e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
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, 2007
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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
(State or Other Jurisdiction
of
Incorporation or Organization)
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20-2485124
(IRS Employer
Identification No.)
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One Williams Center, Tulsa, Oklahoma
(Address of Principal
Executive Offices)
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74172-0172
(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 þ No o
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, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the Exchange Act. (Check one):
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Large accelerated filer
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Accelerated filer
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Non-accelerated
filer o
(Do not check if a smaller reporting company)
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Smaller Reporting
company o
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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 $1,498,921,254. This figure
excludes common units beneficially owned by the directors and
executive officers of Williams Partners GP LLC, our general
partner.
The registrant had 52,774,728 common units outstanding as of
February 26, 2008.
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.
Dth: One dekatherm.
¢/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
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Items 1
and 2.
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Business
and Properties
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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 Wamsutter LLC
(Wamsutter) and Discovery Producer Services LLC (Discovery) in
which we own interests accounted for as equity investments that
are not consolidated in our financial statements. When we refer
to Wamsutter or Discovery by name, we are referring exclusively
to their 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 (the Exchange Act). From time-to-time, we
may also file registration and related statements
and/or
prospectuses or prospectus supplements 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.
Our Internet website is
http://www.williamslp.com.
We make available free of charge on or through our Internet
website 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. (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. This segment includes a 100% interest in
Williams Four Corners LLC (Four Corners) and ownership interests
in Wamsutter, consisting of (i) 100% of the Class A
limited liability company membership interests and (ii) 50%
of the initial Class C units (or 20 Class C units)
representing limited liability company membership interests in
Wamsutter (together, the Wamsutter Ownership Interests). Four
Corners owns a 4,200-mile natural gas gathering system,
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including three natural gas processing plants and two natural
gas treating plants, located in the San Juan Basin in
Colorado and New Mexico. Wamsutter owns an approximate
1,700-mile natural gas gathering system, including a natural gas
processing plant, located in the Washakie Basin in Wyoming. The
Four Corners and Wamsutter 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. This segment includes our equity investment
in Discovery and the Carbonate Trend gathering pipeline. We own
a 60% interest in 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 plant and a natural
gas liquids fractionator in Louisiana. Our Carbonate Trend
gathering pipeline is an unregulated sour gas gathering 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. This 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 the Wamsutter Ownership Interests and our 60%
interest in Discovery as equity investments and, therefore, do
not consolidate their financial results.
Our assets were owned by Williams prior to the initial public
offering (IPO) of our common units in August 2005, our
acquisition of Four Corners in 2006, our acquisition of an
additional 20% ownership percentage of Discovery in 2007 and our
acquisition of the Wamsutter Ownership Interests in 2007.
Williams indirectly owns an approximate 21.6% limited
partnership interest in us and all of our 2% general partner
interest.
Williams is an integrated energy company with 2007 revenues in
excess of $10.5 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
Conversion of Subordinated Units. On
January 28, 2008, our general partners board of
directors confirmed that the financial test contained in our
partnership agreement required for conversion of all of our
outstanding subordinated units into common units had been
satisfied. Accordingly, our 7,000,000 subordinated units held by
four subsidiaries of Williams converted into common units on a
one-for-one basis on February 19, 2008.
Acquisition of Wamsutter Ownership
Interests. On December 11, 2007, we acquired
the Wamsutter Ownership Interests from Williams for aggregate
consideration of $750.0 million. The acquisition was
financed as follows:
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Issuance of Common Units. We sold 9,250,000
common units in an underwritten public offering for $37.75 per
common unit. We received net proceeds of approximately
$335.2 million from the sale of the common units after
deducting underwriting discounts but before estimated offering
expenses. On January 9, 2008, we sold an additional 800,000
common units to the underwriters upon the underwriters
partial exercise of their option to purchase additional common
units.
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Issuance of Common Units to Williams. We
issued approximately $157.2 million of common units, or
4,163,527 common units, to Williams at a price per common unit
of $37.75. On January 9, 2008, we used the net proceeds
from the partial exercise of the underwriters option to
redeem 800,000 common units from Williams at a price per common
unit of $36.24 ($37.75, net of underwriter discount).
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Increase in General Partners Capital
Account. Our general partner contributed
approximately $10.3 million to allow it to maintain its 2%
general partner interest.
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Term Loan. We borrowed $250.0 million
under the term loan provisions of our new credit facility
discussed below.
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Williams Partners L.P.s. New Credit
Facility. We entered into a $450.0 million
five-year senior unsecured credit facility comprised initially
of a $250.0 million term loan used to finance a portion of
the aggregate consideration for the Wamsutter Ownership
Interests and a $200.0 million revolving credit facility,
which is available for borrowings and letters of credit. On
November 21, 2007, we were removed as a borrower under
Williams $1.5 billion revolving credit facility and,
therefore, no longer have access to $75.0 million borrowing
capacity under that facility.
Wamsutters $20.0 million revolving credit
facility. Prior to our acquisition of the
Wamsutter Ownership Interests, Wamsutter entered into a
$20.0 million revolving credit facility with Williams as
the lender. This facility is available to fund working capital
requirements and for other purposes. Any borrowings under the
facility will mature on December 9, 2008.
Ignacio gas processing plant fire. On
November 28, 2007, there was a fire at the Ignacio gas
processing plant. This fire resulted in severe damage to the
facilitys cooling tower, control room, adjacent warehouse
buildings and control systems. The plant was shut down from
November 28 to January 18, 2008. There were no injuries as
a result of this incident and the plant now has full cryogenic
recovery and fractionation facilities in operation.
Additional Investment in Discovery. On
June 28, 2007, we acquired an additional 20% limited
liability company interest in Discovery from Williams for
aggregate consideration of $78.0 million.
Conversion of Class B Units. On
May 21, 2007, our outstanding Class B units were
converted into common units on a one-for-one basis by a majority
vote of common units eligible to vote.
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 and Wamsutter Ownership
Interests.
Four
Corners General
The Four Corners assets include:
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A 4,200-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
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treating services accounted for approximately 69% of our Four
Corners total revenue less its product cost and shrink
replacement costs and expenses for the year ended
December 31, 2007. The remaining 31% of Four Corners
total revenues less product cost and shrink replacement for the
year ended December 31, 2007 was derived from the sale of
NGLs received as consideration for processing services.
For the year ended December 31, 2007, 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 formations with approximately 60% coming from
coal bed formations. We are currently the only company 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.
Four
Corners Natural Gas Gathering System
Our Four Corners natural gas gathering pipeline system consists
of:
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4,200 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 gathering pipeline systems. 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.
Four
Corners Processing and Treating Plants
Natural
Gas Processing Plants
Our Four Corners assets include 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 natural 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, Public Service Company
of New Mexico (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.
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Treating
Plants
Coal bed methane gas typically contains high levels of carbon
dioxide that must be reduced to 2% or less for transportation
through pipelines to end markets. Our Four Corners assets
include 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 Customers and Contracts
Customers. One producer customer,
ConocoPhillips, accounted for approximately 53% of Four
Corners total gathered volumes and 24% of its total
revenues for the year ended December 31, 2007. Four
Corners total revenues are comprised of product sales and
fee-based gathering, processing, and treating revenues. With
respect to total revenues, a subsidiary of Williams, to which we
sell at market prices substantially all of the NGLs we retain
under our keep-whole and percent-of-liquids processing
contracts, accounted for approximately 52% of Four Corners
total revenues for the year ended December 31, 2007.
However, all of the NGLs sold to the subsidiary of Williams are
derived from our processing of producer customers natural
gas. 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.
Contracts. Gathering, processing and treating
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. Gathering
and treating services are generally provided pursuant to
fee-based contracts. These revenues are based on the volumes
gathered and the associated
per-unit
fee. 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 extracted during processing with
natural gas purchases, also known as shrink replacement gas and
(4) deliver an equivalent Btu content of natural gas for
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, 2007, 36% of Four Corners 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, 2007, 12% of Four
Corners 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, 2007, 14% of Four Corners
processing volumes were under fee-based contracts.
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Fee-based and keep-whole. These contracts have
both a
per-unit fee
component and a keep-whole component. The relative proportions
of the fee component and the keep-whole component vary from
contract to contract, with the keep-whole component never
consisting of more than 50% of the total extracted NGLs. For the
year ended December 31, 2007, 38% of the Four Corners
processing volumes were under these fee-based and keep-whole
contracts.
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We do not take title to gas as payment for services, other than
for the reimbursement of gas used or lost during the gathering,
processing or treating of natural gas.
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Four
Corners Competition
Our Four Corners system competes with other gathering,
processing and treating options available to producers in the
San Juan Basin. The Enterprise system is comprised of
approximately 5,400 miles of gathering lines and two
processing plants, one owned by Enterprise and the other by two
large producers. Enterprise owns and operates primarily
conventional natural gas gathering and processing facilities in
the San Juan Basin. The Red Cedar system consists of
approximately 800 miles of gathering lines, and is a joint
venture between the Southern Ute Indian tribe and Kinder Morgan
Energy Partners. The Texas Eastern Products Pipeline Company
(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.
Four
Corners Gas Supply
Our contracts with major customers contain certain production
dedications whereby natural gas produced from a particular area
and/or group
of receipt points flows 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. For Four Corners, 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,
processed and treated volumes or even temporarily 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.
Wamsutter
General
We own the Wamsutter Ownership Interests and account for this
investment under the equity method of accounting due to the
voting provisions of Wamsutters limited liability company
agreement which provide the other member of Wamsutter, Williams,
significant participatory rights such that we do not control the
investment. Wamsutter owns:
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an approximate 1,700-mile natural gas gathering system in the
Washakie Basin, which is located in south-central Wyoming, that
currently connects approximately 1,720 wells, with a
typical operating capacity of approximately
500 MMcf/d
at current operating pressures; and
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the Echo Springs natural gas processing plant in Sweetwater
County, Wyoming, which has
390 MMcf/d
of inlet cryogenic processing capacity and NGL production
capacity of 30,000 bpd.
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Wamsutters customers are primarily natural gas producers
in the Washakie Basin. Wamsutter provides its customers with a
broad range of gathering and processing services. Fee-based
gathering and processing services accounted for approximately
53% of Wamsutters total revenues less related product
costs for the year ended December 31, 2007. The remaining
47% of Wamsutters total revenues less related product
costs for the year ended December 31, 2007 were derived
primarily from the sale of NGLs received by Wamsutter as
consideration for processing services.
The Wamsutter pipeline system gathers approximately 69% of the
natural gas produced in the Washakie Basin and connects with
four natural gas pipeline systems that transport natural gas to
end markets from the basin.
Wamsutter
Natural Gas Gathering System
The Wamsutter natural gas gathering pipeline system consists of:
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Approximately 1,700 miles of
2-inch to
20-inch
diameter natural gas gathering pipelines with approximately
1,720 wells currently connected and
450 MMcf/d
in gathered volumes; and
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Wamsutters 13 operating gathering compression units that
provide approximately 41,000 horsepower of gathering compression.
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Wamsutter
Processing Plant
Wamsutters Echo Springs natural gas processing plant was
constructed in 1994 and is located in Sweetwater County,
Wyoming. The primary processing components of the Echo Springs
plant were installed in 1994 and were subsequently upgraded and
expanded in 1996 and 2001. The Echo Springs plant has three
cryogenic trains with 28,900 horsepower of compression,
processing capacity of
390 MMcf/d
and NGL production capacity of 30,000 bpd. The Echo Springs
plant has pipeline outlet connections to Wyoming Interstate
Company, Colorado Interstate Gas Company, Southern Star Central
Gas Pipeline and Rockies Express, which transport natural gas to
end markets in the Mid-Continent and Western United States from
the Washakie Basin. The Echo Springs plant also connects to
MAPL, which transports NGLs to the Mid-Continent and Gulf Coast.
We expect that in 2008 the plant will have access to the
Overland Pass Pipeline, which will transport NGLs to the
Mid-Continent. The Echo Springs plant is able to recover
approximately 80% of the ethane contained in the natural gas
stream and nearly all of the propane and heavier NGLs.
The Echo Springs plant is currently operating at capacity with
gas in excess of capacity being bypassed around the plant. When
gas is bypassed around the plant, Wamsutter does not recover all
of the NGLs available from the gas. In order to capture some of
the value attributable to these NGLs, Wamsutter has entered into
an agreement with Colorado Interstate Gas Rawlins natural
gas processing plant to process up to
80 MMcf/d
of gas in excess of Wamsutters processing capacity from
the Wamsutter gathering system. This connection to the Rawlins
plant will increase the total processing capacity available to
Wamsutter by
80 MMcf/d,
or approximately 20%.
Wamsutter is planning to expand its processing capacity to
accommodate volumes of natural gas committed to Wamsutter.
Wamsutter expects this expansion to be completed before the end
of 2011. We expect Wamsutters Class B member, owned
by Williams, will fund this project.
Wamsutter
Customers and Contracts
For Wamsutter, six producer customers, BP, Anadarko Petroleum
Corporation, Devon Energy Corporation, Marathon Oil Corporation,
Samson Resources Company and EnCana Corporation, accounted for
approximately 92% of Wamsutters total gathered volumes for
the year ended December 31, 2007. With respect to total
revenues, a subsidiary of Williams, to which Wamsutter sells at
market prices substantially all of the NGLs it retains under
keep-whole contracts, accounted for approximately 56% of
Wamsutters total revenues for the year ended
December 31, 2007. Although this revenue is identified as
sales to a subsidiary of Williams, all of the NGLs sold to the
subsidiary of Williams are derived from the processing of
producer customers natural gas.
Wamsutter provides its customers with a broad range of gathering
and processing 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.
Wamsutter has a portfolio of natural gas processing agreements
that include fee-based and keep-whole contracts. The terms of
these agreements are consistent with those described for Four
Corners. For the year ended December 31, 2007, Wamsutter
processed 75% and 25% of its processing volumes under fee-based
and keep-whole contracts, respectively. Under a contract with
one of Wamsutters significant customers, Wamsutter has
agreed to limit its margins on NGLs (other than ethane) to $0.25
per gallon, with the balance above $0.25 per gallon accruing to
the customer. Effective January 1, 2007, one of
Wamsutters significant customers made an election to
switch from a keep-whole processing arrangement to a fee-based
processing arrangement for three years, which significantly
decreased the NGL volumes received by Wamsutter.
Approximately 80% of the current gathering and processing
volumes on the Wamsutter system are subject to contracts with
terms of eight years or longer. All of Wamsutters
gathering contracts are fee-based. Wamsutter generally charges a
fee on the volume of natural gas gathered on its gathering
pipeline system. Wamsutter does not take title to the natural
gas that it gathers other than natural gas it retains for fuel
and purchases for shrinkage.
7
Wamsutter
Competition
Wamsutter has three primary competitors. Anadarkos Patrick
Draw and Red Desert facilities compete for both gathering and
processing volumes. The Patrick Draw processing plant has
150 MMcf/d
of cryogenic processing capacity and the Anadarko Red Desert
plant has
40 MMcf/d
of cryogenic processing capacity. The Colorado Interstate Gas
Rawlins plant has
250 MMcf/d
of lean oil processing capacity. The Rawlins plant is a
regulated facility that is part of the Colorado Interstate Gas
interstate pipeline system. The Rawlins plants primary
purpose is to process the gas in the Colorado Interstate Gas
pipeline system before natural gas is transported east to Front
Range markets in Colorado.
Wamsutter
LLC Agreement
Overview
We own the Wamsutter Ownership Interests previously described
and Williams owns 100% of the Class B limited liability
company membership interests and the remaining 50% of the
initial Class C units in Wamsutter that we do not own.
Wamsutter is obligated to issue additional Class C units
based on future capital contributions that the Class A
member and the Class B member are obligated or permitted to
make in the circumstances described below.
Cash
Distribution Policy
The Wamsutter LLC Agreement provides for distributions of
available cash to be made quarterly, with available cash defined
as Wamsutters cash on hand at the end of a distribution
period less reserves that are necessary or appropriate to
provide for the conduct of its business and to comply with
applicable law, debt instruments or other agreements to which it
is a party. We expect that Wamsutter will fund its maintenance
capital expenditures through its cash flows from operations.
Williams, as the Class B member, has the discretion to
establish the reserves necessary for Wamsutter, including the
amount set aside for maintenance capital expenditures and thus
can influence the amount of available cash.
Wamsutter will distribute its available cash as follows:
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First, an amount equal to $17.5 million per quarter to us
as the holder of the Class A membership interests;
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Second, an amount equal to the amount the distribution to us as
the Class A membership interests in prior quarters of the
current distribution year was less than $17.5 million per
quarter to the holder of the Class A membership
interests; and
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Third, 5% of remaining available cash shall be distributed to us
as the holder of the Class A membership interests, and 95%
shall be distributed to the holders of the Class C units,
on a pro rata basis.
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In addition, to the extent that at the end of the fourth quarter
of a distribution year, we as the Class A member have
received less than $70.0 million under the first and second
bullets above, the Class C members will be required to
repay, pro rata, any distributions they received in that
distribution year such that we as the Class A member
receive $70.0 million for that distribution year. If this
repayment is insufficient to result in us as the Class A
member receiving $70.0 million, the shortfall will not
carry forward to the next distribution year. The initial
distribution year commenced on December 1, 2007 and ends on
November 30, 2008. Subsequent distribution years for
Wamsutter will commence on December 1 and end on
November 30.
Additionally, each month during fiscal years 2008 through 2012,
the Class B member is obligated to pay to Wamsutter a
transition support payment in an amount equal to the amount by
which Wamsutters general and administrative expenses
exceed a monthly cap. Any such amounts received from the
Class B member will be distributed to the holder of the
Class A membership interests, which is us, but will not be
counted for purposes of determining whether or not Wamsutter has
distributed the $70.0 million in aggregate annual
distributions as described above. The Class B members will
not be issued any Class C units as a result of making a
transition support payment.
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We will be allocated net income by Wamsutter based upon the
allocation and distribution provisions of their LLC Agreement.
In general, the agreement allocates income to the Class A,
B and C ownership interests in a manner that will maintain
capital account balances reflective of the amounts each
ownership interest would receive if Wamsutter were dissolved and
liquidated at carrying value. In general, pursuant to those
provisions, income allocations follow the provisions of the LLC
agreement for the distribution of available cash.
Capital
Investments
If Wamsutter elects to make a growth capital investment in an
amount less than $2.5 million, we as the Class A
member are obligated to make a capital contribution to Wamsutter
in an amount necessary to fund such growth capital investment.
If Wamsutter elects to make a growth capital investment in an
amount equal to or greater than $2.5 million, Williams as
the Class B member is obligated to make a capital
contribution to Wamsutter in an amount necessary to fund such
growth capital investment. Wamsutter will issue to the
contributing member one Class C unit for each $50,000
contributed by it. Wamsutter will issue fractional Class C
units as necessary. A growth capital investment is any
investment other than a maintenance capital investment or a
growth well connection investment.
In addition, starting in 2009, Wamsutter will calculate the
growth well connection investments it has made in the fiscal
year immediately concluded. The Class B member is obligated
to make a capital contribution to Wamsutter in an amount
necessary to fund such growth well connection investments.
Growth well connection investments are investments made over a
one-year period for well connections that Wamsutter expects will
more than offset the estimated decline in its throughput volumes
over that period. The Class B member will receive one
Class C unit for each $50,000 contributed by such member
for these growth well connection investments.
Governance
Most decisions regarding Wamsutters day to day operations
are made by Williams, in its capacity as the owner of the
Class B membership interests. However, certain decisions
require our consent as owner of the Class A membership
interests. Because of these governance provisions, we do not
control Wamsutter; hence, we account for our interest in
Wamsutter as an equity method investment, and do not consolidate
its financial results.
Gathering
and Processing Gulf
Our Gathering and Processing Gulf segment is
comprised of our 60% interest in Discovery and the Carbonate
Trend gathering pipeline.
Discovery
General
We own a 60% interest in Discovery and account for this
investment under the equity method of accounting due to the
voting provisions of Discoverys limited liability company
agreement which provide the other member of Discovery
significant participatory rights such that we do not control the
investment. Discovery 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 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; and
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a fractionator in Paradis, Louisiana.
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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.
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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 is located in the offshore
Louisiana Outer Continental Shelf at Ewing Bank 873. The
mainline extends northerly to the Larose gas processing plant
near Larose, Louisiana. Producers have dedicated their
production from approximately 60 offshore blocks to Discovery.
The mainline has a FERC-certificated capacity of approximately
600 MMcf/d.
The Discovery system connects to six natural gas pipeline
systems: the Bridgeline system, the Texas Eastern Pipeline
system, the Gulfsouth system, the Tennessee Gas Pipeline system,
the Columbia Gulf Transmission system and the Transcontinental
Gas Pipe Line system (Transco). Discoverys
interconnections allow producers to benefit from flexible and
diversified access to a variety of natural gas markets from the
Gulf of Mexico to the eastern United States.
Shallow Water/Onshore Gathering. Discovery
also owns shallow water and onshore gathering assets that
consist of:
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90 miles of offshore laterals with connections to the
mainline. The FERC regulates 60 miles of these 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 two
production handling facilities; and
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a five-mile
onshore gathering lateral 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 consist of 73 miles of gathering
laterals that extend to deepwater producing areas in the Gulf of
Mexico such as the Morpeth prospect, Allegheny prospect and
Front Runner prospect. Additionally, Discovery has signed
definitive agreements with Chevron Corporation, Royal Dutch
Shell plc and StatoilHydro ASA 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.
In October 2007, Chevron announced that it will face delays
because of metallurgical problems discovered in the
facilitys mooring shackles and that it does not expect
first production to commence until the third quarter of 2009.
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. 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%.
Paradis
Fractionation Facility
The fractionator is located onshore near Paradis, Louisiana. The
fractionator and a
22-mile
mixed NGL pipeline connecting it to the Larose processing plant
went into service in January 1998. The Paradis fractionator is
designed to fractionate 32,000 bpd of mixed NGLs and is
expandable to 42,000 bpd. All products can be delivered
through the Chevron TENDS NGL pipeline system, and propane and
heavier products may be transported by truck or railway.
10
Discovery fractionates NGLs for third party customers and for
itself and typically 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 at market prices and reselling them to end-users.
Discovery
Management
Currently, Discovery is owned 60% by us and 40% by DCP Assets
Holding, LP. Discovery is managed by a two-member management
committee consisting of representation from each of the two
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 at market prices substantially all of
the NGLs and excess natural gas to which Discovery takes title,
accounted for approximately 83% of Discoverys revenues for
the year ended December 31, 2007. This amount includes the
sales of NGLs received under processing contracts with producer
customers and 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. Discoverys customers are
primarily offshore natural gas producers. Discovery provides
these customers with wellhead to market delivery
options by offering a full range of services including
gathering, transportation, processing and fractionation.
Discovery also has the ability to provide its customers with
other specialized services, such as offshore production
handling, condensate separation and stabilization and
dehydration. For the year ended December 31, 2007, 44% of
Discoverys total revenues less related product costs
related to Discoverys top three offshore natural gas
producer customers.
In October 2006, Discovery signed a one-year contract with Texas
Eastern Transmission Company (TETCO) that was subsequently
extended through March 31, 2008. The TETCO agreement was
recently extended through May 2008 at which time we expect no
further volumes under this agreement. In the fourth quarter of
2007, Discovery began contracting significant volumes from the
Tennessee Gas Pipeline system (TGP) and expects to expand during
2008 as the TETCO contract expires. Discovery is currently
transporting TGP volumes of approximately 170 BBtu/d under
month-to-month keep-whole contracts and expects to contract a
substantial portion of this gas under longer-term
percent-of-liquids or fee-based arrangements. For the year ended
December 31, 2007, 15% of Discoverys total revenues
less related product costs related to TETCO.
Contracts. Discoverys wholly owned
subsidiary, Discovery Gas Transmission (DGT), 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, DGT has the
authority to negotiate a specific rate arrangement with an
individual shipper and has several of these arrangements
currently in effect.
In November 2007, DGT filed a settlement at FERC which would
increase the maximum regulated rate for mainline transportation,
market expansion and jurisdictional gathering. Please read
FERC Regulation.
Discoverys portfolio of processing contracts includes the
following types of contracts:
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Fee-based. Under fee-based contracts,
Discovery receives revenue based on the volume of natural gas
processed and the
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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Keep-whole contracts. Under keep-whole
contracts, Discovery pays a fee to the customer to process their
gas and Discovery receives all of the extracted NGLs. Discovery
also sells these NGLs to a subsidiary of Williams at market
prices and replaces the shrink removed from the gas stream. The
term of these contracts are typically less than one year in
length.
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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.
Operation
and Contract Optimization
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. In 2007, Discovery connected
Energy Partners ST 46 and Mariners ST 288 blocks and
received significant volumes from the Tennessee system from
multiple shippers. In February 2008, Discovery executed
agreements with LLOG Exploration Company to provide production
handling, transportation, processing and fractionation
12
services for their MC 705 and 707 production. Also in February
2008, Discovery executed agreements with ATP to provide
services, beginning in 2009, related to their production from MC
941 942 and AT 63. ATP has also added four new blocks related to
their existing MC 711 production. 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 (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
Hurricane Katrinas emergency connections to TETCO and TGP
have continued to flow gas throughout 2007. Discovery entered 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. This contract was
recently extended through May 2008 with a minimum volume of 150
BBtu/d. Additionally, as noted earlier, Discovery is currently
contracting on a monthly basis approximately 170 BBtu/d of gas
from TGP.
Carbonate
Trend Pipeline General
Our Carbonate Trend gathering pipeline is a sour gas gathering
pipeline consisting of approximately 34 miles of pipeline
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, 2007, our average
transportation volume was approximately
22 MMcf/d.
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. For the year ended
December 31, 2007, volumes from Chevron leases represented
approximately 69% of Carbonate Trends total throughput and
74% of Carbonate Trends total revenue.
Contracts. We have long-term transportation
agreements with Chevron and Beryl Resources LP (Beryl). Pursuant
to these agreements, Chevron and Beryl have agreed to transport
on our pipeline all gas produced on their 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 Beryl expire or the underlying
reserves are depleted, Chevron and Beryl 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. We have the option to
terminate these
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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 sour gas gathering
pipelines.
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. Smaller producers are now entering the
area which could result in the discovery of additional amounts
of gas.
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 three
end-use interstate NGL pipelines: MAPL, NuStar and the Oneok
North System (formerly Kinder Morgan) pipeline. We also, through
connections of less than a mile, indirectly interconnect to an
additional end-use interstate NGL pipeline: the ONEOK pipeline.
Through these pipelines and other storage facilities we can
provide our customers interconnectivity to additional interstate
NGL pipelines. We believe that the attributes of our storage
facilities, such as the number and size of our caverns and well
bores and our extensive brine system, coupled with our direct
connectivity to MAPL through multiple meters allows our
customers to inject, withdraw and deliver all of their products
stored in our facilities more rapidly than products stored with
our competitors.
Conway West. The Conway West facility located
adjacent to the Conway fractionation facility in McPherson
County, Kansas is our primary storage facility. This facility
has an aggregate storage capacity of approximately ten million
barrels.
Conway East. The Conway East facility is
located approximately four miles east of the Conway West
facility in McPherson County, Kansas. The Conway East facility
has an aggregate storage capacity of approximately five million
barrels. The Conway East facility also has an active truck
loading and unloading facility, each with two spots, and a rail
loading and unloading facility with 20 spots.
Mitchell. The Mitchell facility is located
approximately 14 miles west of the Conway West facility in
Rice County, Kansas and has an aggregate storage capacity of
approximately five million barrels.
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Conway
Storage 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 Oneok North System
pipeline. Other competitors include a ONEOK-owned facility 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. 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 Oneok North System pipeline,
NuStar 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.
These product sales and purchases are completed with a
subsidiary of Williams. If this arrangement with the Williams
subsidiary were terminated, we believe we could make these
product sales and purchases through 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 Buckeye 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 and ONEOK own 40% and 10%
undivided interests, respectively. 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.
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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.
Conway
Fractionation 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, a ONEOK-owned fractionator located in
Bushton, Kansas and an Enterprise-owned fractionator located in
Hobb, Texas. 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.
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 Buckeye 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. We are
currently analyzing the feasibility of processing volumes
sourced through connections to Overland Pass Pipeline, which
will originate in Wyoming and flow into the Mid-Continent.
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 33% of our segment revenues in 2007.
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.
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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.
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. We generally enter into fractionation contracts that
cover portions of our remaining capacity at the Conway facility
for periods of one year or less.
Safety
and Maintenance
Certain of our natural gas pipelines are subject to regulation
by, among others, the United States Department of Transportation
(DOT) under the Accountable Pipeline and Safety Partnership Act
of 1996 (often referred to as the Hazardous Liquid Pipeline
Safety Act) and comparable state statutes with respect to
design, installation, testing, construction, operation,
replacement and management. These statutes require access to and
copying of records and the filing of certain reports and 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. 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 anticipate incurring costs of
approximately $0.8 million in 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.
We implement continuous inspection and compliance programs
designed to keep our facilities in most efficient operating
condition and to ensure compliance with pipeline safety and
pollution control requirements. For example, our Carbonate Trend
pipeline undergoes a corrosion control program that both
protects the integrity of the pipeline and prolongs its life.
The corrosion control program consists of continuous monitoring
and injection of corrosion inhibitor into the pipeline, periodic
chemical treatments and annual detailed
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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.
We are also 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 United States
Environmental Protection Agency (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 some of the entities in which we own an
interest are also subject to OSHA Process Safety Management
regulations, which are designed to prevent or minimize the
consequences of catastrophic releases of toxic, reactive,
flammable or explosive chemicals. These regulations, with a few
exemptions, 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. 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 an interstate pipelines rates be just
and reasonable and not unduly discriminatory or
preferential. 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. 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. Under
the Natural Gas Act the FERC regulates transmission facilities,
but does not regulate gathering facilities. Discoverys
wholly owned subsidiary, Discovery Gas Transmission, owns the
mainline and laterals subject to FERC regulation. Discovery owns
some gathering facilities that are not subject to FERC Natural
Gas Act regulation.
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. In November 2007, Discovery filed a settlement in
lieu of a general rate case filing. If approved by the FERC, the
settlement would resolve numerous rate and other issues and
achieve rate certainty on Discovery for at least five years. As
proposed, the terms of the settlement would become effective
January 1, 2008. Under the settlement, Discovery would
increase its maximum mainline, gathering and market expansion
rates to $0.1729/dekatherm (Dth), $0.0430/Dth and $0.1116/Dth,
respectively. Additionally, the settlement would permit
Discovery to recover certain natural disaster related costs
through the Hurricane Mitigation and Reliability Enhancement
surcharge and to charge a market outlet surcharge to certain
customers receiving discounted services. The settlement rates,
if approved, would not impact the vast majority of the existing
volumes on the Discovery system because those historical volumes
are dedicated to the system under a life of lease rate. The
proposed surcharges would affect some of the dedicated volumes.
The FERC must approve the settlement for its terms to be
effective. On February 5, 2008, the FERC issued an order
approving the settlement except as to the protestor ExxonMobil
Gas & Power Marketing Company, but the order is
subject to rehearing and therefore not final or effective.
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In 2005, the FERC indicated that 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. Please read Risk Factors
Discoverys interstate tariff rates and terms and
conditions are subject to changes in policy by federal
regulators, which could have a material adverse effect on our
business and operating results.
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 and Wamsutter
systems are gathering pipelines, and are not subject to the
FERCs jurisdiction under the Natural Gas Act.
The primary function of natural gas processing plants 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 relating
to the protection of the environment. As such, 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,
operate and upgrade equipment and facilities. While these laws
and regulations carry costs, we believe that they do not affect
our competitive position because 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
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. Please read Risk Factors
Our operations are subject to governmental laws and regulations
related to the protection of the environment, which may expose
us to significant costs and liabilities.
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.
Pursuant to the purchase and sale agreements by which we
acquired Four Corners and the Wamsutter Ownership Interests,
Williams agreed to indemnify us against certain losses resulting
from, among other things, Williams failure to disclose a
violation of any environmental law by Four Corners or Wamsutter
or relating to their assets, operations or businesses that
occurred prior to the respective closings.
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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
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
Hazardous substance laws generally regulate the generation,
storage, treatment, use, transportation and disposal of solid
and hazardous waste. They may 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 may or may not have
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. Despite the petroleum
exclusion of CERCLA Section 101(14) that currently
includes natural gas, we may nonetheless handle other
hazardous substances within the meaning of CERCLA,
or similar state statutes, in the course of our ordinary
operations and, as a result, may be jointly and severally liable
under CERCLA for all or part of the costs required to clean up
sites at which these hazardous substances have been released
into the environment.
We also generate solid wastes, including hazardous wastes that
are subject to the requirements of the federal Solid Waste
Disposal Act, the federal Resource Conservation and Recovery
Act, referred to as RCRA, and comparable state statutes. From
time to time, the EPA considers the adoption of stricter
disposal standards for wastes currently designated as
non-hazardous. However, it is possible that these
wastes, which could include wastes currently generated during
our operations, will in the future be designated as
hazardous wastes and therefore subject to more
rigorous and costly disposal requirements than non-hazardous
wastes. Any such changes in the laws and regulations could have
a material adverse effect on our maintenance capital
expenditures and operating expenses.
We currently own or lease, and our predecessor has in the past
owned or leased, properties where hydrocarbons are being or have
been handled for many years. Although we have utilized operating
and disposal practices that were standard in the industry at the
time, hydrocarbons or other wastes may have been 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, among others, 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. For a discussion of these
hydrocarbon removal and
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groundwater monitoring activities, please read
Managements Discussion and Analysis of Financial
Condition and Results of
Operations Environmental.
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 Kansas Department of Health and Environment
(KDHE) under the Underground Hydrocarbon and Natural Gas Storage
Program. The current revision of the Underground Hydrocarbon and
Natural Gas Storage regulations became effective in 2003; these
rules regulate the storage of liquefied petroleum gas,
hydrocarbons and natural gas in bedded salt for the purpose of
protecting public health and safety, property and the
environment and regulates the construction, operation and
closure of brine ponds associated with our storage caverns. The
regulations specify several compliance deadlines including the
final permit application for existing hydrocarbon storage wells
by April 1, 2006, certain equipment requirements no later
than April 1, 2008 and mechanical integrity and casing
testing requirements by April 1, 2010. Failure to comply
with the Underground Hydrocarbon and Natural Gas Storage Program
may lead to the assessment of administrative, civil or criminal
penalties.
We are in the process of modifying our Conway storage
facilities, including the caverns and brine ponds, and we
believe that our storage operations will be in compliance with
the Underground Hydrocarbon and Natural Gas Storage Program
regulations by the applicable compliance dates. In 2003, we
began to complete workovers on approximately 30 to 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
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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 NGLs observed in the subsurface at the Conway
Underground East facility. In addition, we have also recently
detected 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.
For more information about environmental compliance and other
environmental issues, please read Environmental
under Managements Discussion and Analysis of Financial
Condition and Results of Operations and Note 14,
Commitments and Contingencies, in our Notes to Consolidated
Financial Statements in this report.
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.
Our right of way agreement with the Jicarilla Apache Nation
(JAN), which covered certain gathering system assets in Rio
Arriba County of northern New Mexico, expired on
December 31, 2006. We currently operate our gathering
assets on the JAN lands pursuant to a special business license
granted by the JAN which expires February 29, 2008. We are
engaged in discussions with the JAN designed to result in the
sale of our gathering assets which are located on or are
isolated by the JAN lands. Provided the parties are able to
reach an acceptable value on the sale of the subject gathering
assets, our expectation is that we will nonetheless maintain
partial revenues associated with gathering and processing
downstream of the JAN lands and continue to operate the
gathering assets on the JAN lands for an undetermined period of
time beyond February 29, 2008. Based on current estimated
gathering volumes and a range of annual average commodity prices
over the past five years, we estimate that gas produced on or
isolated by the JAN lands represents approximately
$20 million to $30 million of Four Corners
annual gathering and processing revenue less related product
costs. For more information about this matter, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Gathering and
Processing West Outlook 2008.
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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 266 people, as of December 31, 2007, who
directly support the operations of the Four Corners, Conway and
Carbonate Trend facilities. Additionally, our general partner
and its affiliates provide general and administrative services
to us. Wamsutter and Discovery are operated by Williams pursuant
to agreements and the employees who operate these 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.
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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Lower natural gas and oil prices could adversely affect our
fractionation and storage businesses.
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Our processing, fractionation and storage businesses could be
affected by any decrease in NGL prices or a change in NGL prices
relative to the price of natural gas.
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We depend on certain key customers and producers for a
significant portion of our revenues and supply of natural gas
and 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.
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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.
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We do not own all of the interests in Wamsutter, the Conway
fractionator or Discovery, which could adversely affect our
ability to operate and control these assets in a manner
beneficial to us.
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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.
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Discovery and Wamsutter may reduce their cash distributions to
us in some situations.
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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.
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Discoverys interstate tariff rates and terms and
conditions are subject to changes in policy by federal
regulators, which could have a material adverse effect on our
business and operating results.
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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.
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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 public indentures and our credit facility 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 future financial and operating flexibility may be adversely
affected by restrictions in our indentures and by our leverage.
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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 debt obligations and
distributions on our common units.
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Common units held by Williams eligible for future sale may have
adverse effects on the price of our common units.
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Williams controls our general partner, which has sole
responsibility for conducting our business and managing our
operations. Our general partner and its affiliates have
conflicts of interests with us and limited fiduciary duties, and
they may favor their own interests to the detriment of our
unitholders.
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Even if unitholders are dissatisfied, they have little ability
to remove our general partner without its consent.
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24
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.
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 Williams indentures, our
indentures and credit facility 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 each of Discovery and Wamsutter
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.
25
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, and our Wamsutter gathering system receives
natural gas directly from producers in the Washakie Basin. The
production from existing wells connected to these pipelines and
our Four Corners and Wamsutter gathering systems will naturally
decline over time, which means that our cash flows associated
with these wells will also decline over time. We do not produce
an aggregate reserve report on a regular basis or regularly
obtain or update independent reserve evaluations. The amount of
natural gas reserves underlying these wells may be less than we
anticipate, and the rate at which production will decline from
these reserves may be greater than we anticipate. Accordingly,
to maintain or increase throughput levels on these pipelines and
gathering systems and the utilization rate of our natural gas
processing plants and fractionators, we 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 assets; (2) our
ability to compete for volumes from successful new wells and
existing wells connected to third parties; and (3) our
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 significant lateral
expansion project under construction. Discovery signed
definitive agreements with Chevron Corporation, Royal Dutch
Shell plc, and StatoilHydro ASA 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. In October 2007, Chevron announced that it will face
delays because of metallurgical problems discovered in the
facilitys mooring shackles and that it does not expect
first production to commence until the third quarter of 2009.
The level of drilling activity in the fields served by our
pipelines and gathering systems 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 systems and the
utilization rates of our natural gas processing plants and
fractionators 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 gathering systems. 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, we receive NGLs removed from
the natural gas stream during processing and may 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 us and our
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, we 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. One producer customer, ConocoPhillips,
accounted for approximately 53% of the Gathering and
Processing West segments total gathered
volumes for the year ended December 31, 2007. With respect
to total revenues, a subsidiary of Williams, to which we sell
substantially all of the NGLs we retain under our keep-whole and
percent-of-liquids processing contracts, accounted for
approximately 49% of our total revenues for the year ended
December 31, 2007. However, all of the NGLs sold to the
subsidiary of Williams are derived from our processing of
producer customers natural gas. For the year ended
December 31, 2007, ConocoPhillips accounted for 24% of the
Gathering and Processing West segments total
revenues.
Six producer customers, BP, Anadarko Petroleum Corporation,
Devon Energy Corporation, Marathon Oil Corporation, Samson
Resources Company, and EnCana Corporation, accounted for
approximately 92% of Wamsutters total gathered volumes for
the year ended December 31, 2007. With respect to total
revenues, a subsidiary of Williams, to which Wamsutter sells
substantially all of the NGLs it retains under its keep-whole
contracts, accounted for approximately 56% of Wamsutters
total revenues for the year ended December 31, 2007.
Although this revenue is identified as sales to a subsidiary of
Williams, all of the NGLs sold to the subsidiary of Williams are
derived from Wamsutters processing of producer
customers natural gas.
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.
In addition, we are subject to active negotiations with several
customers to renew gathering, processing and treating contracts
that are in evergreen status and that represent 19% of the total
MMBtu gathered by our Four Corners system. All of the agreements
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in evergreen status represent approximately 33% of our total
MMBtu gathered revenues for the year ended December 31,
2007. The negotiations may not result in any extended
commitments from these customers or may result in extended
commitments on less favorable terms. The loss of all or even a
portion of the revenues from 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.
MAPL also provides the only current liquids pipeline access to
multiple end markets for NGL products that are recovered from
our Four Corners and Wamsutter 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
and Wamsutter processing plants. This would have an immediate
impact on our ability to sell or deliver NGL products recovered
at our Four Corners and Wamsutter processing plants. In
addition, the five pipeline systems that move natural gas to end
markets from the San Juan Basin connected to our Four
Corners treating and processing facilities, including the
El Paso Natural Gas, Transwestern, Williams Northwest
Pipeline, Public Service Company of New Mexico and Southern
Trails systems. The four pipeline systems that move natural gas
to end markets from our Wamsutter processing facilities are the
Colorado Interstate Gas, Wyoming Interstate Gas, Southern Star
Central Gas Pipeline and Rockies Express 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 may be unable to deliver natural gas to end
markets. This could reduce the volumes of natural gas processed
or treated at our Four Corners treating and processing
facilities and our Wamsutter 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 on 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.
We do
not own all of the interests in Wamsutter, 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 Wamsutter, 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.
28
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.
Discovery
and Wamsutter may reduce their cash distributions to us in some
situations.
Discoverys and Wamsutters limited liability company
agreements provide that they will distribute their available
cash to their members on a quarterly basis. Discoverys
available cash includes cash on hand less any reserves that may
be appropriate for operating its business and Wamsutters
available cash includes cash generated from Wamsutters
business less any reserves that may be appropriate for operating
its business. As a result, reserves established by Discovery and
Wamsutter, 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. The amount of Wamsutters quarterly
distributions, including the amount of cash reserves not
distributed, is determined by the affirmative vote of the
Class B members representative on the management
committee.
We own a 60% interest in Discovery. In addition, to the extent
Discovery requires working capital in excess of applicable
reserves, we 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.
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.
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. The FERC
could lower the tariff rates Discovery is currently permitted to
charge its customers, on its own initiative, or as a result of
challenges raised by Discoverys customers or third parties
and 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 or on the
rehearing of the proposed settlement discussed below 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.
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On November 16, 2007, Discovery filed a settlement, which
is uncontested by its active shippers, in lieu of a general rate
case filing. If approved by the FERC, the settlement would
resolve numerous rate and other issues and achieve rate
certainty on Discovery for at least five years. On
February 5, 2008, the FERC approved the settlement but the
order is subject to rehearing and therefore not final or
effective. If the settlement does not become effective and if
Discovery files a rate case, all aspects of Discoverys
cost of service and design of its rates could be reviewed.
Please read Business and Properties FERC
Regulation Discovery for further information.
Discoverys
interstate tariff rates and terms and conditions are subject to
changes in policy by federal regulators, which could have a
material adverse effect on our business and operating
results.
FERC standards of conduct govern how interstate pipelines
communicate and do business with their marketing affiliates.
Among other things, the standards of conduct require that
interstate pipelines do not operate their systems to
preferentially benefit their marketing affiliates. The current
rule, which is an interim rule, applies only to natural gas
transmission providers that are affiliated with a marketing or
brokering entity that conducts transportation transactions on
that natural gas transmission providers pipeline.
Therefore, the interim rule does not currently apply to
Discovery. FERC has issued a notice of proposed rulemaking that
proposes permanent standards of conduct. We have no way to
predict with certainty the scope of FERCs permanent rules
on the standards of conduct. However, we do not believe that
Discoverys natural gas pipeline will be affected by any
action taken previously or in the future on these matters
materially differently than other natural gas service providers
with whom Discovery competes.
In 2005, the FERC indicated that it will permit pipelines to
include in cost-of-service an income tax allowance to reflect
actual or potential income tax liability on their public utility
income attributable to all partnership or limited liability
company interests if the ultimate owner of the interest has an
actual or potential income tax liability on such income (See
FERC Regulation). If the settlement discussed above does not
become final and instead Discovery files a general rate case,
under the FERCs current policy Discovery would be required
to prove that it is permitted to include an income tax allowance
in its cost of service. These aspects of Discoverys rates
could also be reviewed if the FERC or a shipper initiated a
complaint proceeding. 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.
In 2006, the FERC issued a new order addressing rates on one of
the interstate oil pipelines of SFPP, L.P. The FERC refined its
income tax allowance policy, and notably raised a new issue
regarding the implication of the policy statement for
publicly-traded partnerships. It noted that the tax deferral
features of a publicly-traded partnership may cause some
investors to receive, for some indeterminate duration, cash
distributions in excess of their taxable income, which the FERC
characterized as a tax savings. The FERC stated that
it is concerned that this created an opportunity for those
investors to earn an additional return, funded by ratepayers.
Responding to this concern, the FERC chose to adjust the
pipelines equity rate of return downward based on the
percentage by which the publicly-traded partnerships cash
flow exceeded taxable income. In February 2007, SFPP, L.P. asked
the FERC to reconsider this ruling. The rehearing request is
still pending before the FERC. The ultimate outcome of this
proceeding is not certain and could result in changes to the
FERCs treatment of income tax allowances in
cost-of-service. If the FERC does not approve the settlement
discussed above and instead Discovery files a general rate case,
Discovery may be subject to potential adjustment of its equity
rate-of-return that underlies its recourse rates to the extent
that cash distributions in excess of taxable income are allowed
to some unitholders.
In July 2007, the FERC issued a proposed policy statement
regarding the composition of proxy groups for determining the
appropriate returns on equity for natural gas and oil pipelines.
The proposed policy statement would permit the inclusion of
publicly traded master limited partnerships (MLPs) in the proxy
group for purposes of calculating returns on equity under the
discounted cash flow analysis, a change from its prior view that
MLPs had not been shown to be appropriate for such inclusion.
The FERCs proposed policy statement is subject to change.
Therefore, we cannot predict the scope of the final policy
statement. If the settlement discussed above does not become
final and Discovery files a general rate case instead, and
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Discovery has not completed the hearing phase of the rate case
as of the date the FERC issues its final policy statement, as
currently proposed the final policy statement would apply to
Discoverys rate case.
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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most of our Four Corners field compression, excluding major
turbine compressor stations, which are operated by Exterran
Holdings, Inc. (Exterran); and
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Exterran operates two compression units in the Wamsutter
gathering field, and Devon Energy Corporation (Devon) owns and
operates four compressor stations on the Eastern part of the
Wamsutter gathering system that compress its gas.
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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, Exterran and
Devon 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.
Williams
public indentures and our credit facility 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.
Williams public indentures contain covenants that restrict
Williams and our ability to incur liens to support
indebtedness. 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.
Our credit facility contains various covenants that, among other
things, limit our ability to incur indebtedness, grant certain
liens to support indebtedness, merge, or sell substantially all
of our assets. 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. Our ability to comply with the
covenants contained in the credit facility may be affected by
events beyond our control, including prevailing economic,
financial and industry conditions. If market or other economic
conditions deteriorate, our ability to comply with these
covenants may be impaired. 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.
31
Our
future financial and operating flexibility may be adversely
affected by restrictions in our indentures and by our
leverage.
In December 2007, we borrowed $250.0 million under the term
loan portion of our new $450.0 million five-year senior
unsecured credit facility. Our total outstanding long-term debt
as of December 31, 2007 was $1.0 billion, representing
approximately 86% 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
and Wamsutter are not prohibited from incurring indebtedness,
which may affect our ability to make distributions to
unitholders.
Discovery and Wamsutter are not prohibited by the terms of their
respective limited liability company agreements from incurring
indebtedness. If Discovery or Wamsutter was to incur significant
amounts of indebtedness, such occurrence may inhibit their
ability to make distributions to us. An inability by Discovery
or Wamsutter 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 and Wamsutter to represent a significant portion of
the cash we distribute to unitholders.
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
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Coast, including the Manta Ray/Nautilus systems, the Trunkline
pipeline and the Venice Gathering System and the processing and
fractionation facilities that are connected to these pipelines.
Our Conway fractionation facility competes for volumes of mixed
NGLs with 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. 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, treating,
fractionation and storage facilities in lieu of using ours.
Wamsutter competes with other natural gas gathering and
processing facilities in the Washakie Basin, including
Anadarkos Patrick Draw and Red Desert facilities and
Colorado Interstate Gas Rawlins facility. In addition,
customers who are significant producers of gas or consumers of
NGLs may develop their own gathering and processing facilities
in lieu of using Wamsutters gathering and processing
facility.
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.
Pipeline
integrity programs and repairs may impose significant costs and
liabilities on us.
In December 2003, the DOT 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 most of the
testing and expect to complete the remainder of the testing in
2008.
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 corrosion.
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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;
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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.
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 us will be diluted and distributions to unitholders may be
reduced.
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, processing and treating 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
34
Discoverys pipelines due to an influx of seawater while
connecting a new lateral. In addition, on November 28,
2007, we had a fire at our Ignacio gas processing plant that
resulted in a significant disruption of our operations
associated with that plant. Although the plant is now operating,
the fire destroyed much of the plants spare parts
inventory. Consequently, there could be additional disruptions
of operations due to failure of parts for which the acquisition
of replacements requires significant lead time.
Insurance may be inadequate, and in some instances, we may be
unable to obtain insurance on commercially reasonable terms, if
at all. A significant disruption in operations or a significant
liability for which we were not fully insured could have a
material adverse effect on our business, results of operations
and financial condition and our ability to make cash
distributions to unitholders.
We do
not own all of the land on which our pipelines and facilities
are located, which could disrupt our operations.
We do not own 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. We continue to operate these assets under a special
business license that expires February 29, 2008. Based upon
current estimated gathering volumes and a range of annual
average commodity prices over the past five years, we estimate
that gas produced on or isolated by the Jicarilla Apache Nation
lands represents approximately $20.0 million to
$30.0 million of Four Corners annual gathering and
processing revenue less related product costs.
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, processing
and treating, 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 (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 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.
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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 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. In addition, the Department of Environmental
Quality in Wyoming has created a new emissions rule for sites
with production greater than 3,000 million cubic feet per
day. Wamsutter has reacted by installing methanol injectors at
these sites. This requirement increases the well connect costs
for new wells in Wyoming.
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 if 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 laws and regulations might adversely
affect our products and activities, including processing,
fractionation, storage and transportation, as well as waste
management and air emissions. For instance, federal and state
agencies also could impose additional safety requirements, any
of which could affect our profitability. In addition, recent
scientific studies have suggested that emissions of certain
gases, commonly referred to as greenhouse gases, may
be contributing to warming of the Earths atmosphere.
Methane, a primary component of natural gas, and carbon dioxide,
a byproduct of the burning of fossil fuels, are examples of
greenhouse gases. In response to such studies, the
U.S. Congress is actively considering legislation and more
than a dozen states have already taken legal measures to reduce
emissions of greenhouse gases, primarily through the planned
development of greenhouse gas emission inventories and regional
greenhouse gas cap and trade programs. Moreover, the
U.S. Supreme Court only recently held in a case,
Massachusetts, et al. v. EPA, that greenhouse gases
fall within the federal Clean Air Acts definition of
air pollutant, which could result in the regulation
of greenhouse gas emissions from stationary sources under
certain Clean Air Act programs. New legislation or regulatory
programs that restrict emissions of greenhouse gases in areas in
which we conduct business could have an adverse affect on our
operations and demand for our services.
The
natural gas gathering operations in the San Juan Basin and
Washakie 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 in New Mexico will occur, but they could
result in gathering regulation that could affect the fees that
we could collect for gathering services. This type of regulation
could adversely impact our revenues and cash flow.
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Potential
changes in accounting standards might cause us to revise our
financial results and disclosures in the future.
Regulators and legislators continue 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 Securities Exchange
Commission (SEC) could enact new accounting standards that might
impact how we would be 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.
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 debt obligations 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 debt obligations
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 debt obligations,
to repurchase our debt obligations 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 debt obligations or borrowing funds to
37
make distributions on our common units. We cannot assure you
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 February 19, 2008, Williams held 11,613,527 common
units, including common units issued to Williams as partial
consideration for the Wamsutter Ownership Interests representing
a 21.6% 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.
Williams
controls our general partner, which has sole responsibility for
conducting our business and managing our operations. Our general
partner and its affiliates have conflicts of interest with us
and limited fiduciary duties, and they favor their own interests
to the detriment of our unitholders.
Williams owns and controls our general partner, and appoints all
of the directors of our general partner. All of the executive
officers and certain directors of our general partner are
officers
and/or
directors of Williams and its affiliates, including Williams
Pipeline Partners 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 officers of our
general partner have a fiduciary duty to manage our general
partner in a manner beneficial to Williams. Therefore, conflicts
of interest may arise between Williams and its affiliates,
including our general partner and Williams Pipeline Partners, 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. Williams directors and officers
have a fiduciary duty to make decisions in the best interests of
the owners of Williams, which may be contrary to ours;
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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, and, based on the applicable facts and
circumstances, whether a capital expenditure is classified as a
maintenance capital expenditure, which reduces operating
surplus, or an expansion capital expenditure or investment
capital expenditure, neither of which reduces operating surplus.
This determination can affect the amount of cash that is
distributed to our unitholders and to our general partner in
respect of the incentive distribution rights;
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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;
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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 and in some circumstances is
required to be indemnified by us;
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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. The limitation and definition of
these duties is permitted by the Delaware law governing limited
partnerships. In addition, our partnership agreement restricts
the remedies available to holders of our limited partner units
for actions taken by our general partner that might otherwise
constitute breaches of fiduciary duty. 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 or
amendment to the partnership agreement;
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provides that our general partner will not have any liability to
us or our unitholders for decisions made in its capacity as a
general partner so long as it acted in good faith, meaning it
believed the decision was in the best interests of our
partnership;
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generally provides that affiliate transactions and resolutions
of conflicts of interest not approved by the conflicts committee
of the board of directors of our general partner and not
involving a vote of unitholders must be on terms no less
favorable to us than those generally being provided to or
available from unrelated third parties or be fair and
reasonable to us, as determined by 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 or assignees for any acts or
omissions unless there has been a final and non-appealable
judgment entered by a court of competent jurisdiction
determining that our general partner or those other persons
acted in bad faith or engaged in fraud or willful misconduct.
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Common unitholders are 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 units is required to remove our
general partner.
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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. This effectively permits a change of control
without your consent. 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.
In recent years, the United States credit markets experienced
50-year
record lows in interest rates. If the overall economy
strengthens, it is possible that monetary policy will tighten,
resulting in higher interest rates to counter possible inflation
risk. Interest rates on future credit facilities and debt
offerings could be higher than current levels, causing our
financing costs to increase accordingly. As with other
yield-oriented securities, our unit price is impacted by the
level of our cash distributions and implied distribution yield.
The distribution yield is often used by investors to compare and
rank related yield-oriented securities for investment
decision-making purposes. Therefore, changes in interest rates
may affect the yield requirements of investors who invest in our
units, and a rising interest rate environment could have an
adverse impact on our unit price and our ability to issue
additional equity or incur debt to make acquisitions or for
other purposes.
We may
issue additional common units without unitholder approval, which
would dilute unitholder ownership interests.
Our partnership agreement does not limit the number of
additional limited partner interests that we may issue at any
time without the approval of unitholders. The issuance by us of
additional common units or other equity securities of equal or
senior rank will have the following effects:
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our unitholders proportionate ownership interest in us
will decrease;
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the amount of cash available to pay distributions on each unit
may decrease;
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the ratio of taxable income to distribution may decrease;
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the relative voting strength of each previously outstanding unit
may be diminished; and
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the market price of the common units may decline.
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Affiliates
of our general partner, including Williams and Williams Pipeline
Partners, are not limited in their ability to compete with us.
Williams is also not obligated to offer us the opportunity to
acquire additional assets or businesses from it, which could
limit our commercial activities or our ability to grow. In
addition, all of the executive officers and certain of the
directors of our general partner are also officers and/or
directors of Williams and Williams Pipeline Partners
general partner, and these persons will also owe fiduciary
duties to those entities.
While our relationship with Williams and its affiliates is a
significant attribute, it is also a source of potential
conflicts. For example, Williams is in the natural gas business
and is not restricted from competing with us. Williams and its
affiliates, including Williams Pipeline Partners, which trades
on the NYSE under the symbol WMZ, may compete with
us. Williams and its affiliates may acquire, construct or
dispose of natural gas industry assets in the future, some or
all of which may compete with our assets, without any obligation
to offer us the opportunity to purchase or construct such
assets. In addition, all of the executive officers and certain
of the directors of our general partner are also officers
and/or
directors of Williams and Williams Pipeline Partners
general partner and will owe fiduciary duties to those entities
as well as our unitholders and us.
40
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 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 be voted 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 to our general partner and its affiliates
will reduce cash available to pay distributions to
unitholders.
We will reimburse our general partner and its affiliates,
including Williams, for various general and administrative
services they provide for our benefit, including costs for
rendering administrative staff and support services to us, and
overhead allocated to us, which amounts will be determined by
our general partner in its sole discretion. Payments for these
services will be substantial and will reduce the amount of cash
available for distribution to unitholders. Please read
Certain Relationships and Related Transactions, and
Director Independence. In addition, under Delaware
partnership law, our general partner has unlimited liability for
our obligations, such as our debts and environmental
liabilities, except for our contractual obligations that are
expressly made without recourse to our general partner. To the
extent our general partner incurs obligations on our behalf, we
are obligated to reimburse or indemnify it. If we are unable or
unwilling to reimburse or indemnify our general partner, our
general partner may take actions to cause us to make payments of
these obligations and liabilities. Any such payments could
reduce the amount of cash otherwise available for distribution
to our unitholders.
Your
liability may not be limited if a court finds that unitholder
action constitutes control of our business.
A general partner of a partnership generally has unlimited
liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are
expressly made without recourse to the general partner. Our
partnership is organized under Delaware law and we conduct
business in a number of other states. The limitations on the
liability of holders of limited partner interests for the
obligations of a limited partnership have not been clearly
established in some of the other states in which we do business.
You could be liable for any and all of our obligations as if you
were a general partner if a court or government agency were to
determine that:
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we were conducting business in a state but had not complied with
that particular states partnership statute; or
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your right to act with other unitholders to remove or replace
the general partner, to approve some amendments to our
partnership agreement or to take other actions under our
partnership agreement constitute control of our
business.
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41
Unitholders
may have liability to repay distributions that were wrongfully
distributed to them.
Under certain circumstances, unitholders may have to repay
amounts wrongfully returned or distributed to them. Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make a distribution to you if the distribution would cause
our liabilities to exceed the fair value of our assets. Delaware
law provides that for a period of three years from the date of
the impermissible distribution, limited partners who received
the distribution and who knew at the time of the distribution
that it violated Delaware law will be liable to the limited
partnership for the distribution amount. Substituted limited
partners are liable for the obligations of the assignor to make
contributions to the partnership that are known to the
substituted limited partner at the time it became a limited
partner and for unknown obligations if the liabilities could be
determined from the partnership agreement. Liabilities to
partners on account of their partnership interest and
liabilities that are non-recourse to the partnership are not
counted for purposes of determining whether a distribution is
permitted.
Holders
of our common units have limited voting rights and are not
entitled to elect our general partner or its directors, which
could reduce the price at which the common units will
trade.
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, including the independent
directors, will be chosen entirely by Williams and not by the
unitholders. Unlike publicly traded corporations, we will not
conduct annual meetings of our unitholders to elect directors or
conduct other matters routinely conducted at annual meetings of
stockholders. Furthermore, if the unitholders become
dissatisfied with the performance of our general partner, they
will have little ability to remove our general partner. As a
result of these limitations, the price at which the common units
will trade could be diminished because of the absence or
reduction of a takeover premium in the trading price.
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 a
material amount of entity-level taxation by states and
localities. If the IRS were to treat us as a corporation or if
we were to become subject to a material amount of entity-level
taxation for state or local tax purposes, then our cash
available for distribution to unitholders would be substantially
reduced.
The anticipated after-tax economic benefit of an investment in
the common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the IRS on
this or any other tax matter affecting us.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income
at the corporate tax rate, which currently has a top marginal
rate of 35%, and would likely pay state and local income tax at
the corporate tax rate of the various states and localities
imposing a corporate income tax. 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 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 federal, state or local entity-level taxation.
For example, because of widespread state budget deficits and
other reasons, several states are evaluating ways to subject
partnerships to entity-level taxation through the imposition of
state income, 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
42
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.
The
tax treatment of publicly traded partnerships or an investment
in our common units could be subject to potential legislative,
judicial or administrative changes and differing
interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly
traded partnerships, including us, or an investment in our
common units may be modified by administrative, legislative or
judicial interpretation at any time. Any modification to the
U.S. federal income tax laws and interpretations thereof
may or may not be applied retroactively and could make it more
difficult or impossible to meet the exception for us to be
treated as a partnership for U.S. federal income tax
purposes that is not taxable as a corporation, or
Qualifying Income Exception, affect or cause us to change our
business activities, affect the tax considerations of an
investment in us, change the character or treatment of portions
of our income and adversely affect an investment in our common
units. For example, in response to certain recent developments,
members of Congress are considering substantive changes to the
definition of qualifying income under Section 7704(d) of
the Internal Revenue Code. Legislation has been proposed that
would eliminate partnership tax treatment for certain publicly
traded partnerships. Although such legislation would not apply
to us as currently proposed, it could be amended prior to
enactment in a manner that does apply to us. It is possible that
these legislative efforts could result in changes to the
existing U.S. tax laws that affect publicly traded
partnerships, including us. Any modification to the
U.S. federal income tax laws and interpretations thereof
may or may not be applied retroactively. We are unable to
predict whether any of these changes, or other proposals, will
ultimately be enacted. Any such changes could negatively impact
the value of an investment in our common units.
We
prorate our items of income, gain, loss and deduction between
transferors and transferees of the common units each month based
upon the ownership of the units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred.
We prorate our items of income, gain, loss and deduction between
transferors and transferees of the common units each month based
upon the ownership of the units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The use of this proration method may not be
permitted under existing Treasury regulations, and, accordingly,
our counsel is unable to opine as to the validity of this
method. If the IRS were to challenge this method or new Treasury
regulations were issued, we may be required to change the
allocation of items of income, gain, loss and deduction among
our unitholders.
An IRS
contest of the federal income tax positions we take may
adversely impact the market for the common units, and the costs
of any contest will reduce our cash available for distribution
to 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 or from the
positions we take. It may be necessary to resort to
administrative or court proceedings to sustain some or all of
our counsels conclusions or the positions we take. A court
may not agree with some or all of our counsels conclusions
or the positions we take. Any contest with the IRS may
materially and adversely impact the market for the 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.
43
Unitholders
will be required to pay taxes on their share of our income even
if unitholders do not receive any cash distributions from
us.
Because our unitholders will be treated as partners to whom we
will allocate taxable income which could be different in amount
than the cash we distribute, unitholders will be required to pay
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 the common units could be
different than expected.
If a unitholder sells 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, regardless of
whether such amount represents gain, may be taxed as ordinary
income to the unitholder due to potential recapture items,
including depreciation recapture. In addition, if a unitholder
sells its common units, the unitholder may incur a tax liability
in excess of the amount of cash it received from the sale.
Tax-exempt
entities and foreign persons face unique tax issues from owning
common units that may result in adverse tax consequences to
them.
Investment in common units by tax-exempt entities, such as
individual retirement accounts (known as IRAs), other retirement
plans and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to organizations that are exempt from federal
income tax, including individual retirement accounts and other
retirement plans, will be unrelated business taxable income and
will be taxable to them. Distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
will be required to file United States federal income tax
returns and pay tax on their share of our taxable income.
We
will treat each purchaser of common units as having the same tax
benefits without regard to the actual common units purchased.
The IRS may challenge this treatment, which could adversely
affect the value of the common units.
Because we cannot match transferors and transferees of common
units, we will adopt depreciation and amortization positions
that may not conform with all aspects of existing Treasury
regulations. Our counsel is unable to opine as to the validity
of such filing positions. 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 the
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 now or in the future,
even if the unitholder does not live in any of those
jurisdictions. 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
Colorado, Kansas, Louisiana, New Mexico, Alabama and Wyoming. We
may own property or conduct business in other states or foreign
countries in the future. It is the unitholders
44
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 the total interest in our
capital and profits during any
12-month
period will result in the termination of our partnership for
federal income tax purposes.
We will be considered to have terminated our partnership for
federal income tax purposes if there is a sale or exchange of
50% or more of the total interests in our capital and profits
within a
12-month
period. Our termination would, among other things, result in the
closing of our taxable year for all unitholders, which would
result in us filing two tax returns for one fiscal year. Our
termination could also result in a deferral of depreciation
deductions allowable in computing our taxable income. In the
case of a unitholder reporting on a taxable year other than a
fiscal year ending December 31, the closing of our taxable
year may also result in more than 12 months of our taxable
income or loss being includable in the unitholders taxable
income for the year of termination. Our termination currently
would not affect our classification as a partnership for federal
income tax purposes, but instead, we would be treated as a new
partnership, we must make new tax elections and could be subject
to penalties if we are unable to determine that a termination
occurred.
We
have adopted certain valuation methodologies that may result in
a shift of income, gain, loss and deduction between the general
partner and the unitholders. The IRS may challenge this
treatment, which could adversely affect the value of the common
units.
When we issue additional common units or engage in certain other
transactions, we determine the fair market value of our assets
and allocate any unrealized gain or loss attributable to our
assets to the capital accounts of our unitholders and our
general partner. Our methodology may be viewed as understating
the value of our assets. In that case, there may be a shift of
income, gain, loss and deduction between certain unitholders and
the general partner, which may be unfavorable to such
unitholders. Moreover, under our methodologies, subsequent
purchasers of common units may have a greater portion of their
Internal Revenue Code Section 743(b) adjustment allocated
to our tangible assets and a lesser portion allocated to our
intangible assets. The IRS may challenge our methods, or our
allocation of the Section 743(b) adjustment attributable to
our tangible and intangible assets, and allocations of income,
gain, loss and deduction between the general partner and certain
of our unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
gain from a unitholders sale of common units and could
have a negative impact on the value of the common units or
result in audit adjustments to the unitholders tax returns.
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Item 1B.
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Unresolved
Staff Comments
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None.
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Item 3.
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Legal
Proceedings
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The information called for by this item is provided in
Note 14, Commitments and Contingencies, in our Notes to
Consolidated Financial Statements of this report, which
information is incorporated into this Item 3 by reference.
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Item 4.
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Submission
of Matters to a Vote of Security Holders
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None.
45
PART II
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Item 5.
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Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities.
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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 52,774,728 common units outstanding, held
by approximately 16,089 holders, including common units held in
street name and by affiliates of Williams.
On January 28, 2008, our general partners board of
directors confirmed that the financial test contained in our
partnership agreement required for conversion of all of our
outstanding subordinated units into common units had been
satisfied. Accordingly, our 7,000,000 subordinated units held by
four subsidiaries of Williams converted into common units on a
one-for-one
basis on February 19, 2008.
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.
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Cash Distribution
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High
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Low
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per Unit(a)
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2007
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Fourth Quarter
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$
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45.79
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$
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36.60
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$
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0.575
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Third Quarter
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52.00
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40.26
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0.550
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Second Quarter
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50.00
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46.00
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0.525
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First Quarter(b)
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48.20
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38.20
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0.500
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2006
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Fourth Quarter(b)
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$
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40.80
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$
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35.04
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$
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0.470
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Third Quarter
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36.00
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29.25
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0.450
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Second Quarter
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35.55
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30.30
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0.425
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First Quarter
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33.92
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31.00
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0.380
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(a) |
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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 and incentive
distribution rights that totaled $1.8 million and
$10.7 million for the 2006 and 2007 periods, respectively.
On February 19, 2008, the 7,000,000 outstanding
subordinated units held by four subsidiaries of Williams
converted into common units on a
one-for-one
basis. Subordinated units participated in all of the cash
distributions for the periods indicated above. |
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(b) |
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Class B units participated in the fourth quarter 2006 and
first quarter 2007 cash distributions. Class B units were
outstanding between December 13, 2006 and May 21,
2007, on which date all 6,805,492 Class B units converted
into common units on a
one-for-one
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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:
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less the amount of cash reserves established by our general
partner to:
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provide for the proper conduct of our business (including
reserves for future capital expenditures and for our anticipated
credit needs);
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comply with applicable law, any of our debt instruments or other
agreements; or
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46
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provide funds for distribution to our unitholders and to our
general partner for any one or more of the next four quarters;
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plus all cash on hand on the date of determination of available
cash for the quarter resulting from working capital borrowings
made after the end of the quarter for which the determination is
being made. Working capital borrowings are generally borrowings
that will be made under our working capital facility with
Williams and in all cases are used solely for working capital
purposes or to pay distributions to partners.
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If the unitholders remove our general partner other than for
cause and units held by our general partner and its affiliates
are not voted in favor of such removal:
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any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
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our general partner will have the right to convert its general
partner interest and, if any, its incentive distribution rights
into common units or to receive cash in exchange for those
interests.
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We will make distributions of available cash from operating
surplus for any quarter in the following manner:
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first, 98% to all unitholders, pro rata, and 2% to our
general partner, until each outstanding common unit has received
the minimum quarterly distribution for that quarter; and
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thereafter, cash in excess of the minimum quarterly
distributions is distributed to the unitholders and the general
partner based on the incentive percentages below.
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Our general partner is entitled to incentive distributions if
the amount we distribute with respect to any quarter exceeds
specified target levels shown below:
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Marginal Percentage
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Total Quarterly Distribution
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Interest in Distributions
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Target Amount
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Unitholders
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General Partner
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Minimum Quarterly Distribution
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$0.35
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98
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%
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2
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%
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First Target Distribution
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up to $0.4025
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|
|
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
|
%
|
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.
47
|
|
Item 6.
|
Selected
Financial and Operational Data
|
The following table shows selected financial and operating data
of Williams Partners L.P., Wamsutter LLC and Discovery Producer
Services LLC for the periods and as of the dates indicated. We
derived the financial data as of December 31, 2007 and 2006
and for the years ended December 31, 2007, 2006 and 2005 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, Wamsutter and the additional 20% interest
in Discovery were owned by affiliates 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 selected financial and operational data
have been recast to reflect the combined historical results of
these common control acquisitions 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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in thousands, except per unit amounts)
|
|
|
Statement of Income Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
572,817
|
|
|
$
|
563,410
|
|
|
$
|
514,972
|
|
|
$
|
469,199
|
|
|
$
|
382,428
|
|
Costs and expenses
|
|
|
457,880
|
|
|
|
420,342
|
|
|
|
395,556
|
|
|
|
364,602
|
|
|
|
286,637
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
114,937
|
|
|
|
143,068
|
|
|
|
119,416
|
|
|
|
104,597
|
|
|
|
95,791
|
|
Equity earnings Wamsutter
|
|
|
76,212
|
|
|
|
61,690
|
|
|
|
40,555
|
|
|
|
39,016
|
|
|
|
37,997
|
|
Equity earnings Discovery
|
|
|
28,842
|
|
|
|
18,050
|
|
|
|
11,880
|
|
|
|
5,619
|
|
|
|
4,308
|
|
Impairment of investment in Discovery
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16,855
|
)(a)
|
|
|
|
|
Interest expense
|
|
|
(58,348
|
)
|
|
|
(9,833
|
)
|
|
|
(8,238
|
)
|
|
|
(12,476
|
)
|
|
|
(4,176
|
)
|
Interest income
|
|
|
2,988
|
|
|
|
1,600
|
|
|
|
165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
|
$
|
163,778
|
|
|
$
|
119,901
|
|
|
$
|
133,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income(b)
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
|
$
|
162,373
|
|
|
$
|
119,901
|
|
|
$
|
132,491
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting
principle per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unit
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
|
$
|
0.49
|
(c)
|
|
|
N/A
|
|
|
|
N/A
|
|
Subordinated unit
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
|
$
|
0.49
|
(c)
|
|
|
N/A
|
|
|
|
N/A
|
|
Net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unit
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
|
$
|
0.44
|
(c)
|
|
|
N/A
|
|
|
|
N/A
|
|
Subordinated unit
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
|
$
|
0.44
|
(c)
|
|
|
N/A
|
|
|
|
N/A
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,283,477
|
|
|
$
|
1,292,299
|
|
|
$
|
1,190,508
|
|
|
$
|
1,121,862
|
|
|
$
|
1,140,046
|
(d)
|
Property, plant and equipment, net
|
|
|
642,289
|
|
|
|
647,578
|
|
|
|
658,965
|
|
|
|
669,503
|
|
|
|
705,600
|
|
Investment in Wamsutter
|
|
|
284,650
|
|
|
|
262,245
|
|
|
|
240,156
|
|
|
|
221,360
|
|
|
|
220,996
|
|
Investment in Discovery
|
|
|
214,526
|
|
|
|
221,187
|
|
|
|
225,337
|
|
|
|
184,199
|
(a)
|
|
|
178,580
|
(d)
|
Advances from affiliate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
186,024
|
|
|
|
187,193
|
(d)
|
Partners capital
|
|
|
161,487
|
(e)
|
|
|
471,341
|
(e)
|
|
|
1,142,478
|
|
|
|
895,476
|
|
|
|
917,840
|
|
48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in thousands, except per unit amounts)
|
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions declared per unit
|
|
$
|
2.045
|
|
|
$
|
1.605
|
|
|
$
|
0.1484
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Cash distributions paid per unit
|
|
$
|
2.045
|
|
|
$
|
1.605
|
|
|
$
|
0.1484
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Four Corners gathered volumes (MMBtu/d)
|
|
|
1,442,219
|
|
|
|
1,499,937
|
|
|
|
1,521,507
|
|
|
|
1,559,940
|
|
|
|
1,577,181
|
|
Four Corners processed volumes (MMBtu/d)
|
|
|
851,241
|
|
|
|
875,600
|
|
|
|
863,693
|
|
|
|
900,194
|
|
|
|
900,356
|
|
Four Corners liquid sales gallons (000s)
|
|
|
166,689
|
|
|
|
182,010
|
|
|
|
165,479
|
|
|
|
197,851
|
|
|
|
187,788
|
|
Four Corners net liquids margin (¢/gallon)
|
|
|
.61
|
¢
|
|
|
.47
|
¢
|
|
|
.37
|
¢
|
|
|
.29
|
¢
|
|
|
.17
|
¢
|
Conway storage revenues
|
|
$
|
28,016
|
|
|
$
|
25,237
|
|
|
$
|
20,290
|
|
|
$
|
15,318
|
|
|
$
|
11,649
|
|
Conway fractionation volumes (bpd) our 50%
|
|
|
34,460
|
|
|
|
38,859
|
|
|
|
39,965
|
|
|
|
39,062
|
|
|
|
34,989
|
|
Carbonate Trend gathered volumes (MMBtu/d)
|
|
|
22,651
|
|
|
|
29,323
|
|
|
|
35,605
|
|
|
|
49,981
|
|
|
|
67,638
|
|
Wamsutter 100%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wamsutter gathered volumes (MMBtu/d)
|
|
|
515,938
|
|
|
|
490,119
|
|
|
|
463,984
|
|
|
|
451,994
|
|
|
|
473,603
|
|
Wamsutter processed volumes (MMBtu/d)
|
|
|
310,697
|
|
|
|
277,749
|
|
|
|
256,970
|
|
|
|
253,383
|
|
|
|
291,451
|
|
Wamsutter liquid sales gallons (000s)
|
|
|
113,147
|
|
|
|
140,768
|
|
|
|
159,760
|
|
|
|
175,178
|
|
|
|
152,502
|
|
Wamsutter net liquids margin (¢/gallon)
|
|
|
.48
|
¢
|
|
|
.29
|
¢
|
|
|
.13
|
¢
|
|
|
.11
|
¢
|
|
|
.10
|
¢
|
Discovery Producer Services 100%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathered volumes (MMBtu/d)
|
|
|
581,685
|
|
|
|
467,338
|
|
|
|
345,098
|
|
|
|
348,142
|
|
|
|
378,745
|
|
Gross processing margin (¢/MMbtu)
|
|
|
.33
|
¢
|
|
|
.23
|
¢
|
|
|
.19
|
¢
|
|
|
.17
|
¢
|
|
|
.17
|
¢
|
|
|
|
(a) |
|
The $16.9 million impairment of our equity investment in
Discovery in 2004 reduced the investment balance. |
|
(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) |
|
The period of August 23, 2005 through December 31,
2005. |
|
(d) |
|
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. |
|
(e) |
|
Because Four Corners, Wamsutter and the additional 20% in
Discovery were owned by affiliates of Williams at the time of
their acquisition by us, the acquisitions are accounted for as a
combination of entities under common control, whereby the assets
and liabilities 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 these assets and liabilities and the aggregate consideration
paid to the general partner. |
49
|
|
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)
and certain ownership interests in Wamsutter LLC (Wamsutter)
consisting of (i) 100% of the Class A limited
liability company membership interests and (ii) 50% of the
initial Class C units (or 20 Class C units) representing
limited liability company membership interests in Wamsutter
(together, the Wamsutter Ownership Interests). 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. The Wamsutter system gathers
approximately 69% of the natural gas produced in the Washakie
Basin and connects with three pipeline systems that transport
natural gas to end markets from the basin.
|
|
|
|
Gathering and Processing Gulf. Our
Gulf segment includes (1) our 60% ownership interest in
Discovery Producer Services LLC (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 a
natural gas liquids (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 2007, a significant achievement was the December acquisition
of the Wamsutter Ownership Interests from The Williams
Companies, Inc. (Williams) for $750.0 million. The
Wamsutter system serves the Washakie basin, which has stable
production and high growth potential. At Four Corners, record
commodity margins largely offset the negative impacts of the
fire at the Ignacio plant, increased operating expenses and
lower gathered volumes. Important capital investments were
completed at Four Corners, which we believe will lead to
slightly increased gathering volumes in 2008. We also acquired
an additional 20% interest in Discovery from Williams in June
for $78.0 million. Discovery has recently produced record
quarterly profits and looks forward to continued strong
performance in 2008. At Conway, we continue to see strong demand
for leased storage and new product upgrade services. We have
increased unitholder distributions each quarter since our
initial public offering (IPO) and our fourth-quarter 2007
distribution was 22% higher than the fourth-quarter 2006
distribution. Our relationship with Williams and ability to
raise capital has us well-positioned for continued growth
through both internal projects and acquisition transactions with
Williams and other third parties.
Recent
Events
Conversion of Subordinated Units. On
January 28, 2008, our general partners board of
directors confirmed that the financial test contained in our
partnership agreement required for conversion of all of our
50
outstanding subordinated units into common units had been
satisfied. Accordingly, our 7,000,000 subordinated units held by
four subsidiaries of Williams converted into common units on a
one-for-one basis on February 19, 2008.
Acquisition of Wamsutter Ownership
Interests. On December 11, 2007, we acquired
the Wamsutter Ownership Interests from Williams for aggregate
consideration of $750.0 million. The acquisition was
financed with the debt and equity issuances described below.
|
|
|
|
|
Issuance of Common Units. We sold 9,250,000
common units in a public offering. We received net proceeds of
approximately $335.2 million from the sale of the common
units after deducting underwriting discounts but before
estimated offering expenses. On January 9, 2008, we sold an
additional 800,000 common units to the underwriters upon the
underwriters partial exercise of their option to purchase
additional common units.
|
|
|
|
Issuance of Common Units to Williams. We
issued approximately $157.2 million of common units, or
4,163,527 common units, to Williams. On January 9, 2008, we
used the net proceeds from the partial exercise of the
underwriters option to redeem 800,000 common units from
Williams at a price per common unit of $36.24 ($37.75, net of
underwriter discount).
|
|
|
|
Increase in General Partners Capital
Account. The general partner contributed
approximately $10.3 million to maintain its 2% general
partner interest.
|
|
|
|
Term Loan. We borrowed $250.0 million
under the term loan provisions of our new credit facility
discussed below.
|
Williams Partners L.P.s New Credit
Facility. We entered into a $450.0 million
five-year senior unsecured credit facility comprised initially
of a $250.0 million term loan used to finance a portion of
the aggregate consideration for the Wamsutter Ownership
Interests and a $200.0 million revolving credit facility,
which is available for borrowings and letters of credit. On
November 21, 2007, we were removed as a borrower under
Williams $1.5 billion revolving credit facility and;
therefore, no longer have access to a $75.0 million
borrowing capacity under that facility.
Ignacio gas processing plant fire. On
November 28, 2007, there was a fire at the Ignacio gas
processing plant. This fire resulted in severe damage to the
facilitys cooling tower, control room, adjacent warehouse
buildings and control systems. The plant was shut down from
November 28 to January 18, 2008. There were no injuries as
a result of this incident and the plant now has full cryogenic
recovery and fractionation facilities in operation.
Additional Investment in Discovery. On
June 28, 2007, we acquired an additional 20% limited
liability company interest in Discovery from Williams for
aggregate consideration of $78.0 million.
Conversion of Class B Units. On
May 21, 2007, our outstanding Class B units were
converted into common units on a one-for-one basis by a majority
vote of common units eligible to vote.
How We
Evaluate Our Operations
Our management uses a variety of financial and operational
measures to analyze our segment performance, including the
performance of Wamsutter and Discovery. These measurements
include:
|
|
|
|
|
Four Corners and Wamsutters gathering and processing
volumes;
|
|
|
|
Four Corners and Wamsutters net liquids margin;
|
|
|
|
Discoverys and Carbonate Trends pipeline throughput
volumes;
|
|
|
|
Discoverys gross processing margins;
|
|
|
|
Conways fractionation volumes;
|
|
|
|
Conways storage revenues;
|
51
|
|
|
|
|
operating and maintenance expenses; and
|
|
|
|
general and administrative 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 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,
which is net of transportation and fractionation charges. 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 and changes in the cost of
transporting and fractionating the NGLs.
Wamsutter
Gathering and Processing Volumes. The
gathering volumes on the Wamsutter system and volumes processed
at the Echo Springs natural gas processing plant are important
components of maximizing its profitability. The Wamsutter
pipeline system gathers approximately 69% of the natural gas
produced in the Washakie Basin and connects with the Colorado
Interstate Gas, Wyoming Interstate Gas, Southern Star Central
Gas Pipeline, and Rockies Express systems that transport natural
gas to end markets from the basin. Wamsutters gathering
volumes from existing wells connected to our pipelines will
naturally decline over time. Accordingly, to maintain or
increase gathering volumes Wamsutter must continually obtain new
supplies of natural gas. The Wamsutter system processes natural
gas under keep-whole and fee-based contracts. Wamsutters
processing volumes are largely dependent on the volume of
natural gas gathered on its system.
Net Liquids Margin. The net liquids margin is
an important measure of Wamsutters ability to maximize the
profitability of its processing operations. Liquids margin is
derived by deducting the cost of shrink replacement gas from the
revenue Wamsutter receives from the sale of its NGLs, which is
net of transportation and fractionation charges. 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, Wamsutter
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 and changes in the cost of
transporting and fractionating the NGLs.
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 measuring
the results of these assets. 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 and Discoverys 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 and Discoverys ability to maintain existing
supplies of natural gas and obtain new supplies are impacted by
(1) the level of workovers or
52
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 and Discovery 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:
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|
|
|
|
the rates stipulated under fee-based contracts multiplied by the
actual volumes processed;
|
|
|
|
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. 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.
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 system
gains and losses, 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. In the course of
providing gathering, processing and treating services to our
customers, we realize over and under deliveries of
customers products and over and under purchases of shrink
replacement gas when our purchases vary from operational
requirements. In addition, we realize gains and losses which we
believe are related to inaccuracies inherent in the gas
measurement process. These gains and losses are reflected in
operating and maintenance expense as system gains and losses.
These system gains and losses are an unpredictable component of
our operating costs. Leased compression services are dependent
upon the extent and amount of additional compression needed to
meet the needs of our 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.
53
General
and Administrative Expenses
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 considers revenues;
property, plant and equipment; and payroll. Certain of these
costs are charged back to the other Conway fractionator
co-owners. Our share of direct and allocated administrative
expenses is reflected in General and administrative
expense Affiliate in the accompanying Consolidated
Statements of Income.
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. 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.
Critical
Accounting Policies and Estimates
Our financial statements reflect the selection and application
of accounting policies that require management to make
significant estimates and assumptions. The selection of these
policies has been discussed with the audit committee of the
board of directors of our general partner. We believe that the
following are the more critical judgment areas in the
application of our accounting policies that currently affect our
financial condition and results of operations.
Impairment
of Long-Lived Assets and Investments
We evaluate our long-lived assets and investments for impairment
when we believe events or changes in circumstances indicate that
we may not be able to recover the carrying value of certain
long-lived assets or that the decline in value of an investment
is other-than-temporary.
During 2007, we determined that the carrying value of our
Carbonate Trend pipeline may not be recoverable because of
forecasted declining cash flows. As a result, we recognized an
impairment charge of $10.4 million to reduce the carrying
value to managements estimate of fair value at
December 31, 2007. (See Note 7, Other (Income)
Expense, in our Notes to Consolidated Financial Statements.) Our
computations utilized judgments and assumptions in the following
areas:
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|
estimated future volumes and rates; and
|
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|
|
estimated earnings multiples that could be realized in a sale of
the assets.
|
Our projections are sensitive to changes in the above
assumptions. A change to the estimated earnings multiple of one
times would increase or decrease our fair value estimate by
approximately $1.2 million.
Accounting
for Asset Retirement Obligations
We record asset retirement obligations for legal and contractual
obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development
and/or
normal use of the asset in the period in which it is incurred if
a reasonable estimate of fair value can be made. At
December 31, 2007, we have an accrued asset retirement
obligation liability of $8.7 million including estimated
retirement costs associated with the abandonment of Four
Corners gas processing and compression facilities located
on leased land, Four Corners wellhead connections on
federal land, Conways underground storage caverns and
brine ponds in accordance with KDHE regulations and the
Carbonate Trend pipeline. Our estimate utilizes
54
judgments and assumptions regarding the extent of our
obligations, the costs to abandon and the timing of abandonment.
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 2007, and the
expected retirement date for the Carbonate Trend pipeline had
been significantly shortened, the recorded asset retirement
obligation would have increased by approximately $3 million
to $4 million. (See Note 8, Property, Plant and
Equipment, in our 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, 2007, we have an accrual for estimated
environmental remediation obligations of $4.0 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. (Please read Environmental and
Note 14, Commitments and Contingencies, in our Notes to
Consolidated Financial Statements.)
Revenue
Recognition Derivative Instruments and Hedging
Activities
We hold a portfolio of nontrading energy contracts. We review
these contracts to determine whether or not they are
derivatives. If they are derivatives, we further assess whether
the contracts qualify for either cash flow hedge accounting or
the normal purchases and normal sales exception.
The determination of whether a derivative contract qualifies as
a cash flow hedge includes an analysis of historical market
price information to assess whether the derivative is expected
to be highly effective in achieving offsetting cash flows
attributed to the hedged risk. We also assess whether the hedged
forecasted transaction is probable of occurring. This assessment
requires us to exercise judgment and consider a wide variety of
factors in addition to our intent, including internal and
external forecasts, historical experience, changing market and
business conditions, our financial and operational ability to
carry out the forecasted transaction, the length of time until
the forecasted transaction is projected to occur and the
quantity of the forecasted transaction. In addition, we compare
actual cash flows to those that were expected from the
underlying risk. If a hedged forecasted transaction is not
probable of occurring, or if the derivative contract is not
expected to be highly effective, the derivative does not qualify
for hedge accounting.
Derivatives for which the normal purchases and normal sales
exception has been elected are accounted for on an accrual
basis. In determining whether a derivative is eligible for this
exception, we assess whether the contract provides for the
purchase or sale of a commodity that will be physically
delivered in quantities expected to be used or sold over a
reasonable period in the normal course of business. In making
this assessment, we consider numerous factors, including the
quantities provided under the contract in relation to our
business needs, delivery locations per the contract in relation
to our operating locations, duration of time between entering
the contract and delivery, past trends and expected future
demand, and our past practices and customs with regard to such
contracts. Additionally, we assess whether it is probable that
the contract will result in physical delivery of the commodity
and not net financial settlement.
The fair value of derivative contracts is determined based on
the nature of the transaction and the market in which
transactions are executed. We also incorporate assumptions and
judgments about counterparty performance and credit
considerations in our determination of their fair value. Our
contracts are generally executed in over-the-counter markets
with quoted prices. The fair value of all derivative contracts
is
55
continually subject to change as the underlying commodity market
changes and our assumptions and judgments change.
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, 2007. The results of operations by segment are
discussed in further detail following this consolidated overview
discussion.
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|
|
|
|
|
|
|
|
|
|
|
|
|
% Change
|
|
|
|
|
|
% Change
|
|
|
|
|
|
|
|
|
|
from
|
|
|
|
|
|
from
|
|
|
|
|
|
|
2007
|
|
|
2006(1)
|
|
|
2006
|
|
|
2005(1)
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
572,817
|
|
|
|
+2
|
%
|
|
$
|
563,410
|
|
|
|
+9
|
%
|
|
$
|
514,972
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
181,698
|
|
|
|
(4
|
)%
|
|
|
175,508
|
|
|
|
+1
|
%
|
|
|
177,527
|
|
Operating and maintenance expense
|
|
|
162,343
|
|
|
|
(5
|
)%
|
|
|
155,214
|
|
|
|
(20
|
)%
|
|
|
129,759
|
|
Depreciation, amortization and accretion
|
|
|
46,492
|
|
|
|
(6
|
)%
|
|
|
43,692
|
|
|
|
(3
|
)%
|
|
|
42,579
|
|
General and administrative expense
|
|
|
45,628
|
|
|
|
(16
|
)%
|
|
|
39,440
|
|
|
|
(8
|
)%
|
|
|
36,615
|
|
Taxes other than income
|
|
|
9,624
|
|
|
|
(7
|
)%
|
|
|
8,961
|
|
|
|
(6
|
)%
|
|
|
8,446
|
|
Other (income) expense, net
|
|
|
12,095
|
|
|
|
NM
|
|
|
|
(2,473
|
)
|
|
|
NM
|
|
|
|
630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
457,880
|
|
|
|
(9
|
)%
|
|
|
420,342
|
|
|
|
(6
|
)%
|
|
|
395,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
114,937
|
|
|
|
(20
|
)%
|
|
|
143,068
|
|
|
|
+20
|
%
|
|
|
119,416
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|
Equity earnings Wamsutter
|
|
|
76,212
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|
|
|
+24
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%
|
|
|
61,690
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|
|
|
+52
|
%
|
|
|
40,555
|
|
Equity earnings Discovery
|
|
|
28,842
|
|
|
|
+60
|
%
|
|
|
18,050
|
|
|
|
+52
|
%
|
|
|
11,880
|
|
Interest expense
|
|
|
(58,348
|
)
|
|
|
NM
|
|
|
|
(9,833
|
)
|
|
|
(19
|
)%
|
|
|
(8,238
|
)
|
Interest income
|
|
|
2,988
|
|
|
|
+87
|
%
|
|
|
1,600
|
|
|
|
NM
|
|
|
|
165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
164,631
|
|
|
|
(23
|
)%
|
|
|
214,575
|
|
|
|
+31
|
%
|
|
|
163,778
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
+100
|
%
|
|
|
(1,405
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
164,631
|
|
|
|
(23
|
)%
|
|
$
|
214,575
|
|
|
|
+32
|
%
|
|
$
|
162,373
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
2007 vs.
2006
Revenues increased $9.4 million, or 2%, due primarily to
higher revenues in our Gathering and Processing West
segment, slightly offset by lower revenues in our NGL Services
segment. Revenues in our Gathering and Processing
West segment increased due primarily to higher
product sales, partially offset by lower gathering, processing
and other revenues. Revenues in our NGL Services segment
decreased due primarily to lower product sales and fractionation
revenues, partially offset by higher storage and product upgrade
fee revenues. These fluctuations are discussed in detail in the
Results of Operations Gathering
and Processing West section and
Results of Operations NGL
Services sections.
56
Product cost and shrink replacement increased $6.2 million,
or 4%, due primarily to increased NGL purchases from producers
in our Gathering and Processing West segment,
partially offset by lower shrink requirements related primarily
to the fire at Ignacio in the same segment and decreased product
sales volumes in our NGL Services segment. These fluctuations
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 $7.1 million,
or 5%, due primarily to higher expense in our Gathering and
Processing West segment, partially offset by lower
expense in our NGL Services segment. Operating and maintenance
expense in our Gathering and Processing West segment
increased due primarily to higher fuel costs, rent expense and
leased compression, partially offset by lower maintenance costs.
Operating and maintenance expense in our NGL Services segment
decreased due primarily to lower fuel and power costs related to
the lower fractionator throughput. These fluctuations are
discussed in detail in the Results of
Operations Gathering and Processing
West and Results of
Operations NGL Services sections.
General and administrative expense increased $6.2 million,
or 16%, due primarily to higher Williams technical support
services and other charges allocated by Williams to us for
various administrative support functions.
Other (income) expense changed from $2.5 million income in
2006 to $12.1 million expense in 2007, due primarily to the
fourth quarter 2007 impairment of the Carbonate Trend pipeline
and a $3.6 million gain in 2006 on the sale of the
La Maquina carbon dioxide treating facility in the
Gathering and Processing West segment.
Operating income declined $28.1 million, or 20%, due
primarily to lower segment operating income in our Gathering and
Processing West segment, the fourth-quarter 2007
impairment of the Carbonate trend pipeline and higher general
and administrative expense, partially offset by higher storage
revenues and product storage upgrade fees and lower operating
and maintenance expenses in our NGL Services segment. Segment
operating income decreased in our Gathering and
Processing West segment due primarily to the impact
of the Ignacio plant fire. These fluctuations are discussed in
detail in the Results of
Operations Gathering and Processing
West and Results of
Operations NGL Services sections.
Equity earnings from Wamsutter increased $14.5 million, or
24%, due primarily to higher net liquids margins and fee-based
gathering and processing revenues, partially offset by higher
general and administrative expenses. Wamsutters results
are discussed in detail in the Results of
Operations Gathering and Processing
West section.
Equity earnings from Discovery increased $10.8 million, or
60%, due primarily to higher gross processing margins that more
than offset lower fee-based revenues and higher operating and
maintenance expense. Discoverys results are discussed in
detail in the Results of
Operations Gathering and Processing
Gulf section.
Interest expense increased $48.5 million due primarily to
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 Four Corners.
Interest income increased $1.4 million, or 87%, due to
higher cash balances during the first and second quarters of
2007.
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 combined with increased storage revenues and
product sales 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.
57
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.
Operating income increased $23.7 million, or 20%, due
primarily to our Gathering and Processing West
segment where higher net liquids margins and fee-based revenues
were partially offset by higher operating and maintenance
expense.
Equity earnings from Wamsutter increased $21.1 million, or
52%, due primarily to higher net liquids margins. These
increases are discussed in detail in the
Results of Operations Gathering
and Processing West section.
Equity earnings from Discovery increased $6.2 million, or
52%, due primarily to Discoverys higher gross processing
margins partially offset by 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 issued in June and
December of 2006 to finance a portion of our acquisition 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.
Results
of operations Gathering and Processing
West
The Gathering and Processing West segment includes
our Four Corners natural gas gathering, processing and
treating assets and our ownership interest in Wamsutter.
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|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Segment revenues
|
|
$
|
513,787
|
|
|
$
|
502,313
|
|
|
$
|
463,203
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
170,434
|
|
|
|
159,997
|
|
|
|
165,706
|
|
Operating and maintenance expense
|
|
|
135,782
|
|
|
|
124,763
|
|
|
|
104,648
|
|
Depreciation, amortization and accretion
|
|
|
41,523
|
|
|
|
40,055
|
|
|
|
38,960
|
|
General and administrative expense direct
|
|
|
7,790
|
|
|
|
11,920
|
|
|
|
12,230
|
|
Taxes other than income
|
|
|
8,869
|
|
|
|
8,245
|
|
|
|
7,746
|
|
Other (income) expense, net
|
|
|
1,698
|
|
|
|
(2,476
|
)
|
|
|
636
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses, including interest income
|
|
|
366,096
|
|
|
|
342,504
|
|
|
|
329,926
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
147,691
|
|
|
|
159,809
|
|
|
|
133,277
|
|
Equity earnings Wamsutter
|
|
|
76,212
|
|
|
|
61,690
|
|
|
|
40,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
223,903
|
|
|
$
|
221,499
|
|
|
$
|
173,832
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Four
Corners
2007 vs.
2006
Revenues increased $11.5 million, or 2%, due primarily to
$23.7 million higher product sales, partially offset by
$9.5 million lower gathering and processing revenues and
$2.7 million lower other revenues. Product sales increased
due primarily to:
|
|
|
|
|
$24.2 million related to a 17% 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; and
|
58
|
|
|
|
|
$15.3 million higher sales of NGLs on behalf of third party
producers from whom we purchase NGLs for a fee under their
contracts. We subsequently sell the NGLs to an affiliate. This
increase is offset by higher associated product costs of
$15.3 million discussed below.
|
These product sales increases were partially offset by
$12.7 million lower revenues related to an 8% decrease in
NGL volumes that Four Corners received under certain processing
contracts. Based on 2006 prices, the $12.7 million includes
approximately $9.3 million related to NGL volume reductions
caused by the fire at the Ignacio gas processing plant in late
November 2007.
Additionally, product sales decreased in 2007 as a result of
$3.0 million lower condensate and LNG sales.
Gathering and processing revenues decreased $9.5 million,
or 4%, due primarily to $8.3 million lower revenue from a
3% decrease in gathered and processed volumes and a
$1.3 million decrease from a lower average rate charged for
these services. Based on 2006 prices, the $8.3 million
includes approximately $5.5 million related to gathered and
processed volume reductions caused by the fire at the Ignacio
plant. The decrease in the average rate was due primarily to a
lower rate on one of our agreements with an affiliate that is
adjusted annually based on changes in the average price of
natural gas. The price of natural gas was substantially higher
in 2006 than 2007.
Product cost and shrink replacement increased
$10.4 million, or 7%, due primarily to:
|
|
|
|
|
$15.3 million increase from third party producers who
elected to have us purchase their NGLs, which was offset by the
corresponding increase in product sales revenues discussed
above; and
|
|
|
|
$2.8 million increase from 5% higher average natural gas
prices.
|
These increases were partially offset by $6.4 million from
10% lower volumetric shrink requirements under our Four
Corners keep-whole processing contracts. Based on 2006
prices, the $6.4 million includes approximately
$5.1 million related to reduced processing activity caused
by the fire at the Ignacio plant.
Operating and maintenance expense increased $11.0 million,
or 9%, due primarily to:
|
|
|
|
|
$9.6 million higher non-shrink natural gas purchases caused
primarily by $7.9 million higher natural gas costs for
steam generation at our Milagro facility. In 2006, our purchase
of this natural gas from an affiliate of Williams was favorably
impacted by that affiliates fixed price natural gas fuel
contracts. These contracts expired in the fourth quarter of
2006. Additionally, in 2007 gathering fuel increased
$3.3 million including approximately $2.3 million
related to lower customer fuel reimbursements and operational
inefficiencies caused by the fire at the Ignacio plant.
|
|
|
|
$3.9 million higher rent expense related to the purchase of
a temporary special business license upon the expiration of a
right-of-way agreement with the Jicarilla Apache Nation.
|
|
|
|
$3.4 million higher leased compression costs under
agreements that are currently being renegotiated but are
presently on month-to-month terms.
|
|
|
|
$1.0 million higher operating expense for our payment of
the property insurance deductible for the fire at the Ignacio
gas processing plant in late November 2007.
|
Partially offsetting these increases were $5.6 million
lower materials and supplies related primarily to decreased
equipment maintenance activity.
General and administrative expense direct decreased
$4.1 million, or 35%, due primarily to certain management
costs that were directly charged to the segment in 2006 but
allocated to the partnership in 2007. As a result of this
change, these 2007 management costs are included in our overall
general and administrative expense but not in our segment
results.
Other (income) expense, net in 2006 includes a $3.6 million
gain recognized on the sale of the LaMaquina treating facility.
The LaMaquina treating facility was shut down in 2002 and
impairments were recorded in 2003 and 2004.
59
Segment operating income decreased $12.1 million, or 8%,
due primarily to the estimated $13.0 million combined
impact of the fire at the Ignacio gas processing plant. Higher
product sales margins, excluding the impact of the fire, of
$17.5 million and $4.1 million lower direct general
and administrative expense were offset by $7.7 million
higher operating and maintenance expense excluding fire-related
items, $4.0 million lower fee-based gathering and
processing revenues not related to the fire, $4.2 million
lower other (income) expense and $2.7 million lower
miscellaneous revenue.
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; 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.
Product cost and shrink replacement gas costs decreased
$5.7 million, or 3%, due primarily to:
|
|
|
|
|
$9.0 million lower purchases 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
|
|
|
|
$6.0 million 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 keep-whole processing contracts.
Operating and maintenance expense increased $20.1 million,
or 19%, due primarily to:
|
|
|
|
|
$13.4 million higher materials and supplies, outside
services and other operating expenses related primarily to
increased compression and maintenance costs;
|
|
|
|
$4.7 million higher labor and benefits caused by higher
Williams annual incentive program costs and the addition
of new personnel; and
|
|
|
|
$2.0 million higher non-shrink natural gas purchases due
primarily to higher volumetric gathering fuel requirements and
higher system losses.
|
60
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 2006. The LaMaquina treating
facility was shut down in 2002 and impairments were recorded in
2003 and 2004.
Segment operating income 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
$3.1 million improvement in other (income) expense, net.
These increases were partially offset by $20.1 million
higher operating and maintenance expense.
Outlook
for 2008
|
|
|
|
|
We anticipate that growth capital investments we completed in
2007 to support ConocoPhillips and other producer
customers drilling activity, expansion opportunities and
production enhancement activities should be sufficient to more
than offset the historical decline and slightly increase 2008
average gathering and processing volumes above 2007.
|
|
|
|
We have realized above average net liquids margins at our gas
processing plants in recent years due primarily to increasing
prices for NGLs. Based on first-quarter 2008 prices for NGLs and
natural gas and the derivatives described below,
per-unit
margins in 2008 could meet or exceed record levels realized in
2007. However, the prices of NGLs and natural gas can quickly
fluctuate in response to a variety of factors that are
impossible to control and in particular NGL pricing is typically
impacted negatively by recessionary economic conditions.
|
|
|
|
In December 2007 and January 2008, we entered into financial
swap contracts to hedge 5.4 million gallons of monthly
forecasted NGL sales for February through December 2008. Of the
5.4 million gallons, 4.2 million are ethane sales. We
also entered into fixed price natural gas purchase contracts to
hedge the price of our natural gas shrink replacement associated
with these NGL sales, which are derived from keep-whole
processing contracts. As a result, we have effectively hedged a
margin of $31.2 million or an average $0.52 per gallon on
these NGL sales in 2008.
|
|
|
|
We anticipate that operating costs, excluding compression and
system gains and losses, will remain stable as compared to 2007.
Compression cost increases are dependent upon the extent and
amount of additional compression needed to meet the needs of our
customers and the cost at which compression can be purchased,
leased and operated. System gains and losses are an
unpredictable component of our operating costs.
|
|
|
|
Our right of way agreement with the Jicarilla Apache Nation
(JAN), which covered certain gathering system assets in Rio
Arriba County of northern New Mexico, expired on
December 31, 2006. We currently operate our gathering
assets on the JAN lands pursuant to a special business license
granted by the JAN which expires February 29, 2008. We are
engaged in discussions with the JAN designed to result in the
sale of our gathering assets which are located on or are
isolated by the JAN lands. Provided the parties are able to
reach an acceptable value on the sale of the subject gathering
assets, our expectation is that we will nonetheless maintain
partial revenues associated with gathering and processing
downstream of the JAN lands and continue to operate the
gathering assets on the JAN lands for an undetermined period of
time beyond February 29, 2008. Based on current estimated
gathering volumes and a range of annual average commodity prices
over the past five years, we estimate that gas produced on or
isolated by the JAN lands represents approximately $20 million
to $30 million of Four Corners annual gathering and
processing revenue less related product costs.
|
61
Wamsutter
Wamsutter is accounted for using the equity method of
accounting. As such, our interest in Wamsutters 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 Wamsutter.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Revenues
|
|
$
|
175,309
|
|
|
$
|
176,546
|
|
|
$
|
177,090
|
|
Costs and expenses, including interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
46,039
|
|
|
|
71,088
|
|
|
|
100,393
|
|
Operating and maintenance expense
|
|
|
18,257
|
|
|
|
17,047
|
|
|
|
12,505
|
|
Depreciation, amortization and accretion
|
|
|
18,424
|
|
|
|
16,189
|
|
|
|
14,321
|
|
General and administrative expense
|
|
|
12,623
|
|
|
|
8,866
|
|
|
|
8,131
|
|
Taxes other than income
|
|
|
1,637
|
|
|
|
1,411
|
|
|
|
1,175
|
|
Other, net
|
|
|
944
|
|
|
|
255
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
97,924
|
|
|
|
114,856
|
|
|
|
136,535
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
77,385
|
|
|
|
61,690
|
|
|
|
40,555
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
(48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
77,385
|
|
|
$
|
61,690
|
|
|
$
|
40,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest
|
|
$
|
76,212
|
|
|
$
|
61,690
|
|
|
$
|
40,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 vs.
2006
Revenues decreased $1.2 million, or 1%, due primarily to a
$12.3 million decrease in product sales revenues,
substantially offset by a $10.0 million increase in
gathering and fee-based processing revenues.
Product sales revenues decreased $12.3 million, or 11%, due
primarily to:
|
|
|
|
|
$20.8 million related to a 20% decrease in NGL volumes that
Wamsutter received under certain processing contracts. Effective
January 1, 2007, one significant customer made an election
to switch from a keep-whole processing arrangement to a
fee-based processing arrangement for three years. This
significantly decreased the NGL volumes received by Wamsutter
under its keep-whole processing contracts; and
|
|
|
|
$3.4 million lower sales of NGLs on behalf of third party
producers who sell their NGLs to Wamsutter under their
contracts. Under these arrangements, Wamsutter purchases the
NGLs from the third party producers and sells them to an
affiliate. This decrease is offset by lower associated product
costs of $3.4 million discussed below.
|
These product sales decreases were partially offset by a
$12.1 million increase related to 14% higher average NGL
sales prices resulting from an increase in market prices for
these commodities between the two periods.
Gathering and fee-based processing revenues increased
$5.6 million due to a 9% increase in the average fee
received for these services and $4.4 million due to an 8%
increase in volumes. The average fee increased as a result of
fixed annual percentage or inflation-sensitive contractual
escalation clauses and incremental fee revenues from completed
gathering system expansion projects. Certain agreements provide
incremental fee-based revenues upon the completion of projects
that lower system pressures, allowing these customers to flow
higher volumes from their existing wells.
62
Other revenues increased $1.0 million, or 19%, due
primarily to higher revenue from minimum throughput provisions
under certain gathering contracts.
Product cost and shrink replacement decreased
$25.0 million, or 35%, due primarily to:
|
|
|
|
|
$11.2 million decrease from 21% lower average natural gas
prices. Our 2007 net liquids margins were impacted
favorably by very low local shrink replacement natural gas costs
in the Rocky Mountain area as compared with other natural gas
markets;
|
|
|
|
$10.4 million decrease from 16% lower volumetric shrink
requirements under Wamsutters keep-whole processing
contracts following the election of one customer to switch to
fee-based processing discussed above; and
|
|
|
|
$3.4 million lower product cost related to lower sales of
NGLs on behalf of third party producers who sell their NGLs to
Wamsutter under their contracts as discussed above.
|
Operating and maintenance expense increased $1.2 million,
or 7%, due primarily to:
|
|
|
|
|
$4.2 million higher materials and supplies and outside
services expense caused primarily by increased equipment
maintenance activity; and
|
|
|
|
$1.6 million from various smaller increases for rent, labor
and utilities.
|
These increases were partially offset by $4.9 million lower
non-shrink natural gas purchases due primarily to higher system
gains.
Depreciation and accretion expense increased $2.2 million,
or 14%, due primarily to new assets placed into service.
General and administrative expenses increased $3.8 million,
or 42%, due primarily to higher charges allocated by Williams to
Wamsutter for various technical and administrative support
functions.
Net income increased $15.7 million, or 25%, due primarily
to $12.9 million higher net liquids margins and
$10.0 million higher gathering and fee-based processing
revenues, partially offset $3.8 million higher general and
administrative expenses and $2.2 million higher
depreciation and accretion expense.
2006 vs.
2005
Revenues decreased $0.5 million due primarily to an
$8.4 million decrease in product sales revenues
substantially offset by a $7.4 million increase in
gathering and fee-based processing revenues.
Product sales revenues decreased $8.4 million, or 7%, due
primarily to:
|
|
|
|
|
$13.1 million related to a 12% decrease in NGL volumes that
Wamsutter received under certain processing contracts. The total
gas available for processing increased from 2005 to 2006;
however, due to limited plant capacity, not all of this
increased volume could be processed. The increase in total gas
available for processing generally resulted in greater NGL
volumes for Wamsutters customers and lower NGL volumes
received under its keep-whole processing contracts; and
|
|
|
|
a $4.7 million decrease in sales of excess shrink
replacement gas. Wamsutter sold substantial volumes of excess
shrink replacement gas during the fourth quarter of 2005.
Following the hurricanes of 2005, there were unusually high
natural gas prices and reduced ethane processing which caused
Wamsutter to have excess shrink replacement natural gas.
Wamsutter elected to take advantage of the higher natural gas
prices and sell the excess natural gas rather than hold it for
future requirements. There is a corresponding decrease in
product costs discussed below.
|
These product sales decreases were partially offset by a
$9.0 million increase related to 9% higher average NGL
sales prices resulting from an increase in market prices for
these commodities between the two periods.
63
Gathering and fee-based processing revenues increased
$4.2 million due to an 8% increase in the average fee
received for these services and $3.3 million due to a 7%
increase in volumes. The average fee increased as a result of
fixed annual percentage or inflation-sensitive contractual
escalation clauses and incremental fee revenues discussed
previously.
Product cost and shrink replacement decreased
$29.3 million, or 29%, due primarily to:
|
|
|
|
|
$13.1 million decrease from 17% lower average natural gas
prices;
|
|
|
|
$11.7 million decrease from 13% lower volumetric shrink
requirements under keep-whole processing contracts due to
limited plant processing capacity discussed above; and
|
|
|
|
$4.7 million lower product cost related to the sale of
excess shrink replacement gas as discussed above.
|
Operating and maintenance expense increased $4.5 million,
or 36%, due primarily to a $2.1 million increase in
non-shrink natural gas purchases resulting from higher system
losses, a $1.0 million increase in rental expense for
leased compression added in late 2005 and a $0.5 million
increase in labor and benefits expense.
Depreciation and accretion expense increased $1.9 million,
or 13%, due primarily to new assets placed into service in 2006.
Net income increased $21.2 million, or 52%, due primarily
to $20.9 million in higher net liquids margins and
$7.4 million higher gathering and fee-based processing
revenues, partially offset by $4.5 million higher operating
and maintenance expense and $1.9 million higher
depreciation and accretion expense.
Outlook
for 2008
|
|
|
|
|
Compared to 2007, we anticipate that sustained drilling
activity, expansion opportunities and production enhancement
activities by producers should be sufficient to more than offset
the historical production decline and to increase average
gathering volumes.
|
|
|
|
Total gas available for processing has increased in recent
years; however, due to limited plant capacity, not all of this
increased volume could be processed. This results in lower NGL
volumes received under keep-whole processing contracts. In 2008,
we anticipate that a new agreement providing us with third party
processing at Colorado Interstates Rawlins natural gas
processing plant will increase the processing capacity available
to Wamsutter by
80 MMcf/d
or approximately 20%. We anticipate that this third party
processing will result in an increase in NGL volumes sold by
Wamsutter.
|
|
|
|
In 2007, Wamsutter realized record high net liquids margins at
its Echo Springs plant. The 2007 net liquids margins were
significantly impacted by very low local shrink replacement
natural gas costs as compared with other natural gas markets. We
do not expect our shrink replacement natural gas costs will
remain at these levels during 2008. Accordingly, we expect
per-unit
margins in 2008 will remain higher in relation to five-year
historical averages, but below the record levels realized in
2007.
|
|
|
|
Operating costs, excluding system gains and losses and new
third-party processing fees at the Colorado Interstates
Rawlins plant, are expected to be approximately consistent with
those in 2007. System gains and losses are an unpredictable
component of Wamsutters operating costs. Additionally, the
new third-party processing at Colorado Interstates Rawlins
plant mentioned above requires that we pay a fee per MMbtu
processed that will add approximately $4.0 million to
$5.0 million in operating costs.
|
64
Results
of operations Gathering and Processing
Gulf
The Gulf segment includes the Carbonate Trend gathering pipeline
and our 60% ownership interest in Discovery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Segment revenues
|
|
$
|
2,119
|
|
|
$
|
2,656
|
|
|
$
|
3,515
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
1,875
|
|
|
|
1,660
|
|
|
|
714
|
|
Depreciation and accretion
|
|
|
1,249
|
|
|
|
1,200
|
|
|
|
1,200
|
|
General and administrative expense direct
|
|
|
|
|
|
|
1
|
|
|
|
2
|
|
Other, net
|
|
|
10,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
13,530
|
|
|
|
2,861
|
|
|
|
1,916
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss)
|
|
|
(11,411
|
)
|
|
|
(205
|
)
|
|
|
1,599
|
|
Equity earnings Discovery
|
|
|
28,842
|
|
|
|
18,050
|
|
|
|
11,880
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
17,431
|
|
|
$
|
17,845
|
|
|
$
|
13,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carbonate
Trend
2007 vs.
2006
Segment operating loss increased $11.2 million due
primarily to the $10.4 million fourth quarter 2007
impairment of the Carbonate Trend pipeline. (See Note 7,
Other (Income) Expense, of our Notes to Consolidated Financial
Statements.)
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 following 2005 hurricane activity. Additionally, 2005
included $0.5 million in revenues from the settlement of a
contractual volume deficiency payment.
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Revenues
|
|
$
|
260,672
|
|
|
$
|
197,313
|
|
|
$
|
122,745
|
|
Costs and expenses, including interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
155,704
|
|
|
|
119,552
|
|
|
|
64,467
|
|
Operating and maintenance expense
|
|
|
28,988
|
|
|
|
23,049
|
|
|
|
10,165
|
|
General and administrative expense
|
|
|
2,280
|
|
|
|
2,150
|
|
|
|
2,053
|
|
Depreciation and accretion
|
|
|
25,952
|
|
|
|
25,562
|
|
|
|
24,794
|
|
Interest income
|
|
|
(1,799
|
)
|
|
|
(2,404
|
)
|
|
|
(1,685
|
)
|
Other (income) expense, net
|
|
|
1,476
|
|
|
|
(679
|
)
|
|
|
2,123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
212,601
|
|
|
|
167,230
|
|
|
|
101,917
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative effect of change in accounting
principle
|
|
$
|
48,071
|
|
|
$
|
30,083
|
|
|
$
|
20,828
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest
|
|
$
|
28,842
|
|
|
$
|
18,050
|
|
|
$
|
11,880
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
65
2007 vs.
2006
Revenues increased $63.4 million, or 32%, due primarily to
$73.8 million higher product sales, partially offset by a
$9.9 million reduction in fee-based transportation,
gathering, processing and fractionation revenues. The 2006
period included revenues from the Tennessee Gas Pipeline (TGP)
and the Texas Eastern Transmission Company (TETCO) open season
agreements. The open seasons provided outlets for natural gas
that was stranded following damage to third-party facilities
during hurricanes Katrina and Rita in 2005. TGPs open
season contract came to an end in early 2006. TETCOs
volumes continued throughout 2006 and in October 2006 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 $73.8 million primarily due to:
|
|
|
|
|
$36.8 million from higher NGL volumes sold under certain
processing contracts, including the October 2006 TETCO
agreement, which is a percent-of-liquids agreement;
|
|
|
|
$26.2 million from higher average NGL prices received for
these NGLs;
|
|
|
|
$8.1 million increase in NGL sales related to third-party
processing customers elections to have Discovery purchase
their NGLs under an option in their contracts; and
|
|
|
|
$2.7 million from higher sales of excess fuel and shrink
replacement gas.
|
The $9.9 million decrease in fee-based transportation,
gathering, processing and fractionation revenues is due
primarily to the reduced fee-based revenues related to
processing TGP and TETCO volumes under the open season
agreements discussed above.
Product cost and shrink replacement increased
$36.2 million, or 30%, due primarily to
|
|
|
|
|
$19.4 million higher volumetric natural gas requirements
from increased processing activity;
|
|
|
|
$7.8 million higher product purchase costs for the
processing customers who elected to have Discovery purchase
their NGLs; and
|
|
|
|
$2.9 million higher product cost associated with the excess
fuel and shrink replacement gas sales discussed above.
|
Operating and maintenance expense increased $5.9 million,
or 26%, due primarily to $2.7 million higher property
insurance premiums related to the increased hurricane activity
in the Gulf Coast region in prior years, $1.6 million from
costs related to decommissioning two pipelines and other
increased repair, maintenance and labor expenses.
Other (income) expense, net changed from $0.7 million of
income in 2006 to $1.5 million of expense in 2007. The
increased expense was due primarily to a decrease in foreign
currency transaction gains and the loss on retirement of the two
pipelines that were decommissioned. The non-cash foreign
currency transaction gains resulted 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 $18.0 million, or 60%, due primarily
to $39.0 million higher gross processing margins resulting
from higher NGL sales volumes and NGL prices, partially offset
by $9.9 million lower fee-based transportation, gathering,
processing and fractionation revenues, $5.9 million higher
operating and maintenance expense and $2.2 million higher
other expense.
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 TGP and 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
66
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.
|
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 made in 2005.
|
|
|
|
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 and $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 other gathering
revenues.
67
Outlook
for 2008
Discovery
|
|
|
|
|
Discoverys Tahiti pipeline lateral was installed on the
sea bed in February 2007. Chevron had scheduled initial
throughput to begin in mid-2008, but in 2007 announced that it
was facing delays because of metallurgical problems discovered
in their facilitys mooring shackles. Chevron recently
announced that it expects first production by the third quarter
of 2009. Discoverys revenues from the Tahiti project are
dependent on receiving throughput from Chevron. Therefore,
delays Chevron experiences in bringing their production online
impact the initial timing of revenues for Discovery.
|
|
|
|
Discoverys Larose gas processing plant has been operating
at near capacity. We expect that additional processing volumes
from the TGP system in 2008 may replace some of the
processing volumes previously coming from the TETCO system; and
therefore, the Larose plant will continue to remain at near
capacity throughout 2008. The additional volumes from TGP will
require facilities modifications, which may be funded by a 2008
cash call to Discoverys members.
|
|
|
|
The TETCO agreement was recently extended through May 2008 at
which time we expect no further volumes under this agreement.
Current flowing volumes are approximately 170 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.
|
|
|
|
In February 2008, Discovery executed agreements with LLOG
Exploration Company to provide production handling,
transportation, processing and fractionation services for their
MC 705 and 707 production.
|
|
|
|
Gross processing margins have been at record high levels due to
commodity prices for NGLs and natural gas and Discoverys
mix of processing contract types and its operation and
optimization activities. We expect that 2008 gross
processing margins will remain favorable to historical averages.
However, the prices of NGLs and natural gas can quickly
fluctuate in response to a variety of factors that are
impossible to control and, in particular, NGL pricing is
typically impacted negatively by recessionary economic
conditions.
|
|
|
|
We expect Discoverys 2008 results could be favorably
impacted by approximately $3.0 million if its recently
approved FERC rate filing pertaining to the regulated portion of
its business becomes final and effective.
|
68
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Segment revenues
|
|
$
|
56,911
|
|
|
$
|
58,441
|
|
|
$
|
48,254
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost
|
|
|
11,264
|
|
|
|
15,511
|
|
|
|
11,821
|
|
Operating and maintenance expense
|
|
|
24,686
|
|
|
|
28,791
|
|
|
|
24,397
|
|
Depreciation and accretion
|
|
|
3,720
|
|
|
|
2,437
|
|
|
|
2,419
|
|
General and administrative expense direct
|
|
|
2,190
|
|
|
|
1,149
|
|
|
|
1,068
|
|
Other, net
|
|
|
746
|
|
|
|
719
|
|
|
|
694
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
42,606
|
|
|
|
48,607
|
|
|
|
40,399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
14,305
|
|
|
$
|
9,834
|
|
|
$
|
7,855
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 vs.
2006
Segment revenues decreased $1.5 million, or 3%, due
primarily to lower product sales and fractionation revenues,
partially offset by higher storage and product upgrade fee
revenues. The significant components of the revenue fluctuations
are addressed more fully below.
|
|
|
|
|
Product sales decreased $4.7 million due to lower sales
volumes. This decrease was offset by the related decrease in
product cost discussed below.
|
|
|
|
Fractionation revenues decreased $2.1 million due primarily
to 11% lower fractionation volumes and 7% lower rates.
Fractionation throughput was lower during 2007 due to a
customers decision to fractionate a percentage of their
volumes outside of the Mid-Continent region for three months.
This decision was based on current prices being paid for
fractionated products outside of the Mid-Continent region. The
lower fractionation rates relate to the pass through to
customers of decreased fuel and power costs.
|
|
|
|
Storage revenues increased $2.8 million due primarily to
higher average storage rates for all of 2007 and slightly higher
levels of contracted storage.
|
|
|
|
Other revenue increased $2.5 million due primarily to low
sulfur natural gasoline upgrade fees and higher volumes of
trucking loading. The upgrade service began in late 2006.
|
Operating and maintenance expense decreased $4.1 million,
or 14%, due primarily to lower fuel and power costs related to
lower fractionator throughput and lower repairs and maintenance
costs.
Product cost decreased $4.2 million, or 27%, due to the
lower product sales volumes discussed above, resulting in a
decrease in net margin of $0.5 million.
Depreciation and accretion expense increased $1.3 million,
or 53%, due primarily to asset retirement obligation assumption
changes and higher depreciation expense related to a larger
property base.
General and administrative expense direct increased
$1.0 million, or 91%, due primarily to certain costs that
were allocated to the partnership in 2006 but directly charged
to the segment in 2007.
Segment profit increased $4.5 million, or 45%, due
primarily to higher storage and product upgrade fee revenues,
lower repair and maintenance costs and a favorable environmental
reserve adjustment, partially offset by higher depreciation and
accretion expense, higher general and administrative expense
direct and lower net margin on product sales.
69
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.
Outlook
for 2008
|
|
|
|
|
We expect 2008 storage revenues will remain approximately
consistent with 2007 due to continued strong demand for propane
and butane storage as well as higher priced specialty storage
services.
|
|
|
|
We continue to perform 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 2008 to ensure that we
meet the regulatory compliance requirements.
|
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 will
include:
|
|
|
|
|
Cash and cash equivalents on hand;
|
|
|
|
Cash generated from operations, including cash distributions
from Wamsutter and Discovery;
|
|
|
|
Insurance recoveries related to the fire at the Ignacio gas
processing plant, which should generally be received as costs
are incurred;
|
|
|
|
Capital contributions from Williams pursuant to an omnibus
agreement; and
|
|
|
|
Credit facilities, as needed.
|
We anticipate our more significant liquidity requirements to be:
|
|
|
|
|
Maintenance and expansion capital expenditures for our Four
Corners and Conway assets;
|
|
|
|
Four Corners repair expenditures related to the fire at the
Ignacio gas processing plant, which should generally be
reimbursed by insurance approximately as they are incurred;
|
|
|
|
Contributions we must make to Wamsutter LLC to fund certain of
its expansion capital expenditures;
|
|
|
|
Interest on our long-term debt; and
|
|
|
|
Quarterly distributions to our unitholders.
|
70
These liquidity sources and cash requirements are discussed in
greater detail below.
Wamsutter
Distributions
The Wamsutter LLC Agreement provides for distributions of
available cash to be made quarterly beginning in March 2008.
Available cash is defined as cash generated from
Wamsutters business less reserves that are necessary or
appropriate to provide for the conduct of its business and to
comply with applicable law and or debt instrument or other
agreement to which it is a party.
Wamsutter will distribute its available cash as follows:
|
|
|
|
|
First, an amount equal to $17.5 million per quarter
to the holder of the Class A membership interests. We
currently own 100% of the Class A interests;
|
|
|
|
Second, an amount equal to the amount the distribution on
the Class A membership interests in prior quarters of the
current distribution year was less than $17.5 million per
quarter to the holder of the Class A membership
interests; and
|
|
|
|
Third, 5% of remaining available cash shall be
distributed to the holder of the Class A membership
interests and 95% shall be distributed to the holders of the
Class C units, on a pro rata basis. We currently own
50% of the Class C units.
|
In addition, to the extent that at the end of the fourth quarter
of a distribution year, the Class A member has received
less than $70.0 million under the first and second bullets
above, the Class C members will be required to repay any
distributions they received in that distribution year such that
the Class A member receives $70.0 million for that
distribution year. If this repayment is insufficient to result
in the Class A member receiving $70.0 million, the
shortfall will not carry forward to the next distribution year.
The initial distribution year for Wamsutter commenced on
December 1, 2007 and ends on November 30, 2008.
Subsequent distribution years for Wamsutter will commence on
December 1 and end on November 30.
Additionally, each month during fiscal years 2008 through 2012
the Class B member, Williams, is obligated to pay to Wamsutter
and Wamsutter is obligated to pay us a transition support
payment in an amount equal to the amount by which
Wamsutters general and administrative expenses exceed a
certain cap. For 2008 the annualized cap is $5.0 million.
Any such amounts received from the Class B member shall be
distributed to us but shall not be counted for purposes of
determining whether or not Wamsutter has distributed
$70.0 million in aggregate annual distributions as
described above.
Discovery
Distributions
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 Share**
|
|
|
1/30/07
|
|
$
|
9,000
|
|
|
$
|
3,600
|
|
4/30/07
|
|
$
|
16,000
|
|
|
$
|
6,400
|
|
6/22/07*
|
|
$
|
11,173
|
|
|
$
|
4,469
|
|
7/30/07
|
|
$
|
9,000
|
|
|
$
|
3,600
|
|
10/31/07
|
|
$
|
14,000
|
|
|
$
|
8,400
|
|
1/30/08
|
|
$
|
28,000
|
|
|
$
|
16,800
|
|
|
|
|
* |
|
Special distribution Discovery made after receipt of insurance
proceeds. |
|
** |
|
On June 28, 2007, we closed on the acquisition of an
additional 20% limited liability company interest in Discovery.
Because this acquisition was effective July 1, 2007, we did
not begin to receive 60% of Discoverys distributions until
October 2007. |
71
Insurance
Recoveries
As previously discussed, on November 28, 2007 the Ignacio
gas processing plant sustained significant damages from a fire.
The estimated total cost for fire-related repairs is
approximately $27.0 million, including $26.0 million
in potentially reimbursable expenditures in excess of the
insurance deductible. Of this amount, $11.0 million has
been incurred as of December 31, 2007. We are funding these
repairs with cash flows from operations and are seeking
reimbursement from our insurance carrier. Additionally, we will
seek reimbursement from our insurance carrier for approximately
13 days of lost profits under our business interruption
policy.
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
ending August 2008 (for certain of those expenditures) up to a
cap of $14.0 million. As of December 31, 2007 we have
received $5.4 million from Williams for indemnified items
since inception of the agreement in August 2005. Thus,
approximately $8.6 million remains available for
reimbursement of our costs on these items.
Additionally, under the omnibus agreement, we will receive an
annual credit for general and administrative expenses of
$1.6 million in 2008 and $0.8 million in 2009 and up
to $3.4 million to fund our initial 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, 2007
we have received $1.6 million from Williams for the
Tahiti-related indemnification.
Although we recently acquired an additional 20% ownership
interest in Discovery, Tahiti-related indemnifications under the
omnibus agreement continue to be based on the 40% ownership
interest we held when this agreement became effective.
Credit
Facilities
On December 11, 2007, in conjunction with the closing of
our acquisition of the Wamsutter Ownership Interests, we entered
into a $450.0 million senior unsecured credit agreement
with Citibank, N.A. as administrative agent, comprised initially
of a $200.0 million revolving credit facility available for
borrowings and letters of credit and a $250.0 million term
loan. Under certain conditions, the revolving credit facility
may be increased up to an additional $100.0 million.
Borrowings under this agreement must be repaid within
5 years. There were no amounts outstanding at
December 31, 2007 under the revolving credit facility
portion of this credit agreement.
On November 21, 2007, we were removed as a borrower under
Williams $1.5 billion revolving credit facility. As a
result, we no longer have access to a $75.0 million
borrowing capacity under that facility.
We also have a $20.0 million revolving credit facility with
Williams as the lender. The facility is available exclusively to
fund working capital borrowings. 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, 2007 we had no outstanding borrowings under
the working capital credit facility.
On December 11, 2007, Wamsutter entered into a
$20.0 million revolving credit facility with Williams as
the lender. This credit facility is available to fund working
capital requirements and for other purposes. Borrowings under
the credit facility mature on December 9, 2008 and bear
interest at the one-month LIBOR. Wamsutter pays a commitment fee
to Williams on the unused portion of the credit facility of
0.175% annually. As of December 31, 2007, Wamsutter had no
outstanding borrowings under this credit facility.
72
Credit
Ratings
The table below presents our current credit ratings on our
senior unsecured
long-term
debt.
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Unsecured
|
Rating Agency
|
|
Date of Last Change
|
|
Outlook
|
|
Debt Rating
|
|
Standard & Poors
|
|
November 7, 2007
|
|
Stable
|
|
BBB-
|
Moodys Investor Service
|
|
January 28, 2008
|
|
Stable
|
|
Ba2
|
Fitch Ratings
|
|
June 15, 2006
|
|
Positive
|
|
BB
|
Capital
Expenditures
The natural gas gathering, treating, processing and
transportation, and NGL fractionation and storage businesses are
capital-intensive, requiring investment to upgrade or enhance
existing operations and comply with safety and environmental
regulations. The capital expenditures of these businesses
consist primarily of:
|
|
|
|
|
Maintenance capital expenditures, which are capital expenditures
made to replace partially or fully depreciated assets in order
to maintain the existing operating capacity of our assets and to
extend their useful lives; and
|
|
|
|
Expansion capital expenditures such as those to acquire
additional assets to grow our business, to expand and upgrade
plant or pipeline capacity and to construct new plants,
pipelines and storage facilities.
|
Estimated capital expenditures for the year ending
December 31, 2008 are as follows:
|
|
|
|
|
|
|
|
|
Company
|
|
Maintenance
|
|
|
Expansion
|
|
|
|
($ in millions)
|
|
|
Four Corners
|
|
$
|
23.0
|
|
|
$
|
16.0
|
|
Conway
|
|
|
5.0
|
|
|
|
13.0
|
|
Wamsutter (our share)
|
|
|
20.0
|
|
|
|
4.0
|
|
Discovery (our share)
|
|
|
3.0
|
|
|
|
8.0
|
|
We expect to fund Four Corners and Conways
maintenance and expansion capital expenditures with cash flows
from operations. Four Corners maintenance capital
expenditures include approximately $17.0 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. Four Corners expansion
capital expenditures relate primarily to plant and gathering
system expansion projects. Conways expansion capital
expenditures relate to various small projects.
Wamsutters maintenance capital expenditures include
approximately $18.0 million related to well connections
necessary to connect new sources of throughput for the Wamsutter
system which serve to offset the historical decline in
throughput volumes. We expect Wamsutter will fund its
maintenance capital expenditures through its cash flows from
operations.
Wamsutter funds its expansion capital expenditures through
capital contributions from its members as specified in its
limited liability company agreement. This agreement specifies
that expansion capital projects with expected total expenditures
in excess of $2.5 million at the time of approval and well
connections that increase gathered volumes beyond current levels
be funded by contributions from its Class B membership,
which we do not own. However, our ownership of the Class A
membership interest requires us to provide capital contributions
related to expansion projects with expected total expenditures
less than $2.5 million at the time of approval.
Discovery will fund its maintenance and expansion capital
expenditures either by cash calls to its members or from its
cash flows from operations.
Debt
Service Long-Term Debt
We have $150.0 million senior unsecured notes outstanding
that bear interest at 7.5% per annum payable semi-annually in
arrears on June 15 and December 15 of each year. The senior
notes mature on June 15, 2011.
73
We have $600.0 million of 7.25% senior unsecured notes
outstanding. 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.
As discussed previously in Credit Facilities, we
have a $250.0 million term loan outstanding. This borrowing
must be repaid before December 11, 2012.
Cash
Distributions to Unitholders
We have paid quarterly distributions to our unitholders and our
general partner interest after every quarter since our IPO on
August 23, 2005. Our most recently declared quarterly
distribution of $35.3 million was paid on February 14,
2008 to the general partner interest and common and subordinated
unitholders of record at the close of business on
February 7, 2008. This distribution included an incentive
distribution to our general partner of approximately
$4.2 million. On January 28, 2008, the board of
directors of our general partner confirmed that, upon payment of
the distribution to unitholders on February 14, 2008 the
financial tests provided for in our partnership agreement had
been met for the termination of the subordination period. As a
result of the termination on February 19, 2008, all of the
7,000,000 subordinated units owned by four affiliates of
Williams converted to common units on a one-for-one basis.
Results
of Operations Cash Flows
Williams
Partners L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Net cash provided by operating activities
|
|
$
|
192,790
|
|
|
$
|
169,450
|
|
|
$
|
157,932
|
|
Net cash used by investing activities
|
|
|
(399,557
|
)
|
|
|
(624,213
|
)
|
|
|
(55,666
|
)
|
Net cash provided (used) by financing activities
|
|
|
185,423
|
|
|
|
505,465
|
|
|
|
(95,427
|
)
|
Net cash provided by operating activities increased
$23.3 million in 2007 as compared to 2006 due primarily to:
|
|
|
|
|
$53.9 million from changes in working capital excluding
accrued interest. Cash provided by working capital increased due
primarily to $25.4 million in lower accounts receivable and
$31.5 million in higher accounts payable between
periods; and
|
|
|
|
$14.2 million higher distributions related to the equity
earnings of Discovery.
|
Partially offsetting these increases were $33.2 million in
higher cash interest payments for the interest on our
$750.0 million senior unsecured notes issued in 2006 to
finance our acquisition of Four Corners and $11.5 million
lower operating income excluding non- cash items.
The $11.5 million increase in net cash provided by
operating activities for 2006 as compared to 2005 is due
primarily to $23.9 million increase in operating income as
adjusted for non-cash items and a $10.8 million increase in
distributed earnings from Discovery, partially offset by a
$23.2 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 in addition to
other changes in accounts payable.
Net cash used by investing activities in 2007 includes the
purchase of the Wamsutter Ownership Interests on
December 11, 2007 and the additional 20% ownership interest
in Discovery on June 28, 2007. Since these ownership
interests were purchased from Williams, the transactions were
between entities under common control, and have been accounted
for at historical cost. Therefore the amount reflected as cash
used by investing activities for these purchases represents the
historical cost to Williams. Additionally, net cash used by
investing activities in 2007, 2006 and 2005 includes maintenance
and expansion capital expenditures primarily for well connects
in our Four Corners business, the installation of cavern liners,
and KDHE-related cavern compliance with the installation of
wellhead control equipment and well meters in our NGL Services
segment.
74
Net cash used by investing activities in 2006 relates primarily
to the $607.5 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.
Net cash provided by financing activities in 2007 includes:
|
|
|
|
|
$265.9 million of net proceeds from debt and equity
issuances related to our acquisition of the Wamsutter Ownership
Interest less the related amounts distributed to Williams in
excess of Wamsutters contributed basis;
|
|
|
|
distributions to unitholders and our general partner of
$87.3 million; and
|
|
|
|
contributions from our general partner to maintain its 2%
ownership following the issuances of equity and per the omnibus
agreement that totaled $15.7 million.
|
Net cash provided by financing activities in 2006 includes:
|
|
|
|
|
$624.5 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 its 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
and 2005 included $114.5 million and $187.2 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.
Wamsutter
100%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Net cash provided by operating activities
|
|
$
|
85,541
|
|
|
$
|
75,641
|
|
|
$
|
56,067
|
|
Net cash used by investing activities
|
|
|
(31,624
|
)
|
|
|
(36,040
|
)
|
|
|
(34,356
|
)
|
Net cash used by financing activities
|
|
|
(53,917
|
)
|
|
|
(39,601
|
)
|
|
|
(21,711
|
)
|
The $9.9 million increase in net cash provided by operating
activities in 2007 as compared to 2006 is due primarily to
$19.3 million increase in operating income, as adjusted for
non-cash expenses, partially offset by $9.4 million lower
cash provided from changes in working capital.
The $19.6 million increase in net cash provided by
operating activities in 2006 as compared to 2005 is due
primarily to a $23.0 million increase in operating income,
as adjusted for non-cash expenses, partially offset by
$3.4 million lower cash provided from changes in working
capital.
Net cash used by investing activities in 2007, 2006 and 2005 is
primarily comprised of capital expenditures related to the
connection of new wells, the number of which increased
significantly in 2005 and 2006. Additionally, in 2006 and 2005
there were other significant gathering system expansion projects
in addition to the well connections.
Net cash used by financing activities for all periods are
primarily distributions of Wamsutters net cash flows to
Williams pursuant to its participation in Williams cash
management program.
75
Discovery
100%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Net cash provided by operating activities
|
|
$
|
62,092
|
|
|
$
|
63,456
|
|
|
$
|
30,814
|
|
Net cash used by investing activities
|
|
|
(5,914
|
)
|
|
|
(17,162
|
)
|
|
|
(65,997
|
)
|
Net cash provided (used) by financing activities
|
|
|
(55,252
|
)
|
|
|
(30,089
|
)
|
|
|
1,339
|
|
Net cash provided by operating activities decreased
$1.4 million in 2007 as compared to 2006 due primarily to
an increase in cash used for working capital of
$20.3 million, substantially offset by an increase of
$19.0 million in operating income as adjusted for non-cash
items.
Net cash provided by operating activities increased
$32.6 million in 2006 as compared to 2005 due primarily to
an increase of $22.6 million in cash provided from working
capital and an increase of $10.0 million in operating
income as adjusted for non-cash items. The 2006 increase in 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 used by investing activities included
$29.1 million and $32.9 million of capital spending in
2007 and 2006, respectively. These expenditures were primarily
for the Tahiti project, partially offset by the use of
$22.6 million and $15.8 million of Tahiti-related
restricted cash in 2007 and 2006, respectively. 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.
Net cash used by financing activities in 2007 is almost entirely
related to normal cash distributions to Discoverys
members. Net cash used by financing activities in 2006 includes
$13.5 million of capital contributions compared to
$43.6 million in 2005. These contributions related to the
Tahiti pipeline lateral expansion. Additionally, Discovery
distributed $43.6 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,
2007, is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009-2010
|
|
|
2011-2012
|
|
|
2013+
|
|
|
Total
|
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal
|
|
$
|
|
|
|
$
|
|
|
|
$
|
400,000
|
|
|
$
|
600,000
|
|
|
$
|
1,000,000
|
|
Interest
|
|
|
68,480
|
(a)
|
|
|
134,502
|
|
|
|
127,193
|
|
|
|
195,750
|
|
|
|
525,925
|
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
1,513
|
|
|
|
1,574
|
|
|
|
92
|
|
|
|
|
|
|
|
3,179
|
|
Purchase obligations
|
|
|
56,777
|
(b)
|
|
|
240
|
|
|
|
240
|
|
|
|
120
|
(c)
|
|
|
57,377
|
|
Other long term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
126,770
|
|
|
$
|
136,316
|
|
|
$
|
527,525
|
|
|
$
|
795,870
|
|
|
$
|
1,586,481
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The assumed interest rate on our $250.0 million term loan
is based on the forecasted forward LIBOR plus the applicable
margin. |
|
(b) |
|
Includes the open purchase orders in the amount of
$29.3 million as of December 31, 2007 to be paid in
2008 and product purchase and service agreements in the amount
of $24.6 million as of December 31, 2007 to be paid in
2008. |
|
(c) |
|
Year 2013 represents one year of payments associated with an
operating agreement whose term is tied to the life of the
underlying gas reserves. |
76
Our equity investee, Wamsutter, also has contractual obligations
for which we are not contractually liable. These contractual
obligations, however, will impact Wamsutters ability to
make cash distributions to us. A summary of Wamsutters
total contractual obligations as of December 31, 2007, is
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009-2010
|
|
|
2011-2012
|
|
|
2013+
|
|
|
Total
|
|
|
|
|
|
Notes payable/long-term debt
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
1,238
|
|
|
|
2,222
|
|
|
|
15
|
|
|
|
|
|
|
|
3,475
|
|
|
|
|
|
Purchase obligations(a)
|
|
|
3,728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,728
|
|
|
|
|
|
Other long-term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,966
|
|
|
$
|
2,222
|
|
|
$
|
15
|
|
|
$
|
|
|
|
$
|
7,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes the open purchase orders as of December 31, 2007
to be paid in 2008. |
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, 2007, is
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009-2010
|
|
|
2011-2012
|
|
|
2013+
|
|
|
Total
|
|
|
Notes payable/long-term debt
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
858
|
|
|
|
1,715
|
|
|
|
1,715
|
|
|
|
2,388
|
|
|
|
6,676
|
|
Purchase obligations
|
|
|
8,269
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,269
|
|
Other long-term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
9,127
|
|
|
$
|
1,715
|
|
|
$
|
1,715
|
|
|
$
|
2,388
|
|
|
$
|
14,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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% and 54%
of Four Corners and Wamsutters respective 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 these systems
as throughput volumes from existing wells will naturally decline
over time.
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,
contaminants are now present at only five sites. Monitoring will
continue at all sites as necessary to document monitored natural
attenuation and free product will be recovered as practicable.
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, 2007,
we had accrued liabilities totaling $0.7 million for these
environmental activities. Actual costs incurred will depend on
the actual number of
77
contaminated sites identified, the amount and extent of
contamination discovered, the final cleanup standards mandated
by governmental authorities and other factors.
On April 11, 2007, the New Mexico Environment
Departments Air Quality Bureau (NMED) issued a Notice of
Violation to Four Corners that alleges various emission and
reporting violations in connection with our Lybrook gas
processing plants flare and leak detection and repair
program. The NMED proposed a penalty of approximately
$3 million. We are discussing the basis for and the scope
of the proposed penalty with the NMED.
Our Conway storage facilities are subject to strict
environmental regulation by the Underground Hydrocarbon Storage
Unit within the Geology Section of the Bureau of Water of the
KDHE under the Underground Hydrocarbon Storage Program, which
became effective in 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 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. 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. We do not expect to submit any claims under
this insurance policy prior to its expected expiration date on
April 30, 2008. 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. At December 31, 2007,
we had accrued liabilities totaling $3.3 million 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 a
letter of credit on our behalf in the amount of
$18.3 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 Annual Report on
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.
78
Commodity
Price Risk
We are exposed to the impact of fluctuations in the market price
of natural gas liquids and natural gas, as well as other market
factors, such as market volatility and commodity price
correlations. We are exposed to these risks in connection with
our owned energy-related assets and our long-term energy-related
contracts. We manage a portion of the risks associated with
these market fluctuations using various derivative contracts.
The fair value of derivative contracts is subject to changes in
energy-commodity market prices, the liquidity and volatility of
the markets in which the contracts are transacted, and changes
in interest rates. We measure the risk in our portfolio using a
value-at-risk
methodology to estimate the potential
one-day loss
from adverse changes in the fair value of the portfolio.
Value at risk requires a number of key assumptions and is not
necessarily representative of actual losses in fair value that
could be incurred from the portfolio. Our
value-at-risk
model uses a Monte Carlo method to simulate hypothetical
movements in future market prices and assumes that, as a result
of changes in commodity prices, there is a 95% probability that
the one-day
loss in fair value of the portfolio will not exceed the value at
risk. The simulation method uses historical correlations and
market forward prices and volatilities. In applying the
value-at-risk
methodology, we do not consider that the simulated hypothetical
movements affect the positions or would cause any potential
liquidity issues, nor do we consider that changing the portfolio
in response to market conditions could affect market prices and
could take longer than a
one-day
holding period to execute. While a
one-day
holding period has historically been the industry standard, a
longer holding period could more accurately represent the true
market risk given market liquidity and our own credit and
liquidity constraints.
Our derivative contracts are contracts held for nontrading
purposes that hedge a portion of our commodity price risk
exposure from natural gas liquid sales and natural gas
purchases. Certain of our derivative contracts have been
designated as normal purchases or sales under Statement of
Financial Accounting Standards (SFAS) No. 133,
Accounting for Derivative Instruments and Hedging
Activities, and, therefore, have been excluded from our
estimation of value at risk.
The value at risk for our derivative contracts was
$1.0 million at December 31, 2007. We had no
derivative contracts at December 31, 2006.
All of the derivative contracts included in our
value-at-risk
calculation are accounted for as cash flow hedges under
SFAS No. 133. Any change in the fair value of these
hedge contracts would generally not be reflected in earnings
until the associated hedged item affects earnings.
Interest
Rate Risk
Our current interest rate risk exposure is related primarily to
our debt portfolio. A majority of our current debt portfolio is
comprised of fixed interest rate debt which mitigates the impact
of fluctuations in 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.
The tables below provide information about our interest
rate-sensitive instruments as of December 31, 2007 and
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
|
|
|
2012
|
|
|
Thereafter
|
|
|
Total
|
|
|
2007
|
|
|
|
(Dollars in millions)
|
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate
|
|
$
|
150.0
|
|
|
$
|
|
|
|
$
|
600.0
|
|
|
$
|
750.0
|
|
|
$
|
777.5
|
|
Interest rate
|
|
|
7.5
|
%
|
|
|
|
|
|
|
7.25
|
%
|
|
|
|
|
|
|
|
|
Variable rate
|
|
$
|
|
|
|
$
|
250.0
|
|
|
$
|
|
|
|
$
|
250.0
|
|
|
$
|
250.0
|
|
Interest rate(1)
|
|
|
|
|
|
|
6.16
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
79
|
|
|
(1) |
|
The weighted-average interest rate for 2007 is LIBOR plus
1 percent. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2011
|
|
|
2017
|
|
|
Total
|
|
2006
|
|
|
|
(Dollars in millions)
|
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate
|
|
$
|
150
|
.0
|
|
|
$
|
600
|
.0
|
|
|
$
|
750
|
.0
|
|
$
|
768.8
|
|
Interest rate
|
|
|
7
|
.5
|
%
|
|
|
7
|
.25
|
%
|
|
|
|
|
|
|
|
|
80
|
|
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, 2007. 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,
2007, 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 audited the effectiveness of the
companys internal control over financial reporting, as
stated in their report which is included in this Annual Report
on
Form 10-K.
81
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 Williams Partners L.P.s internal control
over financial reporting as of December 31, 2007, 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 included in the accompanying
Managements Report on Internal Control Over Financial
Reporting. Our responsibility is to express an opinion on 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, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, 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, Williams Partners L.P. maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2007 based on the COSO
criteria.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
accompanying consolidated balance sheets of Williams Partners
L.P. as of December 31, 2007 and 2006, and the related
consolidated statements of income, partners capital, and
cash flows for each of the three years in the period ended
December 31, 2007, and our report dated February 25,
2008 expressed an unqualified opinion thereon.
Tulsa, Oklahoma
February 25, 2008
82
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, 2007 and 2006,
and the related consolidated statements of income,
partners capital, and cash flows for each of the three
years in the period ended December 31, 2007. 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, 2007 and 2006, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2007, 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),
Williams Partners L.P.s internal control over financial
reporting as of December 31, 2007, 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 25, 2008 expressed
an unqualified opinion thereon.
Tulsa, Oklahoma
February 25, 2008
83
WILLIAMS
PARTNERS L.P.
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006*
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
36,197
|
|
|
$
|
57,541
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Trade
|
|
|
12,860
|
|
|
|
18,320
|
|
Affiliate
|
|
|
20,402
|
|
|
|
25,324
|
|
Other
|
|
|
2,543
|
|
|
|
3,991
|
|
Product imbalance
|
|
|
20,660
|
|
|
|
10,308
|
|
Gas purchase contract affiliate
|
|
|
|
|
|
|
4,754
|
|
Prepaid expenses
|
|
|
4,056
|
|
|
|
3,765
|
|
Derivative assets affiliate
|
|
|
231
|
|
|
|
|
|
Reimbursable projects
|
|
|
8,989
|
|
|
|
|
|
Other current assets
|
|
|
3,574
|
|
|
|
2,534
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
109,512
|
|
|
|
126,537
|
|
Investment in Wamsutter
|
|
|
284,650
|
|
|
|
262,245
|
|
Investment in Discovery Producer Services
|
|
|
214,526
|
|
|
|
221,187
|
|
Property, plant and equipment, net
|
|
|
642,289
|
|
|
|
647,578
|
|
Other noncurrent assets
|
|
|
32,500
|
|
|
|
34,752
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,283,477
|
|
|
$
|
1,292,299
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
35,947
|
|
|
$
|
19,827
|
|
Affiliate
|
|
|
17,676
|
|
|
|
12,904
|
|
Product imbalance
|
|
|
21,473
|
|
|
|
10,959
|
|
Deferred revenue
|
|
|
4,569
|
|
|
|
3,382
|
|
Derivative liabilities affiliate
|
|
|
2,718
|
|
|
|
|
|
Accrued liabilities
|
|
|
27,743
|
|
|
|
16,173
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
110,126
|
|
|
|
63,245
|
|
Long-term debt
|
|
|
1,000,000
|
|
|
|
750,000
|
|
Environmental remediation liabilities
|
|
|
2,599
|
|
|
|
3,964
|
|
Other noncurrent liabilities
|
|
|
9,265
|
|
|
|
3,749
|
|
Commitments and contingent liabilities (Note 14)
|
|
|
|
|
|
|
|
|
Partners capital:
|
|
|
|
|
|
|
|
|
Common unitholders (45,774,728 and 25,553,306 units
outstanding at December 31, 2007 and 2006)
|
|
|
1,473,814
|
|
|
|
733,878
|
|
Class B unitholders (6,805,492 units outstanding at
December 31, 2006)
|
|
|
|
|
|
|
241,923
|
|
Subordinated unitholders (7,000,000 units outstanding at
December 31, 2007 and 2006)
|
|
|
109,542
|
|
|
|
108,862
|
|
Accumulated other comprehensive loss
|
|
|
(2,487
|
)
|
|
|
|
|
General partner
|
|
|
(1,419,382
|
)
|
|
|
(613,322
|
)
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
161,487
|
|
|
|
471,341
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
1,283,477
|
|
|
$
|
1,292,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Recast as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
84
WILLIAMS
PARTNERS L.P.
CONSOLIDATED
STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006*
|
|
|
2005*
|
|
|
|
(Dollars in thousands, except per-unit amounts)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and processing:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
35,819
|
|
|
$
|
42,228
|
|
|
$
|
36,755
|
|
Third-party
|
|
|
202,775
|
|
|
|
206,432
|
|
|
|
198,041
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
267,970
|
|
|
|
255,075
|
|
|
|
236,020
|
|
Third-party
|
|
|
22,962
|
|
|
|
16,919
|
|
|
|
8,728
|
|
Storage
|
|
|
28,016
|
|
|
|
25,237
|
|
|
|
20,290
|
|
Fractionation
|
|
|
9,622
|
|
|
|
11,698
|
|
|
|
10,770
|
|
Other
|
|
|
5,653
|
|
|
|
5,821
|
|
|
|
4,368
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
572,817
|
|
|
|
563,410
|
|
|
|
514,972
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
73,475
|
|
|
|
78,201
|
|
|
|
58,780
|
|
Third-party
|
|
|
108,223
|
|
|
|
97,307
|
|
|
|
118,747
|
|
Operating and maintenance expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
61,633
|
|
|
|
53,627
|
|
|
|
46,194
|
|
Third-party
|
|
|
100,710
|
|
|
|
101,587
|
|
|
|
83,565
|
|
Depreciation, amortization and accretion
|
|
|
46,492
|
|
|
|
43,692
|
|
|
|
42,579
|
|
General and administrative expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
42,038
|
|
|
|
34,295
|
|
|
|
33,765
|
|
Third-party
|
|
|
3,590
|
|
|
|
5,145
|
|
|
|
2,850
|
|
Taxes other than income
|
|
|
9,624
|
|
|
|
8,961
|
|
|
|
8,446
|
|
Other (income) expense net
|
|
|
12,095
|
|
|
|
(2,473
|
)
|
|
|
630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
457,880
|
|
|
|
420,342
|
|
|
|
395,556
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
114,937
|
|
|
|
143,068
|
|
|
|
119,416
|
|
Equity earnings Wamsutter
|
|
|
76,212
|
|
|
|
61,690
|
|
|
|
40,555
|
|
Equity earnings Discovery Producer Services
|
|
|
28,842
|
|
|
|
18,050
|
|
|
|
11,880
|
|
Interest expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
(61
|
)
|
|
|
(89
|
)
|
|
|
(7,461
|
)
|
Third-party
|
|
|
(58,287
|
)
|
|
|
(9,744
|
)
|
|
|
(777
|
)
|
Interest income
|
|
|
2,988
|
|
|
|
1,600
|
|
|
|
165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
164,631
|
|
|
|
214,575
|
|
|
|
163,778
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
(1,405
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
|
$
|
162,373
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income for calculation of earnings per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
|
$
|
162,373
|
|
Allocation of net income to general partner
|
|
|
85,190
|
|
|
|
182,380
|
|
|
|
155,551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income to limited partners
|
|
$
|
79,441
|
|
|
$
|
32,195
|
|
|
$
|
6,822
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted earnings per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting
principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
|
$
|
0.49
|
|
Subordinated units
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
|
$
|
0.49
|
|
Cumulative effect of change in accounting principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
|
|
|
|
|
|
|
$
|
(0.05
|
)
|
Subordinated units
|
|
$
|
|
|
|
|
|
|
|
$
|
(0.05
|
)
|
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
|
$
|
0.44
|
|
Subordinated units
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
|
$
|
0.44
|
|
Weighted average number of units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
33,131,195
|
(a)
|
|
|
11,986,368
|
(a)
|
|
|
7,001,366
|
|
Subordinated units
|
|
|
7,000,000
|
|
|
|
7,000,000
|
|
|
|
7,000,000
|
|
|
|
|
* |
|
Recast as discussed in Note 1. |
|
(a) |
|
Includes Class B units converted to Common on May 21,
2007. |
See accompanying notes to consolidated financial statements.
85
WILLIAMS
PARTNERS L.P.
CONSOLIDATED
STATEMENT OF PARTNERS CAPITAL*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other
|
|
|
Total
|
|
|
|
|
|
|
Limited Partners
|
|
|
General
|
|
|
Comprehensive
|
|
|
Partners
|
|
|
|
Common
|
|
|
Class B
|
|
|
Subordinated
|
|
|
Partner
|
|
|
Loss
|
|
|
Capital
|
|
|
|
(In thousands)
|
|
|
Balance December 31, 2004
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
895,476
|
|
|
$
|
|
|
|
|
895,476
|
|
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
|
|
|
|
77,574
|
|
|
|
|
|
|
|
194,472
|
|
Net income 2005
|
|
|
3,104
|
|
|
|
|
|
|
|
3,103
|
|
|
|
156,166
|
|
|
|
|
|
|
|
162,373
|
|
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 units (6,146 common units)
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
Distributions to The Williams Companies, Inc. net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(187,217
|
)
|
|
|
|
|
|
|
(187,217
|
)
|
Adjustment in basis of investment in Discovery Producer Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,245
|
|
|
|
|
|
|
|
6,245
|
|
Adjustment in basis of investment in Wamsutter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,711
|
)
|
|
|
|
|
|
|
(21,711
|
)
|
Contributions pursuant to the omnibus agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,610
|
|
|
|
|
|
|
|
1,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2005
|
|
|
108,526
|
|
|
|
|
|
|
|
108,491
|
|
|
|
925,461
|
|
|
|
|
|
|
|
1,142,478
|
|
Net income 2006
|
|
|
21,181
|
|
|
|
655
|
|
|
|
11,606
|
|
|
|
181,133
|
|
|
|
|
|
|
|
214,575
|
|
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 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
|
)
|
Adjustment in basis of investment in Discovery Producer Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,400
|
)
|
|
|
|
|
|
|
(7,400
|
)
|
Adjustment in basis of investment in Wamsutter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(39,601
|
)
|
|
|
|
|
|
|
(39,601
|
)
|
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
|
|
|
|
(613,322
|
)
|
|
|
|
|
|
|
471,341
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income 2007
|
|
|
64,546
|
|
|
|
9,212
|
|
|
|
14,995
|
|
|
|
75,878
|
|
|
|
|
|
|
|
164,631
|
|
Other comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses on cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,763
|
)
|
|
|
(3,763
|
)
|
Reclassification into earnings of derivative instrument losses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,276
|
|
|
|
1,276
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,487
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
162,144
|
|
Cash distributions
|
|
|
(59,573
|
)
|
|
|
(6,601
|
)
|
|
|
(14,315
|
)
|
|
|
(6,792
|
)
|
|
|
|
|
|
|
(87,281
|
)
|
Conversion of Class B units into common
(6,805,492 units)
|
|
|
244,534
|
|
|
|
(244,534
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to general partner in exchange for additional
investment in Discovery Producer Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(78,000
|
)
|
|
|
|
|
|
|
(78,000
|
)
|
Adjustment in basis of investment in Discovery Producer Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,035
|
)
|
|
|
|
|
|
|
(9,035
|
)
|
Issuance of units to public (9,250,000 common units)
|
|
|
335,220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
335,220
|
|
Issuance of units to general partner ( 4,163,257 common units)
|
|
|
157,173
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
157,173
|
|
Distributions to general partner in exchange for investment in
Wamsutter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(750,000
|
)
|
|
|
|
|
|
|
(750,000
|
)
|
Offering costs
|
|
|
(1,927
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,927
|
)
|
Adjustment in basis of investment in Wamsutter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(53,807
|
)
|
|
|
|
|
|
|
(53,807
|
)
|
Contributions from general partner
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,334
|
|
|
|
|
|
|
|
10,334
|
|
Contributions pursuant to the omnibus agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,362
|
|
|
|
|
|
|
|
5,362
|
|
Other
|
|
|
(37
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(37
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007
|
|
$
|
1,473,814
|
|
|
$
|
|
|
|
$
|
109,542
|
|
|
$
|
(1,419,382
|
)
|
|
|
(2,487
|
)
|
|
$
|
161,487
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Recast as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
86
WILLIAMS
PARTNERS L.P.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006*
|
|
|
2005*
|
|
|
|
(In thousands)
|
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
|
$
|
162,373
|
|
Adjustments to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
1,405
|
|
Depreciation, amortization and accretion
|
|
|
46,492
|
|
|
|
43,692
|
|
|
|
42,579
|
|
Provision for loss on property, plant and equipment
|
|
|
11,306
|
|
|
|
|
|
|
|
917
|
|
Gain on sale of property, plant and equipment
|
|
|
|
|
|
|
(3,055
|
)
|
|
|
|
|
Amortization of gas purchase contract affiliate
|
|
|
4,754
|
|
|
|
5,320
|
|
|
|
2,033
|
|
Equity earnings of Wamsutter
|
|
|
(76,212
|
)
|
|
|
(61,690
|
)
|
|
|
(40,555
|
)
|
Equity earnings of Discovery Producer Services
|
|
|
(28,842
|
)
|
|
|
(18,050
|
)
|
|
|
(11,880
|
)
|
Distributions related to equity earnings of Discovery Producer
Services
|
|
|
26,240
|
|
|
|
12,033
|
|
|
|
1,280
|
|
Cash provided (used) by changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
11,830
|
|
|
|
(13,564
|
)
|
|
|
(4,419
|
)
|
Prepaid expenses
|
|
|
(369
|
)
|
|
|
(1,023
|
)
|
|
|
(463
|
)
|
Reimbursable projects
|
|
|
(8,989
|
)
|
|
|
|
|
|
|
|
|
Other current assets
|
|
|
(1,041
|
)
|
|
|
(920
|
)
|
|
|
|
|
Accounts payable
|
|
|
20,892
|
|
|
|
(10,600
|
)
|
|
|
8,801
|
|
Product imbalance
|
|
|
162
|
|
|
|
(1,114
|
)
|
|
|
8,243
|
|
Accrued liabilities
|
|
|
15,914
|
|
|
|
6,395
|
|
|
|
(4,008
|
)
|
Deferred revenue
|
|
|
1,709
|
|
|
|
(170
|
)
|
|
|
247
|
|
Other, including changes in noncurrent assets and liabilities
|
|
|
4,313
|
|
|
|
(2,379
|
)
|
|
|
(8,621
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
192,790
|
|
|
|
169,450
|
|
|
|
157,932
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of Four Corners
|
|
|
|
|
|
|
(607,545
|
)
|
|
|
|
|
Purchase of additional investment in Discovery Producer Services
|
|
|
(69,061
|
)
|
|
|
|
|
|
|
|
|
Purchase of investment in Wamsutter
|
|
|
(277,262
|
)
|
|
|
|
|
|
|
|
|
Distributions in excess of equity earnings of Discovery Producer
Services
|
|
|
229
|
|
|
|
4,367
|
|
|
|
|
|
Capital expenditures
|
|
|
(48,481
|
)
|
|
|
(32,270
|
)
|
|
|
(31,266
|
)
|
Change in accrued liabilities capital
expenditures
|
|
|
(4,982
|
)
|
|
|
5,078
|
|
|
|
|
|
Contribution to Discovery Producer Services
|
|
|
|
|
|
|
(1,600
|
)
|
|
|
(24,400
|
)
|
Proceeds from sales of property, plant and equipment
|
|
|
|
|
|
|
7,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(399,557
|
)
|
|
|
(624,213
|
)
|
|
|
(55,666
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sales of common units
|
|
|
492,393
|
|
|
|
867,263
|
|
|
|
100,247
|
|
Proceeds from debt issuances
|
|
|
250,000
|
|
|
|
750,000
|
|
|
|
|
|
Excess purchase price over the contributed basis of Four Corners
|
|
|
|
|
|
|
(975,455
|
)
|
|
|
|
|
Excess purchase price over the contributed basis of the
investment in Discovery Producer Services
|
|
|
(8,939
|
)
|
|
|
|
|
|
|
|
|
Excess purchase price over the contributed basis of the
investment in Wamsutter
|
|
|
(472,738
|
)
|
|
|
|
|
|
|
|
|
Payment of debt issuance costs
|
|
|
(1,781
|
)
|
|
|
(13,138
|
)
|
|
|
|
|
Payment of offering costs
|
|
|
(1,927
|
)
|
|
|
(4,168
|
)
|
|
|
(4,291
|
)
|
Distributions to The Williams Companies, Inc.
|
|
|
|
|
|
|
(114,497
|
)
|
|
|
(187,217
|
)
|
Changes in advances from affiliates net
|
|
|
|
|
|
|
|
|
|
|
(3,656
|
)
|
Distributions to unitholders and general partner
|
|
|
(87,281
|
)
|
|
|
(29,994
|
)
|
|
|
(2,120
|
)
|
General partner contributions
|
|
|
10,334
|
|
|
|
18,614
|
|
|
|
|
|
Contributions per omnibus agreement
|
|
|
5,362
|
|
|
|
6,840
|
|
|
|
1,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities
|
|
|
185,423
|
|
|
|
505,465
|
|
|
|
(95,427
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents
|
|
|
(21,344
|
)
|
|
|
50,702
|
|
|
|
6,839
|
|
Cash and cash equivalents at beginning of year
|
|
|
57,541
|
|
|
|
6,839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
36,197
|
|
|
$
|
57,541
|
|
|
$
|
6,839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Recast as discussed in Note 1. |
See accompanying notes to consolidated financial statements.
87
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 Wamsutter LLC
(Wamsutter) and Discovery Producer Services LLC (Discovery) in
which we own interests accounted for as equity investments that
are not consolidated in our financial statements. When we refer
to Wamsutter or Discovery by name, we are referring exclusively
to their 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 were 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, a 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
88
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
per unit. Additionally, at the closing, the underwriters fully
exercised their option to purchase 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 were accounted for as a
combination of entities under common control, similar to a
pooling of interests, whereby the assets and liabilities of Four
Corners were combined with Williams Partners L.P. at their
historical amounts for all periods presented. These acquisitions
did not impact historical earnings per unit as pre-acquisition
earnings were allocated to our general partner.
Additional
Investment in Discovery
On June 28, 2007, we closed on the acquisition of an
additional 20% interest in Discovery from Energy and WES for
aggregate consideration of $78.0 million, bringing our
total ownership of Discovery to 60%. This transaction was
effective July 1, 2007. Because this additional 20%
interest in Discovery was purchased from an affiliate of
Williams, the transaction was between entities under common
control, and has been accounted for at historical cost.
Accordingly our consolidated financial statements and notes
reflect the combined historical results of our investment in
Discovery throughout the periods presented. We continue to
account for this investment under the equity method due to the
voting provisions of Discoverys limited liability company
agreement which provide the other member of Discovery
significant participatory rights such that we do not control the
investment. The effect of recasting our financial statements to
account for this common control exchange increased net income
$2.6 million, $6.0 million and $3.5 million for
2007, 2006 and 2005, respectively. The acquisition had no impact
on earnings per unit as pre-acquisition earnings were allocated
to the general partner.
Acquisition
of Wamsutter
On December 11, 2007, we acquired the ownership interests
in Wamsutter, consisting of 100% of the Class A limited
liability company interests and 20 Class C units
representing 50% of the initial Class C ownership interests
(collectively the Wamsutter Ownership Interests) in exchange for
aggregate consideration of $750.0 million. We financed this
acquisition with a combination of equity and debt. On
December 11, 2007, we issued 9,250,000 common units at a
price of $37.75 per unit. This offering yielded net proceeds of
$335.2 million after payment of underwriting discounts and
commissions of $14.0 million but before the payment of
other offering expenses. Additionally, on December 11,
2007, we issued approximately $157.2 million, or 4,163,527
common units to Williams at a price per common unit of $37.75.
On December 11, 2007, we also initiated a term loan under
our $450.0 million credit facility, netting proceeds of
$249.1 million after
89
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
debt acquisition costs. Because the Wamsutter Ownership
Interests were purchased from an affiliate of Williams, the
transaction was between entities under common control, and has
been accounted for at historical cost. Accordingly, our
consolidated financial statements and notes reflect the combined
historical results of our investment in Wamsutter throughout the
periods presented. We account for this investment under the
equity method due to the voting provisions of Wamsutters
limited liability agreement which provide Williams significant
participatory rights such that we do not control the investment.
The effect of recasting our financial statements to account for
this common control exchange increased net income
$68.8 million, $61.7 million and $40.5 million
for 2007, 2006 and 2005, respectively. This acquisition does not
impact historical earnings per unit as pre-acquisition earnings
were allocated to our general partner.
On January 9, 2008, we sold an additional 800,000 common
units to the underwriters upon the underwriters partial
exercise of their option to purchase additional common units. We
used the net proceeds from the partial exercise of the
underwriters option to redeem 800,000 common units from
Williams at a price per common unit of $36.24 ($37.75, net of
underwriter discount).
|
|
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 and our equity
investment in Wamsutter. 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.
Wamsutter owns an approximate 1,700-mile natural gas gathering
system in the Washakie Basin in south-central Wyoming that
currently connects approximately 1,720 wells, with a
typical operating capacity of approximately
500 MMcf/d
at current operating pressures, and the Echo Springs cryogenic
processing plant near Wamsutter, Wyoming which has
390 MMcf/d
of inlet cryogenic processing capacity and NGL production
capacity of 30,000 bpd.
Gathering and Processing-Gulf . We own a 60%
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 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.
90
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
Certain amounts have been reclassified to conform to the current
classifications.
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;
|
|
|
|
impairment assessments of long-lived assets;
|
|
|
|
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.
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.
91
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 was for the purchase of
80,000 MMBtu per month and terminated on December 31,
2007. The initial value of this contract was amortized to
expense over the contract life.
Reimbursable Projects. Expenditures incurred
for the repair of the Ignacio natural gas processing plant
damaged by a fire in November 2007, which are probable of
recovery when incurred, are recorded as reimbursable projects.
Expenditures up to the insurance deductible and amounts
subsequently determined not to be recoverable are expensed.
Investments. We account for our Wamsutter
Ownership Interests and our 60% investment in Discovery under
the equity method due to the voting provisions of their limited
liability company agreements which provide the other members of
these entities significant participatory rights such that we do
not control these investments. In 2004, we recognized an
other-than-temporary impairment of our Discovery investment. As
a result, Discoverys underlying equity exceeds the
carrying value of our investment at December 31, 2007 and
2006.
Property, Plant and Equipment. Property, plant
and equipment is recorded at cost. We base the carrying value of
these assets on estimates, assumptions and judgments relative to
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
92
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
These items are reflected as product imbalance receivables and
payables on the Consolidated Balance Sheets. Product imbalance
receivables are valued based on the lower of current market
prices or current cost of natural gas in the system or in the
case of our Conway facilities, lower of the current market
prices or weighted average value of NGLs. Product imbalance
payables are valued at current market prices. The majority of
Four Corners settlements are through in-kind arrangements
whereby incremental volumes are delivered to a customer (in the
case of an imbalance payable) or received from a customer (in
the case of an imbalance receivable). Such in-kind deliveries
are on-going and take place over several periods. In some cases,
settlements of imbalances build up over a period of time and are
ultimately settled in cash and are generally negotiated at
values which approximate average market prices over a period of
time. These gains and losses impact our results of operations
and are included in operating and maintenance expense in the
Consolidated Statements of Income.
Derivative Instruments and Hedging
Activities. We utilize derivatives to manage a
portion of our commodity price risk. These instruments consist
primarily of swap agreements and forward contracts involving
short- and long-term purchases and sales of a physical energy
commodity. The counterparty to these instruments is a Williams
affiliate. We execute these transactions in over-the-counter
markets in which quoted prices exist for active periods. We
report the fair value of derivatives, except for those which the
normal purchases and normal sales exception has been elected, on
the Consolidated Balance Sheets in other current assets, other
accrued liabilities, other assets or other noncurrent
liabilities. We determine the current and noncurrent
classification based on the timing of expected future cash flows
of individual contracts.
The accounting for changes in the fair value of derivatives is
governed by Statement of Financial Accounting Standards (SFAS)
No. 133, Accounting for Derivative Instruments and
Hedging Activities, and depends on whether the derivative
has been designated in a hedging relationship and what type of
hedging relationship it is. The accounting for the change in
fair value can be summarized as follows:
|
|
|
Derivative Treatment
|
|
Accounting Method
|
|
Normal purchases and normal sales exception
|
|
Accrual accounting
|
Designated in qualifying hedging relationship
|
|
Hedge accounting
|
All other derivatives
|
|
Mark-to-market accounting
|
We have elected the normal purchases and normal sales exception
for certain short- and long-term purchases and sales of a
physical energy commodity. Under accrual accounting, any change
in the fair value of these derivatives is not reflected on the
balance sheet since we made the election of this exception at
the inception of these contracts.
For a derivative to qualify for designation in a hedging
relationship it must meet specific criteria and we must maintain
appropriate documentation. We establish hedging relationships
pursuant to our risk management policies. We evaluate the
hedging relationships at the inception of the hedge and on an
ongoing basis to determine whether the hedging relationship is,
and is expected to remain, highly effective in achieving
offsetting changes in fair value or cash flows attributable to
the underlying risk being hedged. We also regularly assess
whether the hedged forecasted transaction is probable of
occurring. If a derivative ceases to be or is no longer expected
to be highly effective, or if we believe the likelihood of
occurrence of the hedged forecasted transaction is no longer
probable, hedge accounting is discontinued prospectively, and
future changes in the fair value of the derivative are
recognized currently in other revenues.
For derivatives designated as a cash flow hedge, the effective
portion of the change in fair value of the derivative is
reported in other comprehensive loss and reclassified into
product sales revenues in the period in which the hedged item
affects earnings. Any ineffective portion of the
derivatives change in fair value is recognized currently
in product sales revenues. Gains or losses deferred in
accumulated other comprehensive
93
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
loss associated with terminated derivatives, derivatives that
cease to be highly effective hedges, derivatives for which the
forecasted transaction is reasonably possible but no longer
probable of occurring, and cash flow hedges that have been
otherwise discontinued remain in accumulated other comprehensive
loss until the hedged item affects earnings. If it becomes
probable that the forecasted transaction designated as the
hedged item in a cash flow hedge will not occur, any gain or
loss deferred in accumulated other comprehensive loss is
recognized in other revenues at that time. The change in
likelihood of a forecasted transaction is a judgmental decision
that includes qualitative assessments made by management.
Revenue Recognition. The nature of our
businesses results 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 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 based on our average
interest rate on debt to the extent we incur interest expense.
Prior to our IPO, 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.
94
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
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 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
definition of fair value, provides guidance on the methods used
to estimate fair value and expands disclosures about fair value
measurements. SFAS No. 157 is effective for fiscal
years beginning after November 15, 2007. In December 2007,
the FASB issued proposed FASB Staff Position (FSP)
No. FAS 157-b
deferring the effective date of SFAS No. 157 to fiscal
years beginning after November 15, 2008 for all
non-financial assets and liabilities, except those that are
recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually).
SFAS No. 157 requires two distinct transition
approaches; (i) cumulative-effect adjustment to beginning
retained earnings for certain financial instrument transactions
and (ii) prospectively as of the date of adoption through
earnings or other comprehensive income, as applicable. On
January 1, 2008, we adopted SFAS No. 157 applying
a prospective transition for our assets and liabilities that are
measured at fair value on a recurring basis, primarily our
commodity derivatives, with no material impact to our
Consolidated Financial Statements. SFAS No. 157
expands disclosures about assets and liabilities measured at
fair value on a recurring basis effective beginning with the
first quarter of 2008 reporting.
In February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial Assets and Financial
Liabilities Including an Amendment of FASB Statement
No. 115. SFAS No. 159 establishes a fair
value option permitting entities to elect to measure eligible
financial instruments and certain other items at fair value.
Unrealized gains and losses on items for which the fair value
option has been elected will be reported in earnings. The fair
value option may be applied on an
instrument-by-instrument
basis, is irrevocable and is applied only to the entire
instrument. SFAS No. 159 is effective as of the
beginning of the first fiscal year beginning after
November 15, 2007, and should not be applied
retrospectively to fiscal years beginning prior to the effective
date. On the adoption date, an entity may elect the fair value
option for eligible items existing at that date and the
adjustment for the initial remeasurement of those items to fair
value should be reported as a cumulative effect adjustment to
the opening balance of retained earnings. Subsequent to
January 1, 2008, the fair value option can only be elected
when a financial instrument or certain other item is entered
into. On January 1, 2008, we adopted SFAS No. 159
but have not elected the fair value option for any existing
eligible financial instruments or other items.
In December 2007, the FASB issued SFAS No. 141(R)
Business Combinations. SFAS No. 141(R)
applies to all business combinations and establishes guidance
for recognizing and measuring identifiable assets acquired, the
liabilities assumed, noncontrolling interest in the acquiree and
goodwill. Most of these items are recognized at their full fair
value on the acquisition date, including acquisitions where the
acquirer obtains control but less than 100% ownership interest
in the acquiree. SFAS No. 141(R) also requires
expensing of transaction costs as incurred and establishes
disclosure requirements to enable the evaluation of the nature
and
95
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
financial effects of the business combination.
SFAS No. 141(R) is effective for business combinations
with an acquisition date in fiscal years beginning after
December 15, 2008.
|
|
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,
2007 and 2006 are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Allocation of net income to general partner:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
|
$
|
162,373
|
|
Net income applicable to pre-partnership operations allocated to
general partner
|
|
|
(71,426
|
)
|
|
|
(184,157
|
)
|
|
|
(157,439
|
)
|
Beneficial conversion of Class B units
|
|
|
(5,308
|
)
|
|
|
|
|
|
|
|
|
Charges allocated directly to general partner:
|
|
|
|
|
|
|
|
|
|
|
|
|
Reimbursable general and administrative costs
|
|
|
2,400
|
|
|
|
3,200
|
|
|
|
1,400
|
|
Core drilling indemnified costs
|
|
|
|
|
|
|
784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total charges allocated directly to general partner
|
|
|
2,400
|
|
|
|
3,984
|
|
|
|
1,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income subject to 2% allocation of general partner interest
|
|
|
90,297
|
|
|
|
34,402
|
|
|
|
6,334
|
|
General partners share of net income
|
|
|
2.0
|
%
|
|
|
2.0
|
%
|
|
|
2.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners allocated share of net income before
items directly allocable to general partner interest
|
|
|
1,806
|
|
|
|
688
|
|
|
|
127
|
|
Incentive distributions paid to general partner*
|
|
|
5,046
|
|
|
|
272
|
|
|
|
|
|
Charges allocated directly to general partner
|
|
|
(2,400
|
)
|
|
|
(3,984
|
)
|
|
|
(1,400
|
)
|
Pre-partnership net income allocated to general partner interest
|
|
|
71,426
|
|
|
|
184,157
|
|
|
|
157,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to general partner
|
|
$
|
75,878
|
|
|
$
|
181,133
|
|
|
$
|
156,166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
|
$
|
162,373
|
|
Net income allocated to general partner
|
|
|
75,878
|
|
|
|
181,133
|
|
|
|
156,166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to limited partners
|
|
$
|
88,753
|
|
|
$
|
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 years ended December 31, 2007 and 2006 was
$8.4 million and $0.4 million, respectively. There
were no assumed incentive distributions during 2005. |
Pursuant to the partnership agreement, income allocations are
made on a quarterly basis; therefore, earnings per limited
partner unit for each year is calculated as the sum of the
quarterly earnings per limited partner unit for each of the four
quarters in the year. Common and subordinated unitholders share
equally, on a
per-unit
basis, in the net income allocated to limited partners.
96
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, 2006 and 2007 (in thousands, except
for per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General Partner
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive
|
|
|
|
|
|
|
Per Unit
|
|
|
Common
|
|
|
Subordinated
|
|
|
Class B
|
|
|
|
|
|
Distribution
|
|
|
Total Cash
|
|
Payment Date
|
|
Distribution
|
|
|
Units
|
|
|
Units
|
|
|
Units
|
|
|
2%
|
|
|
Rights
|
|
|
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
|
|
$
|
0.4250
|
|
|
$
|
6,204
|
|
|
$
|
2,975
|
|
|
$
|
|
|
|
$
|
189
|
|
|
$
|
74
|
|
|
$
|
9,442
|
|
11/14/2006
|
|
$
|
0.4500
|
|
|
$
|
6,569
|
|
|
$
|
3,150
|
|
|
$
|
|
|
|
$
|
202
|
|
|
$
|
199
|
|
|
$
|
10,120
|
|
2/14/2007
|
|
$
|
0.4700
|
|
|
$
|
12,010
|
|
|
$
|
3,290
|
|
|
$
|
3,198
|
|
|
$
|
390
|
|
|
$
|
603
|
|
|
$
|
19,491
|
|
5/15/2007
|
|
$
|
0.5000
|
|
|
$
|
12,777
|
|
|
$
|
3,500
|
|
|
$
|
3,403
|
|
|
$
|
421
|
|
|
$
|
965
|
|
|
$
|
21,066
|
|
8/14/2007
|
|
$
|
0.5250
|
|
|
$
|
16,989
|
|
|
$
|
3,675
|
|
|
$
|
|
|
|
$
|
447
|
|
|
$
|
1,267
|
|
|
$
|
22,378
|
|
11/14/2007
|
|
$
|
0.5500
|
|
|
$
|
17,799
|
|
|
$
|
3,850
|
|
|
$
|
|
|
|
$
|
487
|
|
|
$
|
2,211
|
|
|
$
|
24,347
|
|
2/14/2008(b)
|
|
$
|
0.5750
|
|
|
$
|
26,321
|
|
|
$
|
4,025
|
|
|
$
|
|
|
|
$
|
706
|
|
|
$
|
4,231
|
|
|
$
|
35,283
|
|
|
|
|
(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) |
|
On February 14, 2008, we paid a cash distribution of $0.575
per unit on our outstanding common and subordinated units to
unitholders of record on February 7, 2008. |
|
|
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. 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 considers revenues;
property, plant and equipment; and payroll. Certain of these
costs are charged back to the other Conway fractionator
co-owners. Our share of direct and allocated administrative
expenses 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
97
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
August 23 to December 31), $3.2 million in 2006,
$2.4 million in 2007, $1.6 million in 2008 and
$0.8 million in 2009.
At December 31, 2007 and 2006 we have a contribution
receivable from our general partner of $0.5 million and
$0.4 million, respectively, for amounts reimbursable to us
under the omnibus agreement. This receivable is netted against
Partners capital on the Consolidated Balance Sheets.
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 Gas Marketing, Inc. (WGM), 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 generally
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 on the Consolidated Balance Sheets. This contract
terminated on December 31, 2007. In December 2007, we
entered into fixed price natural gas purchase contracts with WGM
to hedge the price of a portion of our natural gas shrink
replacement costs for February through December of 2008.
Four Corners uses waste heat from a co-generation plant located
adjacent to the Milagro treating plant. The co-generation plant
is owned by an affiliate of Williams, Williams Flexible
Generation, LLC. Waste heat is required for the natural gas
treating process, which occurs at Milagro. The charge to us for
the waste heat is based on the natural gas needed to generate
the waste heat. We purchase this natural gas from WGM. The
natural gas cost charged to us by WGM has been favorably
impacted by WGMs fixed price natural gas fuel contracts.
This cost is reflected in Operations and maintenance
expense Affiliate. This impact was approximately
$9.0 million annually during 2006 and 2005 as compared to
estimated market prices. These agreements expired in the fourth
quarter of 2006. Milagro natural gas fuel costs have increased
since the expiration of these agreements, due to market prices
exceeding prices associated with these 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 WGM 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, WGM 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 NGL Marketing LLC (WNGLM), 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.
We enter into financial swap contracts with WGM and WNGLM to
hedge forecasted NGL sales. These contracts are priced based on
market rates at the time of execution and are reflected in
Derivative assets affiliate and Derivative
liabilities affiliate on the Consolidated Balance
Sheet.
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. One of the contracts with WPC is
98
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
adjusted annually based on changes in the average price of
natural gas. Revenues associated with these activities are
reflected in the Gathering and processing Affiliate
on the Consolidated Statements of Income.
We sell Conways surplus propane and other NGLs to WGM,
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 WGM to replenish deficit
product inventory positions. The transactions conducted between
us and WGM are transacted at current market prices for the
products.
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, 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 2007, 2006, and 2005 affiliate interest expense includes
commitment fees on the working capital credit facility (see
Note 11). For 2005, affiliate interest expense also
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. 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 receivable Affiliate or Accounts
payable Affiliate in the accompanying Consolidated
Balance Sheets.
|
|
Note 6.
|
Equity
Investments
|
Wamsutter
Our Wamsutter Ownership Interests are accounted for using the
equity method of accounting due to the voting provisions of
Wamsutters limited liability company agreement which
provide the other member, owned by a Williams affiliate,
significant participatory rights such that we do not control the
investment.
Williams is the operator of Wamsutter. As such, effective
December 1, 2007, Williams is reimbursed on a monthly basis
for all direct and indirect expenses it incurs on behalf of
Wamsutter including Wamsutters allocable share of general
and administrative costs.
Wamsutter participates in Williams cash management
program. Therefore, Wamsutter carries no cash balances. Pursuant
to their LLC Agreement, Wamsutter has made net advances to
Williams, which were classified as a component of their
members capital because although the advances are due on
demand, Williams has not historically required repayment or
repaid amounts owed to Wamsutter.
The Wamsutter LLC Agreement provides for distributions of
available cash to be made quarterly beginning in March 2008.
Available cash is defined as cash generated from
Wamsutters business less reserves that are necessary or
appropriate to provide for the conduct of its business and to
comply with applicable law and or debt instrument or other
agreement to which it is a party.
Wamsutter will distribute its available cash as follows:
|
|
|
|
|
First, an amount equal to $17.5 million per quarter
to the holder of the Class A membership interests. We
currently own 100% of the Class A interests;
|
|
|
|
Second, an amount equal to the amount the distribution on
the Class A membership interests in prior quarters of the
current distribution year was less than $17.5 million per
quarter to the holder of the Class A membership
interests; and
|
99
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
Third, 5% of remaining available cash shall be
distributed to the holder of the Class A membership
interests and 95% shall be distributed to the holders of the
Class C units, on a pro rata basis. We currently own
50% of the Class C units.
|
In addition, to the extent that at the end of the fourth quarter
of a distribution year, the Class A member has received
less than $70.0 million under the first and second bullets
above, the Class C members will be required to repay any
distributions they received in that distribution year such that
the Class A member receives $70.0 million for that
distribution year. If this repayment is insufficient to result
in the Class A member receiving $70.0 million, the
shortfall will not carry forward to the next distribution year.
The initial distribution year for Wamsutter commenced on
December 1, 2007 and ends on November 30, 2008.
Subsequent distribution years for Wamsutter will commence on
December 1 and end on November 30.
We will be allocated net income by Wamsutter based upon the
allocation and distribution provisions of their LLC Agreement.
In general, the agreement allocates income to the Class A,
B and C ownership interests in a manner that will maintain
capital account balances reflective of the amounts each
ownership interest would receive if Wamsutter were dissolved and
liquidated at carrying value. In general, pursuant to those
provisions, income allocations follow the provisions of the LLC
agreement for the distribution of available cash.
Wamsutters LLC agreement provides each quarter during 2008
through 2012, that it receive a transition support payment,
related to a cap on general and administrative expenses, from
its Class B ownership interest. This payment will be distributed
directly to our Class A ownership interest. The reimbursement
will be treated as a capital contribution by its Class B member
and the cost subject to this reimbursement will be allocated
entirely to its Class B member.
The summarized financial position and results of operations for
100% of Wamsutter are presented below (in thousands).
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Current assets
|
|
$
|
27,114
|
|
|
$
|
9,841
|
|
Property, plant and equipment
|
|
|
275,163
|
|
|
|
265,519
|
|
Non-current assets
|
|
|
191
|
|
|
|
257
|
|
Current liabilities
|
|
|
(12,944
|
)
|
|
|
(10,413
|
)
|
Non-current liabilities
|
|
|
(2,812
|
)
|
|
|
(1,959
|
)
|
|
|
|
|
|
|
|
|
|
Members capital
|
|
$
|
286,712
|
|
|
$
|
263,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
101,191
|
|
|
$
|
113,484
|
|
|
$
|
121,909
|
|
Third-party
|
|
|
74,118
|
|
|
|
63,062
|
|
|
|
55,181
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
46,834
|
|
|
|
68,041
|
|
|
|
92,656
|
|
Third-party
|
|
|
51,090
|
|
|
|
46,815
|
|
|
|
43,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
77,385
|
|
|
|
61,690
|
|
|
|
40,555
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
(48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
77,385
|
|
|
$
|
61,690
|
|
|
$
|
40,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Discovery
Producer Services
Our 60% investment in Discovery is accounted for using the
equity method of accounting due to the voting provisions of
Discoverys limited liability company agreement which
provide the other member of Discovery significant participatory
rights such that we do not control the investment.
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.
As discussed in Note 1. Organization, our consolidated
financial statements and notes reflect the additional 20%
interest in Discovery which we acquired in mid-2007. However,
certain cash transactions that occurred between Discovery and
Williams prior to this acquisition that related to the
additional 20% interest are not reflected in our Consolidated
Statements of Cash Flows even though these transactions affect
the carrying value of our investment in Discovery. These
transactions were omitted from our Consolidated Statements of
Cash Flows because they did not affect our cash. The total of
these transactions is reflected as an adjustment in the basis of
our investment in Discovery on our Consolidated Statement of
Partners Capital. A summary of these transactions is as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Cash distributions from Discovery to Williams
|
|
$
|
(9,035
|
)
|
|
$
|
(8,200
|
)
|
|
$
|
(26,898
|
)
|
Williams purchase of additional 10% interest in Discovery
|
|
|
|
|
|
|
|
|
|
|
21,000
|
|
Williams capital contributions to Discovery
|
|
|
|
|
|
|
800
|
|
|
|
12,143
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(9,035
|
)
|
|
$
|
(7,400
|
)
|
|
$
|
6,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 then 40% share of the
estimated future capital expenditures for the Tahiti pipeline
lateral expansion project.
During 2007, 2006, and 2005 we received total distributions of
$35.5 million, $16.4 million, and $1.3 million,
respectively, from Discovery for the 60% interest we currently
own or the 40% interest we owned at the time of distribution.
The summarized financial position and results of operations for
100% of Discovery are presented below (in thousands).
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Current assets
|
|
$
|
78,035
|
|
|
$
|
73,841
|
|
Non-current restricted cash
|
|
|
6,222
|
|
|
|
28,773
|
|
Property, plant and equipment
|
|
|
368,228
|
|
|
|
355,304
|
|
Current liabilities
|
|
|
(33,820
|
)
|
|
|
(40,560
|
)
|
Non-current liabilities
|
|
|
(12,216
|
)
|
|
|
(3,728
|
)
|
|
|
|
|
|
|
|
|
|
Members capital
|
|
$
|
406,449
|
|
|
$
|
413,630
|
|
|
|
|
|
|
|
|
|
|
101
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
220,960
|
|
|
$
|
160,825
|
|
|
$
|
76,864
|
|
Third-party
|
|
|
39,712
|
|
|
|
36,488
|
|
|
|
45,881
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
101,581
|
|
|
|
74,316
|
|
|
|
24,895
|
|
Third-party
|
|
|
112,604
|
|
|
|
97,394
|
|
|
|
77,702
|
|
Interest income
|
|
|
(1,799
|
)
|
|
|
(2,404
|
)
|
|
|
(1,685
|
)
|
Loss on sale of operating assets
|
|
|
603
|
|
|
|
|
|
|
|
|
|
Foreign exchange (gain) loss
|
|
|
(388
|
)
|
|
|
(2,076
|
)
|
|
|
1,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
48,071
|
|
|
|
30,083
|
|
|
|
20,828
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
(176
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
48,071
|
|
|
$
|
30,083
|
|
|
$
|
20,652
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 7.
|
Other
(Income) Expense
|
Other (income) expense net reflected on the
Consolidated Statements of Income consists of the following
items:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Impairment of Carbonate Trend pipeline
|
|
$
|
10,406
|
|
|
$
|
|
|
|
$
|
|
|
Gain on sale of LaMaquina carbon dioxide treating facility
|
|
|
|
|
|
|
(3,619
|
)
|
|
|
|
|
Other
|
|
|
1,689
|
|
|
|
1,146
|
|
|
|
630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
12,095
|
|
|
$
|
(2,473
|
)
|
|
$
|
630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of Carbonate Trend Pipeline. During
the fourth quarter of 2007, we determined that the carrying
value of this pipeline, included in our Gathering and
Processing Gulf segment, may not be recoverable
because of forecasted declining cash flows. As a result, we
recognized an impairment charge of $10.4 million to reduce
the carrying value to managements estimate of fair value
at December 31, 2007. We estimated fair value using market
multiples and discounted cash flow projections.
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
managements estimate of fair value. The facility was sold
in the first quarter of 2006 resulting in the recognition of a
gain on the sale in 2006.
102
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 8.
|
Property,
Plant and Equipment
|
Property, plant and equipment, at cost, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Estimated
|
|
|
|
2007
|
|
|
2006
|
|
|
Depreciable Lives
|
|
|
|
(In thousands)
|
|
|
|
|
|
Land and right of way
|
|
$
|
42,657
|
|
|
$
|
41,721
|
|
|
|
30 years
|
|
Gathering pipelines and related equipment
|
|
|
830,437
|
|
|
|
821,478
|
|
|
|
20-30 years
|
|
Processing plants and related equipment
|
|
|
149,855
|
|
|
|
147,241
|
|
|
|
30 years
|
|
Fractionation plant and related equipment
|
|
|
16,720
|
|
|
|
16,697
|
|
|
|
30 years
|
|
Storage plant and related equipment
|
|
|
80,837
|
|
|
|
69,017
|
|
|
|
30 years
|
|
Buildings and other equipment
|
|
|
90,356
|
|
|
|
90,082
|
|
|
|
3-45 years
|
|
Construction work in progress
|
|
|
28,930
|
|
|
|
19,447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
1,239,792
|
|
|
|
1,205,683
|
|
|
|
|
|
Accumulated depreciation
|
|
|
597,503
|
|
|
|
558,105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
642,289
|
|
|
$
|
647,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 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
60% interest in Discoverys cumulative effect of a change
in accounting principle related to the adoption of
FIN No. 47.
Our asset retirement 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 and offshore pipelines. 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 and offshore pipelines,
empty the brine ponds and restore the surface, and remove any
related surface equipment.
A rollforward of our asset retirement obligation for 2007 and
2006 is presented below.
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Balance, January 1
|
|
$
|
4,476
|
|
|
$
|
1,880
|
|
Liabilities incurred during the period
|
|
|
2,950
|
|
|
|
|
|
Liabilities settled during the period
|
|
|
(64
|
)
|
|
|
(510
|
)
|
Accretion expense
|
|
|
1,474
|
|
|
|
86
|
|
Estimate revisions
|
|
|
(93
|
)
|
|
|
2,943
|
|
Loss on settlements
|
|
|
|
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31
|
|
$
|
8,743
|
|
|
$
|
4,476
|
|
|
|
|
|
|
|
|
|
|
103
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 9.
|
Accrued
Liabilities
|
Accrued liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Accrued interest
|
|
$
|
19,500
|
|
|
$
|
2,796
|
|
Environmental remediation current portion
|
|
|
1,396
|
|
|
|
2,636
|
|
Customer deposit for construction
|
|
|
96
|
|
|
|
5,078
|
|
Taxes other than income
|
|
|
2,490
|
|
|
|
2,347
|
|
Other
|
|
|
4,261
|
|
|
|
3,316
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
27,743
|
|
|
$
|
16,173
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 10.
|
Major
Customers, Concentrations of Credit Risk, Financial Instruments
and Energy Commodity Cash Flow Hedges
|
Major
customers
Our largest customer, on a percentage of revenues basis, is
Williams NGL Marketing LLC, which purchases and resells
substantially all of the NGLs to which we take title. Williams
NGL Marketing LLC accounted for 49%, 43%, and 46% of revenues in
2007, 2006 and 2005, respectively. The remaining largest
customer, ConocoPhillips, from our Gathering and
Processing West segment, accounted for 22%, 21%, and
24% of revenues in 2007, 2006 and 2005, respectively.
Concentrations
of Credit Risk
Our cash equivalents consist of high-quality securities placed
with various major financial institutions with credit ratings at
or above AAA by Standard & Poors or Aa by
Moodys Investors Service.
The counterparties to our derivative contracts are affiliates of
Williams, which minimizes our credit risk exposure.
The following table summarizes the concentration of accounts
receivable by service and segment.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Gathering and Processing West:
|
|
|
|
|
|
|
|
|
Natural gas gathering and processing
|
|
$
|
11,512
|
|
|
$
|
16,709
|
|
Other
|
|
|
471
|
|
|
|
561
|
|
Gathering and Processing Gulf:
|
|
|
|
|
|
|
|
|
Natural gas gathering
|
|
|
324
|
|
|
|
468
|
|
Other
|
|
|
881
|
|
|
|
1,343
|
|
NGL Services:
|
|
|
|
|
|
|
|
|
Fractionation services
|
|
|
303
|
|
|
|
320
|
|
Amounts due from fractionator partners
|
|
|
1,068
|
|
|
|
1,833
|
|
Storage
|
|
|
735
|
|
|
|
825
|
|
Accrued interest and other
|
|
|
109
|
|
|
|
252
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
15,403
|
|
|
$
|
22,311
|
|
|
|
|
|
|
|
|
|
|
104
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At December 31, 2007 and 2006, a substantial portion of our
accounts receivable result from product sales and gathering and
processing services provided to two 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.
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.
Energy commodity swap agreements. The fair
value of our swap agreements is based on prices of the
underlying energy commodities over the contract life and
contractual or notional volumes with the resulting expected
future cash flows discounted to a present value using a
risk-free market interest rate.
Carrying
amounts and fair values of our financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
Asset (Liability)
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
Cash and cash equivalents
|
|
$
|
36,197
|
|
|
$
|
36,197
|
|
|
$
|
57,541
|
|
|
$
|
57,541
|
|
Long-term debt
|
|
|
(1,000,000
|
)
|
|
|
(1,027,499
|
)
|
|
|
(750,000
|
)
|
|
|
(768,844
|
)
|
Energy commodity swap agreements
|
|
|
(2,487
|
)
|
|
|
(2,487
|
)
|
|
|
|
|
|
|
|
|
Energy
Commodity Cash Flow Hedges
We are exposed to market risk from changes in energy commodity
prices within our operations. Our Four Corners operation
receives NGL volumes as compensation for certain processing
services. To reduce our exposure to a decrease in revenues from
the sale of these NGL volumes from fluctuations in NGL market
prices, we entered into financial swap contracts. We designate
these derivatives as cash flow hedges under
SFAS No. 133. These derivatives are expected to be
highly effective in offsetting cash flows attributable to the
hedged risk during the term of the hedge. However,
ineffectiveness may be recognized primarily as a result of
locational differences between the hedging derivative and the
hedged item. No net gains or losses from hedge ineffectiveness
are included in the Consolidated Statements of Income during
2007 and 2006. For 2007 and 2006, there were no derivative gains
or losses excluded from the assessment of hedge effectiveness.
At December 31, 2007 we have hedged 4.2 million
gallons of monthly February through December 2008 forecasted NGL
sales. Based on the recorded values at December 31, 2007,
approximately $2.5 million of net losses will be
reclassified into earnings within the next year. These recorded
values are based on market prices of the commodities as of
December 31, 2007. Due to the volatile nature of commodity
prices and changes in the creditworthiness of counterparties,
actual gains or losses realized in 2008 will likely differ from
these values. These gains or losses will offset net losses or
gains that will be realized into earnings from previous
unfavorable or favorable market movements associated with
underlying hedged transactions.
105
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 11.
|
Long-Term
Debt, Credit Facilities and Leasing Activities
|
Long-Term
Debt
Long-term debt at December 31, 2007 and 2006 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
|
December 31,
|
|
|
|
Rate(1)
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(Millions)
|
|
|
Credit agreement term loan, adjustable rate, due 2012
|
|
|
6.16
|
%
|
|
$
|
250.0
|
|
|
$
|
|
|
Senior unsecured notes, fixed rate, due 2017
|
|
|
7.25
|
%
|
|
|
600.0
|
|
|
|
600.0
|
|
Senior unsecured notes, fixed rate, due 2011
|
|
|
7.50
|
%
|
|
|
150.0
|
|
|
|
150.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Long-term debt
|
|
|
|
|
|
$
|
1,000.0
|
|
|
$
|
750.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The terms of the senior unsecured notes are governed by
indentures that contains affirmative and negative covenants
that, among other things, limit (1) our ability and the
ability of our subsidiaries, Discovery and Wamsutter, 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,
our wholly owned subsidiary organized for the sole purpose of
co-issuing our debt securities, 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. The indentures also contain 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 senior unsecured notes at our option in whole
or in part at any time or from time to time prior to the
respective maturity dates, 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 indentures, we may issue additional notes from
time to time. The senior notes and any additional notes
subsequently issued under the indentures, together with any
exchange notes, will be treated as a single class for all
purposes under the indentures, 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 during 2007, 2006 and 2005 were
$38.8 million, $5.5 million and $0.3 million,
respectively.
106
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Credit
Facilities
On December 11, 2007, we entered into a $450.0 million
senior unsecured credit agreement with Citibank, N.A. as
administrative agent, comprised initially of a
$200.0 million revolving credit facility available for
borrowings and letters of credit and a $250.0 million term
loan. Under certain conditions, the revolving credit facility
may be increased up to an additional $100.0 million.
Borrowings under this agreement must be repaid by
December 11, 2012. At December 31, 2007, we had a
$250.0 million term loan outstanding under the term loan
provisions and no amounts outstanding under the revolving credit
facility.
Interest on borrowings under this agreement will be payable at
rates per annum equal to, at our option: (1) a fluctuating
base rate equal to Citibank, N.A.s prime rate plus the
applicable margin, or (2) a periodic fixed rate equal to
LIBOR plus the applicable margin. The applicable margin spread
and commitment fee are based on the specific borrowers
senior unsecured long-term debt ratings.
The credit agreement contains various covenants that limit,
among other things, our, and certain of our subsidiaries,
ability to incur indebtedness, grant certain liens supporting
indebtedness, merge, consolidate or allow any material change in
the character of its business, sell all or substantially all of
our assets, make certain transfers, enter into certain affiliate
transactions, make distributions or other payments other than
distributions of available cash under certain conditions, or use
proceeds other than for partnership purposes (not to include the
purchase or carrying of margin stock). Significant financial
covenants under the credit agreement include the following:
|
|
|
|
|
We together with our consolidated subsidiaries and Wamsutter,
are required to maintain a ratio of consolidated indebtedness to
consolidated EBITDA (each as defined in the credit agreement) of
no greater than 5.00 to 1.00. This ratio may be increased in the
case of an acquisition of $50.0 million or more, in which
case the ratio will be 5.50 to 1.00 for the three fiscal
quarter-periods following such acquisition.
|
|
|
|
Our ratio of consolidated EBITDA to consolidated interest
expense, as defined in the credit agreement, must be not less
than 2.75 to 1.00 as of the last day of any fiscal quarter
commencing March 31, 2008 unless we obtain an investment
grade rating from Standard and Poors Ratings Services or
Moodys Investors Service and the rating from the other
agencies is not less than Ba1 or BB+, as applicable. On
November 10, 2007, Standard and Poors Rating Services
raised our credit rating from BB+ to BBB-. On January 28,
2008, Moodys upgraded the ratings of WPZs senior
unsecured rating to Ba2 from Ba3.
|
Each of the above ratios is to be tested at the end of each
fiscal quarter and measured on a rolling four-quarter basis
commencing March 31, 2008. The credit agreement also
includes customary events of default, upon which the lenders
will be able to accelerate the maturity of the credit agreement
and exercise other rights and remedies.
On November 21, 2007, we were removed as a borrower under
Williams $1.5 billion revolving credit facility. As a
result, we no longer have access to $75.0 million borrowing
capacity under that facility.
On August 7, 2006 we amended and restated our
$20.0 million revolving 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, 2007, we have no outstanding borrowings under
the working capital credit facility.
107
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Exterran Holdings, 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, 2007
are payable as follows:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2008
|
|
$
|
1,513
|
|
2009
|
|
|
1,048
|
|
2010
|
|
|
526
|
|
2011
|
|
|
81
|
|
2012 and thereafter
|
|
|
11
|
|
|
|
|
|
|
|
|
$
|
3,179
|
|
|
|
|
|
|
Total rent expense was $21.2 million, $19.4 million
and $18.9 million for 2007, 2006 and 2005, respectively.
|
|
Note 12.
|
Partners
Capital
|
At December 31, 2007, of our total units outstanding, 75%
were held by the public and the remaining units were held by
affiliates of Williams.
Limited
Partners Rights
Significant rights of the limited partners include the following:
|
|
|
|
|
Right to receive distributions of available cash within
45 days after the end of each quarter.
|
|
|
|
No limited partner shall have any management power over our
business and affairs; the general partner shall conduct, direct
and manage our activities.
|
|
|
|
The general partner may be removed if such removal is approved
by the unitholders holding at least
662/3%
of the outstanding units voting as a single class, including
units held by our general partner and its affiliates.
|
Subordinated
Units
Our subordination period ended on February 19, 2008, the
second business day following the distribution of our available
cash when we met the requirements for early termination pursuant
to our partnership agreement. As a result of the termination,
the 7,000,000 outstanding subordinated units owned by four
subsidiaries of Williams converted one-for-one to common units
and will participate pro rata with the other common units in
distributions of available cash beginning with the May 2008
distribution.
108
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Class B
Units
The Class B units were 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,
and with respect to the right to receive distributions upon our
liquidation.
The Class B units had the same voting rights as our
outstanding common units and were 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 were not entitled to vote on the approval of
the conversion of the Class B units into common units.
On May 21, 2007, the Class B units were converted into
common units on a one-for-one basis upon approval of a majority
of the common units eligible to vote.
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.
|
|
Note 13.
|
Long-Term
Incentive Plan
|
In connection with our initial public offering, 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 granting 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 2007, 2006, and 2005 our general partner granted 2,403,
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 180 days from the
grant date. We recognized compensation expense of $77,000,
$229,000 and $34,000 associated with these awards in 2007, 2006,
and 2005, respectively.
|
|
Note 14.
|
Commitments
and Contingencies
|
Commitments. Commitments for goods and
services used in our operations and for construction and
acquisition of property, plant and equipment are approximately
$56.8 million at December 31, 2007.
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
109
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, 2007 and December 31, 2006 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.
On April 11, 2007, the New Mexico Environment
Departments Air Quality Bureau (NMED) issued a Notice of
Violation to Four Corners that alleges various emission and
reporting violations in connection with our Lybrook gas
processing plants flare and leak detection and repair
program. The NMED proposed a penalty of approximately
$3 million. We are discussing the basis for and the scope
of the proposed penalty with the NMED.
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
$3.1 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 $25.0 million. We
do not expect to submit any claims under this insurance policy
prior to its expected expiration date on April 30, 2008. In
addition, under an omnibus agreement with Williams entered into
at the closing of our IPO, Williams 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 would be reduced by any actual recoveries under the
environmental insurance policy. There is also a three-year time
limitation on this indemnification from the August 23, 2005
IPO closing date. The benefit of this indemnification is
accounted for as a capital contribution to us by Williams as the
costs are reimbursed. At December 31, 2007 and
December 31, 2006, we had accrued liabilities totaling
$3.3 million and $5.9 million, respectively, for these
environmental remediation activities. It is reasonably possible
that we will incur losses in excess of
110
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
our accrual for these matters. However, a reasonable estimate of
such amounts cannot be determined at this time because actual
costs incurred will depend on the actual number of contaminated
sites identified, the amount and extent of contamination
discovered, the final cleanup standards mandated by KDHE and
other governmental authorities and other factors.
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.
The amount of any possible liability cannot be reasonably
estimated at this time.
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. The
amount of any possible liability cannot be reasonably estimated
at this time.
GE Litigation. General Electric International,
Inc. (GEII) worked on turbines at our Ignacio, New Mexico plant.
We disagree with GEII on the quality of GEIIs work and the
appropriate compensation. GEII asserts that it is entitled to
additional extra work charges under the agreement, which we deny
are due.
In 2006 we filed suit in federal court in Tulsa, Oklahoma
against GEII, GE Energy Services, Inc., and Qualified
Contractors, Inc.; alleged, among other claims, breach of
contract, breach of the duty of good faith and fair dealing, and
negligent misrepresentation; and sought unspecified damages. In
2007, the defendants and GEII filed counterclaims against us
that alleged breach of contract and breach of the duty of good
faith and fair dealing. Trial has been set for April 21,
2008. We are unable to quantify or estimate the possible
liability.
Outstanding Registration Rights Agreement. On
December 13, 2006, we issued approximately
$350.0 million of common and Class B units in a
private equity offering. In connection with these issuances, we
entered into a registration rights agreement with the initial
purchasers whereby we agreed to file a shelf registration
statement providing for the resale of the common units purchased
and the common units issued on conversion of the Class B
units. We filed the shelf registration statement on
January 12, 2007 and it became effective on March 13,
2007. On May 21, 2007, our outstanding Class B units
were converted into common units on a one-for-one basis. If the
shelf is unavailable for a period that exceeds an aggregate of
30 days in any
90-day
period or 105 days in any 365 day period, the
purchasers are entitled to receive liquidated damages.
Liquidated damages with respect to each purchaser are calculated
as 0.25% of the Liquidated Damages Multiplier per
30-day
period for the first 60 days following the 90th day,
increasing by an additional
111
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
0.25% of the Liquidated Damages Multiplier per
30-day
period for each subsequent 60 days, up to a maximum of 1%
of the Liquidated Damages Multiplier per
30-day
period; provided, the aggregate amount of liquidated damages
payable to any purchaser is capped at 10% of the Liquidated
Damages Multiplier. The Liquidated Damages Multiplier, with
respect to each purchaser, is (i) the product of $36.59
times the number of common units purchased plus (ii) the
product of $35.81 times the number of Class B units
purchased. Due to amendments made to Rule 144 of the
Securities Act in February 2008, related to securities acquired
by non-affiliates from an issuer subject to public reporting
requirements, we no longer have an obligation to keep our shelf
registration statement effective and would have no liability for
a failure to do so.
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, 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.
112
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering &
|
|
|
Gathering &
|
|
|
|
|
|
|
|
|
|
Processing -
|
|
|
Processing -
|
|
|
NGL
|
|
|
|
|
|
|
West
|
|
|
Gulf
|
|
|
Services
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales
|
|
$
|
279,600
|
|
|
$
|
|
|
|
$
|
11,332
|
|
|
$
|
290,932
|
|
Gathering and processing
|
|
|
236,475
|
|
|
|
2,119
|
|
|
|
|
|
|
|
238,594
|
|
Storage
|
|
|
|
|
|
|
|
|
|
|
28,016
|
|
|
|
28,016
|
|
Fractionation
|
|
|
|
|
|
|
|
|
|
|
9,622
|
|
|
|
9,622
|
|
Other
|
|
|
(2,288
|
)
|
|
|
|
|
|
|
7,941
|
|
|
|
5,653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
513,787
|
|
|
|
2,119
|
|
|
|
56,911
|
|
|
|
572,817
|
|
Product cost and shrink replacement
|
|
|
170,434
|
|
|
|
|
|
|
|
11,264
|
|
|
|
181,698
|
|
Operating and maintenance expense
|
|
|
135,782
|
|
|
|
1,875
|
|
|
|
24,686
|
|
|
|
162,343
|
|
Depreciation, amortization and accretion
|
|
|
41,523
|
|
|
|
1,249
|
|
|
|
3,720
|
|
|
|
46,492
|
|
Direct general and administrative expenses
|
|
|
7,790
|
|
|
|
|
|
|
|
2,190
|
|
|
|
9,980
|
|
Other, net
|
|
|
10,567
|
|
|
|
10,406
|
|
|
|
746
|
|
|
|
21,719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss)
|
|
|
147,691
|
|
|
|
(11,411
|
)
|
|
|
14,305
|
|
|
|
150,585
|
|
Equity earnings
|
|
|
76,212
|
|
|
|
28,842
|
|
|
|
|
|
|
|
105,054
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
223,903
|
|
|
$
|
17,431
|
|
|
$
|
14,305
|
|
|
$
|
255,639
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statement of Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
150,585
|
|
General and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(32,546
|
)
|
Third-party direct
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,102
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
114,937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets
|
|
$
|
1,112,652
|
|
|
$
|
268,471
|
|
|
$
|
98,730
|
|
|
$
|
1,479,853
|
|
Other assets and eliminations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(196,376
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,283,477
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity method investments
|
|
$
|
284,650
|
|
|
$
|
214,526
|
|
|
$
|
|
|
|
$
|
499,176
|
|
Additions to long-lived assets
|
|
$
|
39,391
|
|
|
$
|
|
|
|
$
|
9,090
|
|
|
$
|
48,481
|
|
113
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
61,690
|
|
|
|
18,050
|
|
|
|
|
|
|
|
79,740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
221,499
|
|
|
$
|
17,845
|
|
|
$
|
9,834
|
|
|
$
|
249,178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
143,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets
|
|
$
|
936,317
|
|
|
$
|
281,084
|
|
|
$
|
78,490
|
|
|
$
|
1,295,891
|
|
Other assets and eliminations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,592
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,292,299
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity method investments
|
|
$
|
262,245
|
|
|
$
|
221,187
|
|
|
$
|
|
|
|
$
|
483,432
|
|
Additions to long-lived assets
|
|
|
25,889
|
|
|
|
|
|
|
|
6,381
|
|
|
|
32,270
|
|
114
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
|
|
|
40,555
|
|
|
|
11,880
|
|
|
|
|
|
|
|
52,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
173,832
|
|
|
$
|
13,479
|
|
|
$
|
7,855
|
|
|
$
|
195,166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
119,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets
|
|
$
|
875,250
|
|
|
$
|
246,086
|
|
|
$
|
63,819
|
|
|
$
|
1,185,155
|
|
Other assets and eliminations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,353
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,190,508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity method investments
|
|
$
|
240,156
|
|
|
$
|
225,337
|
|
|
$
|
|
|
|
$
|
465,493
|
|
Additions to long-lived assets
|
|
|
27,578
|
|
|
|
|
|
|
|
3,688
|
|
|
|
31,266
|
|
115
QUARTERLY
FINANCIAL DATA
(Unaudited)
Summarized quarterly financial data are as follows (thousands,
except
per-unit
amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
133,815
|
|
|
$
|
139,269
|
|
|
$
|
149,576
|
|
|
$
|
150,157
|
|
Costs and operating expenses
|
|
|
110,530
|
|
|
|
103,811
|
|
|
|
114,077
|
|
|
|
129,462
|
|
Net income
|
|
|
25,137
|
|
|
|
46,742
|
|
|
|
47,901
|
|
|
|
44,851
|
(a)
|
Basic and diluted net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting
principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
0.31
|
|
|
$
|
0.48
|
(b)
|
|
$
|
0.62
|
|
|
$
|
0.56
|
|
Subordinated units
|
|
$
|
0.31
|
|
|
$
|
0.48
|
(b)
|
|
$
|
0.62
|
|
|
$
|
0.56
|
|
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
0.31
|
|
|
$
|
0.48
|
(b)
|
|
$
|
0.62
|
|
|
$
|
0.56
|
|
Subordinated units
|
|
$
|
0.31
|
|
|
$
|
0.48
|
(b)
|
|
$
|
0.62
|
|
|
$
|
0.56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
48,855
|
|
|
|
53,036
|
|
|
|
66,384
|
|
|
|
46,300
|
|
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
|
|
Subordinated units
|
|
$
|
0.35
|
|
|
$
|
0.25
|
|
|
$
|
0.57
|
|
|
$
|
0.45
|
|
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
0.35
|
|
|
$
|
0.25
|
|
|
$
|
0.57
|
|
|
$
|
0.45
|
|
Subordinated units
|
|
$
|
0.35
|
|
|
$
|
0.25
|
|
|
$
|
0.57
|
|
|
$
|
0.45
|
|
|
|
|
(a) |
|
The fourth quarter of 2007 included |
|
|
|
|
|
a $10.4 million impairment of the Carbonate Trend pipeline
(see Note 7 Other (Income) Expense); and
|
|
|
|
a reduction in operating income from the shutdown of the Ignacio
gas processing plant resulting from a fire.
|
|
|
|
(b) |
|
Earnings per unit for the second quarter of 2007 has been recast
to reflect the conversion of our outstanding Class B units
into common units on a one-for-one basis, which occurred on
May 21, 2007. This resulted in a $5.3 million non-cash
allocation of income to the Class B units representing the
Class B unit beneficial conversion feature during the
second quarter of 2007. The $5.3 million beneficial
conversion feature was computed as the product of the 6,805,492
Class B units and the difference between the fair value of
a privately placed common unit on the date of issuance ($36.59)
and the issue price of a privately placed Class B unit
($35.81). This resulted in an $0.08 decrease from $0.56 per unit
to $0.48 per unit on our earnings per common unit for the second
quarter of 2007. While this correction affects net income
available to limited partners, it does not affect net income,
cash flows nor does it affect total partners equity. |
116
The following table presents the allocation of net income
(loss) for purposes of calculating earnings per unit for each
quarter in 2007, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Net income (loss) allocated to limited partners by quarter:
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
|
$12,225
|
|
|
|
$4,898
|
|
|
|
N/A
|
|
Second quarter
|
|
|
19,017
|
|
|
|
3,795
|
|
|
|
N/A
|
|
Third quarter
|
|
|
24,492
|
|
|
|
12,213
|
|
|
|
(256
|
)
|
Fourth quarter
|
|
|
23,707
|
|
|
|
11,289
|
|
|
|
7,078
|
|
Weighted average common units outstanding by quarter:
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
|
39,358,798
|
|
|
|
14,006,146
|
|
|
|
N/A
|
|
Second quarter
|
|
|
39,358,798
|
|
|
|
14,923,619
|
|
|
|
N/A
|
|
Third quarter
|
|
|
39,359,555
|
|
|
|
21,597,072
|
|
|
|
14,000,000
|
|
Fourth quarter
|
|
|
42,422,444
|
|
|
|
25,266,210
|
|
|
|
14,001,945
|
|
117
|
|
Item 9.
|
Changes
In and Disagreements With Accountants on Accounting and
Financial Disclosure
|
None.
|
|
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 15d 15(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 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 make modifications as necessary; our
intent in this regard is that the Disclosure 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 2007
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
2007 that would need to be reported on
Form 8-K
that have not been previously reported.
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance
|
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.
118
We are managed and operated by the directors and officers of our
general partner. All of our operational personnel are employees
of an affiliate of our general partner.
All of the senior officers of our general partner are also
senior officers of Williams and spend a sufficient amount of
time overseeing the management, operations, corporate
development and future acquisition initiatives of our business.
Alan Armstrong, the chief operating officer of our general
partner, is the principal executive responsible for the
oversight of our affairs. Our non-executive directors 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 25, 2008.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position with Williams Partners GP LLC
|
|
Steven J. Malcolm
|
|
|
59
|
|
|
Chairman of the Board and Chief Executive Officer
|
Donald R. Chappel
|
|
|
56
|
|
|
Chief Financial Officer and Director
|
Alan S. Armstrong
|
|
|
45
|
|
|
Chief Operating Officer and Director
|
James J. Bender
|
|
|
51
|
|
|
General Counsel
|
H. Michael Krimbill
|
|
|
54
|
|
|
Director and Member of Audit and Conflicts Committees
|
Bill Z. Parker
|
|
|
60
|
|
|
Director and Member of Audit and Conflicts Committees
|
Alice M. Peterson
|
|
|
55
|
|
|
Director and Member of Audit and Conflicts Committees
|
Rodney J. Sailor
|
|
|
49
|
|
|
Director and Treasurer
|
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 has served as chairman of the board of
directors and chief executive officer of the general partner of
Williams Pipeline Partners L.P. since August 2007.
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.
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.
Mr. Chappel has served as chief financial officer and a
director of the general partner of Williams Pipeline Partners
L.P. since August 2007. Prior to joining Williams,
Mr. Chappel, from 2000 to April 2003, founded and served as
chief executive officer of a real estate leasing and development
business in Chicago, Illinois. Mr. Chappel has more than
30 years of business and financial management experience
with major corporations and partnerships. From 1987 though
February 2000, Mr. Chappel served in various financial,
administrative and operational leadership positions for Waste
Management, Inc., including twice serving as chief financial
officer, during 1997 and 1998 and most recently during 1999
through February 2000.
Alan S. Armstrong has served as the chief operating
officer and a director of our general partner since February
2005. Since February 2002, Mr. Armstrong has served as a
senior vice president of Williams
119
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. Mr. Bender has served as the general counsel
of the general partner of Williams Pipeline Partners L.P. since
August 2007. 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.
H. Michael Krimbill has served as a director of our
general partner since August 2007. Mr. Krimbill has served
as a director of Seminole Energy Services, LLC, a privately held
natural gas marketing company, since November 2007.
Mr. Krimbill was the president and chief financial officer
of Energy Transfer Partners, L.P. from January 2004 until his
resignation on January 10, 2007. Mr. Krimbill joined
Heritage Propane Partners, L.P. (the predecessor of Energy
Transfer Partners) as vice president and chief financial officer
in 1990. Mr. Krimbill served as president of Heritage from
1999 to 2004 and as president and chief executive officer of
Heritage from 2000 to 2005. Mr. Krimbill also served as a
director of Energy Transfer Equity, the general partner of
Energy Transfer Partners from 2000 to January 2007.
Bill Z. Parker has served as a director of our general
partner since August 2005. Mr. Parker has served as a
director of Laredo Petroleum L.L.C., a privately held
independent oil and gas producing company, since May 2007.
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.
Rodney J. Sailor has served as a director of our general
partner since October 2007. Mr. Sailor has served as vice
president and treasurer of Williams since July 2005. He served
as assistant treasurer of Williams from 2001 to 2005 and was
responsible for capital structuring and capital markets
transactions, management of Williams liquidity position
and oversight of Williams balance sheet restructuring
program. From 1985 to 2001, Mr. Sailor served in various
other capacities for Williams. Mr. Sailor has served as a
director of Apco Argentina Inc., a subsidiary of Williams
engaged oil and gas exploration and production with interests in
seven oil and gas concessions and two exploration permits in
Argentina, since September 2006, and as a director and treasurer
of the general partner of Williams Pipeline Partners L.P. since
August 2007.
120
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 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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121
Our general partners board of directors has affirmatively
determined that each of Ms. Peterson and
Messrs. Krimbill and Parker is an independent
director under the current listing standards of the New
York Stock Exchange and our categorical director independence
standards. In addition, our general partners board of
directors affirmatively determined that Mr. Thomas C.
Knudson, who retired from the board of directors in August 2007,
was an independent director under such standards. In
so doing, 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 provided goods or services for certain of our
subsidiaries, affiliates of Williams and Discovery. The board of
directors also considered the fact that Mr. Krimbill serves
as a director of Seminole Energy Services LLC, which is a
customer and vendor to certain subsidiaries of Williams. The
board of directors also considered the fact that
Ms. Peterson is a director of an affiliate of Research in
Motion Corp., which provides goods or services to affiliates of
Williams. The board of directors noted that, since
Ms. Peterson and Messrs. Knudson and Krimbill do not
serve as executive officers and do not own a significant amount
of voting securities of any of these entities, these
relationships are not material. Accordingly, the board of
directors of our general partner affirmatively determined that
all of the directors mentioned above are independent. Because
Messrs. Armstrong, Chappel, Malcolm, Sailor and Phillip D.
Wright (who served as a director of our general partner until
October 2007) are employees, officers
and/or
directors of Williams, they are not independent under these
standards.
Ms. Peterson and Messrs. Krimbill 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. Krimbill 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 of our general partner 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
Our 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, individually or as a
group, may do so by contacting our general partners
corporate secretary or the presiding director. The contact
information is maintained on the investor relations/corporate
governance page of our website at
http://www.williamslp.com.
122
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 25, 2008.
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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H. Michael Krimbill
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ü
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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 and Mr. H. Michael Krimbill
qualify as audit committee financial experts as
defined by the rules of the SEC. Biographical information for
Ms. Peterson and Mr. Krimbill 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.
123
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 corporate
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, 2007 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 March 26, 2007. 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.
124
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 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,
as amended (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, 2007, 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:
Alice M. Peterson chairman
Bill Z. Parker
H. Michael Krimbill
February 18, 2008
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.
125
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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. Neither we nor our general partner have a
compensation committee. The executive officers of our general
partner are compensated directly by Williams. All 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. None of the executive
officers of our general partner have employment agreements or
are otherwise specifically compensated for their service as an
executive officer of our general partner. A full discussion of
the policies and programs of the compensation committee of
Williams will be set forth in the proxy statement for
Williams 2008 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
Information regarding the portion of Mr. Armstrongs,
Mr. Benders, 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.
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 2008 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.
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 and Donald R.
Chappel, who are directors of our general partner, are also
executive officers of Williams. Rodney J. Sailor, who is a
director of our general partner, is also a non-executive officer
and an employee of Williams. In addition, Phillip D. Wright, who
resigned as a director of our general partner on
October 23, 2007, is also an executive officer 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.
126
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,
H. Michael Krimbill, Steven J. Malcolm
Bill Z. Parker, Alice M. Peterson,
Rodney J. Sailor
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. Please read Certain Relationships and Related
Transactions, and Director Independence
Reimbursement of Expenses of Our General Partner for
information about how we reimburse our general partner for
direct and indirect general and administrative expenses
attributable to our management. Non-employee directors each
receive an annual 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 $25,000 on the date of first election
to the board of directors. Restricted units awarded to
non-employee directors under the annual compensation package or
upon first election to the board of directors are granted under
the Williams Partners GP LLC Long-Term Incentive Plan and vest
180 days after the date of grant. Cash distributions are
paid on these restricted units. Each non-employee director is
also reimbursed for out-of -pocket expenses in connection with
attending meetings of the board of directors or its committees.
Each director will be fully indemnified by us for actions
associated with being a director to the extent permitted under
Delaware law. We also reimburse non-employee directors for the
costs of education programs relevant to their duties as board
members.
For their service, non-management directors received the
following compensation in 2007:
Director
Compensation Fiscal Year 2007
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Fees Earned or Paid
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All Other
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Name
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in Cash
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Unit Awards(1)
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Compensation
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Total
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H. Michael Krimbill
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$
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60,000
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$
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20,706
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(2)
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$
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0
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$
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80,706
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Thomas C. Knudson
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$
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0
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$
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6,670
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(3)
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$
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0
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$
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6,670
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Bill Z. Parker
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$
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60,000
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$
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25,015
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(4)
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$
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0
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$
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85,015
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Alice M. Peterson
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$
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60,000
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$
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25,015
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(5)
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$
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0
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$
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85,015
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(1) |
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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 2007 compensation
expense computed in accordance with Statement of Financial
Accounting Standards No. 123(R). Cash distributions are
paid on these restricted units at the same time and same rate as
distributions paid to our unitholders. |
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(2) |
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The grant date fair value for the 2007 restricted units for
Mr. Krimbill is $50,010. At fiscal year end,
Mr. Krimbill had an aggregate of 1,243 restricted units
outstanding. |
127
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(3) |
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Mr. Knudson did not receive any restricted units in 2007.
At fiscal year end, Mr. Knudson did not have any restricted
units outstanding. Mr. Knudson retired from the board of
directors of our general partner on August 22, 2007. |
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(4) |
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The grant date fair value for the 2007 restricted units for
Mr. Parker is $25,015. At fiscal year end, Mr. Parker
had an aggregate of 580 restricted units outstanding. |
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(5) |
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The grant date fair value for the 2007 restricted units for
Ms. Peterson is $25,015. At fiscal year end,
Ms. Peterson had an aggregate of 580 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, 2006, 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 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
128
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 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
common units of Williams Partners L.P. that are owned by:
|
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|
|
each person known by us to be a beneficial owner of more than 5%
of the units;
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each of the directors of our general partner;
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|
each of the named executive officers of our general
partner; and
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|
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.
129
Percentage of total units beneficially owned is based on
52,774,728 units outstanding. Unless otherwise noted below,
the address for the beneficial owners listed below is One
Williams Center, Tulsa, Oklahoma
74172-0172.
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Percentage
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Common Units
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of Total Common Units
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Name of Beneficial Owner
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Beneficially Owned
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Beneficially Owned
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The Williams Companies, Inc.(a)
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11,613,527
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22.01
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%
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Williams Energy Services, LLC(a)
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8,787,149
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16.65
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%
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Williams Partners GP LLC(a)
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3,363,527
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6.37
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%
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Williams Energy, L.L.C.(a)
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2,952,233
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5.59
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%
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MAPCO Inc.(a)
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2,952,233
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5.59
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%
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Williams Partners Holdings LLC(a)
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2,826,378
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5.35
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%
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Lehman Brothers Holdings Inc.(b)
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3,421,306
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6.48
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%
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Prudential Financial, Inc.(c)
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3,024,864
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5.73
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%
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Jennison Associates LLC(d)
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2,823,749
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5.35
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%
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Alan S. Armstrong(e)
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15,000
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*
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James J. Bender
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2,000
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*
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Donald R. Chappel
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10,000
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*
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H. Michael Krimbill(f)
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26,243
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*
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Steven J. Malcolm(g)
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25,100
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*
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Bill Z. Parker
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8,616
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*
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Alice M. Peterson
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3,616
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*
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Rodney J. Sailor
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0
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*
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All directors and executive officers as a group (eight persons)
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90,575
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*
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* |
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Less than 1%. |
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(a) |
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As noted in the Schedule 13D/A filed with the SEC on
January 18, 2008, The Williams Companies, Inc. is the
ultimate parent company of Williams Energy Services, LLC,
Williams Partners GP 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
each of these companies. 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
Discovery Pipeline LLC is the record holder of 1,425,466 common
units. Williams Energy Services, LLC is the record owner of
1,045,923 common units and, as the sole stockholder of MAPCO
Inc. and the sole member of Williams Discovery Pipeline LLC and
Williams Partners GP LLC, may, pursuant to
Rule 13d-3,
be deemed to beneficially own the units beneficially owned by
MAPCO Inc., Williams Discovery Pipeline LLC and Williams
Partners GP 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
19, 2008, Lehman Brothers Holdings Inc. (Holdings), may be
deemed the beneficial owner of 409,700 common units directly
owned by Lehman Brothers Inc. (LBI), a broker-dealer registered
under Section 15 of the Act, 2,389,206 common units (including
2,200,000 common units issuable upon the exercise of call
options) owned by Lehman Brothers MLP Opportunity Fund LP (MLP
Opport. Fund) and 622,400 common units owned by Lehman Brothers
MLP Partners, LP (MLP Partners). The Schedule 13G notes that:
(i) LBI is a wholly owned subsidiary of Holdings; (ii) Lehman
Brothers MLP Opportunity Associates LP (MLP Opport. Assoc LP) is
the general partner of MLP Opport. Fund, Lehman Brothers MLP
Opportunity Associates LLC (MLP Opport. Assoc LLC) is the
general partner of MLP Opport. Assoc LP and MLP Opport. Assoc
LLC is wholly owned by |
130
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|
Holdings; and (iii) Lehman Brothers MLP Associates, L.P. (MLP
Assoc LP) is the general partner of MLP Partners, LBI Group Lnc.
(LBI Group) is the general partner of MLP Assoc LP and LBI Group
is wholly owned by Holdings. The address of Holdings is 745
Seventh Avenue, New York, New York 10019. |
|
(c) |
|
Based solely on the Schedule 13G/A filed with the SEC on
February 6, 2008, Prudential Financial, Inc. (Prudential),
a Parent Holding Company as defined in the Act, may be deemed to
be the beneficial owner of securities beneficially owned by the
Registered Investment Advisors and Broker Dealers listed in such
Schedule 13G/A, of which Prudential is the direct or
indirect parent, and may have direct or indirect voting power
over the reported 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 13G/A
indicates that Prudential has sole voting and dispositive power
over 1,115 common units and shared voting and dispositive power
over 3,023,749 common units. 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. |
|
(d) |
|
Based solely on the Schedule 13G filed with the SEC on
June 11, 2007, Jennison Associates LLC (Jennison), an
Investment Advisor as defined in the Act, may be deemed to be
the beneficial owner of securities beneficially owned by
investment companies, insurance separate accounts and
institutional clients for which it acts as an investment
advisor. The Schedule 13G notes that Prudential is a managed
portfolio that indirectly owns 100% of equity interests of
Jennison, and may have direct or indirect voting power and/or
dispositive power over the common units which Jennison may be
deemed to beneficially own. The Schedule 13G further notes
that Jennison does not file jointly with Prudential and the
common units reported by Jennison in its Schedule 13G may
be included in the common units reported in the
Schedule 13G filed by Prudential. The address of Jennison
is 466 Lexington Avenue, New York, New York 10017. |
|
(e) |
|
Mr. Armstrong is the trustee of The Shelly Stone Armstrong
Trust dated August 10, 2004, and has the right to receive
or the power to direct the receipt of dividends from, or the
proceeds from the sale of, 5,000 common units that are held by
the trust. |
|
(f) |
|
Includes 663 unvested restricted units granted pursuant to the
Williams Partners GP LLC Long-Term Incentive Plan. |
|
(g) |
|
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 22, 2008,
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.
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Shares of Common
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Stock Owned
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Shares Underlying
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Directly or
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Options Exercisable
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|
|
|
Name of Beneficial Owner
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Indirectly(a)
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Within 60 Days(b)
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Total
|
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|
Percent of Class
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|
|
Alan S. Armstrong
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|
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128,428
|
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75,440
|
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|
203,868
|
|
|
|
|
*
|
James J. Bender
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153,983
|
|
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|
73,825
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|
|
|
227,808
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|
|
|
|
*
|
Donald R. Chappel
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|
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258,285
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|
|
|
113,070
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|
|
|
371,355
|
|
|
|
|
*
|
Steven J. Malcolm
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|
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919,212
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|
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541,665
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|
|
|
1,460,877
|
|
|
|
|
*
|
Rodney J. Sailor
|
|
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33,707
|
|
|
|
26,351
|
|
|
|
60,058
|
|
|
|
|
*
|
Bill Z. Parker
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
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Alice M. Peterson
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
H. Michael Krimbill
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All directors and executive officers as a group (eight persons)
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1,493,615
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|
|
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830,351
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|
|
|
2,323,966
|
|
|
|
|
*
|
131
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|
|
(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 and 128,414 restricted
stock units; Mr. Bender, 2,800 shares owned by
children, 122,693 restricted stock units and 28,490 beneficially
owned shares; Mr. Chappel, 186,642 restricted stock units
and 71,643 beneficially owned shares; Mr. Malcolm,
45,736 shares in The Williams Companies Investment Plus
Plan, 468,092 restricted stock units and 405,384 beneficially
owned shares; and Mr. Sailor, 10,120 shares in The
Williams Investment Plus Plan, 22,933 restricted stock units and
654 beneficially owned shares. Restricted stock units do not
provide the holder with voting or investment power. |
|
(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 22, 2008. Shares subject to
options cannot be voted. |
Securities
Authorized for Issuance Under Equity Compensation
Plans
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,
2007. For more information about this plan, which did not
require approval by our limited partners, please read
Note 13, Long-Term Incentive Plan, of our Notes to
Consolidated Financial Statements and Executive
Compensation Long-Term Incentive Plan.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities
|
|
|
|
|
|
|
|
|
|
Remaining Available
|
|
|
|
Number of Securities
|
|
|
Weighted-Average
|
|
|
for Future Issuance
|
|
|
|
to be Issued Upon
|
|
|
Exercise Price of
|
|
|
Under Equity
|
|
|
|
Exercise of Outstanding
|
|
|
Outstanding
|
|
|
Compensation Plan
|
|
|
|
Options, Warrants
|
|
|
Options, Warrants
|
|
|
(Excluding Securities
|
|
|
|
and Rights
|
|
|
and Rights
|
|
|
Reflected in Column(a))
|
|
Plan Category
|
|
(a)
|
|
|
(b)
|
|
|
(c)
|
|
|
Equity compensation plans approved by security holders
|
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|
|
|
|
|
|
|
|
|
|
|
Equity compensation plans not approved by security holders
|
|
|
|
(1)
|
|
|
|
|
|
|
689,321
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
689,321
|
|
|
|
|
(1) |
|
2,403 unvested restricted units granted pursuant to the Williams
Partners GP LLC Long-Term Incentive Plan were outstanding as of
December 31, 2007. 1,740 restricted units vested on
February 18, 2007 and 663 vest on June 12, 2008. 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. |
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
Transactions
with Related Persons
After the conversion of our subordinated units on
February 19, 2008, our general partner and its affiliates
own 11,613,527 common units representing a 21.6% 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, Related Party
Transactions, 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
132
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 |
|
Distributions of available cash to our general partner and its
affiliates
|
|
We will generally make cash distributions 98% to unitholders,
including our general partner and its affiliates as holders of
an aggregate of 11,613,527 common units and the remaining 2% to
our general partner. |
|
|
|
In addition, if distributions exceed the minimum quarterly
distribution and other higher target levels, our general partner
will be entitled to increasing percentages of the distributions,
up to 50% of the distributions above the highest target level.
We refer to the rights to the increasing distributions as
incentive distribution rights. For further
information about distributions, please read Market for
Registrants Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities. |
|
Reimbursement of expenses to our general partner and its
affiliates
|
|
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. |
|
Withdrawal or removal of our general partner
|
|
If our general partner withdraws or is removed, its general
partner interest and its incentive distribution rights will
either be sold to the new general partner for cash or converted
into common units, in each case for an amount equal to the fair
market value of those interests. |
|
|
|
Liquidation Stage |
|
Liquidation |
|
Upon our liquidation, the partners, including our general
partner, will be entitled to receive liquidating distributions
according to their particular capital account balances. |
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. Our partnership
agreement provides that our general partner will determine in
good faith the expenses that are allocable to us. There is no
minimum or maximum 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, 2007, our general
partner allocated $251,182 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, $109,940 of salary and non-equity incentive plan
compensation expense to us for Donald R. Chappel, the chief
financial officer of our general partner, $312,047 of salary and
non-equity incentive plan compensation expense to us for Alan S.
Armstrong, the chief operating officer of our general partner,
$73,883 of salary and non-equity incentive plan compensation
expense to us for James J. Bender, the general counsel of our
general partner and $31,248 of salary and non-equity incentive
133
plan compensation expense to us for Rodney J. Sailor, a director
of our general partner who is also a non-executive officer and
employee of Williams. Our general partner also allocated to us
$789,029 for Mr. Malcolm, $245,670 for Mr. Chappel,
$593,603 for Mr. Armstrong, $135,483 for Mr. Bender
and $35,843 for Mr. Sailor, 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, Bender, Sailor and
Armstrong, which allocation did not exceed $10,000 for any of
these persons. The foregoing amounts exclude expenses allocated
by Williams to Discovery and Wamsutter. No awards were granted
to our general partners executive officers under the
Williams Partners GP LLC Long-Term Incentive Plan in 2006 or
2007. 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 2008 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, 2007, we incurred
approximately $103.7 million in total 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;
|
|
|
|
indemnification for certain environmental liabilities, tax
liabilities and right-of-way defects;
|
|
|
|
reimbursement for certain expenditures; and
|
|
|
|
a license for the use of certain software and intellectual
property.
|
General
and Administrative Expenses
Williams will provide us with a five-year partial credit for
general and administrative (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 and 2007, the amounts of the G&A credit
were $3.2 million and $2.4 million, respectively, and
in 2008 the amount of the credit will be $1.6 million. We
will receive $800,000 in 2009 and 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:
|
|
|
|
|
remediation costs associated with the KDHE Consent Orders and
certain NGLs associated with our Conway storage facilities;
|
|
|
|
the costs associated with the installation of wellhead control
equipment and well meters at our Conway storage facility;
|
134
|
|
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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 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.
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For the year ended December 31, 2007, Williams indemnified
us $2.9 million, primarily for KDHE related compliance.
Including 2007, Williams has indemnified us for an aggregate of
$5.4 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. The
initial expected cost of the Tahiti pipeline lateral expansion
project was approximately $69.5 million, of which our 40%
share, included in the initial public offering and reimbursed
under the omnibus agreement, is approximately
$27.8 million. Williams will reimburse us for the excess
(up to $3.4 million) 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, included in the initial public
offering and reimbursed under the omnibus agreement. The current
expected cost of the Tahiti pipeline lateral expansion project
is $73.2 million. 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.
Williams has indemnified us for an aggregate of
$1.6 million for 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.
135
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 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
On November 21, 2007, we were removed as a borrower under
Williams $1.5 billion revolving credit facility. As a
result, we no longer have access to a $75.0 million
borrowing capacity under that facility.
Wamsutter
Credit Facility
Prior to our acquisition of the Wamsutter Ownership Interests,
Wamsutter entered into a $20.0 million revolving credit
facility with Williams as the lender. The facility is available
to fund working capital borrowings and for other purposes.
Borrowings under the facility will mature on December 9,
2008. Wamsutter will pay a commitment fee to Williams on the
unused portion of the credit facility of 0.175% annually.
Interest on any borrowings under the facility will be calculated
based upon the one-month LIBOR rate determined the date of the
borrowing.
Wamsutter
Limited Liability Company Agreement
We and an affiliate of Williams have entered into an amended and
restated limited liability company agreement for Wamsutter. This
agreement governs the ownership and management of Wamsutter and
provides for quarterly distributions of available cash to the
members. Please read Business and Properties
Narrative Description of Business Gathering and
Processing West Wamsutter LLC
Agreement.
Additionally, the Wamsutter LLC agreement appoints Williams as
the operator. As such, effective December 1, 2007 Williams
is reimbursed on a monthly basis for all direct and indirect
expenses it incurs on behalf of Wamsutter including
Wamsutters allocable share of general and administrative
costs.
Wamsutter participates in Williams cash management
program. Therefore, Wamsutter carries no cash balances. Pursuant
to this agreement, Wamsutter has made net advances to Williams,
which have been classified as a component of owners equity
because, although the advances are due on demand, Williams has
not historically required repayment or repaid amounts owed to
Wamsutter.
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
136
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, 2007, Discovery reimbursed
Williams $4.8 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 $0.7 million for operation and
management fees, as well as a $0.2 million fee for managing
capitalized projects, pursuant to the operating and maintenance
agreements.
Wamsutter
Purchase and Sale Agreement
On November 30, 2007, 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 (Williams
OLLC). Pursuant to the Purchase and Sale Agreement, on
December 11, 2007, we acquired ownership interests in
Wamsutter consisting of (i) 100% of the Class A
limited liability company membership interests and (ii) 50%
of the initial Class C units (or 20 Class C units)
representing limited liability company membership interests in
Wamsutter for aggregated consideration of $750.0 million.
The conflicts committee of the board of directors of our general
partner recommended approval of the acquisition of the
membership interests in Wamsutter. 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 membership
interests in Wamsutter to our wholly owned subsidiary, Williams
Partners Operating LLC, on December 11, 2007.
Discovery
Purchase and Sale Agreement
On June 20, 2007, Williams Partners Operating LLC, our
operating subsidiary, entered into a Purchase and Sale Agreement
with Williams Energy, L.L.C. and Williams Energy Services, LLC,
pursuant to which the Williams subsidiaries agreed to sell a 20%
limited liability company interest in Discovery to Williams OLLC
for aggregate consideration of $78.0 million. Upon closing
Williams OLLC became the owner of a 60% interest in
Discovery, as Williams OLLC already owned a 40% interest in
Discovery, which it acquired as part of the formation
transaction consummated concurrently with our IPO on
August 23, 2005. The remaining 40% interest in Discovery is
owned by DCP Assets Holding, LP. The conflicts committee of the
board of directors of our general partner recommended approval
of the acquisition of the additional 20% interest in
Discovery. 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.
Natural
Gas and NGL Purchasing Contracts
Certain subsidiaries of Williams market substantially all of the
NGLs and excess natural gas to which Wamsutter and Discovery,
our Conway fractionation and storage facility and our Four
Corners system take title. Wamsutter and 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 Wamsutter and 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,
Wamsutter and 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.
137
For the year ended December 31, 2007, we sold
$268.0 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,
Wamsutter sold $101.2 million of NGLs to a subsidiary of
Williams that purchases substantially all of the NGLs and excess
natural gas to which Wamsutter takes title based on market
pricing and Discovery sold $217.0 million of products 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.
In December 2007 and January 2008, we entered into financial
swap contracts with Williams affiliates to hedge
5.4 million gallons of forecasted NGL sales monthly for
February through December 2008 with a range of fixed prices of
$0.86 to $2.08 per gallon depending on the specific product.
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
34 MMcf/d
during 2007. The term of this agreement expires on
December 31, 2022, but will continue thereafter on a
year-to-year basis subject to termination by either party giving
at least six months written notice of termination prior to the
expiration of each one year period
Pursuant to 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
105 MMcf/d
during 2007. 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
$35.8 million in 2007.
Natural
Gas Purchases
We, Wamsutter and Discovery purchase natural gas primarily for
fuel and shrink replacement from Williams Gas Marketing, an
affiliate of Williams. These purchases are made at current
market prices. For Four Corners, we purchased approximately
$101.9 million of natural gas from Williams Gas Marketing during
2007. Wamsutter purchased approximately $32.0 million and
Discovery purchased approximately $43.8 million of natural
gas for fuel and shrink replacement from Williams Gas Marketing
during 2007.
Four Corners uses waste heat from a co-generation plant located
adjacent to the Milagro treating plant. The co-generation plant
is owned by an affiliate of Williams, Williams Flexible
Generation, LLC. Waste heat is required for the natural gas
treating process, which occurs at Milagro. The charge to us for
the waste heat is based on the natural gas needed to generate
this waste heat. We purchase this natural gas from Williams Gas
Marketing. Included in the $101.9 million presented in the
immediately preceding paragraph is $19.6 million of natural
gas purchases made to pursuant to this arrangement.
For the year ended December 31, 2007 we purchased a gross
amount of $15.3 million of natural gas for our Conway
fractionator from an affiliate of Williams.
In December 2007, we entered into fixed price natural gas
purchase contracts with Williams Gas Marketing to hedge the
price of our natural gas shrink replacement costs for 13.3
BBtu/d at a range of fixed prices from $6.59 to $7.17 per MMBtu.
Balancing
Services Agreement
We maintain a balancing services contract with Williams Gas
Marketing, an affiliate of Williams. Pursuant to this agreement,
Williams Gas Marketing balances deliveries of natural gas
processed by us
138
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 Gas Marketing 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
Gas Marketing at current market prices. Historically, Williams
Gas Marketing 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, 2007:
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we distributed $23.7 million to affiliates of Williams as
quarterly distributions on their common units, subordinated
units, 2% general partner interest and incentive distribution
rights; and
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we purchased $11.3 million of NGLs to replenish deficit
product positions from a subsidiary of Williams based on market
pricing.
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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
us and our 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 us or to our 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.
139
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.
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Item 14.
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Principal
Accountant Fees and Services
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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:
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2007
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2006
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(Thousands)
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Audit Fees
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$
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1,416
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$
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1,459
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Audit-Related Fees
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Tax Fees
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35
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25
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All Other Fees
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$
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1,451
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$
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1,484
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Fees for audit services in 2007 and 2006 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. The fees for audit services do not include audit costs for
stand-alone audits for equity investees, including Discovery or
Wamsutter. Tax fees for 2007 and 2006 include fees for review of
our federal tax return. The audit fees for 2007 and 2006
included in the table above include $0.3 million and
$0.4 million, respectively, for services provided in
connection with the acquisition of interests in Discovery,
Wamsutter and Four Corners.
The audit committee of our general partner 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 our 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 2007, 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.
140
PART IV
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Item 15.
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Exhibits
and Financial Statement Schedules
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(a) 1 and 2. Williams Partners L.P. financials
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Page
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Covered by reports of independent auditors:
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Consolidated balance sheets at December 31, 2007 and 2006
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84
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Consolidated statements of income for each of the three years
ended December 31, 2007
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85
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Consolidated statement of partners capital for each of the
three years ended December 31, 2007
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86
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Consolidated statements of cash flows for each of the three
years ended December 31, 2007
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87
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Notes to consolidated financial statements
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88
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Not covered by reports of independent auditors:
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Quarterly financial data (unaudited)
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115
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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:
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Exhibit
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Number
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Description
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*§Exhibit 2
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.1
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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).
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*§Exhibit 2
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.2
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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).
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*§Exhibit 2
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.3
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Purchase and Sale Agreement, dated June 20, 2007, by and
among Williams Energy, L.L.C., Williams Energy Services, LLC 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 June 25, 2007).
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*§Exhibit 2
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.4
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Purchase and Sale Agreement, dated November 30, 2007, 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 December 3, 2007).
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*Exhibit 3
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.1
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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).
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*Exhibit 3
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.2
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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).
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*Exhibit 3
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.3
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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 (attached
as Exhibit 3.3 to Williams Partners L.P.s annual
report on
Form 10-K
(File
No. 001-32599)
filed with the SEC on February 28, 2007).
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Exhibit
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Number
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Description
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*Exhibit 3
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.4
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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).
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*Exhibit 4
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.1
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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).
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*Exhibit 4
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.2
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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).
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*Exhibit 4
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.3
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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).
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*Exhibit 4
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.4
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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).
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*Exhibit 4
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.5
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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).
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*Exhibit 4
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.6
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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).
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*Exhibit 4
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.7
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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).
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*Exhibit 10
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.1
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|
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
|
|
|
|
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).
|
142
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
*Exhibit 10
|
.6
|
|
|
|
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
|
.7
|
|
|
|
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
|
.8
|
|
|
|
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
|
.9
|
|
|
|
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
|
.10
|
|
|
|
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
|
.11
|
|
|
|
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
|
.12
|
|
|
|
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 10
|
.13
|
|
|
|
Assignment Agreement, dated December 11, 2007, by and
between Williams Field Services Company, LLC and Wamsutter LLC
(attached as Exhibit 10.01 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 17, 2007).
|
|
*Exhibit 10
|
.14
|
|
|
|
Contribution, Conveyance and Assumption Agreement, dated
December 11, 2007, 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 10.2 to Williams Partners L.P.s current
report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 17, 2007).
|
|
*Exhibit 10
|
.15
|
|
|
|
Amended and Restated Limited Liability Company Agreement of
Wamsutter LLC, dated December 11, 2007, 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 10.3 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 17, 2007).
|
|
*Exhibit 10
|
.16
|
|
|
|
Common Unit Redemption Agreement, dated December 11,
2007, by and between Williams Partners L.P. and Williams
Partners GP 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 December 17, 2007).
|
143
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
*Exhibit 10
|
.17
|
|
|
|
Credit Agreement dated as of December 11, 2007, by and
among Williams Partners L.P., the lenders party hereto,
Citibank, N.A., as Administrative Agent and Issuing Bank, and
The Bank of Nova Scotia, as Swingline Lender (attached as
Exhibit 10.5 to Williams Partners L.P.s current
report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 17, 2007).
|
|
*Exhibit 10
|
.18
|
|
|
|
Working Capital Loan Agreement, dated December 11, 2007, by
and between The Williams Companies, Inc. and Wamsutter LLC
(attached as Exhibit 10.6 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 17, 2007).
|
|
+Exhibit 12
|
|
|
|
|
Computation of Ratio of Earnings to Fixed Charges
|
|
+Exhibit 21
|
|
|
|
|
List of subsidiaries of Williams Partners L.P.
|
|
+Exhibit 23
|
.1
|
|
|
|
Consent of Independent Registered Public Accounting Firm,
Ernst & Young LLP.
|
|
+Exhibit 23
|
.2
|
|
|
|
Consent of Independent Auditors, 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. |
|
|
|
(c) |
|
Wamsutter LLC financial statements and notes thereto
Discovery Producer Services LLC financial statements and notes
thereto |
144
Report of
Independent Auditors
To the Management Committee of
Wamsutter LLC
We have audited the accompanying balance sheets of Wamsutter LLC
as of December 31, 2007 and 2006, and the related
statements of income, members capital, and cash flows for
each of the three years in the period ended December 31,
2007. 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 auditing standards
generally accepted in the United States. Those standards require
that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of
material misstatement. We were not engaged to perform an audit
of Wamsutter LLCs internal control over financial
reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of
Wamsutter LLCs internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of Wamsutter LLC at December 31, 2007 and 2006, and the
results of its operations and its cash flows for each of the
three years in the period ended December 31, 2007 in
conformity with U.S. generally accepted accounting
principles.
As described in Note 5, effective December 31, 2005,
Wamsutter LLC adopted Financial Accounting Standards Board
Interpretation No. 47, Accounting for Conditional Asset
Retirement Obligations.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 25, 2008
145
WAMSUTTER
LLC
BALANCE
SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
7,644
|
|
|
$
|
6,713
|
|
Affiliate
|
|
|
13,299
|
|
|
|
|
|
Other
|
|
|
2,424
|
|
|
|
|
|
Product imbalance
|
|
|
2,038
|
|
|
|
1,449
|
|
Reimbursable capital projects
|
|
|
1,709
|
|
|
|
1,679
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
27,114
|
|
|
|
9,841
|
|
Property, plant and equipment, net
|
|
|
275,163
|
|
|
|
265,519
|
|
Other noncurrent assets
|
|
|
191
|
|
|
|
257
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
302,468
|
|
|
$
|
275,617
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable trade
|
|
$
|
4,627
|
|
|
$
|
5,842
|
|
Accounts payable affiliate
|
|
|
5,153
|
|
|
|
|
|
Product imbalance
|
|
|
2,296
|
|
|
|
3,041
|
|
Accrued liabilities
|
|
|
868
|
|
|
|
1,530
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
12,944
|
|
|
|
10,413
|
|
Deferred revenue
|
|
|
2,311
|
|
|
|
1,429
|
|
Other noncurrent liabilities
|
|
|
501
|
|
|
|
530
|
|
Commitments and contingencies (Note 10)
|
|
|
|
|
|
|
|
|
Members capital
|
|
|
286,712
|
|
|
|
263,245
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members capital
|
|
$
|
302,468
|
|
|
$
|
275,617
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
146
WAMSUTTER
LLC
STATEMENTS
OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales affiliate
|
|
$
|
101,191
|
|
|
$
|
113,484
|
|
|
$
|
121,909
|
|
Gathering and processing services
|
|
|
67,904
|
|
|
|
57,859
|
|
|
|
50,420
|
|
Other revenues
|
|
|
6,214
|
|
|
|
5,203
|
|
|
|
4,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
175,309
|
|
|
|
176,546
|
|
|
|
177,090
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
34,973
|
|
|
|
55,206
|
|
|
|
83,562
|
|
Third-party
|
|
|
11,066
|
|
|
|
15,882
|
|
|
|
16,831
|
|
Operating and maintenance expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
36
|
|
|
|
3,969
|
|
|
|
1,100
|
|
Third-party
|
|
|
18,221
|
|
|
|
13,078
|
|
|
|
11,405
|
|
Depreciation, amortization and accretion
|
|
|
18,424
|
|
|
|
16,189
|
|
|
|
14,321
|
|
General and administrative expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
11,825
|
|
|
|
8,866
|
|
|
|
7,994
|
|
Third-party
|
|
|
798
|
|
|
|
|
|
|
|
137
|
|
Taxes other than income
|
|
|
1,637
|
|
|
|
1,411
|
|
|
|
1,175
|
|
Other net
|
|
|
944
|
|
|
|
255
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
97,924
|
|
|
|
114,856
|
|
|
|
136,535
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
77,385
|
|
|
|
61,690
|
|
|
|
40,555
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
(48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
77,385
|
|
|
$
|
61,690
|
|
|
$
|
40,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
147
WAMSUTTER
LLC
STATEMENT
OF MEMBERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor
|
|
|
Williams
|
|
|
|
|
|
Class C*
|
|
|
|
|
|
|
Owners
|
|
|
Partners
|
|
|
Williams
|
|
|
|
|
|
Williams
|
|
|
|
|
|
|
Equity
|
|
|
Class A
|
|
|
Class B
|
|
|
Williams
|
|
|
Partners
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Balance December 31, 2004
|
|
$
|
222,360
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
222,360
|
|
Net income 2005
|
|
|
40,507
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,507
|
|
Distributions
|
|
|
(21,711
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,711
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2005
|
|
|
241,156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
241,156
|
|
Net income 2006
|
|
|
61,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61,690
|
|
Distributions
|
|
|
(39,601
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(39,601
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2006
|
|
|
263,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
263,245
|
|
Net income through November 30, 2007
|
|
|
70,023
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70,023
|
|
Distributions
|
|
|
(55,006
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(55,006
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
278,262
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
278,262
|
|
Conversion of predecessor owners equity to member capital
|
|
|
(278,262
|
)
|
|
|
276,262
|
|
|
|
|
|
|
|
1,000
|
|
|
|
1,000
|
|
|
|
|
|
Capital contributions
|
|
|
|
|
|
|
|
|
|
|
1,088
|
|
|
|
|
|
|
|
|
|
|
|
1,088
|
|
Net income December 2007
|
|
|
|
|
|
|
7,362
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,362
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007
|
|
$
|
|
|
|
$
|
283,624
|
|
|
$
|
1,088
|
|
|
$
|
1,000
|
|
|
$
|
1,000
|
|
|
$
|
286,712
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Williams and Williams Partners each have 20 Class C units |
See accompanying notes to financial statements.
148
WAMSUTTER
LLC
STATEMENTS
OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
77,385
|
|
|
$
|
61,690
|
|
|
$
|
40,507
|
|
Adjustments to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
48
|
|
Depreciation, amortization and accretion
|
|
|
18,424
|
|
|
|
16,189
|
|
|
|
14,321
|
|
Provision for loss on property plant & equipment
|
|
|
1,392
|
|
|
|
|
|
|
|
|
|
Cash provided (used) by changes in current assets and
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(16,655
|
)
|
|
|
(1,118
|
)
|
|
|
(995
|
)
|
Reimbursable capital projects
|
|
|
(29
|
)
|
|
|
(1,662
|
)
|
|
|
797
|
|
Accounts payable
|
|
|
6,113
|
|
|
|
(659
|
)
|
|
|
1,373
|
|
Product imbalance
|
|
|
(1,335
|
)
|
|
|
(8
|
)
|
|
|
(546
|
)
|
Accrued liabilities
|
|
|
(662
|
)
|
|
|
473
|
|
|
|
527
|
|
Deferred revenue
|
|
|
882
|
|
|
|
682
|
|
|
|
35
|
|
Other, including changes in other noncurrent assets and
liabilities
|
|
|
26
|
|
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
85,541
|
|
|
|
75,641
|
|
|
|
56,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(29,450
|
)
|
|
|
(36,133
|
)
|
|
|
(35,161
|
)
|
Change in accounts payable capital expenditures
|
|
|
(2,174
|
)
|
|
|
93
|
|
|
|
805
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(31,624
|
)
|
|
|
(36,040
|
)
|
|
|
(34,356
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to The Williams Companies, Inc. net
|
|
|
(55,005
|
)
|
|
|
(39,601
|
)
|
|
|
(21,711
|
)
|
Capital contributions
|
|
|
1,088
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by financing activities
|
|
|
(53,917
|
)
|
|
|
(39,601
|
)
|
|
|
(21,711
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in cash and cash equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
149
WAMSUTTER
LLC
NOTES TO
FINANCIAL STATEMENTS
|
|
Note 1.
|
Basis of
Presentation
|
References in this report to we, our,
us or like terms refer to Wamsutter LLC. The
accompanying financial statements and related notes present the
financial position, results of operations, cash flows and
members capital of a natural gas gathering and processing
system in Wyoming previously held by Williams Field Services
Company, LLC (WFSC). This system is collectively referred to as
the Wamsutter system. WFSC is a wholly owned
subsidiary of The Williams Companies, Inc (Williams). In June
2007, WFSC formed a new entity, Wamsutter LLC. On
December 11, 2007, the Wamsutter assets were conveyed by
WFSC into Wamsutter LLC in connection with the acquisition of
certain ownership interests in Wamsutter LLC by Williams
Partners L.P. (the Partnership). Pursuant to that acquisition
effective December 1, 2007, the Partnership owns 100% of
our Class A membership interests and 50% of our initial
Class C units (or 20 Class C units). WFSC owns 100% of
our Class B membership interests and the remaining 50% of
our initial Class C units (or 20 Class C units). See
Note 8, Members Capital, for more
information about these different forms of ownership.
|
|
Note 2.
|
Description
of Business
|
We operate a natural gas gathering and processing system in
Wyoming. This gathering and processing system includes natural
gas gathering pipelines and a processing plant. The system
includes approximately 1,700 miles of natural gas gathering
pipelines with typical operating capacity of approximately
500 million cubic feet per day (MMcfd) at current operating
pressures. The system has total compression of approximately
70,000 horsepower. The assets include the Echo Springs natural
gas processing plant, which has an inlet capacity of
390 million cubic feet per day and can produce
approximately 30,000 barrels per day (bpd) of natural gas
liquids (NGLs).
|
|
Note 3.
|
Summary
of Significant Accounting Policies
|
Basis of Presentation. The financial
statements have been prepared based upon accounting principles
generally accepted in the United States. 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 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 asset retirement obligations. These estimates
are discussed further in the accompanying notes.
Accounts Receivable. Accounts receivable are
carried on a gross basis, with no discounting, less an allowance
for doubtful accounts. No allowance for doubtful accounts is
recognized at the time the revenue which generates the accounts
receivable is recognized. We estimate the allowance for doubtful
accounts based on existing economic conditions, the financial
condition of our customers and the amount and age of past due
accounts. Receivables are considered past due if full payment is
not received by the contractual due date. Past due accounts are
generally written off against the allowance for doubtful
accounts only after all collection attempts have been
unsuccessful.
Product Imbalances. In the course of providing
gathering and processing services to our customers, we realize
over and under deliveries of our customers products, and
over and under purchases of shrink replacement gas when our
purchases vary from operational requirements. In addition, we
realize gains and losses which we believe are related to
inaccuracies inherent in the gas measurement process. These
items are reflected as product imbalance receivables and
payables on the Balance Sheets. Product imbalance receivables
150
WAMSUTTER
LLC
NOTES TO
FINANCIAL STATEMENTS (Continued)
are valued based on the lower of the current market prices or
current cost of natural gas in the system. Product imbalance
payables are valued at current market prices. The majority of
our settlements are through in-kind arrangements whereby
incremental volumes are delivered to a customer (in the case of
an imbalance payable) or received from a customer (in the case
of an imbalance receivable). Such in-kind deliveries are
on-going and take place over several periods. In some cases,
settlements of imbalances built up over a period of time are
ultimately settled in cash and are generally negotiated at
values which approximate average market prices over a period of
time. These gains and losses impact our results of operations
and are included in operating and maintenance expense in the
Statements of Income.
Property, Plant and Equipment. Property, plant
and equipment is recorded at cost. We base the carrying value of
these assets on capitalized costs, useful lives and salvage
values. Depreciation of property, plant and equipment is
provided on a straight-line basis over estimated useful lives.
Expenditures for maintenance and repairs are expensed as
incurred. Expenditures that extend the useful lives of the
assets or increase their functionality are capitalized. The cost
of property, plant and equipment sold or retired and the related
accumulated depreciation is removed from the accounts in the
period of sale or disposition. Gains and losses on the disposal
of property, plant and equipment are recorded in operating
income.
We record an asset and a liability equal to the present value of
each expected future asset retirement obligation (ARO). The ARO
asset is depreciated in a manner consistent with the
depreciation of the underlying physical asset. We measure
changes in the liability due to passage of time by applying an
interest method of allocation. This amount is recognized as an
increase in the carrying amount of the liability and as a
corresponding accretion expense included in operating income.
Revenue Recognition. Revenue for sales of
products are recognized when the product has been delivered, and
revenues from the gathering and processing of gas are generally
recognized in the period the service is provided, based on
contractual terms and the related natural gas and liquid
volumes. One gathering agreement provides incremental fee-based
revenues upon the completion of projects that lower system
pressures. This revenue is recognized on a units-of-production
basis as gas is produced under this agreement. Additionally,
revenue from customers for the installation and operation of
electronic flow measurement equipment is recognized evenly over
the life of the underlying agreements.
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 members through the allocation of
taxable income. Net income for financial statement purposes may
differ significantly from taxable income of members as a result
of differences between the tax basis and financial reporting
basis of assets and liabilities.
Recent Accounting Standards. In September
2006, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 157,
Fair Value Measurements. This Statement establishes
a framework for fair value measurements in the financial
statements by providing a definition of fair value, provides
guidance on the methods used to estimate fair value and expands
disclosures about fair value measurements.
SFAS No. 157 is effective for fiscal years beginning
after November 15, 2007. In December 2007, the FASB issued
proposed FASB Staff Position (FSP)
No. FAS 157-b
deferring the effective date of SFAS No. 157 to fiscal
years beginning after November 15, 2008 for all
non-financial assets and liabilities, except those that are
recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually).
SFAS No. 157 requires two distinct transition
approaches; (i) cumulative-effect adjustment to beginning
retained earnings for certain financial instrument transactions
and (ii) prospectively as of the date of adoption through
earnings or other comprehensive income, as applicable. On
January 1, 2008, we adopted SFAS No. 157 applying
a prospective transition for our assets and liabilities that are
measured at fair value on a recurring basis with no material
impact to our Consolidated Financial Statements.
SFAS No. 157 expands disclosures about assets and
liabilities measured at fair value on a recurring basis
effective beginning with the first-quarter 2008 reporting.
151
WAMSUTTER
LLC
NOTES TO
FINANCIAL STATEMENTS (Continued)
In February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial Assets and Financial
Liabilities Including an Amendment of FASB Statement
No. 115. SFAS No. 159 establishes a fair
value option permitting entities to elect to measure eligible
financial instruments and certain other items at fair value.
Unrealized gains and losses on items for which the fair value
option has been elected will be reported in earnings. The fair
value option may be applied on an
instrument-by-instrument
basis, is irrevocable and is applied only to the entire
instrument. SFAS No. 159 is effective as of the
beginning of the first fiscal year beginning after
November 15, 2007, and should not be applied
retrospectively to fiscal years beginning prior to the effective
date. On the adoption date, an entity may elect the fair value
option for eligible items existing at that date and the
adjustment for the initial remeasurement of those items to fair
value should be reported as a cumulative effect adjustment to
the opening balance of retained earnings. Subsequent to
January 1, 2008, the fair value option can only be elected
when a financial instrument or certain other item is entered
into. On January 1, 2008, we adopted SFAS No. 159
but have not elected the fair value option for any existing
eligible financial instruments or other items.
|
|
Note 4.
|
Related
Party Transactions
|
The employees supporting our operations are employees of
Williams. Their payroll costs are directly charged to us by
Williams. Williams carries the accruals for most
employee-related liabilities in its financial statements,
including the liabilities related to the employee retirement and
medical plans and paid time off accruals. Our share of these
costs is charged to us through a benefit load factor with the
payroll costs and are reflected in Operating and maintenance
expense Affiliate in the accompanying Statements of
Income.
We purchase natural gas for fuel and shrink replacement from
Williams Gas Marketing (WGM), a wholly owned indirect subsidiary
of Williams. These purchases are made at market rates at the
time of purchase. These costs are reflected in Operating and
maintenance expense Affiliate and Product
cost Affiliate in the accompanying Statements of
Income.
A summary of affiliate operating and maintenance expenses
directly charged to us for the periods stated is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Thousands)
|
|
|
Operating and maintenance expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Other natural gas purchases, system gains
|
|
$
|
(5,225
|
)
|
|
$
|
(323
|
)
|
|
$
|
(2,649
|
)
|
Salaries and benefits and other
|
|
|
5,261
|
|
|
|
4,292
|
|
|
|
3,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
36
|
|
|
$
|
3,969
|
|
|
$
|
1,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We are charged for certain administrative expenses by Williams
and its Midstream segment of which we are a part. These charges
are either directly identifiable or allocated to our assets.
Direct charges are for goods and services provided by Williams
and Midstream at our request. Allocated charges are either
(1) charges allocated to the Midstream segment by Williams
and then reallocated from the Midstream segment to us or
(2) Midstream-level administrative costs that are allocated
to us. These expenses are allocated based on a three-factor
formula, which considers revenues, property, plant and equipment
and payroll. These costs are reflected in General and
administrative expenses Affiliate in the
accompanying Statements of Income. In managements
estimation, the allocation methodologies used are reasonable and
result in a reasonable allocation to us of our costs of doing
business incurred by Williams and its Midstream segment.
We sell the NGLs to which we take title to Williams NGL
Marketing LLC (WNGLM), a wholly owned indirect subsidiary of
Williams. Revenues associated with these activities are
reflected as Product sales affiliate on the
Statements of Income. These sales are made at market rates at
the time of sale.
152
WAMSUTTER
LLC
NOTES TO
FINANCIAL STATEMENTS (Continued)
We participate in Williams cash management program; hence,
we maintain no cash balances. Prior to December 1, 2007,
our net advances to Williams under an unsecured promissory note
agreement which allowed for both advances to and from Williams
were classified as a component of members capital because,
although the advances were due on demand, Williams had not
historically required repayment or repaid amounts owed to us.
Changes in the advances to Williams are presented as
distributions to Williams in the Statement of Members
Capital and Statements of Cash Flows. As of December 1,
2007 these net advances to Williams are included in Accounts
receivable Affiliate. As of December 31, 2007
we had a receivable of $1.3 million. Interest is paid to us
on amounts receivable from Williams under the cash
management program based on the rate received by Williams on the
overnight investment of its excess cash.
|
|
Note 5.
|
Property,
Plant and Equipment
|
Property, plant and equipment, at cost, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
|
December 31,
|
|
|
Depreciable
|
|
|
|
2007
|
|
|
2006
|
|
|
Lives
|
|
|
|
(Thousands)
|
|
|
Land, rights of way and other
|
|
$
|
18,613
|
|
|
$
|
15,304
|
|
|
|
30 years
|
|
Gathering pipelines and related equipment
|
|
|
313,283
|
|
|
|
287,028
|
|
|
|
30 years
|
|
Processing plants and related equipment
|
|
|
48,673
|
|
|
|
43,650
|
|
|
|
30 years
|
|
Buildings and related equipment
|
|
|
11,122
|
|
|
|
11,271
|
|
|
|
3-30 years
|
|
Construction work in progress
|
|
|
7,212
|
|
|
|
14,161
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
398,903
|
|
|
|
371,414
|
|
|
|
|
|
Accumulated depreciation
|
|
|
123,740
|
|
|
|
105,895
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
275,163
|
|
|
$
|
265,519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective December 31, 2005, we adopted FASB Interpretation
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 approximately $57,000 equal to the present
value of expected future asset retirement obligations at
December 31, 2005. The liabilities are slightly offset by a
$9,000 increase in property, plant and equipment, net of
accumulated depreciation, recorded as if the provisions of the
Interpretation had been in effect at the date the obligation was
incurred. The net $48,000 reduction to earnings is reflected as
a cumulative effect of change in accounting principle for the
year ended 2005.
Our ARO at December 31, 2007 and 2006 is approximately
$0.2 million. The obligations relate to gas processing and
compression facilities located on leased land and wellhead
connections on federal land. At the end of the useful life of
each respective asset, we are legally or contractually obligated
to remove certain surface equipment and cap certain gathering
pipelines at the wellhead connection.
153
WAMSUTTER
LLC
NOTES TO
FINANCIAL STATEMENTS (Continued)
|
|
Note 6.
|
Accrued
Liabilities
|
Accrued liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands)
|
|
|
Taxes other than income
|
|
$
|
818
|
|
|
$
|
820
|
|
Construction retainage
|
|
|
50
|
|
|
|
689
|
|
Other
|
|
|
|
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
868
|
|
|
$
|
1,530
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 7.
|
Credit
Facilities and Leasing Activities
|
On December 11, 2007, we entered into a $20.0 million
revolving credit facility with Williams as the lender. The
credit facility is available to fund working capital
requirements and for other purposes. Borrowings under the credit
facility mature on December 9, 2008 and bear interest at
the one-month LIBOR. We pay a commitment fee to Williams on the
unused portion of the credit facility of 0.175% annually. As of
December 31, 2007, we had no outstanding borrowings under
the credit facility.
We lease the land on which a significant portion of our pipeline
assets are located. The primary landowner is the Bureau of Land
Management (BLM). The BLM leases are for thirty years with
renewal options. In 2005, we also began leasing two compression
units under a five-year agreement. Under the terms of this lease
agreement, we have guaranteed the residual value of the
compression units in the event of a casualty loss. The guarantee
has a maximum potential exposure at December 31, 2007 of
$5.7 million. The recorded carrying value of this guarantee
was $0.2 million and $0.3 million at December 31,
2007 and 2006, respectively. We also lease vehicles under
non-cancelable leases, which are for lease terms of about
45 months. These leases are accounted for as operating
leases. The future minimum annual rentals under these
non-cancelable leases as of December 31, 2007 are payable
as follows:
|
|
|
|
|
|
|
(Thousands)
|
|
|
2008
|
|
|
1,238
|
|
2009
|
|
|
1,142
|
|
2010
|
|
|
1,080
|
|
2011
|
|
|
8
|
|
2012
|
|
|
7
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,475
|
|
|
|
|
|
|
Total rent expense for the years ended 2007, 2006 and 2005 was
$2.0 million, $1.7 million and $0.7 million,
respectively.
Governance. Most decisions regarding our day
to day operations are made by Williams, in its capacity as the
Class B member. However, certain decisions require the
consent of the Class A member, including, but not limited
to, (i) the sale or disposition of assets over
$20.0 million, (ii) the merger or consolidation with
another entity, (iii) the purchase or acquisition of assets
or businesses, (iv) the making of an investment in a third
party in excess of $20.0 million, (v) the guarantee or
incurrence of any debt, (vi) the cancelling or settling of
any claim in excess of $20.0 million, (vii) the
selling or redeeming of any equity interests in us,
154
WAMSUTTER
LLC
NOTES TO
FINANCIAL STATEMENTS (Continued)
(viii) the declaration of distributions not described
below, (ix) the entering into certain transactions outside
the ordinary course of business with our affiliates and
(x) the approval of our annual business plan. Williams also
controls the Class A member through its ownership of the
Class A members general partner.
Distributions. Our limited liability company
(LLC) agreement provides for distributions of available
cash to be made quarterly. We distribute our available cash as
follows:
|
|
|
|
|
First, an amount equal to $17.5 million per quarter
to the holder of our Class A membership interests;
|
|
|
|
Second, an amount to the holder of our Class A
membership interests, if any, needed to increase the
distribution on our Class A membership interests in prior
quarters of the current distribution year to $17.5 million
per quarter; and
|
|
|
|
Third, 5% of remaining available cash shall be
distributed to the holder of our Class A membership
interests and 95% shall be distributed to the holders of our
Class C units, on a pro rata basis.
|
In addition, to the extent that at the end of the fourth quarter
of a distribution year, our Class A member has received
less than $70.0 million under the first and second bullets
above, our Class C members will be required to repay any
distributions they received in that distribution year such that
our Class A member receives $70.0 million for that
distribution year. If this repayment is insufficient to result
in the Class A member receiving $70.0 million, the
shortfall will not carry forward to the next distribution year.
Our initial distribution year for Wamsutter began on
December 1, 2007 and will end on November 30, 2008.
Subsequent distribution years for Wamsutter will commence on
December 1 and end on November 30.
Our LLC agreement provides each quarter during 2008 through
2012, that we will receive a transition support payment, related
to a cap on general and administrative expenses, from our
Class B ownership interest. This payment will be
distributed directly to our Class A ownership interest. The
reimbursement will be treated as a capital contribution by our
Class B member and the cost subject to this reimbursement
will be allocated entirely to our Class B member.
Income Allocation. The allocation of our net
income is based upon the allocation and distribution provisions
of our LLC agreement. In general, the agreement allocates income
to the Class A, B and C ownership interest in a manner that
will maintain capital account balances reflective of the amounts
each ownership interest would receive if we were dissolved and
liquidated at our carrying value. In general, income allocations
follow the provisions of our LLC agreement for the distribution
of our available cash.
Contributions for Capital Expenditures. We
fund expansion capital expenditures through capital
contributions from our members as specified in our LLC
agreement. The agreement specifies that expansion capital
expenditures with expected total expenditures in excess of
$2.5 million at the time of approval and well connections
that grow gathered volumes as defined in our LLC agreement be
funded by contributions from our Class B membership. Our
Class A membership interest will provide capital
contributions related to expansion projects with expected total
expenditures less than $2.5 million at the time of
approval. On the first day of the quarter following the quarter
the asset related to these expansion capital expenditures is
placed in service, we will issue to each contributing member one
Class C unit for each $50,000 contributed by it, including
the interest accrued on the investment prior to the issuance of
the Class C units. We will issue fractional Class C
units as necessary.
|
|
Note 9.
|
Major
Customers and Concentrations of Credit Risk
|
At December 31, 2007 and 2006, substantially all of our
accounts receivable result from product sales and gathering and
processing services provided to our five largest customers. This
concentration of customers may impact our overall credit risk
either positively or negatively, in that these entities may be
similarly affected by industry-wide changes in economic or other
conditions. As a general policy, collateral is not
155
WAMSUTTER
LLC
NOTES TO
FINANCIAL STATEMENTS (Continued)
required for receivables, but customers financial
condition and credit worthiness are evaluated regularly. Our
credit policy and the relatively short duration of receivables
mitigate the risk of uncollected receivables.
Our largest customer, on a percentage of revenues basis, is
WNGLM, which purchases and resells substantially all of the NGLs
to which we take title. WNGLM accounted for 56%, 66% and 72% of
revenues in 2007, 2006 and 2005, respectively. The percentages
for the remaining two largest customers are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
2006
|
|
2005
|
|
Customer A
|
|
|
20
|
%
|
|
|
16
|
%
|
|
|
14
|
%
|
Customer B
|
|
|
10
|
|
|
|
10
|
|
|
|
8
|
|
|
|
Note 10.
|
Commitments
and Contingencies
|
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.
The amount of any possible liability cannot be reasonably
estimated at this time.
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. The
amount of any possible liability cannot be reasonably estimated
at this time.
156
Report of
Independent Registered Public Accounting Firm
To the Management Committee of
Discovery Producer Services LLC
We have audited the accompanying consolidated balance sheets of
Discovery Producer Services LLC as of December 31, 2007 and
2006, and the related consolidated statements of income,
members capital, and cash flows for each of the three
years in the period ended December 31, 2007. 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. We were not engaged to perform an
audit of the Companys internal control over financial
reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of
the Companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Discovery Producer Services LLC at
December 31, 2007 and 2006, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2007, in conformity with
U.S. generally accepted accounting principles.
As described in Note 4, effective December 31, 2005,
Discovery Producer Services LLC adopted Financial Accounting
Standards Board Interpretation No. 47, Accounting for
Conditional Asset Retirement Obligations.
Tulsa, Oklahoma
February 25, 2008
157
DISCOVERY
PRODUCER SERVICES LLC
CONSOLIDATED
STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
216,889
|
|
|
$
|
148,385
|
|
|
$
|
70,848
|
|
Third-party
|
|
|
5,251
|
|
|
|
|
|
|
|
4,271
|
|
Gas and condensate transportation services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
979
|
|
|
|
3,835
|
|
|
|
2,104
|
|
Third-party
|
|
|
15,553
|
|
|
|
14,668
|
|
|
|
13,302
|
|
Gathering and processing services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
3,092
|
|
|
|
8,605
|
|
|
|
3,912
|
|
Third-party
|
|
|
17,767
|
|
|
|
19,473
|
|
|
|
25,806
|
|
Other revenues
|
|
|
1,141
|
|
|
|
2,347
|
|
|
|
2,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
260,672
|
|
|
|
197,313
|
|
|
|
122,745
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
93,722
|
|
|
|
66,890
|
|
|
|
19,103
|
|
Third-party
|
|
|
61,982
|
|
|
|
52,662
|
|
|
|
45,364
|
|
Operating and maintenance expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
5,579
|
|
|
|
5,276
|
|
|
|
3,739
|
|
Third-party
|
|
|
23,409
|
|
|
|
17,773
|
|
|
|
6,426
|
|
Depreciation and accretion
|
|
|
25,952
|
|
|
|
25,562
|
|
|
|
24,794
|
|
Taxes other than income
|
|
|
1,330
|
|
|
|
1,114
|
|
|
|
1,151
|
|
General and administrative expenses affiliate
|
|
|
2,280
|
|
|
|
2,150
|
|
|
|
2,053
|
|
Other (income) expense, net
|
|
|
534
|
|
|
|
283
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
214,788
|
|
|
|
171,710
|
|
|
|
102,597
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
45,884
|
|
|
|
25,603
|
|
|
|
20,148
|
|
Interest income
|
|
|
(1,799
|
)
|
|
|
(2,404
|
)
|
|
|
(1,685
|
)
|
Foreign exchange (gain) loss
|
|
|
(388
|
)
|
|
|
(2,076
|
)
|
|
|
1,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
48,071
|
|
|
|
30,083
|
|
|
|
20,828
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
(176
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
48,071
|
|
|
$
|
30,083
|
|
|
$
|
20,652
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
158
DISCOVERY
PRODUCER SERVICES LLC
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
38,509
|
|
|
$
|
37,583
|
|
Trade accounts receivable:
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
22,467
|
|
|
|
11,986
|
|
Other
|
|
|
5,847
|
|
|
|
6,838
|
|
Insurance receivable
|
|
|
5,692
|
|
|
|
12,623
|
|
Inventory
|
|
|
483
|
|
|
|
576
|
|
Other current assets
|
|
|
5,037
|
|
|
|
4,235
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
78,035
|
|
|
|
73,841
|
|
Restricted cash
|
|
|
6,222
|
|
|
|
28,773
|
|
Property, plant, and equipment, net
|
|
|
368,228
|
|
|
|
355,304
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
452,485
|
|
|
$
|
457,918
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
8,106
|
|
|
$
|
7,017
|
|
Other
|
|
|
17,617
|
|
|
|
23,619
|
|
Accrued liabilities
|
|
|
6,439
|
|
|
|
5,119
|
|
Deposit held for construction
|
|
|
|
|
|
|
3,322
|
|
Other current liabilities
|
|
|
1,658
|
|
|
|
1,483
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
33,820
|
|
|
|
40,560
|
|
Noncurrent accrued liabilities
|
|
|
12,216
|
|
|
|
3,728
|
|
Commitments and contingent liabilities (Note 7)
|
|
|
|
|
|
|
|
|
Members capital
|
|
|
406,449
|
|
|
|
413,630
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members capital
|
|
$
|
452,485
|
|
|
$
|
457,918
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
159
DISCOVERY
PRODUCER SERVICES LLC
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
48,071
|
|
|
$
|
30,083
|
|
|
$
|
20,652
|
|
Cumulative effect of change in accounting principle
|
|
|
|
|
|
|
|
|
|
|
176
|
|
Adjustments to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and accretion
|
|
|
25,952
|
|
|
|
25,562
|
|
|
|
24,794
|
|
Net Loss on disposal of equipment
|
|
|
603
|
|
|
|
|
|
|
|
|
|
Cash provided (used) by changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade accounts receivable
|
|
|
(9,389
|
)
|
|
|
26,599
|
|
|
|
(35,263
|
)
|
Insurance receivable
|
|
|
6,931
|
|
|
|
(12,147
|
)
|
|
|
(476
|
)
|
Inventory
|
|
|
93
|
|
|
|
348
|
|
|
|
(84
|
)
|
Other current assets
|
|
|
(802
|
)
|
|
|
(1,911
|
)
|
|
|
(1,012
|
)
|
Accounts payable
|
|
|
(7,540
|
)
|
|
|
(6,062
|
)
|
|
|
29,355
|
|
Accrued liabilities
|
|
|
1,320
|
|
|
|
(1,086
|
)
|
|
|
(7,992
|
)
|
Other current liabilities
|
|
|
(3,147
|
)
|
|
|
2,070
|
|
|
|
664
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
62,092
|
|
|
|
63,456
|
|
|
|
30,814
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease (increase) in restricted cash
|
|
|
22,551
|
|
|
|
15,786
|
|
|
|
(44,559
|
)
|
Property, plant, and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(31,739
|
)
|
|
|
(33,516
|
)
|
|
|
(12,906
|
)
|
Proceeds from sale of property, plant and equipment
|
|
|
649
|
|
|
|
|
|
|
|
|
|
Change in accounts payable capital expenditures
|
|
|
2,625
|
|
|
|
568
|
|
|
|
(8,532
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(5,914
|
)
|
|
|
(17,162
|
)
|
|
|
(65,997
|
)
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to members
|
|
|
(59,172
|
)
|
|
|
(43,598
|
)
|
|
|
(46,964
|
)
|
Capital contributions
|
|
|
3,920
|
|
|
|
13,509
|
|
|
|
48,303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used) provided by financing activities
|
|
|
(55,252
|
)
|
|
|
(30,089
|
)
|
|
|
1,339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents
|
|
|
926
|
|
|
|
16,205
|
|
|
|
(33,844
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
37,583
|
|
|
|
21,378
|
|
|
|
55,222
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
38,509
|
|
|
$
|
37,583
|
|
|
$
|
21,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
160
DISCOVERY
PRODUCER SERVICES LLC
CONSOLIDATED
STATEMENT OF MEMBERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners
|
|
|
DCP Assets
|
|
|
Eni BB
|
|
|
|
|
|
|
Williams
|
|
|
Operating
|
|
|
Holding,
|
|
|
Pipelines
|
|
|
|
|
|
|
Energy, L.L.C.
|
|
|
LLC
|
|
|
LP
|
|
|
LLC
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
Balance at December 31, 2004
|
|
$
|
195,822
|
|
|
$
|
|
|
|
$
|
130,540
|
|
|
$
|
65,283
|
|
|
$
|
391,645
|
|
Contributions
|
|
|
16,269
|
|
|
|
24,400
|
|
|
|
7,634
|
|
|
|
|
|
|
|
48,303
|
|
Distributions
|
|
|
(30,030
|
)
|
|
|
(1,280
|
)
|
|
|
(15,654
|
)
|
|
|
|
|
|
|
(46,964
|
)
|
Net income
|
|
|
8,063
|
|
|
|
4,651
|
|
|
|
6,909
|
|
|
|
1,029
|
|
|
|
20,652
|
|
Sale of Eni 16.67% interest to Williams Energy L.L.C.
|
|
|
66,312
|
|
|
|
|
|
|
|
|
|
|
|
(66,312
|
)
|
|
|
|
|
Sale of Williams Energy, L.L.C.s 40% interest to Williams
Partners Operating LLC
|
|
|
(142,761
|
)
|
|
|
142,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sale of Williams Energy, L.L.C.s 6.67% interest to DCP
Assets Holding, LP
|
|
|
(25,869
|
)
|
|
|
|
|
|
|
25,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
|
87,806
|
|
|
|
170,532
|
|
|
|
155,298
|
|
|
|
|
|
|
|
413,636
|
|
Contributions
|
|
|
800
|
|
|
|
1,600
|
|
|
|
11,109
|
|
|
|
|
|
|
|
13,509
|
|
Distributions
|
|
|
(10,798
|
)
|
|
|
(16,400
|
)
|
|
|
(16,400
|
)
|
|
|
|
|
|
|
(43,598
|
)
|
Net income
|
|
|
6,017
|
|
|
|
12,033
|
|
|
|
12,033
|
|
|
|
|
|
|
|
30,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
|
83,825
|
|
|
|
167,765
|
|
|
|
162,040
|
|
|
|
|
|
|
|
413,630
|
|
Contributions
|
|
|
|
|
|
|
|
|
|
|
3,920
|
|
|
|
|
|
|
|
3,920
|
|
Distributions
|
|
|
(7,233
|
)
|
|
|
(28,270
|
)
|
|
|
(23,669
|
)
|
|
|
|
|
|
|
(59,172
|
)
|
Net income
|
|
|
2,602
|
|
|
|
26,241
|
|
|
|
19,228
|
|
|
|
|
|
|
|
48,071
|
|
Sale of Williams Energy, L.L.C.s 20% interest to Williams
Partners Operating LLC
|
|
|
(79,194
|
)
|
|
|
79,194
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
$
|
|
|
|
$
|
244,930
|
|
|
$
|
161,519
|
|
|
$
|
|
|
|
$
|
406,449
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
161
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
Note 1.
|
Organization
and Description of Business
|
Our company consists of Discovery Producer Services LLC, or DPS,
a Delaware limited liability company formed on June 24,
1996, and its wholly owned subsidiary, Discovery Gas
Transmission LLC, or DGT, a Delaware limited liability company
also formed on June 24, 1996. DPS was formed for the
purpose of constructing and operating a 600 million cubic
feet per day
(MMcf/d)
cryogenic natural gas processing plant near Larose, Louisiana
and a 32,000 barrel per day (bpd) natural gas liquids
fractionator plant near Paradis, Louisiana. DGT was formed for
the purpose of constructing and operating a natural gas pipeline
from offshore deep water in the Gulf of Mexico to DPSs gas
processing plant in Larose, Louisiana. The pipeline has a design
capacity of
600 MMcf/d
and consists of approximately 173 miles of pipe. DPS has
since connected several laterals to the DGT pipeline to expand
its presence in the Gulf. Herein, DPS and DGT are collectively
referred to in the first person as we,
us or our and sometimes as the
Company.
Until April 14, 2005, we were owned 50% by Williams Energy,
L.L.C. (a wholly owned subsidiary of The Williams Companies,
Inc.), 33.33% by DCP Assets, LP (DCP) formerly Duke Energy Field
Services, LLC, and 16.67% by Eni BB Pipeline, LLC (Eni).
Williams Energy, L.L.C. is our operator. Herein, The Williams
Companies, Inc. and its subsidiaries are collectively referred
to as Williams.
On April 14, 2005, Williams acquired the 16.67% ownership
interest in us, which was previously held by Eni. As a result,
we became 66.67% owned by Williams and 33.33% owned by DCP.
On August 23, 2005, Williams Partners Operating LLC (a
wholly owned subsidiary of Williams Partners L.P. (WPZ) acquired
a 40% interest in us, which was previously held by Williams. In
connection with this acquisition, Williams, DCP and WPZ amended
our limited liability company agreement including provisions for
(1) quarterly distributions of available cash, as defined
in the amended agreement and (2) pursuit of capital
projects for the benefit of one or more of our members when
there is not unanimous consent. On December 22, 2005, DCP
acquired a 6.67% interest in us, which was previously held by
Williams. On June 28, 2007, WPZ acquired an additional 20%
interest in us from Williams. At December 31, 2007, we are
owned 60% by WPZ and 40% by DCP.
|
|
Note 2.
|
Summary
of Significant Accounting Policies
|
Basis of Presentation. The consolidated
financial statements have been prepared based upon accounting
principles generally accepted in the United States and include
the accounts of DPS and its wholly owned subsidiary, DGT.
Intercompany accounts and transactions have been eliminated.
Reclassifications. Certain prior year amounts
have been reclassified to conform with the current year
presentation.
Use of Estimates. The preparation of
consolidated financial statements in conformity with accounting
principles generally accepted in the United States requires
management to make estimates and assumptions that affect the
amounts reported in the consolidated financial statements and
accompanying notes. Actual results could differ from those
estimates.
Estimates and assumptions used in the calculation of asset
retirement obligations are, in the opinion of management,
significant to the underlying amounts included in the
consolidated financial statements. It is reasonably possible
that future events or information could change those estimates.
Cash and Cash Equivalents. Cash and cash
equivalents include demand and time deposits, certificates of
deposit and other marketable securities with maturities of three
months or less when acquired.
Trade Accounts Receivable. Trade accounts
receivable are carried on a gross basis, with no discounting,
less an allowance for doubtful accounts. No allowance for
doubtful accounts is recognized at the time the revenue that
generates the accounts receivable is recognized. We estimate the
allowance for doubtful accounts
162
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
based on existing economic conditions, the financial condition
of the customers, and the amount and age of past due accounts.
Receivables are considered past due if full payment is not
received by the contractual due date. Past due accounts are
generally written off against the allowance for doubtful
accounts only after all collection attempts have been exhausted.
There was no allowance for doubtful accounts at
December 31, 2007 and 2006.
Insurance Receivable. Expenditures incurred
for the repair of the pipeline and onshore facilities damaged by
Hurricane Katrina in 2005 and damage to the Tahiti steel
catenary riser (SCR), which are probable of recovery when
incurred, are recorded as insurance receivable. Expenditures up
to the insurance deductible and amounts subsequently determined
not to be recoverable are expensed.
Gas Imbalances. In the course of providing
transportation services to customers, DGT may receive different
quantities of gas from shippers than the quantities delivered on
behalf of those shippers. This results in gas transportation
imbalance receivables and payables which are recovered or repaid
in cash, based on market-based prices, or through the receipt or
delivery of gas in the future. Imbalance receivables and
payables are included in Other current assets and Other current
liabilities in the Consolidated Balance Sheets. Imbalance
receivables are valued based on the lower of the current market
prices or current cost of natural gas in the system. Imbalance
payables are valued at current market prices. Settlement of
imbalances requires agreement between the pipelines and shippers
as to allocations of volumes to specific transportation
contracts and the timing of delivery of gas based on operational
conditions. In accordance with its tariff, DGT is required to
account for this imbalance (cash-out) liability/receivable and
refund or invoice the excess or deficiency when the cumulative
amount exceeds $400,000. To the extent that this difference, at
any year end, is less than $400,000, such amount would carry
forward and be included in the cumulative computation of the
difference evaluated at the following year end.
Inventory. Inventory includes fractionated
products at our Paradis facility and is carried at the lower of
cost or market.
Restricted Cash. Restricted cash within
non-current assets relates to escrow funds contributed by our
members for the construction of the Tahiti pipeline lateral
expansion. The restricted cash is classified as non-current
because the funds will be used to construct a long-term asset.
The restricted cash is primarily invested in short-term money
market accounts with financial institutions.
Property, Plant, and Equipment. Property,
plant, and equipment are carried at cost. We base the carrying
value of these assets on estimates, assumptions and judgments
relative to capitalized costs, useful lives and salvage values.
The natural gas and natural gas liquids maintained in the
pipeline facilities necessary for their operation (line fill)
are included in property, plant, and equipment.
Depreciation of DPSs facilities and equipment is computed
primarily using the straight-line method with
25-year
lives. Depreciation of DGTs facilities and equipment is
computed using the straight-line method with
15-year
lives.
We record an asset and a liability equal to the present value of
each expected future asset retirement obligation (ARO). The ARO
asset is depreciated in a manner consistent with the
depreciation of the underlying physical asset. We measure
changes in the liability due to passage of time by applying an
interest method of allocation. This amount is recognized as an
increase in the carrying amount of the liability and as a
corresponding accretion expense included in operating income.
Revenue Recognition. Revenue for sales of
products are recognized in the period of delivery and revenues
from the gathering, transportation and processing of gas are
recognized in the period the service is provided based on
contractual terms and the related natural gas and liquid
volumes. DGT is subject to Federal Energy Regulatory Commission
(FERC) regulations, and accordingly, certain revenues collected
may be subject to possible refunds upon final orders in pending
cases. DGT records rate refund liabilities considering
163
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
regulatory proceedings by DGT and other third parties, advice of
counsel, and estimated total exposure as discounted and risk
weighted, as well as collection and other risks. There were no
rate refund liabilities accrued at December 31, 2007 or
2006.
Impairment of Long-Lived Assets. We evaluate
long-lived assets for impairment on an individual asset or asset
group basis when events or changes in circumstances indicate
that, in our managements judgment, the carrying value of
such assets may not be recoverable. When such a determination
has been made, we compare our managements estimate of
undiscounted future cash flows attributable to the assets to the
carrying value of the assets to determine whether the carrying
value is recoverable. 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.
Accounting for Repair and Maintenance
Costs. We expense the cost of maintenance and
repairs as incurred. Expenditures that enhance the functionality
or extend the useful lives of the assets are capitalized and
depreciated over the remaining useful life of the asset.
Income Taxes. For federal tax purposes, we
have elected to be treated as a partnership with each member
being separately taxed on its ratable share of our taxable
income. This election, to be treated as a pass-through entity,
also applies to our wholly owned subsidiary, DGT. Therefore, no
income taxes or deferred income taxes are reflected in the
consolidated financial statements.
Foreign Currency Transactions. Transactions
denominated in currencies other than the functional currency are
recorded based on exchange rates at the time such transactions
arise. Subsequent changes in exchange rates result in
transaction gains or losses which are reflected in the
Consolidated Statements of Income.
Recent Accounting Standards. In September
2006, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 157,
Fair Value Measurements. This Statement establishes
a framework for fair value measurements in the financial
statements by providing a definition of fair value, provides
guidance on the methods used to estimate fair value and expands
disclosures about fair value measurements.
SFAS No. 157 is effective for fiscal years beginning
after November 15, 2007. In December 2007, the FASB issued
proposed FASB Staff Position
No. FAS 157-b
deferring the effective date of SFAS No. 157 to fiscal
years beginning after November 15, 2008 for all
non-financial assets and liabilities, except those that are
recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually).
SFAS No. 157 requires two distinct transition
approaches; (i) cumulative-effect adjustment to beginning
retained earnings for certain financial instrument transactions
and (ii) prospectively as of the date of adoption through
earnings or other comprehensive income, as applicable. On
January 1, 2008, we adopted SFAS No. 157 with no
impact to our Consolidated Financial Statements.
SFAS No. 157 expands disclosures about assets and
liabilities measured at fair value on a recurring basis
effective beginning with the first quarter 2008 reporting.
In February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial Assets and Financial
Liabilities Including an Amendment of FASB Statement
No. 115. SFAS No. 159 establishes a fair
value option permitting entities to elect to measure eligible
financial instruments and certain other items at fair value.
Unrealized gains and losses on items for which the fair value
option has been elected will be reported in earnings. The fair
value option may be applied on an
instrument-by-instrument
basis, is irrevocable and is applied only to the entire
instrument. SFAS No. 159 is effective as of the
beginning of the first fiscal year beginning after
November 15, 2007, and should not be applied
retrospectively to fiscal years beginning prior to the effective
date. On the adoption date, an entity may elect the fair value
option for eligible items existing at that date and the
adjustment for the initial remeasurement of those items to fair
value should be reported as a cumulative effect adjustment to
the opening balance of retained earnings. Subsequent to
164
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
January 1, 2008, the fair value option can only be elected
when a financial instrument or certain other item is entered
into. On January 1, 2008, we adopted SFAS No. 159 but did
not elect the fair value option for any existing eligible
financial instruments or other items.
|
|
Note 3.
|
Related
Party Transactions
|
We have various business transactions with our members and
subsidiaries and affiliates of our members. Revenues include the
following:
|
|
|
|
|
sales to Williams of NGLs to which we take title and excess gas
at current market prices for the products,
|
|
|
|
processing and sales of natural gas liquids and transportation
of gas and condensate for DCPs affiliates, Texas Eastern
Corporation and ConocoPhillips Company,
|
|
|
|
and processing and transportation of gas and condensate for Eni.
|
The following table summarizes these related-party revenues
during 2007, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Williams
|
|
$
|
217,012
|
|
|
$
|
148,543
|
|
|
$
|
70,848
|
|
Texas Eastern Corporation
|
|
|
3,912
|
|
|
|
12,282
|
|
|
|
2,663
|
|
Eni*
|
|
|
|
|
|
|
|
|
|
|
2,830
|
|
ConocoPhillips
|
|
|
36
|
|
|
|
|
|
|
|
523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
220,960
|
|
|
$
|
160,825
|
|
|
$
|
76,864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We have no employees. Pipeline and plant operations are
performed under operation and maintenance agreements with
Williams. Most costs for materials, services and other charges
are third-party charges and are invoiced directly to us.
Operating and maintenance expenses affiliate includes
the following:
|
|
|
|
|
direct payroll and employee benefit costs incurred on our behalf
by Williams,
|
|
|
|
and rental expense resulting from a
10-year
leasing agreement for pipeline capacity from Texas Eastern
Transmission, LP (an affiliate of DCP), as part of our market
expansion project which began in June 2005.
|
Product costs and shrink replacement affiliate
includes natural gas purchases from Williams for fuel and shrink
requirements made at market rates at the time of purchase.
General and administrative expenses affiliate
includes a monthly operation and management fee paid to Williams
to cover the cost of accounting services, computer systems and
management services provided to us.
165
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We also pay Williams a project management fee to cover the cost
of managing capital projects. This fee is determined on a
project by project basis and is capitalized as part of the
construction costs. A summary of the payroll costs and project
fees charged to us by Williams and capitalized are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Capitalized labor
|
|
$
|
222
|
|
|
$
|
373
|
|
|
$
|
115
|
|
Capitalized project fee
|
|
|
651
|
|
|
|
538
|
|
|
|
351
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
873
|
|
|
$
|
911
|
|
|
$
|
466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 4.
|
Property,
Plant, and Equipment
|
Property, plant, and equipment consisted of the following at
December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Property, plant, and equipment:
|
|
|
|
|
|
|
|
|
Construction work in progress
|
|
$
|
66,550
|
|
|
$
|
37,259
|
|
Buildings
|
|
|
4,950
|
|
|
|
4,434
|
|
Land and land rights
|
|
|
2,491
|
|
|
|
2,491
|
|
Transportation lines
|
|
|
311,368
|
|
|
|
303,283
|
|
Plant and other equipment
|
|
|
200,722
|
|
|
|
200,990
|
|
|
|
|
|
|
|
|
|
|
Total property, plant, and equipment
|
|
|
586,081
|
|
|
|
548,457
|
|
Less accumulated depreciation
|
|
|
217,853
|
|
|
|
193,153
|
|
|
|
|
|
|
|
|
|
|
Net property, plant, and equipment
|
|
$
|
368,228
|
|
|
$
|
355,304
|
|
|
|
|
|
|
|
|
|
|
Commitments for construction and acquisition of property, plant,
and equipment for the Tahiti pipeline lateral expansion are
approximately $9 million at December 31, 2007.
Effective December 31, 2005, we adopted Financial
Accounting Standards Board Interpretation No. 47,
Accounting for Conditional Asset Retirement
Obligations. This Interpretation clarifies that an entity
is required to recognize a liability for the fair value of a
conditional ARO when incurred if the liabilitys fair value
can be reasonably estimated. The Interpretation clarifies when
an entity would have sufficient information to reasonably
estimate the fair value of an ARO. As required by the new
standard, we reassessed the estimated remaining life of all our
assets with a conditional ARO. We recorded additional
liabilities totaling $327,000 equal to the present value of
expected future asset retirement obligations at
December 31, 2005. The liabilities are slightly offset by a
$151,000 increase in property, plant, and equipment, net of
accumulated depreciation, recorded as if the provisions of the
Interpretation had been in effect at the date the obligation was
incurred. The net $176,000 reduction to earnings is reflected as
a cumulative effect of a change in accounting principle for the
year ended 2005.
Our obligations relate primarily to our offshore platform and
pipelines and our onshore processing and fractionation
facilities. At the end of the useful life of each respective
asset, we are legally or contractually obligated to dismantle
the offshore platform, properly abandon the offshore pipelines,
remove the onshore facilities and related surface equipment and
restore the surface of the property.
A rollforward of our asset retirement obligation for 2007 and
2006 is presented below.
166
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Balance at January 1
|
|
$
|
3,728
|
|
|
$
|
1,121
|
|
Accretion expense
|
|
|
422
|
|
|
|
135
|
|
Estimate revisions
|
|
|
7,554
|
|
|
|
2,472
|
|
Liabilities incurred
|
|
|
414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
12,118
|
|
|
$
|
3,728
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 5.
|
Leasing
Activities
|
We lease the land on which the Paradis fractionator plant and
the Larose processing plant are located. The initial term of
each lease is 20 years with renewal options for an
additional 30 years. We entered into a ten-year leasing
agreement for pipeline capacity from Texas Eastern Transmission,
LP, as part of our market expansion project which began in June
2005. The lease includes renewal options and options to increase
capacity which would also increase rentals. The future minimum
annual rentals under these non-cancelable leases as of
December 31, 2007 are payable as follows:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2008
|
|
$
|
858
|
|
2009
|
|
|
858
|
|
2010
|
|
|
858
|
|
2011
|
|
|
858
|
|
2012
|
|
|
858
|
|
Thereafter
|
|
|
2,388
|
|
|
|
|
|
|
|
|
$
|
6,678
|
|
|
|
|
|
|
Total rent expense for 2007, 2006 and 2005, including a
cancelable platform space lease and
month-to-month
leases, was $1.4 million, $1.4 million and
$1.1 million, respectively.
|
|
Note 6.
|
Financial
Instruments and Concentrations of Credit Risk
|
Financial
Instruments Fair Value
We used the following methods and assumptions to estimate the
fair value of financial instruments:
Cash and cash equivalents. The carrying
amounts reported in the consolidated balance sheets approximate
fair value due to the short-term maturity of these instruments.
Restricted cash. The carrying amounts reported
in the consolidated balance sheets approximate fair value as
these instruments have interest rates approximating market.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
(In thousands)
|
|
|
Cash and cash equivalents
|
|
$
|
38,509
|
|
|
$
|
38,509
|
|
|
$
|
37,583
|
|
|
$
|
37,583
|
|
Restricted cash
|
|
|
6,222
|
|
|
|
6,222
|
|
|
|
28,773
|
|
|
|
28,773
|
|
167
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Concentrations
of Credit Risk
Our cash equivalents and restricted cash consist of high-quality
securities placed with various major financial institutions with
credit ratings at or above AA by Standard &
Poors or Aa by Moodys Investors Service.
At December 31, 2007 and 2006, substantially all of our
customer accounts receivable result from gas transmission
services for and natural gas liquids sales to our two largest
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 condition and credit worthiness are evaluated
regularly. Our credit policy and the relatively short duration
of receivables mitigate the risk of uncollected receivables. We
did not incur any credit losses on receivables during 2007 and
2006.
Major Customers. Williams accounted for
approximately $217.0 million (83%), $149.0 million
(75%), $70.8 million (58%) respectively, of our total
revenues in 2007, 2006 and 2005.
|
|
Note 7.
|
Rate and
Regulatory Matters and Contingent Liabilities
|
Rate and Regulatory Matters. Annually, DGT
files a request with the FERC for a
lost-and-unaccounted-for
gas percentage to be allocated to shippers for the upcoming
fiscal year beginning July 1. On May 31, 2007, DGT
filed to maintain a
lost-and-unaccounted-for
percentage of zero percent for the period July 1, 2007 to
June 30, 2008 and to retain the 2006 net system gains
of $1.8 million that are unrelated to the
lost-and-unaccounted-for
gas over recovered from its shippers. By Order dated
June 28, 2007 the filing was approved. The approval was
subject to a 30 day protest period, which passed without
protest. As of December 31, 2007, and 2006, DGT has
deferred amounts of $5.8 million and $4.4 million,
respectively, included in current accrued liabilities in the
accompanying Consolidated Balance Sheets representing amounts
collected from customers pursuant to prior years lost and
unaccounted for gas percentage and unrecognized net system gains.
On November 25, 2003, the FERC issued Order No. 2004
promulgating new standards of conduct applicable to natural gas
pipelines. On August 10, 2004, the FERC granted DGT a
partial exemption allowing the continuation of DGTs
current ownership structure and management subject to compliance
with many of the other standards of conduct. 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 March 21, 2007 the FERC issued an
Order on Clarification and Rehearing of the Interim Rule. The
FERC clarified that the interim standards of conduct only apply
to natural gas transmission providers that are affiliated with a
marketing or brokering entity that conducts transportation
transactions on such natural gas transmission providers
pipeline. Currently DGTs marketing or brokering affiliates
do not conduct transmission transactions on DGT. On
January 18, 2007, the FERC issued a Notice of Proposed
Rulemaking to propose permanent regulations regarding the
standards of conduct. Comments were due April 4, 2007. The
FERC may enact a final rule at any time. At this stage, it
cannot be determined how a final rule may or may not affect us
(or DGT).
On November 16, 2007, DGT filed a petition for approval of
settlement in lieu of a general rate change filing with FERC.
FERC issued a Notice of DGTs filing setting a deadline for
comments on November 27, 2007. One shipper, ExxonMobil,
filed a protest. On December 3, DGT filed a response to
ExxonMobils protest. On December 18, ExxonMobil filed
a Motion for Leave to Answer and Answer and DGT responded
168
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
on December 20. On February 5, 2008 the FERC issued an
order approving the settlement as to all parties except the
protesting ExxonMobil Gas & Power Marketing Company.
The order is subject to rehearing until March 6, 2008. The
settlement is not final until the order is final and no longer
subject to rehearing.
Pogo Producing Company. On January 16,
2006, DPS and DGT received notice of a claim by Pogo Producing
Company (Pogo) relating to the results of a Pogo audit performed
first in April 2004 and then continued through August 2005. Pogo
claimed that DPS and DGT overcharged Pogo and its working
interest owners approximately $600,000 relating to condensate
transportation and handling during 2000 2005. The
underlying agreements limit audit claims to a two-year period
from the date of the audit. DPS and DGT disputed the validity of
the claim. On November 2, 2007, the claim was settled for
$300,000. In connection with the settlement, Pogo assigned
production module equipment to us, and we assumed the associated
asset retirement obligation. No gain or loss was recognized.
Environmental Matters. We are subject to
extensive federal, state, and local environmental laws and
regulations which affect our operations related to the
construction and operation of our facilities. Appropriate
governmental authorities may enforce these laws and regulations
with a variety of civil and criminal enforcement measures,
including monetary penalties, assessment and remediation
requirements and injunctions as to future compliance. We have
not been notified and are not currently aware of any
noncompliance under the various environmental laws and
regulations.
Other. We are party to various other claims,
legal actions and complaints arising in the ordinary course of
business. Litigation, arbitration and environmental matters are
subject to inherent uncertainties. Were an unfavorable ruling to
occur, there exists the possibility of a material adverse impact
on the results of operations in the period in which the ruling
occurs. Management, including internal counsel, currently
believes that the ultimate resolution of the foregoing matters,
taken as a whole, and after consideration of amounts accrued,
insurance coverage or other indemnification arrangements, will
not have a material adverse effect upon our future financial
position.
|
|
Note 8.
|
Subsequent
Events
|
On January 30, 2008, we made quarterly cash distributions
totaling $28.0 million to our members.
169
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
|
|
|
By:
|
/s/ William
H. Gault
|
William H. Gault
Attorney-in-fact
Date: February 26, 2008
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 26, 2008
|
|
|
|
|
|
/s/ DONALD
R. CHAPPEL*
Donald
R. Chappel
|
|
Chief Financial Officer and Director (Principal Financial
Officer)
|
|
February 26, 2008
|
|
|
|
|
|
/s/ TED
T. TIMMERMANS*
Ted
T. Timmermans
|
|
Chief Accounting Officer and Controller (Principal Accounting
Officer)
|
|
February 26, 2008
|
|
|
|
|
|
/s/ ALAN
S. ARMSTRONG*
Alan
S. Armstrong
|
|
Chief Operating Officer and Director
|
|
February 26, 2008
|
|
|
|
|
|
/s/ BILL
Z. PARKER*
Bill
Z. Parker
|
|
Director
|
|
February 26, 2008
|
|
|
|
|
|
/s/ ALICE
M. PETERSON*
Alice
M. Peterson
|
|
Director
|
|
February 26, 2008
|
|
|
|
|
|
/s/ H.
MICHAEL KRIMBILL*
H.
Michael Krimbill
|
|
Director
|
|
February 26, 2008
|
|
|
|
|
|
/s/ RODNEY
J. SAILOR*
Rodney
J. Sailor
|
|
Director
|
|
February 26, 2008
|
|
|
|
|
|
*By /s/ WILLIAM
H. GAULT
William
H. Gault
Attorney-in-fact
|
|
|
|
February 26, 2008
|
170
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 2
|
.3
|
|
|
|
Purchase and Sale Agreement, dated June 20, 2007, by and
among Williams Energy, L.L.C., Williams Energy Services, LLC 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 June 25, 2007).
|
|
*§Exhibit 2
|
.4
|
|
|
|
Purchase and Sale Agreement, dated November 30, 2007, 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 December 3, 2007).
|
|
*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 (attached
as Exhibit 3.3 to Williams Partners L.P.s annual
report on
Form 10-K
(File
No. 001-32599)
filed with the SEC on February 28, 2007).
|
|
*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
|
|
|
|
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
|
.4
|
|
|
|
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
|
.5
|
|
|
|
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
|
.6
|
|
|
|
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).
|
171
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
*Exhibit 4
|
.7
|
|
|
|
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 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
|
|
|
|
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
|
.6
|
|
|
|
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
|
.7
|
|
|
|
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
|
.8
|
|
|
|
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
|
.9
|
|
|
|
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
|
.10
|
|
|
|
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
|
.11
|
|
|
|
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).
|
172
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
*Exhibit 10
|
.12
|
|
|
|
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 10
|
.13
|
|
|
|
Assignment Agreement, dated December 11, 2007, by and
between Williams Field Services Company, LLC and Wamsutter LLC
(attached as Exhibit 10.01 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 17, 2007).
|
|
*Exhibit 10
|
.14
|
|
|
|
Contribution, Conveyance and Assumption Agreement, dated
December 11, 2007, 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 10.2 to Williams Partners L.P.s current
report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 17, 2007).
|
|
*Exhibit 10
|
.15
|
|
|
|
Amended and Restated Limited Liability Company Agreement of
Wamsutter LLC, dated December 11, 2007, 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 10.3 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 17, 2007).
|
|
*Exhibit 10
|
.16
|
|
|
|
Common Unit Redemption Agreement, dated December 11,
2007, by and between Williams Partners L.P. and Williams
Partners GP 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 December 17, 2007).
|
|
*Exhibit 10
|
.17
|
|
|
|
Credit Agreement dated as of December 11, 2007, by and
among Williams Partners L.P., the lenders party hereto,
Citibank, N.A., as Administrative Agent and Issuing Bank, and
The Bank of Nova Scotia, as Swingline Lender (attached as
Exhibit 10.5 to Williams Partners L.P.s current
report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 17, 2007).
|
|
*Exhibit 10
|
.18
|
|
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Working Capital Loan Agreement, dated December 11, 2007, by
and between The Williams Companies, Inc. and Wamsutter LLC
(attached as Exhibit 10.6 to Williams Partners L.P.s
current report on
Form 8-K
(File
No. 001-32599)
filed with the SEC on December 17, 2007).
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+Exhibit 12
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Computation of Ratio of Earnings to Fixed Charges
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+Exhibit 21
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List of subsidiaries of Williams Partners L.P.
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+Exhibit 23
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.1
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Consent of Independent Registered Public Accounting Firm,
Ernst & Young LLP.
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+Exhibit 23
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.2
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Consent of Independent Auditors, Ernst & Young LLP.
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+Exhibit 24
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Power of attorney together with certified resolution.
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+Exhibit 31
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.1
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Rule 13a-14(a)/15d-14(a)
Certification of Chief Executive Officer.
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+Exhibit 31
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.2
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Rule 13a-14(a)/15d-14(a)
Certification of Chief Financial Officer.
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+Exhibit 32
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Section 1350 Certifications of Chief Executive Officer and
Chief Financial Officer.
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+Exhibit 99
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.1
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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.
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+Exhibit 99
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.2
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Williams Partners GP LLC Financial Statements.
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* |
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Each such exhibit has heretofore been filed with the SEC as part
of the filing indicated and is incorporated herein by reference. |
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+ |
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Filed herewith. |
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§ |
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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. |
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# |
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Management contract or compensatory plan or arrangement. |
173