from
time to time. The senior notes and any additional notes
subsequently issued under the indenture, together with any
exchange notes, will be treated as a single class for all
purposes under the indenture, including, without limitation,
waivers, amendments, redemptions and offers to purchase.
The senior notes are our senior unsecured obligations and rank
equally in right of payment with all of our other senior
indebtedness and senior to all of our future indebtedness that
is expressly subordinated in right of payment to the senior
notes. The senior notes will not initially be guaranteed by any
of our subsidiaries. In the future in certain instances as set
forth in the indenture, one or more of our subsidiaries may be
required to guarantee the senior notes.
Cash payments for interest for 2006 and 2005 were
$5.5 million and $0.3 million, respectively.
Credit
Facilities
In May 2006, Williams replaced its $1.275 billion secured
credit facility with a $1.5 billion unsecured credit
facility (Williams facility). The new facility,
which also allows us to borrow up to $75.0 million,
contains substantially similar terms and covenants as the prior
facility, but contains additional restrictions on asset sales,
certain subsidiary debt and sale-leaseback transactions.
Borrowings under the Williams facility mature in May 2009. Our
$75.0 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.
Letters of credit totaling $29.0 million at
December 31, 2006 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 our $75.0 million borrowing limit under
the Williams facility, 0.25% at December 31, 2006 and
0.325% at December 31, 2005. The applicable margins, which
were 1.25% at December 31, 2006 and 1.75% at
December 31, 2005 related to LIBOR and 0.25% at
December 31, 2006 and 0.75% at December 31, 2005
related to the facilitating banks base rate, 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, and in compliance with, include the
following:
|
|
|
|
|
ratio of debt to net worth no greater than 65%;
|
|
|
|
ratio of debt to net worth no greater than 55% for Northwest
Pipeline Corporation, a wholly owned subsidiary of Williams, and
Transco; and
|
94
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
ratio of EBITDA to interest, on a rolling four quarter basis, no
less than (i) 2.5 for any period through December 31,
2007 and (ii) 3.0 for the remaining term of the agreement.
|
On August 7, 2006 we amended and restated the
$20.0 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 June 20,
2009 and bear interest at the one-month LIBOR. We pay a
commitment fee to Williams on the unused portion of the credit
facility of 0.30% 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. As of
December 31, 2006, we have had no borrowings under the
working capital credit facility.
Leasing
Activities
We lease the land on which a significant portion of Four
Corners 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. Four Corners leases compression units under a
lease agreement with Hanover Compression, Inc. The initial term
of this agreement expired on June 30, 2006. We continue to
lease these units on a
month-to-month
basis during the ongoing renegotiation. The
month-to-month
arrangement can be terminated by either party upon thirty days
advance written notice. We also lease other minor office,
warehouse equipment and automobiles under non-cancelable leases.
The future minimum annual rentals under these non-cancelable
leases as of December 31, 2006 are payable as follows:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2007
|
|
|
2,426
|
|
2008
|
|
|
2,188
|
|
2009
|
|
|
1,837
|
|
2010
|
|
|
1,410
|
|
2011 and thereafter
|
|
|
2,030
|
|
|
|
|
|
|
|
|
$
|
9,891
|
|
|
|
|
|
|
Total rent expense was $19.4 million, $18.9 million
and $14.8 million for 2006, 2005 and 2004, respectively.
|
|
Note 12.
|
Partners
Capital
|
Of the 25,553,306 common units outstanding at December 31,
2006, 21,398,276 are held by the public, 2,905,030 are privately
held, and the remaining 1,250,000 held by our affiliates. The
6,805,492 Class B units outstanding at December 31,
2006 are privately held. All of the 7,000,000 subordinated units
are held by our affiliates.
Description
of Class B Units
The Class B units are subordinated to common units and
senior to subordinated units with respect to the payment of the
minimum quarterly distribution, including any arrearages with
respect to minimum quarterly distributions from prior periods.
The Class B units are subordinated to common units and
senior to subordinated units with respect to the right to
receive distributions upon our liquidation.
The Class B units will convert into common units on a
one-for-one
basis upon the approval of a majority of the votes cast by
common unitholders provided that the total number of votes cast
is at least a majority of common units eligible to vote
(excluding common units held by Williams). We are required to
seek such approval as promptly as practicable after issuance of
the Class B units and not later than June 11, 2007. If
the
95
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
requisite approval is not obtained, we will be obligated to
resubmit the conversion proposal to holders of our common units,
but not more frequently than once every six months. If we have
not obtained the requisite unitholder approval of the conversion
of the Class B units by June 11, 2007, the
Class B units will be entitled to receive 115% of the
quarterly distribution and distributions on liquidation payable
on each common unit, subject to the subordination provisions
described above.
The Class B units have the same voting rights as our
outstanding common units and are entitled to vote as a separate
class on any matters that adversely affect the rights or
preferences of the Class B units in relation to other
classes of partnership interests or as required by law. The
Class B units are not entitled to vote on the approval of
the conversion of the Class B units into common units.
Subordinated
Units
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. 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.
Limited
Partners Rights
Significant information regarding rights of the limited partners
includes 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%
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.
|
Incentive
Distribution Rights
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.
96
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 13.
|
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.
During 2006 and 2005, our general partner granted 2,130 and
6,146 restricted units, respectively, 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 vested six months from grant
date. We recognized compensation expense of $229,000 and $34,000
associated with these awards in 2006 and 2005, respectively.
|
|
Note 14.
|
Commitments
and Contingencies
|
Environmental Matters-Four Corners. 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 hydrocarbon removal and
groundwater monitoring activities associated with 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.
We have accrued liabilities totaling $0.7 million at
December 31, 2006 and December 31, 2005 for these
environmental activities. It is reasonably possible that we will
incur costs 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.
Environmental Matters-Conway. 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
$5.0 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 projects to the extent such
costs exceed a $4.2 million deductible, of which
$0.7 million has been incurred to date from the onset of
the policy. The policy also covers costs incurred as a result of
third party claims associated with then existing but unknown
97
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
contamination related to the storage facilities. The aggregate
limit under the policy for all claims is $25.0 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 not covered by the
insurance policy, excluding costs of project management and soil
and groundwater monitoring. There is a $14.0 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 August 23, 2005 IPO closing date.
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 $0.2 million to $0.4 million per year
following the completion of the remediation work. At
December 31, 2006 and 2005, we had accrued liabilities
totaling $5.9 million and $5.4 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 any excess 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.
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 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. On October 20, 2006, the court dismissed
all claims against us. In November 2006, Grynberg filed his
notice of appeals with the Tenth Circuit Court of Appeals.
Vendor Dispute. We are parties to an agreement
with a service provider for work on turbines at our Ignacio, New
Mexico plant. A dispute has arisen between us as to the quality
of the service providers work and the appropriate
compensation. The service provider claims it is entitled to
additional extra work charges under the agreement, which we deny
are due.
Other. We are not currently a party to any
other legal proceedings but are a party to various
administrative and regulatory proceedings 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,
98
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
|
|
Note 15.
|
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 &
|
|
|
Gathering &
|
|
|
|
|
|
|
|
|
|
Processing -
|
|
|
Processing -
|
|
|
NGL
|
|
|
|
|
|
|
West
|
|
|
Gulf
|
|
|
Services
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales
|
|
$
|
255,907
|
|
|
$
|
|
|
|
$
|
16,087
|
|
|
$
|
271,994
|
|
Gathering and processing
|
|
|
246,004
|
|
|
|
2,656
|
|
|
|
|
|
|
|
248,660
|
|
Storage
|
|
|
|
|
|
|
|
|
|
|
25,237
|
|
|
|
25,237
|
|
Fractionation
|
|
|
|
|
|
|
|
|
|
|
11,698
|
|
|
|
11,698
|
|
Other
|
|
|
402
|
|
|
|
|
|
|
|
5,419
|
|
|
|
5,821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
502,313
|
|
|
|
2,656
|
|
|
|
58,441
|
|
|
|
563,410
|
|
Product cost and shrink replacement
|
|
|
159,997
|
|
|
|
|
|
|
|
15,511
|
|
|
|
175,508
|
|
Operating and maintenance expense
|
|
|
124,763
|
|
|
|
1,660
|
|
|
|
28,791
|
|
|
|
155,214
|
|
Depreciation, amortization and
accretion
|
|
|
40,055
|
|
|
|
1,200
|
|
|
|
2,437
|
|
|
|
43,692
|
|
Direct general and administrative
expenses
|
|
|
11,920
|
|
|
|
1
|
|
|
|
1,149
|
|
|
|
13,070
|
|
Other, net
|
|
|
5,769
|
|
|
|
|
|
|
|
719
|
|
|
|
6,488
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss)
|
|
|
159,809
|
|
|
|
(205
|
)
|
|
|
9,834
|
|
|
|
169,438
|
|
Equity earnings
|
|
|
|
|
|
|
12,033
|
|
|
|
|
|
|
|
12,033
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
159,809
|
|
|
$
|
11,828
|
|
|
$
|
9,834
|
|
|
$
|
181,471
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated
Statement of Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
169,438
|
|
General and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23,721
|
)
|
Third-party direct
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,649
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
143,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets
|
|
$
|
653,949
|
|
|
$
|
207,390
|
|
|
$
|
76,502
|
|
|
$
|
937,841
|
|
Other assets and eliminations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,693
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
933,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity method investments
|
|
$
|
|
|
|
$
|
147,493
|
|
|
$
|
|
|
|
$
|
147,493
|
|
Additions to long-lived assets
|
|
|
25,889
|
|
|
|
|
|
|
|
6,381
|
|
|
|
32,270
|
|
99
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering &
|
|
|
Gathering &
|
|
|
|
|
|
|
|
|
|
Processing -
|
|
|
Processing -
|
|
|
NGL
|
|
|
|
|
|
|
West
|
|
|
Gulf
|
|
|
Services
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales
|
|
$
|
231,285
|
|
|
$
|
|
|
|
$
|
13,463
|
|
|
$
|
244,748
|
|
Gathering and processing
|
|
|
231,733
|
|
|
|
3,063
|
|
|
|
|
|
|
|
234,796
|
|
Storage
|
|
|
|
|
|
|
|
|
|
|
20,290
|
|
|
|
20,290
|
|
Fractionation
|
|
|
|
|
|
|
|
|
|
|
10,770
|
|
|
|
10,770
|
|
Other
|
|
|
185
|
|
|
|
452
|
|
|
|
3,731
|
|
|
|
4,368
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
463,203
|
|
|
|
3,515
|
|
|
|
48,254
|
|
|
|
514,972
|
|
Product cost and shrink replacement
|
|
|
165,706
|
|
|
|
|
|
|
|
11,821
|
|
|
|
177,527
|
|
Operating and maintenance expense
|
|
|
104,648
|
|
|
|
714
|
|
|
|
24,397
|
|
|
|
129,759
|
|
Depreciation, amortization and
accretion
|
|
|
38,960
|
|
|
|
1,200
|
|
|
|
2,419
|
|
|
|
42,579
|
|
Direct general and administrative
expenses
|
|
|
12,230
|
|
|
|
2
|
|
|
|
1,068
|
|
|
|
13,300
|
|
Other, net
|
|
|
8,382
|
|
|
|
|
|
|
|
694
|
|
|
|
9,076
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
133,277
|
|
|
|
1,599
|
|
|
|
7,855
|
|
|
|
142,731
|
|
Equity earnings
|
|
|
|
|
|
|
8,331
|
|
|
|
|
|
|
|
8,331
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
133,277
|
|
|
$
|
9,930
|
|
|
$
|
7,855
|
|
|
$
|
151,062
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated
Statement of Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
142,731
|
|
General and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22,256
|
)
|
Third-party direct
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,059
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
119,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets
|
|
$
|
635,094
|
|
|
$
|
171,009
|
|
|
$
|
63,819
|
|
|
$
|
869,922
|
|
Other assets and eliminations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,353
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
875,275
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity method investments
|
|
$
|
|
|
|
$
|
150,260
|
|
|
$
|
|
|
|
$
|
150,260
|
|
Additions to long-lived assets
|
|
|
27,578
|
|
|
|
|
|
|
|
3,688
|
|
|
|
31,266
|
|
100
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering &
|
|
|
Gathering &
|
|
|
|
|
|
|
|
|
|
Processing -
|
|
|
Processing -
|
|
|
NGL
|
|
|
|
|
|
|
West
|
|
|
Gulf
|
|
|
Services
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales
|
|
$
|
204,868
|
|
|
$
|
|
|
|
$
|
8,453
|
|
|
$
|
213,321
|
|
Gathering and processing
|
|
|
221,939
|
|
|
|
3,883
|
|
|
|
|
|
|
|
225,822
|
|
Storage
|
|
|
|
|
|
|
|
|
|
|
15,318
|
|
|
|
15,318
|
|
Fractionation
|
|
|
|
|
|
|
|
|
|
|
9,070
|
|
|
|
9,070
|
|
Other
|
|
|
1,416
|
|
|
|
950
|
|
|
|
3,302
|
|
|
|
5,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
428,223
|
|
|
|
4,833
|
|
|
|
36,143
|
|
|
|
469,199
|
|
Product cost and shrink replacement
|
|
|
146,328
|
|
|
|
|
|
|
|
6,635
|
|
|
|
152,963
|
|
Operating and maintenance expense
|
|
|
97,070
|
|
|
|
572
|
|
|
|
18,804
|
|
|
|
116,446
|
|
Depreciation, amortization and
accretion
|
|
|
40,675
|
|
|
|
1,200
|
|
|
|
2,486
|
|
|
|
44,361
|
|
Direct general and administrative
expenses
|
|
|
8,500
|
|
|
|
|
|
|
|
535
|
|
|
|
9,035
|
|
Other, net
|
|
|
18,028
|
|
|
|
|
|
|
|
625
|
|
|
|
18,653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
117,622
|
|
|
|
3,061
|
|
|
|
7,058
|
|
|
|
127,741
|
|
Equity earnings
|
|
|
|
|
|
|
4,495
|
|
|
|
|
|
|
|
4,495
|
|
Impairment of investment
|
|
|
|
|
|
|
(13,484
|
)
|
|
|
|
|
|
|
(13,484
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit (loss)
|
|
$
|
117,622
|
|
|
$
|
(5,928
|
)
|
|
$
|
7,058
|
|
|
$
|
118,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated
Statement of Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
127,741
|
|
Allocated general and
administrative expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23,144
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
104,597
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
645,294
|
|
|
$
|
166,985
|
|
|
$
|
51,305
|
|
|
$
|
863,584
|
|
Equity method investments
|
|
|
|
|
|
|
147,281
|
|
|
|
|
|
|
|
147,281
|
|
Additions to long-lived assets
|
|
|
14,069
|
|
|
|
|
|
|
|
1,622
|
|
|
|
15,691
|
|
101
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
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
132,735
|
|
|
|
141,186
|
|
|
|
146,582
|
|
|
|
142,907
|
|
Costs and operating expenses
|
|
|
98,726
|
|
|
|
109,401
|
|
|
|
104,424
|
|
|
|
107,791
|
|
Net income
|
|
|
37,624
|
|
|
|
33,594
|
|
|
|
43,404
|
|
|
|
32,246
|
|
Basic and diluted net income per
limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of
change in accounting principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
0.35
|
|
|
$
|
0.25
|
|
|
$
|
0.57
|
|
|
$
|
0.45
|
|
Class B units
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
0.45
|
|
Subordinated units
|
|
$
|
0.35
|
|
|
$
|
0.25
|
|
|
$
|
0.57
|
|
|
$
|
0.45
|
|
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
0.35
|
|
|
$
|
0.25
|
|
|
$
|
0.57
|
|
|
$
|
0.45
|
|
Class B units
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
0.45
|
|
Subordinated units
|
|
$
|
0.35
|
|
|
$
|
0.25
|
|
|
$
|
0.57
|
|
|
$
|
0.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
119,272
|
|
|
$
|
120,256
|
|
|
$
|
132,340
|
|
|
$
|
143,104
|
|
Costs and operating expenses
|
|
|
92,274
|
|
|
|
89,301
|
|
|
|
99,216
|
|
|
|
114,765
|
|
Income before cumulative effect of
change in accounting principle
|
|
|
26,206
|
|
|
|
28,664
|
|
|
|
31,252
|
|
|
|
33,552
|
|
Net income
|
|
|
26,206
|
|
|
|
28,664
|
|
|
|
31,252
|
|
|
|
32,230
|
|
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
|
|
|
|
Item 9.
|
Changes
In and Disagreements With Accountants on Accounting and
Financial Disclosure
|
None.
102
|
|
Item 9A.
|
Controls
and Procedures
|
Evaluation
of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation
of our disclosure controls and procedures (as defined in
Rules 13a-15(e)
and 15(d) (e) of the Securities Exchange Act)
(Disclosure Controls) was performed as of the end of
the period covered by this report. This evaluation was performed
under the supervision and with the participation of our general
partners management, including our general partners
chief executive officer and chief financial officer. Based upon
that evaluation, our general partners chief executive
officer and chief financial officer concluded that these
Disclosure Controls are effective at a reasonable assurance
level.
Our management, including our general partners chief
executive officer and chief financial officer, does not expect
that our Disclosure Controls or our internal controls over
financial reporting (Internal Controls) will prevent
all errors and all fraud. A control system, no matter how well
conceived and operated, can provide only reasonable, not
absolute, assurance that the objectives of the control system
are met. Further, the design of a control system must reflect
the fact that there are resource constraints, and the benefits
of controls must be considered relative to their costs. Because
of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all
control issues and instances of fraud, if any, within the
company have been detected. These inherent limitations include
the realities that judgments in decision-making can be faulty,
and that breakdowns can occur because of simple error or
mistake. Additionally, controls can be circumvented by the
individual acts of some persons, by collusion of two or more
people, or by management override of the control. The design of
any system of controls also is based in part upon certain
assumptions about the likelihood of future events, and there can
be no assurance that any design will succeed in achieving its
stated goals under all potential future conditions. Because of
the inherent limitations in a cost-effective control system,
misstatements due to error or fraud may occur and not be
detected. We monitor our Disclosure Controls and Internal
Controls and make modifications as necessary; our intent in this
regard is that the Disclosure Controls and the Internal Controls
will be modified as systems change and conditions warrant.
Changes
in Internal Controls Over Financial Reporting
There have been no changes during the fourth quarter of 2006
that have materially affected, or are reasonably likely to
materially affect, our Internal Controls over financial
reporting.
Managements
Report on Internal Control over Financial Reporting
See Managements Report on Internal Control over
Financial Reporting set forth above in Item 8,
Financial Statements and Supplementary Data.
Item 9B. Other
Information
There have been no events that occurred in the fourth quarter of
2006 that would need to be reported on
Form 8-K
that have not been previously reported.
PART III
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Item 10.
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Directors
, Executive Officers and Corporate Governance
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As a limited partnership, we have no directors or officers.
Instead, our general partner, Williams Partners GP LLC, 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.
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.
103
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.
The following table shows information for the directors and
executive officers of our general partner as of
February 26, 2007.
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Name
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Age
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Position with Williams Partners GP LLC
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Steven J. Malcolm
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58
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Chairman of the Board and Chief
Executive Officer
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Donald R. Chappel
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55
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Chief Financial Officer and
Director
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Alan S. Armstrong
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44
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Chief Operating Officer and
Director
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James J. Bender
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50
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General Counsel
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Thomas C. Knudson
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60
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Director and Member of Audit and
Conflicts Committees
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Bill Z. Parker
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59
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Director and Member of Audit and
Conflicts Committees
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Alice M. Peterson
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54
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Director and Member of Audit and
Conflicts Committees
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Phillip D. Wright
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51
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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. (now known as Magellan Midstream Partners,
L.P.) from its initial public offering in February 2001 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 was named as a defendant in numerous
shareholder class action suits that have been filed against
Williams by Williams securities holders. 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. Settlement of
the Williams securities holders class action was approved by the
court in February 2007. 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.
104
Alan S. Armstrong has served as the chief operating
officer and a director of our general partner since February
2005. Since February 2002, Mr. Armstrong has served as a
senior vice president of Williams 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. Prior to joining Williams in December 2002,
Mr. Bender was senior vice president and general counsel
with NRG Energy, Inc., a position held since June 2000.
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 June
2004. Mr. Knudson has served as chairman of the board of
directors of Bristow Group Inc. since August 2006.
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.
Bill Z. Parker has served as a director of our general
partner since August 2005. Mr. Parker served as a director
for Latigo Petroleum, Inc., a privately-held independent oil and
gas production company, from January 2003 to May 2006, when it
was acquired by POGO Producing Company. 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
of Hanesbrands Inc., an apparel company, since August 2006.
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 with
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
105
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. (now known as Magellan
Midstream Partners, L.P.) from its initial public offering in
February 2001 to the sale of Williams interests therein in
June 2003. Mr. Wright was 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.
Governance
Our general partner adopted governance guidelines that address,
among other areas, director independence standards, policies on
meeting attendance and preparation, executive sessions of
non-management directors and communications with non-management
directors.
Director
Independence
Because we are a limited partnership, the New York Stock
Exchange does not require our general partners board of
directors to be composed of a majority of directors who meet the
criteria for independence required by the New York Stock
Exchange or to maintain nominating/corporate governance and
compensation committees composed entirely of independent
directors.
Our general partners board of directors annually reviews
the independence of directors and affirmatively makes a
determination that each director expected to be independent has
no material relationship with our general partner (either
directly or indirectly or as a partner, shareholder or officer
of an organization that has a relationship with our general
partner). In order to make this determination, our general
partners board of directors broadly considers all relevant
facts and circumstances and applies categorical standards from
our governance guidelines, which are set forth below and also
available on our Internet website at
http://www.williamslp.com
under the Investor Relations caption. Under
those categorical standards, a director will not be considered
to be independent if:
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the director, or an immediate family member of the director, has
received during any twelve-month period within the last three
years more than $100,000 per year in direct compensation
from our general partner, us, and any parent or subsidiary in a
consolidated group with such entities (collectively, the
Partnership Group), other than board and committee
fees and pension or other forms of deferred compensation for
prior service (provided such compensation is not contingent in
any way on continued service). Neither compensation received by
a director for former service as an interim chairman or chief
executive officer or other executive officer nor compensation
received by an immediate family member for service as an
employee of the Partnership Group will be considered in
determining independence under this standard.
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the director is a current employee, or has an immediate family
member who is a current executive officer, of another company
that has made payments to, or received payments from, the
Partnership Group for property or services in an amount which,
in any of the last three fiscal years, exceeds the greater of
$1.0 million, or 2% of the other companys
consolidated gross annual revenues. Contributions to tax exempt
organizations are not considered payments for
purposes of this standard.
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the director is, or has been within the last three years, an
employee of the Partnership Group, or an immediate family member
is, or has been within the last three years, an executive
officer, of the Partnership Group. Employment as an interim
chairman or chief executive officer or other executive officer
will not disqualify a director from being considered independent
following that employment.
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(i) the director or an immediate family member is a current
partner of a present or former internal or external auditor for
the Partnership Group, (ii) the director is a current
employee of such a firm, (iii) the director has an
immediate family member who is a current employee of such a firm
and participates in such firms audit, assurance or tax
compliance (but not tax planning) practice or (iv) the
director or an
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106
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immediately family member was within the last three years (but
is no longer) a partner or employee of such a firm and
personally worked on an audit for the Partnership Group within
that time.
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if the director or an immediate family member is, or has been
within the last three years, employed as an executive officer of
another company where any of the Partnership Groups
present executive officers at the same time serves or served on
that companys compensation committee.
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if the board of directors determines that a discretionary
contribution made by any member of the Partnership Group to a
non-profit organization with which a director, or a
directors spouse, has a relationship, impacts the
directors independence.
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Our general partners board of directors has affirmatively
determined that each of Ms. Peterson and
Messrs. Knudson and Parker is an independent
director under the current listing standards of the New
York Stock Exchange and our categorical director independence
standards. In doing so, the board of directors determined that
each of these individuals met the bright line
independence standards of the New York Stock Exchange. In
addition, the board of directors considered relationships with
our general partner, either directly or indirectly. The purpose
of this review was to determine whether any such relationships
or transactions were inconsistent with a determination that the
director is independent. The board of directors considered the
fact that Mr. Knudson serves as a director for NATCO Group
Inc., which provides goods or services for certain of our
subsidiaries, affiliates of Williams and Discovery. The board of
directors noted that, since Mr. Knudson does not serve as
an executive officer and is not a significant stockholder of
NATCO Group Inc., these relationships are not material and
affirmatively determined that all of the directors mentioned
above are independent. Because Messrs. Armstrong, Chappel,
Malcolm and Wright are employees, officers
and/or
directors of Williams, they are not independent under these
standards.
Ms. Peterson and Messrs. Knudson and Parker do not
serve as an executive officer of any non-profit organization to
which the Partnership Group made contributions within any single
year of the preceding three years that exceeded the greater of
$1.0 million or 2% of such organizations consolidated
gross revenues. Further, in accordance with our categorical
director independence standards, there were no discretionary
contributions made by any member of the Partnership Group to a
non-profit organization with which such director, or such
directors spouse, has a relationship that impact the
directors independence.
In addition, our general partners board of directors
determined that each of Ms. Peterson and
Messrs. Knudson and Parker, who constitute the members of
the audit committee of the board of directors, meet the
heightened independence requirements of the New York Stock
Exchange for audit committee members.
Meeting
Attendance and Preparation
Members of the board of directors are expected to attend at
least 75% of regular board meetings and meetings of the
committees on which they serve, either in person or
telephonically. In addition, directors are expected to be
prepared for each meeting of the board by reviewing written
materials distributed in advance.
Executive
Sessions of Non-Management Directors
The general partners non-management board members
periodically meet outside the presence of our general
partners executive officers. The chairman of the audit
committee serves as the presiding director for executive
sessions of non-management board members. The current chairman
of the audit committee and the presiding director is
Ms. Alice M. Peterson.
Communications
with Directors
Interested parties wishing to communicate with our general
partners non-management directors or the presiding
director may contact our general partners corporate
secretary or the presiding director. The contact information is
published on the investor relations page of our website at
http://www.williamslp.com.
107
The current contact information is as follows:
Williams Partners L.P.
c/o Williams Partners GP LLC
One Williams Center, Suite 4700
Tulsa, Oklahoma 74172
Attn: Corporate Secretary
Williams Partners L.P.
c/o Williams Partners GP LLC
One Williams Center, Suite 4700
Tulsa, Oklahoma 74172
Attn: Presiding Director
E-mail:
brian.shore@williams.com
Board
Committees
The board of directors of our general partner has a
separately-designated standing audit committee established in
accordance with Section 3(a)(58)(A) of the Securities
Exchange Act of 1934 and a conflicts committee. The following is
a description of each of the committees and committee membership
as of February 26, 2007.
Board
Committee Membership
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Audit
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Conflicts
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Committee
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Committee
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Thomas C. Knudson
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ü
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Bill Z. Parker
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ü
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Alice M. Peterson
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ü
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ü |
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= committee member |
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= chairperson |
Audit
Committee
Our general partners board of directors has determined
that all members of the audit committee meet the heightened
independence requirements of the New York Stock Exchange for
audit committee members and that all members are financially
literate as defined by the rules of the New York Stock Exchange.
The board of directors has further determined that
Ms. Alice M. Peterson is an audit committee financial
expert as defined by the rules of the SEC.
Ms. Petersons biographical information is set forth
above. The audit committee is governed by a written charter
adopted by the board of directors. For further information about
the audit committee, please read the Report of the Audit
Committee below and Principal Accountant Fees and
Services.
Conflicts
Committee
The conflicts committee of our general partners board of
directors reviews specific matters that the board believes may
involve conflicts of interest. The conflicts committee
determines if resolution of the conflict 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 requirements 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 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 to us or our unitholders.
108
Code of
Business Conduct and Ethics
Our general partner has adopted a code of business conduct and
ethics for directors, officers and employees. We intend to
disclose any amendments to or waivers of the code of business
conduct and ethics on behalf of our general partners chief
executive officer, chief financial officer, controller and
persons performing similar functions on our Internet website at
http://www.williamslp.com under the Investor
Relations caption, promptly following the date of any such
amendment or waiver.
Internet
Access to Governance Documents
Our general partners code of business conduct and ethics,
governance guidelines and the charter for the audit committee
are available on our Internet website at
http://www.williamslp.com under the Investor
Relations caption. We will provide, free of charge, a copy
of our code of business conduct and ethics or any of our other
governance documents listed above upon written request to our
general partners secretary at Williams Partners L.P., One
Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
Section 16(a)
Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934
requires our general partners officers and directors, and
persons who own more than 10% of a registered class of our
equity securities to file with the SEC and the New York Stock
Exchange reports of ownership of our securities and changes in
reported ownership. Officers and directors of our general
partner and greater than 10% common unitholders are required to
by SEC rules to furnish to us copies of all Section 16(a)
reports that they file. Based solely on a review of reports
furnished to our general partner, or written representations
from reporting persons that all reportable transactions were
reported, we believe that during the fiscal year ended
December 31, 2006 our general partners officers,
directors and greater than 10% common unitholders filed all
reports they were required to file under Section 16(a).
Transfer
Agent and Registrar
Computershare Trust Company, N.A. serves as registrar and
transfer agent for our common units. Contact information for
Computershare is as follows:
Computershare Trust Company, N.A.
P.O. Box 43069
Providence, Rhode Island
02940-3069
Phone:
(781) 575-2879
or toll-free,
(877) 498-8861
Hearing impaired:
(800) 952-9245
Internet: www.computershare.com/investor
Send overnight mail to:
Computershare
250 Royall St.
Canton, Massachusetts 02021
CEO/CFO
Certifications
We submitted the certification of Steven J. Malcolm, our general
partners chairman of the board and chief executive
officer, to the New York Stock Exchange pursuant to NYSE
Section 303A.12(a) on September 11, 2006. In addition,
the certificates of our chief executive officer and chief
financial officer as required by Section 302 of the
Sarbanes-Oxley Act of 2002 are filed as Exhibits 31.1 and
31.2 to this annual report.
REPORT OF
THE AUDIT COMMITTEE
The audit committee oversees our financial reporting process on
behalf of the board of directors. Management has the primary
responsibility for the financial statements and the reporting
process including the systems of internal controls. The audit
committee operates under a written charter approved by the
board. The
109
charter, among other things, provides that the audit committee
has authority to appoint, retain and oversee the independent
auditor. In this context, the audit committee:
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reviewed and discussed the audited financial statements in this
annual report on
Form 10-K
with management, including a discussion of the quality, not just
the acceptability, of the accounting principles, the
reasonableness of significant judgments and the clarity of
disclosures in the financial statements;
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reviewed with Ernst & Young LLP, the independent
auditors, who are responsible for expressing an opinion on the
conformity of those audited financial statements with generally
accepted accounting principles, their judgments as to the
quality and acceptability of Williams Partners L.P.s
accounting principles and such other matters as are required to
be discussed with the audit committee under generally accepted
auditing standards;
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received the written disclosures and the letter required by
standard No. 1 of the independence standards board
(independence discussions with audit committees) provided to the
audit committee by Ernst & Young LLP;
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discussed with Ernst & Young LLP its independence from
management and Williams Partners L.P. and considered the
compatibility of the provision of nonaudit services by the
independent auditors with the auditors independence;
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discussed with Ernst & Young LLP the matters required
to be discussed by statement on auditing standards No. 61
(communications with audit committees);
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discussed with Williams Partners L.P.s internal auditors
and Ernst & Young LLP the overall scope and plans
for their respective audits. The audit committee meets with the
internal auditors and Ernst & Young LLP, with and
without management present, to discuss the results of their
examinations, their evaluations of Williams Partners L.P.s
internal controls and the overall quality of Williams Partners
L.P.s financial reporting;
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based on the foregoing reviews and discussions, recommended to
the board of directors that the audited financial statements be
included in the annual report on
Form 10-K
for the year ended December 31, 2006, for filing with the
SEC; and
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approved the selection and appointment of Ernst & Young
LLP to serve as Williams Partners L.P.s independent
auditors.
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This report has been furnished by the members of the audit
committee of the board of directors:
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Alice M. Peterson chairman
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Bill Z. Parker
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Thomas C. Knudson
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February 20, 2007
The report of the audit committee in this report shall not be
deemed incorporated by reference into any other filing by
Williams Partners L.P. under the Securities Act of 1933, as
amended, or the Securities Exchange Act of 1934, except to the
extent that we specifically incorporate this information by
reference, and shall not otherwise be deemed filed under such
acts.
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Item 11.
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Executive
Compensation
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Compensation
Discussion and Analysis
We and our general partner, Williams Partners GP LLC, were
formed in February 2005. We are managed by the executive
officers of our general partner who are also executive officers
of Williams. We have no compensation committee and the
compensation committee of our general partner was dissolved on
November 28, 2006. The executive officers of our
general partner are compensated directly by Williams. All
110
decisions as to the compensation of the executive officers of
our general partner who are involved in our management are made
by the compensation committee of Williams. Therefore, we do not
have any policies or programs relating to compensation of the
executive officers of our general partner and we make no
decisions relating to such compensation. A full discussion of
the policies and programs of the compensation committee of
Williams will be set forth in the proxy statement for
Williams 2007 annual meeting of stockholders which will be
available upon its filing on the SECs website at
http://www.sec.gov and on Williams website at
http://www.williams.com
under the heading Investors SEC
Filings. We reimburse our general partner for direct and
indirect general and administrative expenses attributable to our
management (which expenses include the share of the compensation
paid to the executive officers of our general partner
attributable to the time they spend managing our business).
Please read Certain Relationships and Related
Transactions, and Director
Independence Reimbursement of Expenses of Our
General Partner for more information regarding this
arrangement.
Executive
Compensation
None of the executive officers of our general partner received,
other than Messrs. Armstrong and Malcolm, directly or
indirectly, more than $100,000 for services performed for us in
2006.
Further information regarding the compensation of our principal
executive officer, Steven J. Malcolm, who also serves as the
chairman, president and chief executive officer of Williams, and
our principal financial officer, Donald R. Chappel, who also
serves as the chief financial officer of Williams, will be set
forth in the proxy statement for Williams 2007 annual
meeting of stockholders which will be available upon its filing
on the SECs website at http://www.sec.gov and on
Williams website at http:/www.williams.com under
the heading Investors SEC Filings.
Further information regarding the portion of
Mr. Armstrongs, Mr. Chappels and
Mr. Malcolms compensation and employment-related
expenses allocable to us may be found in this filing under the
heading Certain Relationships and Related Transactions,
and Director Independence Reimbursement of Expenses
of Our General Partner.
Compensation
Committee Interlocks and Insider Participation
As previously discussed, our general partners board of
directors is not required to maintain, and does not maintain, a
compensation committee. Steven J. Malcolm, our general
partners chief executive officer and chairman of the board
of directors serves as the chairman of the board and chief
executive officer of Williams. Alan S. Armstrong, Donald R.
Chappel and Phillip D. Wright, who are directors of our general
partner, are also executive officers of Williams. However, all
compensation decisions with respect to each of these persons are
made by Williams and none of these individuals receive any
compensation directly from us or our general partner. Please
read Certain Relationships and Related Transactions, and
Director Independence below for information about
relationships among us, our general partner and Williams.
Board
Report on Compensation
Neither we nor our general partner has a compensation committee.
The board of directors of our general partner has reviewed and
discussed the Compensation Discussion and Analysis set forth
above and based on this review and discussion has approved it
for inclusion in this
Form 10-K.
The Board of Directors of Williams Partners GP LLC:
Alan S. Armstrong, Donald R. Chappel,
Thomas C. Knudson, Steven J. Malcolm
Bill Z. Parker, Alice M. Peterson,
Phillip D. Wright
Compensation
of Directors
We are managed by the board of directors of our general partner.
Members of the board of directors who are also officers or
employees of Williams or an affiliate of us or Williams do not
receive additional compensation for serving on the board of
directors. Non-employee directors each receive an annual
111
compensation package consisting of the following:
(a) $50,000 cash retainer; (b) restricted units
representing our limited partnership interests valued at $25,000
in the aggregate; and (c) $5,000 cash for service on the
conflicts or audit committees of the board of directors. The
annual compensation package is paid to each non-employee
director based on their service on the board of directors for
the period beginning on August 22 of each fiscal year and ending
on August 21 of each fiscal year. If a non-employee
directors service on the board of directors commences on
or after December 1 of a fiscal year, such non-employee
director will receive a prorated annual compensation package for
such fiscal year. In addition to the annual compensation
package, each non-employee director receives a one-time grant of
restricted units valued at $25,000 on the date of first election
to the board of directors. Restricted units awarded to
non-employee directors under the annual compensation package or
upon first election to the board of directors are granted under
the Williams Partners GP LLC Long-Term Incentive Plan and vest
180 days after the date of grant. Cash distributions are be
paid on these restricted units. Each non-employee director is
also 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.
For their service, non-management directors received the
following compensation in 2006:
Director
Compensation Fiscal Year 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fees Earned or Paid
|
|
|
|
All Other
|
|
|
Name
|
|
in Cash
|
|
Unit Awards(1)
|
|
Compensation
|
|
Total
|
|
Thomas C. Knudson
|
|
$
|
60,000
|
|
|
$
|
63,394.66
|
(2)
|
|
$
|
0
|
|
|
$
|
123,394.66
|
|
Bill Z. Parker
|
|
$
|
60,000
|
|
|
$
|
82,738.39
|
(3)
|
|
$
|
0
|
|
|
$
|
142,738.39
|
|
Alice M. Peterson
|
|
$
|
60,000
|
|
|
$
|
82,738.39
|
(4)
|
|
$
|
0
|
|
|
$
|
142,738.39
|
|
|
|
|
(1) |
|
Awards were granted under the Williams Partners GP LLC Long-Term
Incentive Plan. Awards are in the form of restricted units and
are shown using a dollar value equal to the 2006 compensation
expense computed in accordance with FAS 123(R). Cash
distributions are paid on these restricted units at the same
time and same rate as dividends paid to our unitholders. |
|
(2) |
|
The grant date fair value for the 2006 restricted units for
Mr. Knudson is $25,013. At fiscal year end,
Mr. Knudson had an aggregate of 710 restricted units
outstanding. |
|
(3) |
|
The grant date fair value for the 2006 restricted units for
Mr. Parker is $25,013. At fiscal year end, Mr. Parker
had an aggregate of 710 restricted units outstanding. |
|
(4) |
|
The grant date fair value for the 2006 restricted units for
Ms. Peterson is $25,013. At fiscal year end,
Ms. Peterson had an aggregate of 710 restricted units
outstanding. |
Long-Term
Incentive Plan
In connection with our IPO, 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 directors
who are not officers or employees of us or our affiliates. On
November 28, the board of directors of our general partner
dissolved its compensation committee. The only function
performed by the committee prior to its dissolution was to
administer the Williams Partners GP LLC Long-Term Incentive
Plan. Accordingly, also on November 28, 2006, the board of
directors approved an amendment to the long-term incentive plan
to allow the full board of directors to administer the plan. 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.
Our general partners board of directors, 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 also has
the right to alter or amend the long-term incentive plan or any
part of the plan
112
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.
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 will be 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 board of directors of our general partner may
determine to make grants under the plan of restricted units and
phantom units to employees, consultants and directors containing
such terms as the board of directors shall determine. The board
of directors determines the period over which restricted units
and phantom units granted to employees, consultants and
directors will vest. The board of directors may base its
determination upon the 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 board of directors.
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 board of
directors 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 board of
directors of our general partner, in its discretion, may grant
tandem distribution rights with respect to restricted units and
tandem distribution equivalent rights with respect to phantom
units.
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 board of directors in its discretion. Our
general partners board of directors may make grants of
unit options and unit appreciation rights under the plan to
employees, consultants and directors containing such terms as
the board of directors 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
board of directors. 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 board of directors.
The board of directors, 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
113
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.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
The following table sets forth the beneficial ownership of units
of Williams Partners L.P. that are owned 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 beneficially owned is based on
39,358,798 units outstanding. Unless otherwise noted below,
the address for the beneficial owners listed below is One
Williams Center, Tulsa, Oklahoma
74172-0172.
114
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
Percentage
|
|
|
|
Common
|
|
|
of Common
|
|
|
Subordinated
|
|
|
Percentage of
|
|
|
Class B
|
|
|
of Class B
|
|
|
of Total
|
|
Name of
|
|
Units
|
|
|
Units
|
|
|
Units
|
|
|
Subordinated
|
|
|
Units
|
|
|
Units
|
|
|
Units
|
|
Beneficial
|
|
Beneficially
|
|
|
Beneficially
|
|
|
Beneficially
|
|
|
Beneficially
|
|
|
Beneficially
|
|
|
Beneficially
|
|
|
Beneficially
|
|
Owner
|
|
Owned
|
|
|
Owned
|
|
|
Owned
|
|
|
Owned
|
|
|
Owned
|
|
|
Owned
|
|
|
Owned
|
|
|
The Williams Companies, Inc.(a)
|
|
|
1,250,000
|
|
|
|
4.9
|
%
|
|
|
7,000,000
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
21
|
%
|
Williams Energy Services, LLC(a)
|
|
|
821,761
|
|
|
|
3.2
|
|
|
|
4,601,861
|
|
|
|
65.7
|
|
|
|
|
|
|
|
|
|
|
|
13.8
|
|
Williams Energy, L.L.C.
|
|
|
447,308
|
|
|
|
1.8
|
|
|
|
2,504,925
|
|
|
|
35.8
|
|
|
|
|
|
|
|
|
|
|
|
7.5
|
|
Williams Discovery Pipeline LLC
|
|
|
215,980
|
|
|
|
.8
|
|
|
|
1,209,486
|
|
|
|
17.3
|
|
|
|
|
|
|
|
|
|
|
|
3.6
|
|
Williams Partners Holdings LLC
|
|
|
428,239
|
|
|
|
1.7
|
|
|
|
2,398,139
|
|
|
|
34.2
|
|
|
|
|
|
|
|
|
|
|
|
7.2
|
|
MAPCO Inc.(a)
|
|
|
447,308
|
|
|
|
1.8
|
|
|
|
2,504,925
|
|
|
|
35.8
|
|
|
|
|
|
|
|
|
|
|
|
7.5
|
|
Prudential Financial, Inc.(b)
|
|
|
2,776,949
|
|
|
|
10.87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.06
|
|
Jennison Utility Fund(c)
|
|
|
714,680
|
|
|
|
2.8
|
|
|
|
|
|
|
|
|
|
|
|
2,062,269
|
|
|
|
30.3
|
%
|
|
|
7.1
|
|
Goldman Sachs & Co.(d)
|
|
|
357,340
|
|
|
|
1.4
|
|
|
|
|
|
|
|
|
|
|
|
1,031,134
|
|
|
|
15.2
|
|
|
|
3.5
|
|
GPS Income Fund (Cayman) LTD(e)
|
|
|
164,376
|
|
|
|
.6
|
|
|
|
|
|
|
|
|
|
|
|
474,321
|
|
|
|
7.0
|
|
|
|
1.6
|
|
Tortoise Capital Advisors L.L.C.(f)
|
|
|
1,487,094
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
721,796
|
|
|
|
10.6
|
|
|
|
5.6
|
|
Perry Partners L.P.(g)
|
|
|
178,670
|
|
|
|
.7
|
|
|
|
|
|
|
|
|
|
|
|
515,566
|
|
|
|
6
|
|
|
|
8
|
|
The Cushing MLP Opportunity
Fund I, LP(h)
|
|
|
178,670
|
|
|
|
.7
|
|
|
|
|
|
|
|
|
|
|
|
515,566
|
|
|
|
7.6
|
|
|
|
1.8
|
|
Alan S. Armstrong
|
|
|
10,000
|
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
James J. Bender
|
|
|
2,000
|
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Donald R. Chappel
|
|
|
10,000
|
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Steven J. Malcolm(i)
|
|
|
25,100
|
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Bill Z. Parker
|
|
|
8,036
|
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Alice M. Peterson
|
|
|
3,036
|
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Thomas C. Knudson
|
|
|
2,204
|
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Phillip D. Wright
|
|
|
2,000
|
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
All directors and executive
officers as a group (eight persons)
|
|
|
62,376
|
|
|
|
|
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
|
|
|
* |
|
Less than 1%. |
|
(a) |
|
As noted in the Schedule 13D/A filed with the SEC on
December 19, 2006, The Williams Companies, Inc. is the
ultimate parent company of Williams Energy Services, LLC,
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
(the Act). 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. |
|
(b) |
|
Based solely on the Schedule 13G filed with the SEC on
February 9, 2007, Prudential Financial, Inc.
(Prudential), a Parent Holding Company as defined in
the Securities Exchange Act of 1934, may be deemed to be the
beneficial owner of securities beneficially owned by the
Registered Investment Advisors listed in such Schedule 13G,
of which Prudential is the direct or indirect parent, and may
have direct or |
115
|
|
|
|
|
indirect voting power over 2,776,949 common units which are held
for Prudentials benefit or for the benefit of its clients
by its separate accounts, externally managed accounts,
registered investment companies subsidiaries
and/or
affiliates. The Schedule 13G notes that Prudential reported
the combined holdings of these entities for the purpose of
administrative convenience. The address of Prudential is 751
Broad Street, Newark, New Jersey
07102-3777. |
|
(c) |
|
The address of Jennison Utility Fund is 466 Lexington Avenue,
New York, New York 10017. |
|
(d) |
|
The address of Goldman Sachs & Co. is 85 Broad Street,
29th Floor, New York, New York 10004. |
|
(e) |
|
Also includes 64,321 common units and 185,604 Class B units
held by GPS Income Fund LP and 20,011 common units and
57,743 Class B units held by GPS High Yield Equities Fund.
The address of GPS Income Fund (Cayman) LTD is 1000 Wilshire
Blvd., Suite 900, Santa Monica, California, 90401. |
|
(f) |
|
According to the Schedule 13G filed with the SEC on
February 13, 2007, Tortoise Capital Advisors, L.L.C.
(TCA) acts as an investment advisor to certain
closed-end investment companies registered under the Investment
Company Act of 1940. TCA, by virtue of investment advisory
agreements with these investment companies, has all investment
and voting power over the units owned of record by these
companies. In addition, TCA acts as an investment advisor to
certain managed accounts. Under contractual agreements with
individual account holders, TCA, with respect to the units held
in the managed accounts, shares investment and voting power with
certain account holders, and has no voting power but shares
investment power with certain other account holders.
Accordingly, TCA may be deemed to beneficially own 1,487,094
common units and 721,796 Class B units. The address of TCA
is 10801 Mastin Boulevard, Suite 222 Overland Park, Kansas
66210. |
|
(g) |
|
Also includes 5,717 common units and 16,498 Class B units
held by Perry Commitment Fund L.P. The address of Perry
Partners L.P. is 767 5th Ave, 19th Floor, New York,
New York 10153. |
|
(h) |
|
Also includes 35,734 common units and 103,113 Class B units
held by Swank MLP Convergence Fund, LP. The address of The
Cushing MLP Opportunity Fund I, LP is 3300 Oak Lawn Avenue,
Suite 650 Dallas, Texas 75219. |
|
(i) |
|
Represents units beneficially owned by Mr. Malcolm that are
held by the Steven J. Malcolm Revocable Trust. |
The following table sets forth, as of February 20, 2007,
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 of Common
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Owned
|
|
|
Shares Underlying
|
|
|
|
|
|
|
|
|
|
Directly or
|
|
|
Options Exercisable
|
|
|
|
|
|
|
|
Name of Beneficial Owner
|
|
Indirectly(a)
|
|
|
Within 60 Days(b)
|
|
|
Total
|
|
|
Percent of Class
|
|
|
Alan S. Armstrong
|
|
|
123,999
|
|
|
|
21,378
|
|
|
|
145,377
|
|
|
|
*
|
|
James J. Bender
|
|
|
139,732
|
|
|
|
21,378
|
|
|
|
161,110
|
|
|
|
*
|
|
Donald R. Chappel
|
|
|
229,077
|
|
|
|
32,306
|
|
|
|
261,383
|
|
|
|
*
|
|
Steven J. Malcolm
|
|
|
794,117
|
|
|
|
158,333
|
|
|
|
952,450
|
|
|
|
*
|
|
Bill Z. Parker
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alice M. Peterson
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thomas C. Knudson
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phillip D. Wright
|
|
|
217,385
|
|
|
|
21,378
|
|
|
|
238,763
|
|
|
|
*
|
|
All directors and executive
officers as a group (eight persons)
|
|
|
1,504,310
|
|
|
|
254,773
|
|
|
|
1,759,083
|
|
|
|
*
|
|
|
|
|
* |
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Less than 1%. |
|
(a) |
|
Includes shares held under the terms of incentive and investment
plans as follows: Mr. Armstrong, 14 shares in The
Williams Companies Investment Plus Plan, 88,368 restricted stock
units and 35,617 beneficially owned shares; Mr. Bender,
6,000 shares owned by children, 88,368 restricted stock
units and |
116
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|
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45,364 beneficially owned shares; Mr. Chappel, 129,434
restricted stock units and 99,643 beneficially owned shares;
Mr. Malcolm, 45,297 shares in The Williams Companies
Investment Plus Plan, 393,092 restricted stock units and 355,728
beneficially owned shares; and Mr. Wright,
14,964 shares in The Williams Investment Plus Plan, 88,368
restricted stock units and 114,053 beneficially owned shares.
Restricted stock units do not provide the holder with voting or
investment power. |
|
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(b) |
|
The shares indicated represent stock options granted under
Williams current or previous stock option plans, which are
currently exercisable or which will become exercisable within
60 days of February 20, 2007. Shares subject to
options cannot be voted. |
Securities
Authorized for Issuance Under Equity Compensation
Plans(1)
The following table provides information concerning common units
that were potentially subject to issuance under the Williams
Partners GP LLC Long-Term Incentive Plan as of December 31,
2006. For more information about this plan, which did not
require approval by our limited partners, please read
Note 13 of our Notes to Consolidated Financial Statements
and Executive Compensation Long-Term Incentive
Plan. Please read Executive Compensation
Long Term Incentive Plan for a description of the material
features of the plan, including the awards that may be granted
under the plan.
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Number of Securities
|
|
|
|
|
|
|
|
|
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Remaining Available
|
|
|
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Number of Securities
|
|
|
Weighted-Average
|
|
|
for Future Issuance
|
|
|
|
to be Issued Upon
|
|
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Exercise Price of
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Under Equity
|
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|
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Exercise of Outstanding
|
|
|
Outstanding
|
|
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Compensation Plan
|
|
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|
Options, Warrants
|
|
|
Options, Warrants
|
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(Excluding Securities
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|
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|
and Rights
|
|
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and Rights
|
|
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Reflected in Column(a))
|
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Plan category
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(a)
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(b)
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(c)
|
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Equity compensation plans approved
by security holders
|
|
|
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|
|
|
|
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|
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Equity compensation plans not
approved by security holders
|
|
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2,130
|
|
|
|
|
|
|
|
691,724
|
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Total
|
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2,130
|
(1)
|
|
|
|
|
|
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691,724
|
|
|
|
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(1) |
|
Represents unvested restricted units granted pursuant to the
Williams Partners GP LLC Long-Term Incentive Plan as of
December 31, 2006. The restricted units vested on
February 18, 2007. No value is shown in column (b) of
the table because the restricted units do not have an exercise
price. To date, the only grants under the plan have been grants
of restricted units. |
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Item 13.
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Certain
Relationships and Related Transactions, and Director
Independence
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Transactions
with Related Persons
Affiliates of our general partner own 1,250,000 common units and
7,000,000 subordinated units representing a 20.5% limited
partner interest in us. Williams also indirectly owns 100% of
our general partner, which allows it to control us. Certain
officers and directors of our general partner also serve as
officers
and/or
directors of Williams. In addition, our general partner owns a
2% general partner interest and incentive distribution rights in
us.
In addition to the related transactions and relationships
discussed below, information about such transactions and
relationships is included in Note 5 of our Notes to
Consolidated Financial Statements and is incorporated herein by
reference in its entirety.
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, which include Williams, in connection with the
ongoing operation and liquidation of
117
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.
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Operational
Stage
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Distributions of available cash to
our general partner and its affiliates
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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 and all of the subordinated units, and the
remaining 2% to our general partner.
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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. For further information about
distributions, please read Market for Registrants
Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities.
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Reimbursement of expenses 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.
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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.
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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 our business. However, we
reimburse our general partner for expenses incurred on our
behalf, including expenses incurred in compensating employees of
an affiliate of our general partner who perform services on our
behalf. These expenses include all allocable expenses necessary
or appropriate to the conduct of our business. The expenses that
are allocable to us vary for each employee of an affiliate of
our general partner performing services on our behalf and are
based on the amount of time such employee devotes to matters
related to our business as compared to the amount of time such
employee devotes to matters related to the business Williams and
its other affiliates. Our partnership agreement provides that
our general partner will determine in good faith the expenses
that are allocable to us. There is no cap on the amount that may
be paid or reimbursed to our general partner for 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 IPO of common units in August 2005. Please
read Omnibus Agreement below for more
information.
For the fiscal year ended December 31, 2006, our general
partner allocated $35,822 of salary and non-equity incentive
plan compensation expense to us for Steven J. Malcolm, the
chairman of the board and chief executive officer of our general
partner, $17,985 of salary and non-equity incentive plan
compensation expense to us for Donald R. Chappel, the chief
financial officer of our general partner and $156,115 of salary
and non-equity incentive plan compensation expense to us for
Alan S. Armstrong, the chief operating officer of our general
partner. Our general partner also allocated to us $71,449 for
Steven J. Malcolm, $21,100 for Don Chappel and $91,475 for Alan
Armstrong, which expenses are attributable to additional
compensation paid to each of them and other employment-related
expenses, including Williams restricted stock unit and stock
option awards, retirement plans, health and welfare plans,
employer-related payroll taxes, matching contributions made
under a Williams 401(k) plan and premiums for life insurance.
Our general partner also allocated to us a portion of
Williams expenses related to perquisites for each of
Messrs. Malcolm, Chappel and Armstrong,
118
which allocation did not exceed $10,000 for any of these
persons. The foregoing amounts exclude expenses allocated by
Williams to Discovery. No awards were granted to our general
partners executive officers under the Williams Partners GP
LLC Long-Term Incentive Plan in 2005 or 2006 and no other
executive officer of our general partner, other than
Messrs. Armstrong and Malcolm received total compensation
allocable to us in excess of $100,000. The total compensation
received by Mr. Malcolm, the chairman of the board and
chief executive officer of our general partner who is also the
chairman, president and chief executive officer of Williams, and
Mr. Chappel, the chief financial officer of our general
partner who is also the chief financial officer of Williams,
will be set forth in the proxy statement for Williams 2007
annual meeting of stockholders which will be available upon its
filing on the SECs website at http://www.sec.gov
and on Williams website at
http://www.williams.com
under the heading Investors SEC
Filings.
For the year ended December 31, 2006, we incurred
approximately $87.3 million in operating and maintenance
and general and administrative expenses from Williams incurred
on our behalf pursuant to the partnership agreement.
Omnibus
Agreement
Upon the closing of our initial public offering, we entered into
an omnibus agreement with Williams and its affiliates that was
not the result of arms-length negotiations. The omnibus
agreement governs our relationship with Williams 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, resulting in a $1.4 million
credit. In 2006, the amount of the G&A credit was
$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.
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.
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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
119
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.
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.
|
For the year ended December 31, 2006, Williams indemnified
us $2.0 million, primarily for KDHE related compliance.
Including 2006, Williams has indemnified us for an aggregate of
$2.5 million pursuant to the omnibus agreement.
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.
During 2006, Williams indemnified us $1.6 million for our
40% of Discoverys capital call related to this project.
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.
Amendments
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.
Competition
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
Working
Capital Facility
At the closing of our initial public offering in August 2005, we
entered into a $20.0 million revolving credit facility with
Williams as the lender. The facility was amended and restated on
August 7, 2006. The
120
facility is available exclusively to fund working capital
borrowings. Borrowings under the facility will mature on
June 20, 2009 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.
Williams
Credit Agreement
In addition, we also have the ability to borrow up to
$75.0 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 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.
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. 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.
Under the Discovery limited liability company agreement, each
member is subject to a right of first refusal in favor of the
other members, except in the case of certain related-party
transfers, such as between Williams and us. Accordingly, if a
member identifies a potential third-party purchaser for all or a
portion of its interest, that member must first offer the other
members the opportunity to acquire the interest that it proposes
to sell on the same terms and conditions as proposed by such
potential purchaser.
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.
For the year ended December 31, 2006, Discovery reimbursed
Williams $4.5 million for direct payroll and employee
benefit costs, as well as $0.4 million for capitalized
labor costs, pursuant to the operating and maintenance
agreements and paid Williams $2.2 million for operation and
management fees, as well as a $0.5 million fee for managing
capitalized projects, pursuant to the operating and maintenance
agreements.
121
Four
Corners Purchase and Sale Agreements
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, on June 20, 2006, we acquired
a 25.1% membership interest in Four Corners for
$360.0 million. The conflicts committee of the board of
directors of our general partner recommended approval of the
acquisition of the 25.1% 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 paid by us to Williams
was fair, from a financial point of view, to us and our public
unitholders. In connection with the transactions contemplated by
the Purchase and Sale Agreement, we contributed the 25.1%
interest in Four Corners to our wholly owned subsidiary,
Williams Partners Operating LLC, on June 20, 2006.
On November 16, 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 LLC. Pursuant to
the Purchase and Sale Agreement, on December 13, 2006, we
acquired the remaining 74.9% membership interest in Four Corners
for $1.223 billion, subject to possible adjustment in our
favor. The conflicts committee of the board of directors of our
general partner recommended approval of our acquisition of the
remaining 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 was fair,
from a financial point of view, to us and our public
unitholders. In connection with the transactions contemplated by
the Purchase and Sale Agreement, we contributed the remaining
74.9% interest in Four Corners to Williams Partners Operating
LLC on December 13, 2006.
Natural
Gas and NGL Purchasing Contracts
Certain subsidiaries of Williams market substantially all of the
NGLs and excess natural gas to which Discovery, our Conway
fractionation and storage facility and our Four Corners system
take title. Discovery, our Conway fractionation and storage
facility and our Four Corners system conduct the sales of the
NGLs and excess natural gas to which they take title pursuant to
base contracts 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
confidentiality. Historically, the sales of natural gas and NGLs
to which Discovery, our Conway fractionation and storage
facility and our Four Corners system 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 our Four Corners system
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.
For the year ended December 31, 2006, we sold
$255.1 million of products to a subsidiary of Williams that
purchases substantially all of the NGLs and excess natural gas
to which our Conway fractionation and storage facility and our
Four Corners system take title based on market pricing, and
Discovery sold $148.4 million of NGLs to a subsidiary of
Williams that purchases substantially all of the NGLs and excess
natural gas to which Discovery takes title based on market
pricing.
Gathering,
Processing and Treating Contracts
We maintain 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, our Four Corners system gathers and treats coal seam
gas delivered by the affiliate to our Four Corners
gathering systems. Deliveries of gas under this agreement
averaged approximately 52 MMcf/d during 2006. The term of
this agreement expires on December 31, 2022, but will
continue thereafter on a
year-to-year
basis subject to termination by
122
either party giving at least six months written notice of
termination prior to the expiration of each one year period
Pursuant to gas gathering and processing contracts, our Four
Corners system gathers and processes conventional and coal seam
gas delivered by the affiliate to our Four Corners gathering
systems. Deliveries of gas under these agreements averaged
approximately 109 MMcf/d during 2006. The primary terms of
these agreements ended on March 1, 2004, but continue 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
$42.2 million in 2006.
Natural
Gas Purchases
We purchase 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. We
purchased approximately $78.2 million of natural gas for
fuel and shrink replacement from Williams Power Company during
2006.
Four Corners maintains a contract with two affiliates of
Williams, Williams Power Company, Inc. and Williams Flexible
Generation, LLC under which natural gas is supplied for
consumption at the co-generation plant. The co-generation plant
produces waste heat that assists in the operation of the Milagro
treating plant. During 2006, pursuant to a predecessor contract
that expired on December 31, 2006, Four Corners purchased
$23.1 million of natural gas from Williams Flexible
Generation, LLC. This contract was renegotiated with a term that
will expire on December 31, 2012, or when the companies are
no longer affiliated with each other, whichever occurs earlier.
For the year ended December 31, 2006 we purchased a gross
amount of $16.2 million of natural gas for our Conway
fractionator from an affiliate of Williams.
Balancing
Services Agreement
We maintain 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 us between certain points on our Four Corners
gathering system. We determine on a daily basis the volumes of
natural gas to be moved between gathering systems at established
interconnect points to optimize flow, an activity referred to as
crosshauling. Under the balancing services contract,
Williams Power Company purchases gas for delivery to customers
at certain plant outlets and sells such volumes at other
designated plant outlets to implement the crosshaul. These
purchase and sales transactions are conducted for us by Williams
Power Company at current market prices. Historically, Williams
Power Company has not charged a fee for providing this service,
but has occasionally benefited from price differentials that
historically existed from time to time between the designated
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 will expire
upon six months or more written notice of termination from
either party. To date, neither party has provided six months
notice to terminate the agreement.
Summary
of Other Transactions with Williams
For the year ended December 31, 2006:
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we distributed $15.0 million to affiliates of Williams as
quarterly distributions on their common units, subordinated
units, 2% general partner interest and incentive distribution
rights;
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we purchased $14.9 million of NGLs to replenish deficit
product positions from a subsidiary of Williams based on market
pricing; and
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123
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we previously sold electricity and capacity to Williams Power
Company at the Ignacio plant. The revenue from these sales
during 2006 were $0.4 million.
|
Review,
Approval or Ratification of Transactions with Related
Persons
Our partnership agreement contains specific provisions that
address potential conflicts of interest between our general
partner and its affiliates, including Williams, on one hand, and
the Partnership and its subsidiaries, on the other hand.
Whenever such a conflict of interest arises, our general partner
will resolve the 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, which is comprised of independent directors. The
partnership agreement provides that our general partner will not
be in breach of its obligations under the partnership agreement
or its duties to the Partnership or to unitholders if the
resolution of the conflict is:
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approved by the conflicts committee;
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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.
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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 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. See
Directors, Executive Officers and Corporate
Governance Governance Board
Committees Conflict Committee.
In addition, our code of business conduct and ethics requires
that all employees, including employees of affiliates of
Williams who perform services for us and our general partner,
avoid or disclose any activity that may interfere, or have the
appearance of interfering, with their responsibilities to us and
our unitholders. Conflicts of interest that cannot be avoided
must be disclosed to a supervisor who is then responsible for
establishing and monitoring procedures to ensure that we are not
disadvantaged.
Director
Independence
Please read Directors, Executive Officers and
Corporate Governance Governance Director
Independence above for information about the independence
of our general partners board of directors and its
committees, which information is incorporated herein by
reference in its entirety.
124
|
|
Item 14.
|
Principal
Accountant Fees and Services
|
Fees for professional services provided by our independent
auditors, Ernst & Young LLP, for each of the last two
fiscal years in each of the following categories are:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Audit Fees
|
|
$
|
1,459
|
|
|
$
|
1,624
|
|
Audit-Related Fees
|
|
|
|
|
|
|
|
|
Tax Fees
|
|
|
25
|
|
|
|
|
|
All Other Fees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,484
|
|
|
$
|
1,624
|
|
|
|
|
|
|
|
|
|
|
Fees for audit services in 2006 and 2005 include fees associated
with the annual audit, the reviews of our quarterly reports on
Form 10-Q,
and services provided in connection with other filings with the
SEC. Tax fees for 2006 include fees for review of our federal
tax return. The audit fees for 2006 and 2005 included in the
table above include $0.4 million for services provided in
connection with the acquisition of Four Corners and
$1.2 million for services rendered in connection with our
initial public offering, respectively.
The audit committee has established a policy regarding
pre-approval of all audit and non-audit services provided by
Ernst & Young LLP. On an ongoing basis, our general
partners management presents specific projects and
categories of service to our general partners audit
committee for which advance approval is requested. The audit
committee reviews those requests and advises management if the
audit committee approves the engagement of Ernst &
Young LLP. On a quarterly basis, the management of the general
partner reports to the audit committee regarding the services
rendered by, including the fees of, the independent accountant
in the previous quarter and on a cumulative basis for the fiscal
year. The audit committee may also delegate the ability to
pre-approve permissible services, excluding services related to
our internal control over financial reporting, to any two
committee members, provided that any such pre-approvals are
reported at a subsequent audit committee meeting. In 2006, 100%
of Ernst & Young LLPs fees were pre-approved by
the audit committee. The audit committees pre-approval
policy with respect to audit and non-audit services is provided
as an exhibit to this report.
PART IV
|
|
Item 15.
|
Exhibits
and Financial Statement Schedules
|
(a) 1 and 2. Williams Partners L.P. financials
|
|
|
|
|
|
|
Page
|
|
Covered by reports of independent
auditors:
|
|
|
|
|
|
|
|
75
|
|
|
|
|
76
|
|
|
|
|
77
|
|
|
|
|
78
|
|
|
|
|
79
|
|
Not covered by reports of
independent auditors:
|
|
|
|
|
Quarterly financial data
(unaudited)
|
|
|
102
|
|
125
All other schedules have been omitted since the required
information is not present or is not present in amounts
sufficient to require submission of the schedule, or because the
information required is included in the financial statements and
notes thereto.
(a) 3 and(b). The exhibits listed below are furnished or
filed as part of this annual report:
The exhibits listed below are filed as part of this annual
report:
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
*§Exhibit 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 (attached as
Exhibit 2.1 to Williams Partners L.P.s current report
on
Form 8-K
(File
No. 001-32599)
filed with the SEC on April 7, 2006.
|
|
*§Exhibit 2
|
.2
|
|
|
|
Purchase and Sale Agreement, dated
November 16, 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 (attached as
Exhibit 2.1 to Williams Partners L.P.s current report
on
Form 8-K
(File
001-32599)
filed with the SEC on November 21, 2006).
|
|
*Exhibit 3
|
.1
|
|
|
|
Certificate of Limited Partnership
of Williams Partners L.P. (attached as Exhibit 3.1 to
Williams Partners L.P.s registration statement on
Form S-1
(File
No. 333-124517)
filed with the SEC on May 2, 2005).
|
|
*Exhibit 3
|
.2
|
|
|
|
Certificate of Formation of
Williams Partners GP LLC (attached as Exhibit 3.3 to
Williams Partners L.P.s registration statement on
Form S-1
(File
No. 333-124517)
filed with the SEC on May 2, 2005).
|
|
+Exhibit 3
|
.3
|
|
|
|
Amended and Restated Agreement of
Limited Partnership of Williams Partners L.P. (including form of
common unit certificate), as amended by Amendments Nos. 1,
2 and 3.
|
|
*Exhibit 3
|
.4
|
|
|
|
Amended and Restated Limited
Liability Company Agreement of Williams Partners GP LLC
(attached as Exhibit 3.2 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on August 26, 2005).
|
|
*Exhibit 4
|
.1
|
|
|
|
Indenture, dated June 20,
2006, by and among Williams Partners L.P., Williams Partners
Finance Corporation and JPMorgan Chase Bank, N.A. (attached as
Exhibit 4.1 to Williams Partners L.P.s current report
on
Form 8-K
(File
No. 001-32599)
filed with the SEC on June 20, 2006).
|
|
*Exhibit 4
|
.2
|
|
|
|
Form of
71/2% Senior
Note due 2011 (included as Exhibit 1 to
Rule 144A/Regulation S Appendix of Exhibit 4.1
attached to Williams Partners L.P.s current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on June 20, 2006).
|
|
*Exhibit 4
|
.3
|
|
|
|
Registration Rights Agreement,
dated June 20, 2006, by and between Williams Partners L.P.,
Williams Partners Finance Corporation, Citigroup Global Markets
Inc. and Lehman Brothers Inc. (attached as Exhibit 4.3 to
Williams Partners L.P.s current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on June 20, 2006).
|
|
*Exhibit 4
|
.4
|
|
|
|
Certificate of Incorporation of
Williams Partners Finance Corporation (attached as
Exhibit 4.5 to Williams Partners L.P.s registration
statement on
Form S-3
(File
No. 333-137562)
filed with the SEC on September 22, 2006).
|
|
*Exhibit 4
|
.5
|
|
|
|
Bylaws of Williams Partners
Finance Corporation (attached as Exhibit 4.6 to Williams
Partners L.P.s registration statement on
Form S-3
(File
No. 333-137562)
filed with the SEC on September 22, 2006).
|
|
*Exhibit 4
|
.6
|
|
|
|
Indenture, dated December 13,
2006, by and among Williams Partners L.P., Williams Partners
Finance Corporation and The Bank of New York (attached as
Exhibit 4.1 to Williams Partners L.P.s current report
on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 19, 2006).
|
|
*Exhibit 4
|
.7
|
|
|
|
Form of
71/4% Senior
Note due 2017 (included as Exhibit 1 to
Rule 144A/Regulation S Appendix of Exhibit 4.1
attached to Williams Partners L.P. current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 19, 2006).
|
126
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
*Exhibit 4
|
.8
|
|
|
|
Registration Rights Agreement,
dated December 13, 2006, by and between Williams Partners
L.P., Williams Partners Finance Corporation, Citigroup Global
Markets Inc., Lehman Brothers Inc. and Merrill Lynch, Pierce,
Fenner & Smith Incorporated (attached as
Exhibit 4.3 to Williams Partners L.P.s current report
on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 19, 2006).
|
|
*Exhibit 4
|
.9
|
|
|
|
Registration Rights Agreement,
dated December 13, 2006, by and between Williams Partners
L.P. and the purchasers named therein (attached as
Exhibit 4.4 to Williams Partners L.P.s current report
on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 19, 2006).
|
|
*Exhibit 4
|
.10
|
|
|
|
Common Unit and Class B Unit
Purchase Agreement, dated December 1, 2006, by and among
Williams Partners L.P. and the purchasers names therein
(attached as Exhibit 1.1 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 4, 2006)
|
|
*Exhibit 10
|
.1
|
|
|
|
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. (attached as
Exhibit 10.1 to Williams Partners L.P.s current
report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on August 26, 2005).
|
|
*#Exhibit 10
|
.2
|
|
|
|
Williams Partners GP LLC Long-Term
Incentive Plan (attached as Exhibit 10.2 to Williams
Partners L.P.s current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on August 26, 2005).
|
|
*#Exhibit 10
|
.3
|
|
|
|
Amendment to the Williams Partners
GP LLC Long-Term Incentive Plan, dated November 28, 2006
(attached as Exhibit 10.1 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 4, 2006).
|
|
*Exhibit 10
|
.4
|
|
|
|
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.
(attached as Exhibit 10.3 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on August 26, 2005).
|
|
*Exhibit 10
|
.5
|
|
|
|
Amended and Restated Credit
Agreement dated as of May 20, 2005 among The Williams
Companies, Inc., Williams Partners L.P., Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation, and the
Banks, Citibank, N.A. and Bank of America, N.A., and Citicorp
USA, INC. as administrative agent (attached as Exhibit 1.1
to The Williams Companies, Inc.s current report on
Form 8-K
(File
No. 001-04174)
filed with the SEC on May 26, 2005).
|
|
*Exhibit 10
|
.6
|
|
|
|
Third Amended and Restated Limited
Liability Company Agreement for Discovery Producer Services LLC
(attached as Exhibit 10.7 to Amendment No. 1 to
Williams Partners L.P.s registration statement on
Form S-1
(File
No. 333-124517)
filed with the SEC on June 24, 2005).
|
|
*Exhibit 10
|
.7
|
|
|
|
Amendment No. 1 to Third
Amended and Restated Limited Liability Company Agreement for
Discovery Producer Services LLC (attached as Exhibit 10.6
to Williams Partners L.P.s quarterly report on
Form 10-Q
(File
No. 001-32599)
filed with the SEC on August 8, 2006).
|
|
*#Exhibit 10
|
.8
|
|
|
|
Director Compensation Policy dated
November 29, 2005 (attached as Exhibit 10.1 to
Williams Partners L.P.s current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 1, 2005).
|
|
*#Exhibit 10
|
.9
|
|
|
|
Form of Grant Agreement for
Restricted Units (attached as Exhibit 10.2 to Williams
Partners L.P.s current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 1, 2005).
|
127
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
*Exhibit 10
|
.10
|
|
|
|
Credit agreement dated as of
May 1, 2006 among Williams Partners L.P., The Williams
Companies, Inc., Northwest Pipeline Corporation,
Transcontinental Gas Pipeline Corporation, and Citibank, N.A.,
as administrative agent (attached as Exhibit 10.1 to The
Williams Companies, Incs current report on
Form 8-K
(File
No. 001-04174)
filed with the SEC on May 1, 2006).
|
|
*Exhibit 10
|
.12
|
|
|
|
Contribution, Conveyance and
Assumption Agreement, dated June 20, 2006, 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
(attached as Exhibit 10.1 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on June 20, 2006).
|
|
*Exhibit 10
|
.13
|
|
|
|
Contribution, Conveyance and
Assumption Agreement, dated June 20, 2006, by and among
Williams Field Services Company, LLC and Williams Four Corners
LLC (attached as Exhibit 10.4 to Williams Partners
L.P.s current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on June 20, 2006).
|
|
*Exhibit 10
|
.14
|
|
|
|
Amended and Restated Working
Capital Loan Agreement, dated August 7, 2006, between The
Williams Companies, Inc. and Williams Partners L.P. (attached as
Exhibit 10.7 to Williams Partners L.P.s quarterly
report on
Form 10-Q
(File
No. 001-32599)
filed with the SEC on August 8, 2006).
|
|
*Exhibit 10
|
.15
|
|
|
|
Contribution, Conveyance and
Assumption Agreement, dated December 13, 2006, 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
(attached as Exhibit 10.1 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 19, 2006).
|
|
+Exhibit 12
|
|
|
|
|
Computation of Ratio of Earnings
to Fixed Charges
|
|
+Exhibit 21
|
|
|
|
|
List of subsidiaries of Williams
Partners L.P.
|
|
+Exhibit 23
|
|
|
|
|
Consent of Independent Registered
Public Accounting Firm, Ernst & Young LLP.
|
|
+Exhibit 24
|
|
|
|
|
Power of attorney together with
certified resolution.
|
|
+Exhibit 31
|
.1
|
|
|
|
Rule 13a-14(a)/15d-14(a)
Certification of Chief Executive Officer.
|
|
+Exhibit 31
|
.2
|
|
|
|
Rule 13a-14(a)/15d-14(a)
Certification of Chief Financial Officer.
|
|
+Exhibit 32
|
|
|
|
|
Section 1350 Certifications
of Chief Executive Officer and Chief Financial Officer.
|
|
+Exhibit 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.
|
|
+Exhibit 99
|
.2
|
|
|
|
Williams Partners GP LLC Financial
Statements.
|
|
|
|
* |
|
Each such exhibit has heretofore been filed with the SEC as part
of the filing indicated and is incorporated herein by reference. |
|
+ |
|
Filed herewith. |
|
|
|
§ |
|
Pursuant to item 601(b) (2) of
Regulation S-K,
the registrant agrees to furnish supplementally a copy of any
omitted exhibit or schedule to the SEC upon request. |
|
# |
|
Management contract or compensatory plan or arrangement. |
128
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
Williams Partners L.P.
(Registrant)
|
|
|
|
By:
|
Williams Partners GP LLC,
|
its general partner
William H. Gault
Attorney-in-fact
Date: February 28, 2007
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
/s/ Steven
J. Malcolm*
Steven
J. Malcolm
|
|
President, Chief Executive Officer
and Chairman of the Board
(Principal Executive Officer)
|
|
February 28, 2007
|
|
|
|
|
|
/s/ Donald
R. Chappel*
Donald
R. Chappel
|
|
Chief Financial Officer and
Director (Principal Financial Officer)
|
|
February 28, 2007
|
|
|
|
|
|
/s/ Ted
T.
Timmermans*
Ted
T. Timmermans
|
|
Chief Accounting Officer and
Controller (Principal Accounting Officer)
|
|
February 28, 2007
|
|
|
|
|
|
/s/ Alan
S.
Armstrong*
Alan
S. Armstrong
|
|
Chief Operating Officer and
Director
|
|
February 28, 2007
|
|
|
|
|
|
/s/ Bill
Z. Parker*
Bill
Z. Parker
|
|
Director
|
|
February 28, 2007
|
|
|
|
|
|
/s/ Alice
M.
Peterson*
Alice
M. Peterson
|
|
Director
|
|
February 28, 2007
|
|
|
|
|
|
/s/ Thomas
C. Knudson*
Thomas
C. Knudson
|
|
Director
|
|
February 28, 2007
|
|
|
|
|
|
/s/ Phillip
D. Wright*
Phillip
D. Wright
|
|
Director
|
|
February 28, 2007
|
|
|
|
|
|
*By: /s/ William
H. Gault
William
H. Gault
Attorney-in-fact
|
|
|
|
February 28, 2007
|
129
INDEX TO
EXHIBITS
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
*§Exhibit 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 (attached as
Exhibit 2.1 to Williams Partners L.P.s current report
on
Form 8-K
(File
No. 001-32599)
filed with the SEC on April 7, 2006.
|
|
*§Exhibit 2
|
.2
|
|
|
|
Purchase and Sale Agreement, dated
November 16, 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 (attached as
Exhibit 2.1 to Williams Partners L.P.s current report
on
Form 8-K
(File
001-32599)
filed with the SEC on November 21, 2006).
|
|
*Exhibit 3
|
.1
|
|
|
|
Certificate of Limited Partnership
of Williams Partners L.P. (attached as Exhibit 3.1 to
Williams Partners L.P.s registration statement on
Form S-1
(File
No. 333-124517)
filed with the SEC on May 2, 2005).
|
|
*Exhibit 3
|
.2
|
|
|
|
Certificate of Formation of
Williams Partners GP LLC (attached as Exhibit 3.3 to
Williams Partners L.P.s registration statement on
Form S-1
(File
No. 333-124517)
filed with the SEC on May 2, 2005).
|
|
+Exhibit 3
|
.3
|
|
|
|
Amended and Restated Agreement of
Limited Partnership of Williams Partners L.P. (including form of
common unit certificate), as amended by Amendments Nos. 1,
2 and 3.
|
|
*Exhibit 3
|
.4
|
|
|
|
Amended and Restated Limited
Liability Company Agreement of Williams Partners GP LLC
(attached as Exhibit 3.2 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on August 26, 2005).
|
|
*Exhibit 4
|
.1
|
|
|
|
Indenture, dated June 20,
2006, by and among Williams Partners L.P., Williams Partners
Finance Corporation and JPMorgan Chase Bank, N.A. (attached as
Exhibit 4.1 to Williams Partners L.P.s current report
on
Form 8-K
(File
No. 001-32599)
filed with the SEC on June 20, 2006).
|
|
*Exhibit 4
|
.2
|
|
|
|
Form of
71/2% Senior
Note due 2011 (included as Exhibit 1 to
Rule 144A/Regulation S Appendix of Exhibit 4.1
attached to Williams Partners L.P.s current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on June 20, 2006).
|
|
*Exhibit 4
|
.3
|
|
|
|
Registration Rights Agreement,
dated June 20, 2006, by and between Williams Partners L.P.,
Williams Partners Finance Corporation, Citigroup Global Markets
Inc. and Lehman Brothers Inc. (attached as Exhibit 4.3 to
Williams Partners L.P.s current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on June 20, 2006).
|
|
*Exhibit 4
|
.4
|
|
|
|
Certificate of Incorporation of
Williams Partners Finance Corporation (attached as
Exhibit 4.5 to Williams Partners L.P.s registration
statement on
Form S-3
(File
No. 333-137562)
filed with the SEC on September 22, 2006).
|
|
*Exhibit 4
|
.5
|
|
|
|
Bylaws of Williams Partners
Finance Corporation (attached as Exhibit 4.6 to Williams
Partners L.P.s registration statement on
Form S-3
(File
No. 333-137562)
filed with the SEC on September 22, 2006).
|
|
*Exhibit 4
|
.6
|
|
|
|
Indenture, dated December 13,
2006, by and among Williams Partners L.P., Williams Partners
Finance Corporation and The Bank of New York (attached as
Exhibit 4.1 to Williams Partners L.P.s current report
on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 19, 2006).
|
|
*Exhibit 4
|
.7
|
|
|
|
Form of
71/4% Senior
Note due 2017 (included as Exhibit 1 to
Rule 144A/Regulation S Appendix of Exhibit 4.1
attached to Williams Partners L.P. current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 19, 2006).
|
|
*Exhibit 4
|
.8
|
|
|
|
Registration Rights Agreement,
dated December 13, 2006, by and between Williams Partners
L.P., Williams Partners Finance Corporation, Citigroup Global
Markets Inc., Lehman Brothers Inc. and Merrill Lynch, Pierce,
Fenner & Smith Incorporated (attached as
Exhibit 4.3 to Williams Partners L.P.s current report
on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 19, 2006).
|
130
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
*Exhibit 4
|
.9
|
|
|
|
Registration Rights Agreement,
dated December 13, 2006, by and between Williams Partners
L.P. and the purchasers named therein (attached as
Exhibit 4.4 to Williams Partners L.P.s current report
on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 19, 2006).
|
|
*Exhibit 4
|
.10
|
|
|
|
Common Unit and Class B Unit
Purchase Agreement, dated December 1, 2006, by and among
Williams Partners L.P. and the purchasers names therein
(attached as Exhibit 1.1 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 4, 2006)
|
|
*Exhibit 10
|
.1
|
|
|
|
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. (attached as
Exhibit 10.1 to Williams Partners L.P.s current
report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on August 26, 2005).
|
|
*#Exhibit 10
|
.2
|
|
|
|
Williams Partners GP LLC Long-Term
Incentive Plan (attached as Exhibit 10.2 to Williams
Partners L.P.s current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on August 26, 2005).
|
|
*#Exhibit 10
|
.3
|
|
|
|
Amendment to the Williams Partners
GP LLC Long-Term Incentive Plan, dated November 28, 2006
(attached as Exhibit 10.1 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 4, 2006).
|
|
*Exhibit 10
|
.4
|
|
|
|
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.
(attached as Exhibit 10.3 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on August 26, 2005).
|
|
*Exhibit 10
|
.5
|
|
|
|
Amended and Restated Credit
Agreement dated as of May 20, 2005 among The Williams
Companies, Inc., Williams Partners L.P., Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation, and the
Banks, Citibank, N.A. and Bank of America, N.A., and Citicorp
USA, INC. as administrative agent (attached as Exhibit 1.1
to The Williams Companies, Inc.s current report on
Form 8-K
(File
No. 001-04174)
filed with the SEC on May 26, 2005).
|
|
*Exhibit 10
|
.6
|
|
|
|
Third Amended and Restated Limited
Liability Company Agreement for Discovery Producer Services LLC
(attached as Exhibit 10.7 to Amendment No. 1 to
Williams Partners L.P.s registration statement on
Form S-1
(File
No. 333-124517)
filed with the SEC on June 24, 2005).
|
|
*Exhibit 10
|
.7
|
|
|
|
Amendment No. 1 to Third
Amended and Restated Limited Liability Company Agreement for
Discovery Producer Services LLC (attached as Exhibit 10.6
to Williams Partners L.P.s quarterly report on
Form 10-Q
(File
No. 001-32599)
filed with the SEC on August 8, 2006).
|
|
*#Exhibit 10
|
.8
|
|
|
|
Director Compensation Policy dated
November 29, 2005 (attached as Exhibit 10.1 to
Williams Partners L.P.s current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 1, 2005).
|
|
*#Exhibit 10
|
.9
|
|
|
|
Form of Grant Agreement for
Restricted Units (attached as Exhibit 10.2 to Williams
Partners L.P.s current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 1, 2005).
|
|
*Exhibit 10
|
.10
|
|
|
|
Credit agreement dated as of
May 1, 2006 among Williams Partners L.P., The Williams
Companies, Inc., Northwest Pipeline Corporation,
Transcontinental Gas Pipeline Corporation, and Citibank, N.A.,
as administrative agent (attached as Exhibit 10.1 to The
Williams Companies, Incs current report on
Form 8-K
(File
No. 001-04174)
filed with the SEC on May 1, 2006).
|
131
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
*Exhibit 10
|
.12
|
|
|
|
Contribution, Conveyance and
Assumption Agreement, dated June 20, 2006, 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
(attached as Exhibit 10.1 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on June 20, 2006).
|
|
*Exhibit 10
|
.13
|
|
|
|
Contribution, Conveyance and
Assumption Agreement, dated June 20, 2006, by and among
Williams Field Services Company, LLC and Williams Four Corners
LLC (attached as Exhibit 10.4 to Williams Partners
L.P.s current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on June 20, 2006).
|
|
*Exhibit 10
|
.14
|
|
|
|
Amended and Restated Working
Capital Loan Agreement, dated August 7, 2006, between The
Williams Companies, Inc. and Williams Partners L.P. (attached as
Exhibit 10.7 to Williams Partners L.P.s quarterly
report on
Form 10-Q
(File
No. 001-32599)
filed with the SEC on August 8, 2006).
|
|
*Exhibit 10
|
.15
|
|
|
|
Contribution, Conveyance and
Assumption Agreement, dated December 13, 2006, 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
(attached as Exhibit 10.1 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 19, 2006).
|
|
+Exhibit 12
|
|
|
|
|
Computation of Ratio of Earnings
to Fixed Charges
|
|
+Exhibit 21
|
|
|
|
|
List of subsidiaries of Williams
Partners L.P.
|
|
+Exhibit 23
|
|
|
|
|
Consent of Independent Registered
Public Accounting Firm, Ernst & Young LLP.
|
|
+Exhibit 24
|
|
|
|
|
Power of attorney together with
certified resolution.
|
|
+Exhibit 31
|
.1
|
|
|
|
Rule 13a-14(a)/15d-14(a)
Certification of Chief Executive Officer.
|
|
+Exhibit 31
|
.2
|
|
|
|
Rule 13a-14(a)/15d-14(a)
Certification of Chief Financial Officer.
|
|
+Exhibit 32
|
|
|
|
|
Section 1350 Certifications
of Chief Executive Officer and Chief Financial Officer.
|
|
+Exhibit 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.
|
|
+Exhibit 99
|
.2
|
|
|
|
Williams Partners GP LLC Financial
Statements.
|
|
|
|
* |
|
Each such exhibit has heretofore been filed with the SEC as part
of the filing indicated and is incorporated herein by reference. |
|
+ |
|
Filed herewith. |
|
§ |
|
Pursuant to item 601(b) (2) of
Regulation S-K,
the registrant agrees to furnish supplementally a copy of any
omitted exhibit or schedule to the SEC upon request. |
|
# |
|
Management contract or compensatory plan or arrangement. |
132