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 1934
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For the fiscal year ended
December 31, 2008
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or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number 1-32599
Williams Partners
L.P.
(Exact name of Registrant as
Specified in Its Charter)
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Delaware
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20-2485124
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(State or Other Jurisdiction
of
Incorporation or Organization)
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(IRS Employer
Identification No.)
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One Williams Center, Tulsa, Oklahoma
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74172-0172
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(Address of Principal Executive
Offices)
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(Zip Code)
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918-573-2000
(Registrants Telephone
Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Units
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
(Title of Class)
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes 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 þ
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Accelerated filer o
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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 $1,348,907,264. This figure
excludes common units beneficially owned by the directors and
executive officers of Williams Partners GP LLC, our general
partner.
The registrant had 52,777,452 common units outstanding as of
February 25, 2009.
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.
MMcf/d: One
million cubic feet per day.
Other definitions:
Fractionation: The process by which a mixed
stream of natural gas liquids is separated into its constituent
products, such as ethane, propane and butane.
NGLs: Natural gas liquids. 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.
NGL margins: NGL revenues less Btu replacement
cost, plant fuel, transportation and fractionation.
Recompletions: After the initial completion of
a well, the action and techniques of reentering the well and
redoing or repairing the original completion to restore the
wells productivity.
Throughput: The volume of product transported
or passing through a pipeline, plant, terminal or other facility.
Workover: Operations on a completed production
well to clean, repair and maintain the well for the purposes of
increasing or restoring production.
WILLIAMS
PARTNERS L.P.
FORM 10-K
PART I
Items 1
and 2. Business and Properties
Unless the context clearly indicates otherwise, references in
this report to we, our, us
or like terms refer to Williams Partners L.P. and its
subsidiaries. Unless the context clearly indicates otherwise,
references to we, our, and
us include the operations of 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.
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 gather, transport, process and treat natural
gas and fractionate and store NGLs. Fractionation is the process
by which a mixed stream of NGLs is separated into its
constituent products, such as ethane, propane and butane. These
NGLs 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) 65%
of the Class C limited liability company membership
interests in Wamsutter (together, the Wamsutter Ownership
Interests). Four Corners owns an approximate 3,800-mile natural
gas gathering system, including three natural gas processing
plants and two natural gas treating plants, located in the
San Juan Basin in Colorado and New Mexico. Wamsutter owns
an approximate 1,800-mile natural gas gathering system,
including a natural gas processing plant, located in the
Washakie Basin in Wyoming. The Four Corners and Wamsutter assets
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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 its natural gas processing plant and NGL
fractionator in Louisiana. Our Carbonate Trend gathering
pipeline is a 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 NGL storage facilities and a 50% undivided interest
in an NGL 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.
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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 2008 revenues in
excess of $12.4 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.
Our principal executive offices are located at One Williams
Center, Tulsa, Oklahoma 74172. Our telephone number is
918-573-2000.
RECENT
EVENTS
The global recession and resulting drop in demand and prices for
NGLs has significantly reduced the profitability and cash flows
of our gathering and processing businesses including Four
Corners, our ownership interests in Wamsutter and Discovery. We
expect low NGL margins during 2009, including periods when it is
not economical to recover ethane. As a result, we expect cash
flow from operations, including cash distributions to us from
Wamsutter and Discovery, to be significantly lower in 2009 than
2008.
Given the current energy commodity price and NGL margin
environment, together with our cash balance of approximately
$66 million at February 16, we expect to maintain our
current level of cash distributions throughout 2009. During 2006
through 2008, we retained a portion of our excess cash flow for
future periods when NGL prices and margins might be
substantially lower as they are now. However, if energy
commodity prices and NGL margins decline further for a prolonged
period of time,
and/or if
other unexpected events adversely affect cash flows
and/or our
available cash balance, we may need to reduce distributions.
During September 2008, Discoverys offshore gathering
system sustained hurricane damage and was unable to accept gas
from producers while repairs were being made through the end of
2008. Inspections revealed that an
18-inch
lateral was severed from its connection to the
30-inch
mainline in 250 feet of water. The
30-inch
mainline was repaired and returned to service in January 2009.
The 30-inch
mainline is now delivering
150 MMcf/d
of production, which was its approximate volume prior to the
hurricanes. Both the Larose processing plant and the Paradis
fractionator are operational and processed gas from third-party
sources during the fourth quarter of 2008.
We concluded our negotiations with the Jicarilla Apache Nation
(JAN) during February 2009 with the execution of a
20-year
right-of-way agreement. Under the new agreement, the JAN granted
rights-of-way for Four Corners existing natural gas
gathering system on JAN land as well as a significant
geographical area for
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additional growth of the system. We paid an initial payment of
$7.3 million upon execution of the agreement. Beginning in
2010, we will make annual payments of approximately
$7.5 million and an additional annual payment which varies
depending on the prior years
per-unit NGL
margins and the volume of gas gathered by our gathering
facilities subject to the agreement. Depending primarily on the
per-unit NGL
margins for any given year, the additional annual payments could
approximate the fixed amount. Additionally, five years from the
effective date of the agreement, the JAN will have the option to
acquire up to a 50% joint venture interest for 20 years in
certain of Four Corners assets existing at the time the
option is exercised. The joint venture option includes Four
Corners gathering assets subject to the agreement and
portions of Four Corners gathering and processing assets
located in an area adjacent to the JAN lands. If the JAN selects
the joint venture option, the value of the assets contributed by
each party to the joint venture will be based upon a market
value determined by a neutral third party at the time the joint
venture is formed. This right-of-way agreement is subject to the
consent of the United States Secretary of the Interior before it
may become effective.
In January 2009, Wamsutter issued an additional 70.8 and 28.8
Class C units to us and Williams, respectively, related to
funding of expansion capital expenditures placed in service
during 2008. Therefore, we now own 65% and Williams owns 35% of
Wamsutters outstanding Class C units. As of
December 31, 2008, Williams has contributed
$28.8 million for an expansion capital project that is
expected to be placed in service during 2010. Williams will
receive Class C units related to these expenditures after
the asset is placed in service; thus, our Class C ownership
interest will decline at that time.
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 a natural gas gathering system
in the San Juan Basin in New Mexico and Colorado, three
natural gas processing plants and two natural gas treating
plants. We provide our customers, primarily natural gas
producers in the San Juan Basin, with a full range of
gathering, processing and treating services. Four Corners
revenues are comprised of product sales and fee-based gathering,
processing, and treating revenues. Fee-based gathering,
processing and treating services accounted for approximately 64%
of Four Corners total revenue less product cost and shrink
replacement for the year ended December 31, 2008. The
remaining 36% was derived from the sale of NGLs received as
consideration for processing services. For more detail of Four
Corners revenues, please read Note 15, Segment
Disclosures, in our Notes to Consolidated Financial Statements
in this report.
During 2008, our Four Corners gathering system gathered
approximately 36% of the natural gas produced in the
San Juan Basin. It 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.
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Four
Corners Natural Gas Gathering System
Our Four Corners natural gas gathering pipeline system consists
of:
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Approximately 3,800 miles of
2-inch to
30-inch
diameter natural gas gathering pipelines with capacity of two
Bcf/d and approximately 6,450 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
owned and operated by a third party. We have taken direct
responsibility for some field compression that was previously
operated by a third party, and we plan to assume responsibility
in 2009 for compression that is currently third-party operated.
By the end of 2009, we will operate approximately one-half of
the field compression that has historically been 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.
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
765 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 and installed and upgraded the primary processing
components of the plant in 1984 and 1999, respectively. 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 we retain some
NGLs, fractionate them at Ignacio and distribute them 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 approximately
315 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 we retain some liquids, fractionate them at Lybrook
and distribute them locally via trucks. 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.
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 removal capacity of approximately
67 MMcf/d
and a combined gas inlet volume of approximately
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.
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Four
Corners Customers and Contracts
Customers. One producer customer,
ConocoPhillips, accounted for approximately 50% of Four
Corners total gathered volumes and 19% of its total
revenues for the year ended December 31, 2008. We sold, at
market prices, substantially all of the NGLs we retain to a
subsidiary of Williams at the respective tailgates of our
natural gas plants. These sales accounted for approximately 54%
of Four Corners total revenues for the year ended
December 31, 2008. Our NGLs sold to the Williams
subsidiary are derived from our processing of producer
customers natural gas under our keep-whole and
percent-of-liquids processing contracts. 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 Williams subsidiary at market prices. For the
year ended December 31, 2008, 37% 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 Williams
subsidiary at market prices. For the year ended
December 31, 2008, 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 we retain none of the extracted NGLs. For the
year ended December 31, 2008, 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. The keep-whole component is never more
than 50% of the total extracted NGLs. For the year ended
December 31, 2008, 37% 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.
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 6,065 miles of gathering lines and one
processing plant. Enterprise owns and operates primarily
conventional natural gas gathering and processing facilities in
the San Juan Basin. The Red Cedar system consists of
approximately 800 miles of gathering lines and three
treating plants 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 and one treating plant. Red
Cedar and TEPPCO own and operate primarily coal bed methane
gathering and treating facilities in the San Juan Basin.
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Four
Corners Gas Supply
Our contracts with major customers contain certain production
dedications of natural gas from particular areas
and/or group
of receipt points 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, drilling activity by
producers is expected to decline in 2009. However, when drilling
activity increases, we anticipate that our historical capital
investments will support producer customers drilling
activity, expansion opportunities and production enhancement
activities. 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 a natural gas gathering system in the Washakie
Basin and a natural gas processing plant in Sweetwater County,
Wyoming. Wamsutter provides its customers, primarily natural gas
producers in the Washakie Basin, with a broad range of gathering
and processing services. Fee-based gathering, processing and
other services accounted for approximately 48% of
Wamsutters total revenues less product costs for the year
ended December 31, 2008. The remaining 52% was derived
primarily from the sale of NGLs received by Wamsutter as
consideration for processing services.
The Wamsutter pipeline system gathers and processes
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 1,800 miles of
2-inch to
20-inch
diameter natural gas gathering pipelines with capacity of
500 MMcf/d
at current operating pressures and approximately 2,000 receipt
points; and
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Approximately 39,700 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. In 2008, the Echo Springs plant gained
access to the new Overland Pass Pipeline, which transports NGLs
to the Mid-Continent. The plant also connects to MAPL, which
transports NGLs to the Mid-Continent and Gulf Coast. 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
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connection to the Rawlins plant has increased the total
processing capacity available to Wamsutter by
80 MMcf/d,
or approximately 20%.
Wamsutter is expanding its processing capacity to accommodate
volumes of natural gas committed to Wamsutter. Wamsutter expects
this expansion to be completed before the end of 2010.
Wamsutters Class B member, Williams, will fund this
project.
Wamsutter
Customers and Contracts
Customers. Three of Wamsutters producer
customers (BP America Production Company, Devon Energy
Corporation and Anadarko Petroleum Corporation) accounted for
approximately 78% of Wamsutters total gathered volumes for
the year ended December 31, 2008. Wamsutter sells, at
market prices, substantially all of the NGLs it retains to a
subsidiary of Williams at the tailgate of the Echo Springs
plant. These sales accounted for approximately 56% of
Wamsutters total revenues for the year ended
December 31, 2008. Its NGLs sold to the Williams
subsidiary are derived from its processing of producer
customers natural gas.
Contracts. Wamsutter usually provides these
services to each customer under long-term contracts with
applicable acreage dedications, reserve dedications or both, for
the life of the contract. Approximately 80% of the current
gathering and processing volumes on the Wamsutter system are
subject to contracts with terms of seven 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.
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, 2008, 73% and 27%
of Wamsutters processing volumes were under fee-based and
keep-whole contracts, respectively.
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.
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 35% of the
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.
7
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 to us as the holder of the Class A
membership interests, if needed, 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; 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 began December 1, 2007 and ended
November 30, 2008. Subsequent distribution years for
Wamsutter will begin December 1 and end 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 us as the holder of
the Class A membership interests 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.
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
Wamsutter may elect to make growth capital investments, which
are investments other than maintenance capital investments or
growth well connection investments. Such growth capital
investments are required to be funded by the members as follows:
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We, as the Class A member, are obligated to fund growth
capital investments under $2.5 million.
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The Class B member, Williams, is obligated to fund growth
capital investments of $2.5 million or more.
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In addition, the Class B member is obligated to make a
capital contribution to Wamsutter in an amount necessary to fund
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.
Wamsutter will issue to the contributing member one Class C
unit for each $50,000 contributed by it for capital investments.
Wamsutter will issue fractional Class C units as necessary.
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,
8
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 an approximate
300-mile
natural gas gathering and transportation pipeline system,
located primarily off the coast of Louisiana in the Gulf of
Mexico, a cryogenic natural gas processing plant in Larose,
Louisiana and a fractionator in Paradis, Louisiana.
Although Discovery includes fractionation operations, which
would normally fall within the NGL Services segment, it is
primarily engaged in gathering and processing and is managed as
such. Accordingly, this equity investment is considered part of
our Gathering and Processing Gulf segment.
Discovery
Natural Gas Pipeline System
Transportation and Gathering Natural Gas
Pipeline. The mainline of the Discovery pipeline
system consists of a
105-mile,
30-inch
diameter natural gas and condensate pipeline, which begins at a
platform owned by a third party and 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 80 offshore blocks to Discovery.
The mainline has a Federal Energy Regulatory Commission (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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91 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.
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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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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, Total E&P
USA, Inc. and StatoilHydro ASA to construct an approximate
34-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 has a design
capacity of approximately
200 MMcf/d.
Chevron expects first production of gas to begin in the third
quarter of 2009. The FERC does not regulate any of
Discoverys deepwater laterals.
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Larose
Gas Processing Plant
Discoverys cryogenic gas processing plant is located near
Larose, Louisiana at the onshore terminus of Discoverys
natural gas pipeline. The plant was placed in service in January
1998 and has a design capacity of approximately
600 MMcf/d.
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%. A Chevron-owned gathering system also connects
to the Larose gas processing plant. Discovery has historically
received title to approximately one-half of the mixed NGL
volumes leaving the Larose plant.
Paradis
Fractionation Facility
Discovery fractionates NGLs for third-party customers and for
itself at the fractionator 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.
Discovery
Management
Currently, Discovery is owned 60% by us and 40% by DCP Assets
Holding, LP. A two-member management committee, consisting of
representation from each of the two owners, manages Discovery.
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 Discovery all opportunities to construct
pipeline laterals within an area of interest.
Discovery
Customers and Contracts
Customers. Product sales to subsidiaries of
Williams, which purchase at market prices substantially all of
the NGLs and excess natural gas to which Discovery takes title,
accounted for approximately 86% of Discoverys revenues for
the year ended December 31, 2008. 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 third-party 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 gas dehydration. For the year ended
December 31, 2008, 55% of Discoverys total revenues
less related product costs related to Discoverys top four
third-party customers.
In October 2006, Discovery signed a one-year contract with Texas
Eastern Transmission Company (TETCO) that was subsequently
extended through June 2008 after which there were no further
volumes under this agreement. For the year ended
December 31, 2008, 14% of Discoverys total revenues
less related product costs were related to TETCO.
In the fourth quarter of 2007, Discovery began contracting
significant volumes from the Tennessee Gas Pipeline system (TGP)
and continued to expand during 2008 as the TETCO contract
expired. Discovery transported and processed approximately 160
BBtu/d from various customers delivering volumes from TGP. For
the year ended December 31, 2008, 19% of Discoverys
total revenues less related product costs were
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related to TGP. Discovery is currently transporting TGP volumes
of approximately 100 BBtu/d. This decrease in the volumes from
2008 is primarily due to the lower NGL margins in early 2009.
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,
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 was
approved and implemented in 2008. This settlement increased 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 Btu content removed from the gas stream.
The term of these contracts is 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. As a
result, Discovery is generally able to pass through increases in
those fractionation expenses to its customers.
Discovery
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.
Discovery
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
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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.
Discovery
Gas Supply
Approximately 80 offshore production blocks are currently
dedicated to the Discovery system. 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.
Production from these blocks began in July 2008. Also in
February 2008, Discovery executed agreements with ATP to provide
services, beginning in late third-quarter 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. In
August 2008, Discovery received a dedication from Petrobras
America Inc. for their Cascade and Chinook prospects which are
comprised of eight blocks located in the Walker Ridge Area.
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.
Discovery
Third-Party Pipeline Supply
Hurricane Katrinas emergency connections to TETCO and TGP
have continued to flow gas through December 2008.
Discoverys 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 was being rebuilt)
terminated on June 30, 2008. Discovery continued to
contract with individual shippers on TETCO and TGP throughout
2008 on a monthly basis when economical. Additionally, as noted
earlier, Discovery is currently contracting on a monthly basis
approximately 100 BBtu/d of gas from TGP.
Discovery is in the process of modifying the Columbia Gas
Transmissions (CGT) meter facilities to allow Discovery to
receive gas from CGT. Construction will begin late in the first
quarter of 2009 with first flow expected shortly thereafter. The
modified metering facilities will have a capacity of 150 BBtu/d
which further adds supply depth to the Discovery system.
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. 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, 2008, our average
transportation volume was approximately
22 MMcf/d.
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.
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. The Carbonate Trend
pipeline generates revenue through negotiated fees that we
charge our customers to transport gas to the Shell offshore sour
gas gathering system. These fees typically depend on the volume
of gas we transport.
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Carbonate
Trend Customers and Contracts
Customers. Our primary customer on the
Carbonate Trend pipeline is Chevron. For the year ended
December 31, 2008, volumes from Chevron leases represented
approximately 68% of Carbonate Trends total throughput and
71% of Carbonate Trends total revenue.
Contracts. We have long-term transportation
agreements with Chevron and Beryl Resources LP (Beryl). Under
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 agreements if expenses exceed certain levels or
if revenues fall below certain levels and we are not compensated
for these expenses or shortfalls.
Carbonate
Trend 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.
Carbonate
Trend 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. Production from this area has declined
in recent years, and we no longer expect significant, near-term
discoveries of sour gas in the area served by the Carbonate
Trend gathering pipeline.
NGL
Services
Our NGL Services segment includes our three integrated NGL
storage facilities and a 50% interest in an NGL fractionator
near Conway, Kansas. These 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 storage
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. A brine pond
is an above-ground location that stores brine, or salt water,
until it is pumped into the storage cavern to displace and move
NGLs.
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.
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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 30 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.
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 resulting in proportionate 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.
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
Customers and Contracts
Customers. Our NGL Services segment customers
include NGL producers, NGL pipeline operators, NGL service
providers and NGL end-users. Our largest customer accounted for
14% of our segment revenues in 2008. We sold, at market prices,
substantially all NGLs derived from our operating supply
management (discussed below) to a subsidiary of Williams. These
sales accounted for approximately 22% of Conways total
revenues for the year ended December 31, 2008.
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 2010
and 2018. Each of these long-term contracts is based on a
percentage of our published price for storage in our Conway
facilities, which we adjust annually. Our storage revenues are
not generally affected by seasonality because our customers
generally pay for storage capacity, not injected or withdrawn
volumes.
We currently offer our customers four types of storage
contracts single product fungible, two product
fungible, multi-product fungible and segregated product
storage in various quantities and at varying terms.
Single product fungible storage allows customers to store a
single product. Two-product fungible storage allows customers to
store any combination of two fungible products. Multi-product
fungible storage allows customers to store any combination of
fungible products. In the case of two-product and multi-product
storage, the customer designates the quantity of storage space
for each product at the beginning of the lease period. Customers
may change their quantity configurations throughout the year
based upon our ability to accommodate each change. Segregated
storage also is available to customers who desire to store
non-fungible products at Conway, such as propylene, refinery
grade butane and naphtha. 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. We evaluate pricing,
volume and availability for
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segregated storage on a
case-by-case
basis. We also charge overstorage fees to the customers when
their product storage inventory exceeds their leased capacity.
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.
Conway
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
Williams subsidiary. If this arrangement with the
Williams subsidiary were terminated, we believe we could
make these product sales and purchases through third parties.
Conway
Competition
Storage services. Our most direct storage
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 interstate pipelines to the extent that they offer storage
services.
Fractionation Services. 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 storage and fractionation 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. An increase in competition in the overall 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 costs
and rates of our competitors, (3) the ability to offer
service from multiple storage locations,
(4) competitors services including the purchase of
customers mixed NGLs as an alternative to fee-based
fractionation services and (5) NGL commodity prices in the
Mid-Continent region compared to prices in other regions.
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Conway
NGL Sources and Transportation Options
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
originates in Wyoming and flows into the Mid-Continent.
After we separate the mixed NGLs at the fractionator, the NGL
products are typically transported to our storage facilities. We
also receive a portion of the NGLs that we inject into our
facilities from our customers. Our customers may transport the
NGLs through the interstate NGL pipelines that interconnect with
our storage facilities including MAPL, a ONEOK North System
pipeline, NuStar pipeline and a ONEOK pipeline. Our customers
may deliver or transport their NGL products through our truck
loading and unloading facility and our rail loading and
unloading facilities. Additionally, when market conditions
dictate, we have the ability to place propane directly into MAPL
from our fractionator, providing our customers with expedited
access to interstate markets.
Safety
and Maintenance
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 carry
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 certain
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
safeguards in areas where the potential consequences of pipeline
accidents pose the greatest risk to people and property. We
currently anticipate incurring costs of approximately
$0.6 million in 2009 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 repair, remediation, preventative or any mitigating actions
that may be deemed necessary as a result of the testing program.
States are largely preempted by federal law from regulating
pipeline safety but may, in certain cases, 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 the 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 comprehensive
inspections. We believe that this aggressive and proactive
corrosion control program will reduce metal loss, limit
corrosion and possibly extend the service life of the pipe by 15
to 20 years.
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We are also subject to a number of federal and state laws and
regulations such as 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 and the
general public, 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 remain in material compliance with the OSHA
and similar state and local 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, as a general rule, does not regulate gathering facilities
except under certain conditions. Discoverys wholly owned
subsidiary, Discovery Gas Transmission, owns the mainline and
certain shallow water offshore gathering laterals subject to
FERC regulation. Discovery owns some gathering facilities that
are not subject to FERC Natural Gas Act regulation.
In November 2007, Discovery filed a settlement in lieu of a
general rate case filing. The FERC approved the settlement
effective January 1, 2008 for all parties except as to one
protestor, ExxonMobil Gas & Power Marketing Company.
The settlement resolved numerous rate and other issues and
achieved rate certainty on Discovery for at least five years.
Pursuant to the terms of the settlement agreement, we and the
other parties to the settlement are precluded from filing for
any further increases or decreases in existing rates prior to
January 1, 2013. Under the settlement, Discovery increased
its maximum mainline, gathering and market expansion rates to
$0.1729/Dth, $0.0430/Dth and $0.1116/Dth, respectively.
Additionally, the settlement permits 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 did 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 surcharges affect some of the
dedicated volumes.
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
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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.
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 initial
public offering (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 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.
This indemnification obligation terminated three years after the
closing of our IPO, except in the case of the remediation costs
associated with Consent Orders issued by the Kansas Department
of Health and Environment (KDHE). Please read
Kansas Department of Health and Environment
Obligations. 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 more consistent
permitting process; however, threshold limits and control
technologies written into the regulations regularly change over
time keeping specific allowable limits and technologies dynamic.
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, often
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, as well as successors in interest.
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, or our predecessors in interest may
have so handled hazardous substances 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.
Please read Safety and Maintenance.
Kansas
Department of Health and Environment Obligations
We currently own and operate underground storage caverns near
Conway, Kansas. These storage caverns are used to store NGLs and
other liquid hydrocarbons and are subject to strict
environmental regulation by the KDHE. The current revision of
the Underground Hydrocarbon and Natural Gas Storage regulations
became effective in 2003 and regulates the storage of liquefied
petroleum gas and other hydrocarbons in bedded salt for the
purpose of protecting public health and safety, property and the
environment. The revision also regulates the construction,
operation and closure of brine ponds associated with our storage
caverns. These regulations specify several compliance deadlines
including the due date for final permit submittals, which was
met by April 1, 2006, and the April 1, 2010 deadline
for completion of mechanical integrity and casing testing
requirements, which our facilities are in the process of
completing. 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 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 to two brine ponds
per year. The incremental cost of these activities is
approximately $5.0 million per year to complete the
workovers and approximately $1.2 million per year to
install a double liner on a brine pond. We expect, on average,
to complete workovers on each of our caverns every five to ten
years and install double liners on each of our brine ponds every
18 years.
Additionally, we are currently undergoing remedial activities
pursuant to KDHE Consent Orders issued in the early 1990s. The
Consent Orders were issued after elevated concentrations of
chlorides were discovered in various
on-site and
off-site shallow groundwater resources at each of our Conway
storage facilities. With KDHE approval, we have installed and
are operating a containment and monitoring system to contain the
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
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is located near the Groundwater Management District
No. 2s jurisdictional boundary of the Equus Beds
aquifer. At the Conway West 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
NGL 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.
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 283 people, as of December 31, 2008, 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 equity investments and are
operated by Williams pursuant to agreements; therefore, the
employees who operate these assets are 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.
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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 FOR PURPOSES
OF THE SAFE HARBOR PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
Certain matters contained in this report include
forward-looking statements that 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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the levels of cash distributions to unitholders;
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seasonality of certain business segments; and
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natural gas and natural gas liquids 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,
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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availability of supplies (including the uncertainties inherent
in assessing and estimating future natural gas reserves), market
demand, volatility of prices and the availability and costs of
capital;
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inflation, interest rates and general economic conditions
(including the recent economic slowdown and the disruption of
global credit markets and the impact of these events on our
customers and suppliers);
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the strength and financial resources of our competitors;
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development of alternative energy sources;
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the impact of operational and development hazards;
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costs of, changes in, or the results of laws, government
regulations (including proposed climate change legislation),
environmental liabilities, litigation and rate proceedings;
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increasing maintenance and construction costs;
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changes in the current geopolitical situation;
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our exposure to the credit risks of our customers;
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risks related to strategy and financing, including restrictions
stemming from our debt agreements, future changes in our credit
ratings and the availability and cost of credit;
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risks associated with future weather conditions;
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acts of terrorism; and
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additional risks described in our filings with the Securities
and Exchange Commission.
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Given the uncertainties and risk factors that could cause our
actual results to differ materially from those contained in any
forward-looking statement, we caution investors not to unduly
rely on our forward-looking statements. We disclaim any
obligations to and do not intend to update the above list or to
announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or
developments.
In addition to causing our actual results to differ, the factors
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 are described in the following section.
RISK
FACTORS
You should carefully consider the following risk factors in
addition to the other information in this report. Each of these
factors could adversely affect our business, operating results
and financial condition as well as adversely affect the value of
an investment in our securities.
Risks
Inherent in Our Business
We may
not have sufficient cash from operations to enable us to
maintain current levels of cash distributions or 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 from operating surplus
each quarter to maintain current levels of cash distributions or
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 and our NGL margins;
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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, some of which are
beyond our control, 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; and
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the amount of cash that each of Wamsutter and Discovery
distributes to us.
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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.
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 our
ability to successfully identify, finance, acquire, integrate
and operate projects and businesses. 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.
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 may require substantial new capital and could result in
the incurrence of indebtedness, 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. 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. Further, any
limitations on our access to capital, including limitations
caused by illiquidity in the capital markets, may impair our
ability to complete future acquisitions and construction
projects on favorable terms, if at all.
Lower
natural gas and oil prices could adversely affect our gathering,
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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fluctuations in the storage levels of natural gas and NGLs;
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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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Any
decrease in NGL prices or a change in NGL prices relative to the
price of natural gas could affect our processing, fractionation
and storage businesses.
The relationship between natural gas prices and NGL prices
affects 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 of separating the mixed NGLs from the
natural gas. As a result, we have experienced and, if low NGL
prices persist for a prolonged period of time, will likely
continue to experience significant reductions in the volumes of
NGLs removed at our processing plants, which also significantly
reduces our margins. Higher natural gas prices relative to NGL
prices may also make it uneconomical to recover ethane, which
may further negatively impact sales volumes and 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.
Significant
prolonged changes in natural gas prices could affect supply and
demand, cause a reduction in or termination of the long-term
transportation and storage contracts or throughput on
Discoverys system, and adversely affect our cash available
to make distributions.
Higher natural gas prices over the long term could result in a
decline in the demand for natural gas and, therefore, in
Discoverys long-term transportation and storage contracts
or throughput on Discoverys system. Also, lower natural
gas prices over the long term could result in a decline in the
production of natural gas resulting in reduced contracts or
throughput on Discoverys system. As a result, significant
prolonged changes in natural gas prices could have a material
adverse effect on Discoverys business, financial
condition, results of operations and cash flows, and on our
ability to make distributions to unitholders.
Any
significant decrease in supplies of natural gas in our areas of
operation could adversely affect our business and operating
results.
Our business is dependent on the continued availability of
natural gas production and reserves. The development of
additional natural gas reserves requires significant capital
expenditures by others for exploration and development drilling.
Low prices for natural gas, regulatory limitations, or the lack
of available capital for these projects could adversely affect
the development and production of additional reserves, adversely
impacting our ability to fill the capacities of our gathering,
transmission and processing facilities.
Production from existing wells connected to our and
Discoverys pipelines and our gathering systems will
naturally decline over time. The amount of natural gas reserves
underlying these wells may also be less than anticipated, and
the rate at which production from these reserves declines may be
greater than anticipated. Additionally, the competition for
natural gas supplies to serve other markets could reduce the
amount of natural gas supply for our customers. Accordingly, to
maintain or increase throughput levels on our pipelines and
gathering systems and the utilization rate of our natural gas
processing plants and fractionators, we must continually connect
to new supplies of natural gas.
If we are not able to connect new supplies of natural gas to
replace the natural decline in volumes from the existing supply
area, throughput on our pipelines and gathering systems and the
utilization rates of our natural gas processing plants and
fractionators will decline, which could have a material adverse
effect on our business, financial condition, results of
operations and ability to make cash distributions to unitholders.
Our
industry is highly competitive, and increased competitive
pressure could adversely affect our business and operating
results.
We have numerous competitors in all aspects of our businesses,
and additional competitors may enter our markets. Some of our
competitors are large oil, natural gas and petrochemical
companies that have greater
25
access to supplies of natural gas and NGLs than we do. In
addition, current or potential competitors may make strategic
acquisitions or have greater financial resources than we do,
which could affect our ability to make investments or
acquisitions. Other companies with which we compete may be able
to respond more quickly to new laws or regulations or emerging
technologies or to devote greater resources to the construction,
expansion or refurbishment of their facilities than we can.
There can be no assurance that we will be able to compete
successfully against current and future competitors and any
failure to do so could have a material adverse effect on our
business, results of operations, financial condition and ability
to make cash distributions to unitholders.
We
depend on certain key customers and producers for a significant
portion of our revenues and supply of natural gas and NGLs. If
we lost any of these key customers or producers, our revenues
and cash available to pay distributions could
decline.
We rely on a limited number of customers for a significant
portion of our revenues. 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 in active negotiations
with several customers to renew gathering, processing and
treating contracts that are in evergreen status. 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.
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 in the ordinary course of our
business. 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.
The
failure of counterparties to perform their contractual
obligations could adversely affect our operating results,
financial condition and cash available to pay
distributions.
Despite performing credit analysis prior to extending credit, we
are exposed to the credit risk of our contractual counterparties
in the ordinary course of business even though we monitor these
situations and attempt to take appropriate measures to protect
ourselves. In addition to credit risk, counterparties to our
commercial agreements, such as product sales, gathering,
treating, storage, transportation, processing and fractionation
agreements, may fail to perform their other contractual
obligations. A failure of counterparties to perform their
contractual obligations, including Williams, could cause us to
write down or write off doubtful accounts, which could
materially adversely affect our operating results, financial
condition and cash available to pay distributions. The recent
general downturn in the economy and tightening of global credit
markets could cause more of our counterparties to fail to
perform than we have expected.
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. If any of them 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, increased credit requirements or rates charged by such
pipelines or facilities or other causes, we and our customers
would have reduced capacity to store or
26
deliver NGL products or to receive deliveries of mixed NGLs and
deliver gas to end markets thereby reducing our revenues.
Further, although there are laws and regulations designed to
encourage competition in wholesale market transactions, some
companies may fail to provide fair and equal access to their
transportation systems or may not provide sufficient
transportation capacity for other market participants.
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.
Events
in the global financial crisis have made equity and debt markets
less accessible, created a shortage in the availability of
credit and have led to credit market volatility, which could
disrupt our financing plans and limit our ability to
grow.
In 2008, public equity markets experienced significant declines,
and global credit markets experienced a shortage in overall
liquidity and a resulting disruption in the availability of
credit. Under current market conditions, it is unclear whether
we could issue additional equity or debt securities or, even if
we were able, whether we could do so at prices and pursuant to
terms that would be acceptable to us. We have availability under
our credit facility, but our ability to borrow under the
facility could be impaired if one or more of our lenders fail to
honor its contractual obligation to lend to us. Continuing or
additional disruptions in the global financial marketplace,
including the bankruptcy or restructuring of certain financial
institutions, could make equity and debt markets inaccessible
and adversely affect the availability of credit already arranged
and the availability and cost of credit in the future.
As a publicly traded partnership, these developments could
significantly impair our ability to make acquisitions or finance
growth projects. We distribute all of our available cash to our
unitholders on a quarterly basis. We typically rely upon
external financing sources, including the issuance of debt and
equity securities and bank borrowings, to fund acquisitions or
expansion capital expenditures. Any limitations on our access to
external capital, including limitations caused by illiquidity or
volatility in the capital markets, may impair our ability to
complete future acquisitions and construction projects on
favorable terms, if at all. As a result, we may be at a
competitive disadvantage as compared to businesses that reinvest
all of their available cash to expand ongoing operations,
particularly under current economic conditions.
Williams
public indentures and our debt agreements contain financial and
operating restrictions that may limit our access to credit and
affect our ability to operate our business.
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 continue to deteriorate, Williams
ability to comply with these covenants may be negatively
impacted.
Our credit facility and public indentures contain 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 our
debt agreements and other related transactional documents may be
affected by events beyond our control, including prevailing
economic, financial and industry conditions. If market or other
economic conditions continue to deteriorate, our current
assumptions about future economic conditions turn out to be
incorrect or unexpected events occur, our ability to comply with
these covenants may be significantly impaired.
27
Our failure to comply with the covenants in our debt agreements
and other related transactional documents could result in events
of default. Upon the occurrence of such an event of default, the
lenders could elect to declare all amounts outstanding under a
particular facility to be immediately due and payable and
terminate all commitments, if any, to extend further credit. An
event of default or an acceleration under our public indentures
could cause a cross-default or cross-acceleration of our credit
facility. Such a cross-default or cross-acceleration could have
a wider impact on our liquidity than might otherwise arise from
a default or acceleration of a single debt instrument. If an
event of default occurs, or if other credit facility
cross-defaults, and the lenders under the affected debt
agreements accelerate the maturity of any loans or other debt
outstanding to us, we may not have sufficient liquidity to repay
amounts outstanding under such debt agreements. For more
information regarding our debt agreements, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and
Capital Resources.
Restrictions
in our debt agreements and our leverage may adversely affect our
future financial and operating flexibility.
Our total outstanding long-term debt as of December 31,
2008 was $1.0 billion, representing approximately 81% 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;
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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. Our ability to refinance existing debt obligations or
obtain future credit will also depend upon the current
conditions in the credit markets and the availability of credit
generally. If we are unable to meet our debt service obligations
or obtain future credit on favorable terms, if at all, 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.
A
downgrade of our current credit rating could impact our
liquidity, access to capital and our costs of doing business,
and maintaining current credit ratings is within the control of
independent third parties. In addition, Williams credit
ratings affect our ability to obtain credit in the
future.
A downgrade of our credit rating might increase our cost of
borrowing and could require us to post collateral with third
parties, negatively impacting our available liquidity. Our
ability to access capital markets
28
could also be limited by a downgrade of our credit rating and
other disruptions. Such disruptions could include:
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economic downturns;
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deteriorating capital market conditions;
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declining market prices for natural gas, natural gas liquids and
other commodities;
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terrorist attacks or threatened attacks on our facilities or
those of other energy companies;
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the overall health of the energy industry, including the
bankruptcy or insolvency of other companies.
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Credit rating agencies perform independent analysis when
assigning credit ratings. The analysis includes a number of
criteria including, but not limited to, business composition,
market and operational risks, as well as various financial
tests. Credit rating agencies continue to review the criteria
for industry sectors and various debt ratings and may make
changes to those criteria from time to time. Our current credit
ratings for Moodys Investor Service is Ba2, for
Standard & Poors is BBB-, and for Fitch Ratings
is BB+. On November 6, 2008, Moodys Investor Service
changed our ratings outlook to Negative. No
assurance can be given that we will maintain our current credit
ratings. In addition, due to our relationship with Williams, our
ability to obtain credit is also 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.
The
financial condition and liquidity of Williams affects our access
to capital, our credit standing and our financial
condition.
Substantially all of Williams operations are conducted
through its subsidiaries. Williams cash flows are
substantially derived from loans and dividends paid to it by its
subsidiaries. Williams cash flows are typically utilized
to service debt and pay dividends on the common stock of
Williams, with the balance, if any, reinvested in its
subsidiaries as contributions to capital.
Our ratings and credit are impacted by Williams credit
standing. If Williams were to experience a deterioration in its
credit standing or financial difficulties, our access to credit
and our ratings could be adversely affected.
Our
allocation from Williams for costs and funding obligations for
its defined benefit pension plans and costs for other
postretirement benefit plans are affected by factors beyond our
and Williams control.
Employees of Williams and its affiliates provide services to us.
As a result, we are allocated a portion of Williams costs
and funding obligations in defined benefit pension plans
covering substantially all of Williams or its
affiliates employees providing services to us, as well as
a portion of other postretirement benefit plans covering certain
eligible participants providing services to us. The timing and
amount of our allocations under the defined benefit pension
plans depend upon a number of factors Williams controls,
including changes to pension plan benefits, as well as factors
outside of Williams control, such as asset returns,
interest rates and changes in pension laws. Changes to these and
other factors that can significantly increase our allocations
could have a significant adverse effect on our financial
condition. The amount of expenses recorded for the defined
benefit pension plans and other postretirement benefit plans is
also dependent on changes in several factors, including market
interest rates and the returns on plan assets. Significant
changes in any of these factors may significantly increase our
allocations and adversely impact our future results of
operations.
Wamsutter
and Discovery are not prohibited from incurring indebtedness,
which may affect our ability to make distributions to
unitholders.
Wamsutter and Discovery 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
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distributions to unitholders because we expect distributions we
receive from Wamsutter and Discovery to represent a significant
portion of the cash we distribute 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 or cash distributions received 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.
Our
storage and fractionation operations depend on the demand for
propane and other NGLs. A substantial decrease in this demand
could adversely affect our business and operating
results.
More than any other NGLs, demand for propane impacts our Conway
storage and fractionation operations. Demand for propane at
Conway is principally driven by demand for its use as a heating
fuel which is significantly affected by weather conditions and
the availability of alternative heating fuels. 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
could be adversely impacted by many factors, including general
economic conditions, reductions in demand for end products made
from NGLs, increases in competition from petroleum-based
products and government regulations. Any decline in demand for
propane or other NGLs could cause a reduction in demand for our
storage and fractionation services.
Wamsutter
and Discovery may reduce their cash distributions to us in some
situations.
Discoverys and Wamsutters limited liability company
agreements require distribution of their available cash to their
members on a quarterly basis. In each case, available cash is
reduced, in part, by reserves appropriate for operating their
respective businesses. The amount of Wamsutters quarterly
distributions, including the amount of cash reserves not
distributed, is determined by the affirmative vote of the
management committee representative of the Class B member,
Williams.
If 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
natural gas transportation operations are subject to regulation
by FERC, which could have an adverse impact on its ability to
establish transportation rates that would allow it to recover
the full cost of operating its pipeline, including a reasonable
return.
Discoverys interstate natural gas transportation
operations are subject to federal, state and local regulatory
authorities. Specifically, Discoverys interstate pipeline
transportation service is subject to regulation by FERC. The
federal regulation extends to such matters as:
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transportation and sale for resale of natural gas in interstate
commerce;
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rates, operating terms and conditions of service, including
initiation and discontinuation of services;
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the types of services Discovery may offer to its customers;
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certification and construction of new facilities;
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acquisition, extension, disposition or abandonment of facilities;
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accounts and records;
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relationships with affiliated companies who are involved in
marketing functions of the natural gas business; and
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market manipulation in connection with interstate sales,
purchases or transportation of natural gas.
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Under the Natural Gas Act (NGA), FERC has authority to regulate
providers of natural gas pipeline transportation services in
interstate commerce, and such providers may only charge rates
that have been determined to be just and reasonable by FERC. In
addition, FERC prohibits providers from unduly preferring or
unreasonably discriminating against any person with respect to
pipeline rates or terms and conditions of service.
The rates, terms and conditions for Discoverys interstate
pipeline services are set forth in its FERC-approved tariff.
Pursuant to the terms of Discoverys most recent rate
settlement agreement, Discovery may not file a new rate case
before January 1, 2013. Any successful complaint or protest
against its rates could have an adverse impact on their revenues
associated with providing transportation services. In addition,
there is a risk that rates set by the FERC in future rate cases
filed by Discovery will be inadequate to recover increases in
operating costs or to sustain an adequate return on capital
investments. There is also the risk that higher rates would
cause Discoverys customers to look for alternative ways to
transport their natural gas.
Discovery
could be subject to penalties and fines if it fails to comply
with FERC regulations.
Discoverys transportation and storage operations are
regulated by FERC. Should Discovery fail to comply with all
applicable FERC administered statutes, rules, regulations and
orders, it could be subject to substantial penalties and fines.
Under the Energy Policy Act of 2005, FERC has civil penalty
authority under the NGA to impose penalties for current
violations of up to $1,000,000 per day for each violation. Any
material penalties or fines imposed by FERC could have a
material adverse impact on Discoverys business, financial
condition, results of operations and cash flows, and on our
ability to make distributions to unitholders.
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;
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damages to pipelines and pipeline blockages;
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uncontrolled releases 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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damage inadvertently caused by third party activity, such as
operation of construction equipment;
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pollution and other environmental risks;
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fires, explosions, craterings and blowouts;
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risks related to truck and rail loading and unloading;
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risks related to operating in a marine environment; and
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terrorist attacks or threatened attacks on our facilities or
those of other energy companies.
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Any of these risks could result in loss of human life, personal
injuries, significant damage to property, environmental
pollution, impairment of our operations and substantial losses
to us. In accordance with customary industry practice, we
maintain insurance against some, but not all, of these risks and
losses, and only at levels we believe to be appropriate. The
location of certain segments of our facilities in or near
populated areas, including residential areas, commercial
business centers and industrial sites, could increase the level
of damages resulting from these risks. In spite of our
precautions, an event such as those described
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above could cause considerable harm to people or property, and
could have a material adverse effect on our financial condition
and results of operations, particularly if the event is not
fully covered by insurance. Accidents or other operating risks
could further result in loss of service available to our
customers. In addition, certain insurance companies that provide
coverage to us, Wamsutter and Discovery, including American
International Group, Inc., have experienced negative
developments that could impair their ability to pay any
potential claims. As a result, we could be exposed to greater
losses than anticipated and replacement insurance may have to be
obtained, if available, at a greater cost. Such circumstances
could materially impact our ability to meet contractual
obligations and retain customers, with a resulting negative
impact on our business, financial condition, results of
operations and cash flows, and our ability to make cash
distributions to unitholders.
Our
operations are subject to governmental laws and regulations
relating to the protection of the environment, which may expose
us to significant costs and liabilities and could exceed current
expectations.
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 extensive federal, state and local environmental laws
and regulations governing environmental protection, the
discharge of materials into the environment and the security of
chemical and industrial facilities. For a description of these
laws and regulations, please read Business and
Properties Environmental Regulation.
Various governmental authorities, including the
U.S. Environmental Protection Agency and analogous state
agencies and the United States Department of Homeland Security,
have the power to enforce compliance with these laws and
regulations and the permits issued under them, oftentimes
requiring difficult and costly actions. Failure to comply with
these laws, regulations, and permits may result in the
assessment of administrative, civil, and criminal penalties, the
imposition of remedial obligations, and the issuance of
injunctions limiting or preventing some or all of our operations.
There is 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.
Joint and several, strict liability may be incurred without
regard to fault under certain environmental laws and
regulations, including the Federal Comprehensive Environmental
Response, Compensation, and Liability Act, the Federal Resource
Conservation and Recovery Act, and analogous state laws, for the
remediation of contaminated areas and in connection with spills
or releases of natural gas and wastes on, under, or from our
properties and facilities. 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.
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.
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. The
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United States Congress and certain states have for some time
been considering various forms of legislation related to
greenhouse gas emissions. Increased public awareness and concern
may result in more state, regional
and/or
federal requirements to reduce or mitigate the emission of
greenhouse gases. Numerous states have announced or adopted
programs to stabilize and reduce greenhouse gases, and similar
federal legislation has been introduced in both houses of the
Congress. We may be subject to regulation under climate change
policies introduced at either the state or federal level within
the next few years. There is a possibility that, when and if
enacted, the final form of such legislation could increase our
costs of compliance with environmental laws. If we are unable to
recover or pass through all costs related to complying with
climate change regulatory requirements imposed on us, it could
have a material adverse effect on our results of operations. To
the extent financial markets view climate change and emissions
of greenhouse gases as a financial risk, this could negatively
impact our cost of and access to capital.
Execution
of our capital projects subjects us to construction risks,
increases in labor costs and materials, and other risks that may
adversely affect financial results.
Our growth may be dependent upon the construction of new natural
gas gathering, transportation, processing or treating pipelines
and facilities or natural gas liquids fractionation or storage
facilities, as well as the expansion of existing facilities.
Construction or expansion of these facilities is subject to
various regulatory, development and operational risks, including:
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the ability to obtain necessary approvals and permits by
regulatory agencies on a timely basis and on acceptable terms;
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the availability of skilled labor, equipment, and materials to
complete expansion projects;
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potential changes in federal, state and local statutes and
regulations, including environmental requirements, that prevent
a project from proceeding or increase the anticipated cost of
the project;
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impediments on our ability to acquire rights-of-way or land
rights on a timely basis and on acceptable terms;
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the ability to construct projects within estimated costs,
including the risk of cost overruns resulting from inflation or
increased costs of equipment, materials, labor or other factors
beyond our control, that may be material; and
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the ability to access capital markets to fund construction
projects.
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Any of these risks could prevent a project from proceeding,
delay its completion or increase its anticipated costs. As a
result, new facilities may not achieve expected investment
return, which could adversely affect our results of operations,
financial position or cash flows and our ability to make
distributions to unitholders.
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 and other third parties operate all of our assets. We
have a limited ability to control these operations and the
associated costs. 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 rely on Williams for certain 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 and others as operators and on
Williams outsourcing relationships, 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.
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We do
not own all of the land on which our pipelines and facilities
are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and
facilities have been constructed. As such, we are 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.
Our
assets and operations can be affected by weather and other
natural phenomena.
Our assets and operations can be adversely affected by
hurricanes, floods, earthquakes, tornadoes and other natural
phenomena and weather conditions including extreme temperatures,
making it more difficult for us to realize the historic rates of
return associated with these assets and operations. 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.
In addition, there is a growing belief that emissions of
greenhouse gases may be linked to global climate change. Climate
change creates physical and financial risk. Our customers
energy needs vary with weather conditions. To the extent weather
conditions are affected by climate change or demand is impacted
by regulations associated with climate change, customers
energy use could increase or decrease depending on the duration
and magnitude of the changes, leading either to increased
investment or decreased revenues.
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, the Securities Exchange
Commission (SEC) or FERC could enact new accounting standards or
FERC orders that might impact how we are required to record
revenues, expenses, assets and liabilities. Any significant
change in accounting standards or disclosure requirements could
have a material adverse effect on our business, results of
operations, financial condition and ability to make cash
distributions to unitholders.
Institutional
knowledge residing with current employees nearing retirement
eligibility might not be adequately preserved.
In our business, institutional knowledge resides with employees
who have many years of service. As these employees reach
retirement age, we may not be able to replace them with
employees of comparable knowledge and experience. In addition,
we may not be able to retain or recruit other qualified
individuals and our efforts at knowledge transfer could be
inadequate. If knowledge transfer, recruiting and retention
efforts are inadequate, access to significant amounts of
internal historical knowledge and expertise could become
unavailable to us.
Failure
of or disruptions to our outsourcing relationships might
negatively impact our ability to conduct our
business.
Some studies indicate a high failure rate of outsourcing
relationships. Although Williams has taken steps to build a
cooperative and mutually beneficial relationship with its
outsourcing providers and to closely monitor their performance,
a deterioration in the timeliness or quality of the services
performed by the outsourcing providers or a failure of all or
part of these relationships could lead to loss of institutional
knowledge and interruption of services necessary for us to be
able to conduct our business. The expiration of
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such agreements or the transition of services between providers
could lead to similar losses of institutional knowledge or
disruptions.
Certain of our accounting, information technology, application
development, and help desk services are currently provided by
Williams outsourcing provider from service centers outside
of the United States. The economic and political conditions in
certain countries from which Williams outsourcing
providers may provide services to us present similar risks of
business operations located outside of the United States,
including risks of interruption of business, war, expropriation,
nationalization, renegotiation, trade sanctions or nullification
of existing contracts and changes in law or tax policy, that are
greater than in the United States.
Acts
of terrorism could have a material adverse effect on our
financial condition, results of operations and cash
flows.
Our assets and the assets of our customers and others may be
targets of terrorist activities that could disrupt our business
or cause significant harm to our operations, such as full or
partial disruption to our ability to produce, process, transport
or distribute natural gas, natural gas liquids or other
commodities. Acts of terrorism as well as events occurring in
response to or in connection with acts of terrorism could cause
environmental repercussions that could result in a significant
decrease in revenues or significant reconstruction or
remediation costs, which could have a material adverse effect on
our financial condition, results of operations and cash flows
and on our ability to make cash distributions to unitholders
Risks
Inherent in an Investment in Us
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 may 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 factors:
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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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all of the executive officers and certain of the directors of
our general partner are also officers
and/or
directors of Williams and Williams Partners general
partner, and these persons will also owe fiduciary duties to
those entities;
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our general partner is allowed to take into account the
interests of parties other than us, such as Williams and its
affiliates, in resolving conflicts of interest;
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Williams owns common units representing a 21.6% limited partner
interest in us, and if a vote of limited partners is required,
Williams will be entitled to vote its units in accordance with
its own interests, which may be contrary to our interests or
your interests;
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all of the executive officers and certain of the directors of
our general partner will devote significant time to the business
of Williams
and/or
Williams Partners, and will be compensated by Williams for the
services rendered to them;
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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 with
respect to its 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 incentive
distributions to our general partner;
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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. In determining whether a transaction or resolution
is fair and reasonable, our general
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partner may consider the totality of the relationships between
the parties involved, including other transactions that may be
particularly advantageous or beneficial to us;
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provides that our general partner, 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; and
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provides that in resolving conflicts of interest, it will be
presumed that in making its decision our general partner or the
conflicts committee of its board of directors acted in good
faith, and in any proceeding brought by or on behalf of any
limited partner or us, the person bringing or prosecuting such
proceeding will have the burden of overcoming such presumption.
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Common unitholders are bound by the provisions in the
partnership agreement, including the provisions discussed above.
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.
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.
Cost
reimbursements 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. Our general partner determines the
amount of these reimbursements 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
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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.
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.
We
have a holding company structure in which our subsidiaries
conduct our operations and own our operating assets. This 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 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.
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 effectively permits a
change of control without your consent.
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 distributions 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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Common
units held by Williams eligible for future sale may adversely
affect the price of our common units.
As of December 31, 2008, Williams held 11,613,527 common
units, representing a 21.6% limited partnership interest in us.
Williams may, from time to time, sell all or a portion of its
common units. Sales of substantial amounts of its common units,
or the anticipation of such sales, could lower the market price
of our common units and may make it more difficult for us to
sell our equity securities in the future at a time and at a
price that we deem appropriate.
Our
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, 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. Our general
partner may assign this right to any of its affiliates or to us.
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, to acquire
information about our operations and to influence the manner or
direction of management.
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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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.
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 Internal Revenue Service (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 entity-level taxation. In addition, because of
widespread state budget deficits and other reasons, several
states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income,
franchise or other forms of taxation. If any state were to
impose a tax upon us as an entity, the cash available for
distributions to unitholders would be reduced. The partnership
agreement provides that if a law is enacted or existing law is
modified or interpreted in a manner that subjects us to taxation
as a corporation or otherwise subjects us to entity-level
taxation for federal, state or local income tax purposes, then
the minimum quarterly distribution amount and the target
distribution amounts will be adjusted to reflect the impact of
that law on us.
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 (the Qualifying
Income Exception), affect or cause us to change our business
activities, affect the tax considerations of an
40
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 Internal Revenue Code
Section 7704(d) and the treatment of certain types of
income earned from profits interests in partnerships. 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. Modifications 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 common units on the first day of each
month, instead of on the basis of the date a particular common
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 common units on the first day of each
month, instead of on the basis of the date a particular common
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 federal income tax 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.
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 that was
allocated to a unitholder 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
41
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
non-U.S.
persons face unique tax issues from owning common units that may
result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as
individual retirement accounts (known as IRAs), and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to the unitholders who are organizations that
are exempt from federal income tax, including IRAs and other
retirement plans, may be taxable to them as unrelated
business taxable income. 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 applicable 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, 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. As we
make acquisitions or expand our business, we may own assets or
conduct business in additional states or foreign countries that
impose a personal income tax or an entity level tax. It is the
unitholders responsibility to file all federal, state and
local tax returns. Our counsel has not rendered an opinion on
the state and local tax consequences of an investment in our
common units.
The
sale or exchange of 50% or more of the total interest in our
capital and profits within a
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 would be required to make new tax elections and
could be subject to penalties if we are unable to determine that
a termination occurred.
42
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 current valuation methods,
subsequent purchasers of common units may have a greater portion
of their Internal Revenue Code Section 743(b) adjustment
allocated to our tangible assets and a lesser portion allocated
to our intangible assets. The IRS may challenge our valuation
methods, or our allocation of the Section 743(b) adjustment
attributable to our tangible and intangible assets, and
allocations of income, gain, loss and deduction between 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.
|
|
Item 1B.
|
Unresolved
Staff Comments
|
None.
|
|
Item 3.
|
Legal
Proceedings
|
The information called for by this item is provided in
Note 14, Commitments and Contingencies, in our Notes to
Consolidated Financial Statements of this report, which
information is incorporated into this Item 3 by reference.
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders
|
None.
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
|
Market
Information, Holders and Distributions
Our common units are listed on the New York Stock Exchange under
the symbol WPZ. At the close of business on
February 17, 2009, there were 52,777,452 common units
outstanding, held by approximately 21,823 holders, including
common units held in street name and by affiliates of Williams.
43
The following table sets forth, for the periods indicated, the
high and low sales prices for our common units, as reported on
the New York Stock Exchange Composite Transactions Tape, and
quarterly cash distributions paid to our unitholders.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Distribution
|
|
|
High
|
|
Low
|
|
per Unit(a)
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
$
|
26.25
|
|
|
$
|
9.96
|
|
|
$
|
0.635
|
|
Third Quarter
|
|
|
32.84
|
|
|
|
22.77
|
|
|
|
0.635
|
|
Second Quarter
|
|
|
37.66
|
|
|
|
31.33
|
|
|
|
0.625
|
|
First Quarter
|
|
|
39.31
|
|
|
|
31.24
|
|
|
|
0.600
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter
|
|
$
|
45.79
|
|
|
$
|
36.60
|
|
|
$
|
0.575
|
|
Third Quarter
|
|
|
52.00
|
|
|
|
40.26
|
|
|
|
0.550
|
|
Second Quarter
|
|
|
50.00
|
|
|
|
46.00
|
|
|
|
0.525
|
|
First Quarter(b)
|
|
|
48.20
|
|
|
|
38.20
|
|
|
|
0.500
|
|
|
|
|
(a) |
|
Represents cash distributions attributable to the quarter and
declared and paid or to be paid within 45 days after
quarter end. We paid cash distributions to our general partner
with respect to its 2% general partner interest and incentive
distribution rights that totaled $10.7 million and
$30.0 million for the 2007 and 2008 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 2007
periods indicated above. |
|
(b) |
|
Class B units participated in the 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 basis. |
Distributions
of Available Cash
Within 45 days after the end of each quarter we will
distribute all of our available cash, as defined in our
partnership agreement, to unitholders of record on the
applicable record date. Available cash generally means, for each
fiscal quarter, all cash on hand at the end of the quarter:
|
|
|
|
|
less the amount of cash reserves established by our general
partner to:
|
|
|
|
|
|
provide for the proper conduct of our business (including
reserves for future capital expenditures and for our anticipated
credit needs);
|
|
|
|
comply with applicable law, any of our debt instruments or other
agreements; or
|
|
|
|
provide funds for distribution to our unitholders and to our
general partner for any one or more of the next four quarters;
|
|
|
|
|
|
plus all cash on hand on the date of determination of available
cash for the quarter resulting from working capital borrowings
made after the end of the quarter for which the determination is
being made. Working capital borrowings are generally borrowings
that will be made under our working capital facility with
Williams and in all cases are used solely for working capital
purposes or to pay distributions to partners.
|
We will make distributions of available cash from operating
surplus for any quarter in the following manner:
|
|
|
|
|
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
|
|
|
|
thereafter, cash in excess of the minimum quarterly
distributions is distributed to the unitholders and the general
partner based on the incentive percentages below.
|
44
Our general partner is entitled to incentive distributions if
the amount we distribute with respect to any quarter exceeds
specified target levels shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marginal Percentage
|
|
|
Total Quarterly Distribution
|
|
Interest in Distributions
|
|
|
Target Amount
|
|
Unitholders
|
|
General Partner
|
|
Minimum Quarterly Distribution
|
|
$0.35
|
|
|
98
|
%
|
|
|
2
|
%
|
First Target Distribution
|
|
up to $0.4025
|
|
|
98
|
%
|
|
|
2
|
%
|
Second Target Distribution
|
|
above $0.4025 up to $0.4375
|
|
|
85
|
%
|
|
|
15
|
%
|
Third Target distribution
|
|
above $0.4375 up to $0.5250
|
|
|
75
|
%
|
|
|
25
|
%
|
Thereafter
|
|
Above $0.5250
|
|
|
50
|
%
|
|
|
50
|
%
|
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:
|
|
|
|
|
any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
|
|
|
|
our general partner will have the right to convert its general
partner interest and, if any, its incentive distribution rights
into common units or to receive cash in exchange for those
interests.
|
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.
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations
Financial Condition and Liquidity.
|
|
Item 6.
|
Selected
Financial and Operational Data
|
The following table shows our selected financial and operating
data and selected financial and operating data of Wamsutter and
Discovery for the periods and as of the dates indicated. We
derived the financial data as of December 31, 2008 and 2007
and for the years ended December 31, 2008, 2007 and 2006 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 a 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 retrospectively adjusted 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.
45
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Dollars in thousands, except per-unit amounts)
|
|
|
Statement of Income Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
637,060
|
|
|
$
|
572,817
|
|
|
$
|
563,410
|
|
|
$
|
514,972
|
|
|
$
|
469,199
|
|
Costs and expenses
|
|
|
490,052
|
|
|
|
457,880
|
|
|
|
420,342
|
|
|
|
395,556
|
|
|
|
364,602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
147,008
|
|
|
|
114,937
|
|
|
|
143,068
|
|
|
|
119,416
|
|
|
|
104,597
|
|
Equity earnings Wamsutter
|
|
|
88,538
|
|
|
|
76,212
|
|
|
|
61,690
|
|
|
|
40,555
|
|
|
|
39,016
|
|
Discovery investment income
|
|
|
22,357
|
|
|
|
28,842
|
|
|
|
18,050
|
|
|
|
11,880
|
|
|
|
5,619
|
|
Impairment of investment in Discovery
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16,855
|
)
|
Interest expense
|
|
|
(67,220
|
)
|
|
|
(58,348
|
)
|
|
|
(9,833
|
)
|
|
|
(8,238
|
)
|
|
|
(12,476
|
)
|
Interest income
|
|
|
706
|
|
|
|
2,988
|
|
|
|
1,600
|
|
|
|
165
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
$
|
191,389
|
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
|
$
|
163,778
|
|
|
$
|
119,901
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income(a)
|
|
$
|
191,389
|
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
|
$
|
162,373
|
|
|
$
|
119,901
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting
principle per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unit
|
|
$
|
2.55
|
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
|
$
|
0.49
|
(b)
|
|
|
N/A
|
|
Subordinated unit
|
|
$
|
N/A
|
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
|
$
|
0.49
|
(b)
|
|
|
N/A
|
|
Net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unit
|
|
$
|
2.55
|
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
|
$
|
0.44
|
(b)
|
|
|
N/A
|
|
Subordinated unit
|
|
$
|
N/A
|
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
|
$
|
0.44
|
(b)
|
|
|
N/A
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,291,819
|
|
|
$
|
1,283,477
|
|
|
$
|
1,292,299
|
|
|
$
|
1,190,508
|
|
|
$
|
1,121,862
|
|
Property, plant and equipment, net
|
|
|
640,520
|
|
|
|
642,289
|
|
|
|
647,578
|
|
|
|
658,965
|
|
|
|
669,503
|
|
Investment in Wamsutter
|
|
|
277,707
|
|
|
|
284,650
|
|
|
|
262,245
|
|
|
|
240,156
|
|
|
|
221,360
|
|
Investment in Discovery
|
|
|
184,466
|
|
|
|
214,526
|
|
|
|
221,187
|
|
|
|
225,337
|
|
|
|
184,199
|
|
Advances from affiliate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
186,024
|
|
Long-term debt
|
|
|
1,000,000
|
|
|
|
1,000,000
|
|
|
|
750,000
|
|
|
|
|
|
|
|
|
|
Partners capital
|
|
|
203,610
|
(c)
|
|
|
161,487
|
(c)
|
|
|
471,341
|
(c)
|
|
|
1,142,478
|
|
|
|
895,476
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions declared per unit
|
|
$
|
2.435
|
|
|
$
|
2.045
|
|
|
$
|
1.605
|
|
|
$
|
0.1484
|
|
|
|
N/A
|
|
Cash distributions paid per unit
|
|
$
|
2.435
|
|
|
$
|
2.045
|
|
|
$
|
1.605
|
|
|
$
|
0.1484
|
|
|
|
N/A
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Dollars in thousands, except per-unit amounts)
|
|
|
Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Four Corners gathering volumes (BBtu/d)
|
|
|
1,380
|
|
|
|
1,442
|
|
|
|
1,500
|
|
|
|
1,522
|
|
|
|
1,560
|
|
Four Corners plant inlet natural gas volumes (BBtu/d)
|
|
|
646
|
|
|
|
620
|
|
|
|
678
|
|
|
|
685
|
|
|
|
716
|
|
Four Corners NGL equity sales (million gallons)
|
|
|
162
|
|
|
|
167
|
|
|
|
182
|
|
|
|
165
|
|
|
|
198
|
|
Four Corners NGL margin ($/gallon)
|
|
$
|
.75
|
|
|
$
|
.61
|
|
|
$
|
.47
|
|
|
$
|
.37
|
|
|
$
|
.29
|
|
Four Corners NGL production (million gallons)
|
|
|
518
|
|
|
|
545
|
|
|
|
569
|
|
|
|
550
|
|
|
|
566
|
|
Conway storage revenues
|
|
$
|
31,429
|
|
|
$
|
28,016
|
|
|
$
|
25,237
|
|
|
$
|
20,290
|
|
|
$
|
15,318
|
|
Conway fractionation volumes (bpd) our 50%
|
|
|
39,019
|
|
|
|
34,460
|
|
|
|
38,859
|
|
|
|
39,965
|
|
|
|
39,062
|
|
Carbonate Trend gathering volumes (BBtu/d)
|
|
|
22
|
|
|
|
23
|
|
|
|
29
|
|
|
|
36
|
|
|
|
50
|
|
Wamsutter 100%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wamsutter gathering volumes (BBtu/d)
|
|
|
499
|
|
|
|
516
|
|
|
|
490
|
|
|
|
464
|
|
|
|
452
|
|
Wamsutter plant inlet natural gas volumes (BBtu/d)
|
|
|
409
|
|
|
|
425
|
|
|
|
432
|
|
|
|
422
|
|
|
|
417
|
|
Wamsutter NGL equity sales (million gallons)
|
|
|
139
|
|
|
|
113
|
|
|
|
141
|
|
|
|
160
|
|
|
|
175
|
|
Wamsutter NGL margin ($/gallon)
|
|
$
|
.59
|
|
|
$
|
.48
|
|
|
$
|
.29
|
|
|
$
|
.13
|
|
|
$
|
.11
|
|
Wamsutter NGL production (million gallons)
|
|
|
415
|
|
|
|
420
|
|
|
|
377
|
|
|
|
419
|
|
|
|
435
|
|
Discovery Producer Services 100%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery plant inlet natural gas volumes (BBtu/d)
|
|
|
457
|
|
|
|
582
|
|
|
|
467
|
|
|
|
345
|
|
|
|
348
|
|
Discovery gross processing margin ($/MMbtu)
|
|
$
|
.37
|
|
|
$
|
.33
|
|
|
$
|
.23
|
|
|
$
|
.19
|
|
|
$
|
.17
|
|
Discovery NGL equity sales (million gallons)
|
|
|
85
|
|
|
|
99
|
|
|
|
60
|
|
|
|
38
|
|
|
|
61
|
|
Discovery NGL production (million gallons)
|
|
|
181
|
|
|
|
252
|
|
|
|
232
|
|
|
|
147
|
|
|
|
134
|
|
|
|
|
(a) |
|
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. |
|
(b) |
|
The period of August 23, 2005 through December 31,
2005. |
|
(c) |
|
Because Four Corners, Wamsutter and a 20% interest 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 acquired are combined with ours 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. |
47
|
|
Item 7.
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
Please
read the following discussion of our financial condition and
results of operations in conjunction with the consolidated
financial statements and related notes included in Item 8
of this annual report.
Overview
We gather, transport, process and treat natural gas and
fractionate and store 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
(West). Our West segment includes
(1) Williams Four Corners LLC (Four Corners) and
(2) certain ownership interests in Wamsutter LLC
(Wamsutter) consisting of (i) 100% of the Class A
limited liability company membership interests and (ii) 65%
of the Class C limited liability company membership
interests in Wamsutter (together, the Wamsutter Ownership
Interests). The Four Corners system gathers and processes or
treats 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
and processes natural gas produced in the Washakie Basin and
connects with four pipeline systems that transport natural gas
to end markets from the basin.
|
|
|
|
Gathering and Processing Gulf
(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 its natural gas processing
facility and NGL fractionator in Louisiana. These systems
gather, transport and process natural gas and fractionate NGLs
to customers under a range of contractual arrangements. Although
Discovery includes fractionation operations, which would
normally fall within the NGL Services segment, it primarily
gathers and processes, and is so managed.
|
|
|
|
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 provide stand-alone NGL fractionation and storage
services using various fee-based contractual arrangements.
|
Executive
Summary
In the first three quarters of 2008, our segment profit improved
considerably compared to 2007. However, these results were
followed by a steep decline in the fourth quarter due to a rapid
decline in NGL prices. As evidenced by recent events, NGL, crude
oil and natural gas prices are highly volatile. NGL price
changes have historically tracked with changes in the price of
crude oil; however, ethane prices have recently disassociated
from crude oil prices. As NGL prices, especially ethane,
decline, we experience significantly lower
per-unit NGL
margins and periods when it is not economical to recover ethane.
Additionally, as discussed below, Hurricanes Gustav and Ike
severely disrupted Discoverys operations in September and
limited its operations throughout the fourth quarter.
Discoverys operations have been significantly restored,
but will continue to be impacted while additional repairs are
ongoing. We maintained our fourth-quarter unitholder
distribution at $0.635 per unit, which was the same as the
third-quarter 2008 distribution and 10% higher than the
fourth-quarter 2007 distribution.
Recent
Events
The global recession and resulting drop in demand and prices for
NGLs has significantly reduced the profitability and cash flows
of our gathering and processing businesses including Four
Corners, our ownership interests in Wamsutter and Discovery. We
expect low NGL margins during 2009, including periods when it is
not economical to recover ethane. As a result, we expect cash
flow from operations, including cash distributions to us from
Wamsutter and Discovery, to be significantly lower in 2009 than
2008.
48
Given the current energy commodity price and NGL margin
environment, together with our cash balance of approximately
$66 million at February 16, we expect to maintain our
current level of cash distributions throughout 2009. During 2006
through 2008, we retained a portion of our excess cash flow for
future periods when NGL prices and margins might be
substantially lower as they are now. However, if energy
commodity prices and NGL margins decline further for a prolonged
period of time,
and/or if
other unexpected events adversely affect cash flows
and/or our
available cash balance, we may need to reduce distributions.
During September 2008, Discoverys offshore gathering
system sustained hurricane damage and was unable to accept gas
from producers while repairs were being made through the end of
2008. Inspections revealed that an
18-inch
lateral was severed from its connection to the
30-inch
mainline in 250 feet of water. The
30-inch
mainline was repaired and returned to service in January 2009.
The 30-inch
mainline is now delivering
150 MMcf/d
of production, which was its approximate volume prior to the
hurricanes. Both the Larose processing plant and the Paradis
fractionator are operational and processed gas from third-party
sources during the fourth quarter of 2008.
We concluded our negotiations with the Jicarilla Apache Nation
(JAN) during February 2009 with the execution of a
20-year
right-of-way agreement. Under the new agreement, the JAN granted
rights-of-way for Four Corners existing natural gas
gathering system on JAN land as well as a significant
geographical area for additional growth of the system. We paid
an initial payment of $7.3 million upon execution of the
agreement. Beginning in 2010, we will make annual payments of
approximately $7.5 million and an additional annual payment
which varies depending on the prior years
per-unit NGL
margins and the volume of gas gathered by our gathering
facilities subject to the agreement. Depending primarily on the
per-unit NGL
margins for any given year, the additional annual payments could
approximate the fixed amount. Additionally, five years from the
effective date of the agreement, the JAN will have the option to
acquire up to a 50% joint venture interest for 20 years in
certain of Four Corners assets existing at the time the
option is exercised. The joint venture option includes Four
Corners gathering assets subject to the agreement and
portions of Four Corners gathering and processing assets
located in an area adjacent to the JAN lands. If the JAN selects
the joint venture option, the value of the assets contributed by
each party to the joint venture will be based upon a market
value determined by a neutral third party at the time the joint
venture is formed. This right-of-way agreement is subject to the
consent of the United States Secretary of the Interior before it
may become effective.
In January 2009, Wamsutter issued an additional 70.8 and 28.8
Class C units to us and Williams, respectively, related to
funding of expansion capital expenditures placed in service
during 2008. Therefore, we now own 65% and Williams owns 35% of
Wamsutters outstanding Class C units. As of
December 31, 2008, Williams has contributed
$28.8 million for an expansion capital project that is
expected to be placed in service during 2010. Williams will
receive Class C units related to these expenditures after
the asset is placed in service; thus, our Class C ownership
interest will decline at that time.
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
throughput volumes;
|
|
|
|
Four Corners and Wamsutters NGL margins;
|
|
|
|
Discoverys and Carbonate Trends pipeline throughput
volumes;
|
|
|
|
Discoverys gross processing margins;
|
|
|
|
Conways fractionation volumes;
|
|
|
|
Conways storage revenues; and
|
|
|
|
Operating and maintenance expenses.
|
49
Gathering,
Processing and Throughput Volumes
Gathering, processing and throughput volumes on the following
assets are important components of maximizing our profitability
and the profitability of Wamsutter and Discovery:
|
|
|
|
|
Our Four Corners gathering system and Ignacio, Kutz and Lybrook
natural gas processing plants;
|
|
|
|
Wamsutters gathering system and Echo Springs natural gas
processing plant;
|
|
|
|
Discoverys gathering and transportation system, Larose gas
processing plant and Paradis fractionator; and
|
|
|
|
Our Carbonate Trend transportation pipeline.
|
We gather approximately 36% of the San Juan Basins
natural gas production on our Four Corners system at
approximately 6,450 receipt points, and the Wamsutter pipeline
system gathers approximately 69% of the natural gas produced in
the Washakie Basin. Gathering and transportation services are
provided primarily under fee-based contracts. Gathering and
transportation throughput volumes from existing wells will
naturally decline over time. In order to maintain or increase
gathering volumes, we, Wamsutter and Discovery must continually
obtain new supplies of natural gas. The ability to maintain
existing supplies of natural gas and obtain new supplies are
impacted by (1) the level of workovers or recompletions of
existing connected wells and successful drilling activity in
areas currently dedicated to our gathering pipelines and
(2) the ability to compete for volumes from successful new
wells in other areas. Offshore drilling activity, which supplies
Discoverys gathering system, is generally subject to
significantly higher costs and longer lead times than the
onshore drilling, which supplies the Four Corners and Wamsutter
gathering systems. We, Wamsutter and Discovery routinely monitor
producer activity in the areas served by our assets and pursue
opportunities to connect new wells to these pipelines.
Processing volumes are largely dependant on the volume of
natural gas gathered or transported on these systems. Our Four
Corners system processes natural gas under keep-whole,
percent-of-liquids, fee-based and combination fee-based and
keep-whole contracts. Wamsutter and Discovery process natural
gas under keep-whole and fee-based contracts.
Four
Corners and Wamsutter NGL Margins
We and Wamsutter use NGL margins as an important measure of our
ability to maximize the profitability of the processing
operations. NGL margins are derived by deducting the cost of
shrink replacement gas from the revenue received from the sale
of NGLs, 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, we and
Wamsutter receive NGLs as compensation for processing services
provided to customers. The NGL 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
Gross Processing Margins
We view total gross processing margins as an important measure
of Discoverys ability to maximize the profitability of its
processing operations. Gross processing margins include revenue
derived from:
|
|
|
|
|
The rates stipulated under fee-based contracts multiplied by the
actual volumes processed.
|
|
|
|
Sales of NGL volumes received under certain processing contracts
for Discoverys account and keep-whole contracts.
|
|
|
|
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.
50
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. We calculate storage
revenues 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, compression and
other contract services, right-of-way costs, fuel, utilities,
materials and 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. Compression
service costs 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 are a
component in assessing Discoverys gross processing margins.
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.
In analyses conducted during 2007 and 2008, 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 impairment charges of $10.4 million
and $6.2 million in 2007 and 2008, respectively, to reduce
the carrying value to managements estimate of fair value
at the end of each of those years. As of December 31, 2008,
the carrying value of this asset has been written down to zero.
(See Note 7, Other (Income) Expense, in our Notes
51
to Consolidated Financial Statements.) Our most recent analysis
utilized judgments and assumptions in the following areas:
|
|
|
|
|
expected future drilling in the area,
|
|
|
|
estimated future volumes from currently producing wells and new
discoveries,
|
|
|
|
estimated future gathering rates, and
|
|
|
|
estimated operating and maintenance cost increases.
|
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, 2008, we have accrued asset retirement
obligations of $13.2 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 Kansas Department of Health and Environment
(KDHE) regulations and the Carbonate Trend pipeline. Our
estimate utilizes judgments and assumptions regarding the extent
of our obligations, the costs to abandon and the timing of
abandonment. In 2008, we revised our estimated asset retirement
obligations by $3.6 million. 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 2008, and the expected retirement date for
the Carbonate Trend pipeline had been significantly shortened,
the recorded asset retirement obligation would have increased by
an additional $12.0 million to $14.0 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
obligations when we assess that a loss is probable and the
amount of the loss can be reasonably estimated. At
December 31, 2008, we have an accrual for estimated
environmental remediation obligations of $4.8 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.)
Results
of Operations
Consolidated
Overview
The following table and discussion summarizes our consolidated
results of operations for the three years ended
December 31, 2008. The results of operations by segment are
discussed in further detail following this
52
consolidated overview discussion and relate to the segment
tables in Note 15, Segment Disclosures, in our Notes to
Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Change
|
|
|
|
|
|
% Change
|
|
|
|
|
|
|
|
|
|
from
|
|
|
|
|
|
from
|
|
|
|
|
|
|
2008
|
|
|
2007(1)
|
|
|
2007
|
|
|
2006(1)
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
637,060
|
|
|
|
+11
|
%
|
|
$
|
572,817
|
|
|
|
+2
|
%
|
|
$
|
563,410
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
206,078
|
|
|
|
(13
|
)%
|
|
|
181,698
|
|
|
|
(4
|
)%
|
|
|
175,508
|
|
Operating and maintenance expense
|
|
|
185,901
|
|
|
|
(15
|
)%
|
|
|
162,343
|
|
|
|
(5
|
)%
|
|
|
155,214
|
|
Depreciation, amortization and accretion
|
|
|
45,029
|
|
|
|
+3
|
%
|
|
|
46,492
|
|
|
|
(6
|
)%
|
|
|
43,692
|
|
General and administrative expense
|
|
|
47,059
|
|
|
|
(3
|
)%
|
|
|
45,628
|
|
|
|
(16
|
)%
|
|
|
39,440
|
|
Taxes other than income
|
|
|
9,508
|
|
|
|
+1
|
%
|
|
|
9,624
|
|
|
|
(7
|
)%
|
|
|
8,961
|
|
Other (income) expense net
|
|
|
(3,523
|
)
|
|
|
NM
|
|
|
|
12,095
|
|
|
|
NM
|
|
|
|
(2,473
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
490,052
|
|
|
|
(7
|
)%
|
|
|
457,880
|
|
|
|
(9
|
)%
|
|
|
420,342
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
147,008
|
|
|
|
+28
|
%
|
|
|
114,937
|
|
|
|
(20
|
)%
|
|
|
143,068
|
|
Equity earnings Wamsutter
|
|
|
88,538
|
|
|
|
+16
|
%
|
|
|
76,212
|
|
|
|
+24
|
%
|
|
|
61,690
|
|
Discovery investment income
|
|
|
22,357
|
|
|
|
(22
|
)%
|
|
|
28,842
|
|
|
|
+60
|
%
|
|
|
18,050
|
|
Interest expense
|
|
|
(67,220
|
)
|
|
|
(15
|
)%
|
|
|
(58,348
|
)
|
|
|
NM
|
|
|
|
(9,833
|
)
|
Interest income
|
|
|
706
|
|
|
|
(76
|
)%
|
|
|
2,988
|
|
|
|
+87
|
%
|
|
|
1,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
191,389
|
|
|
|
+16
|
%
|
|
$
|
164,631
|
|
|
|
(23
|
)%
|
|
$
|
214,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
2008 vs.
2007
Revenues increased $64.2 million, or 11%, due
primarily to higher product sales in our West segment and higher
fractionation, product sales and storage revenues in our NGL
Services segment.
Product cost and shrink replacement increased
$24.4 million, or 13%, due primarily to higher cost of
product sales in both our West and NGL Services segments and
higher average natural gas prices for shrink replacement in our
West segment.
Operating and maintenance expense increased
$23.6 million, or 15%, due primarily to higher repairs and
maintenance, materials and supplies and system losses in our
West segment.
Other (income) expense net in 2008 reflects
an $11.6 million involuntary conversion gain related to the
November 2007 Ignacio plant fire. Other (income)
expense net for 2008 and 2007 includes a
$6.2 million and $10.4 million impairment,
respectively, of our Carbonate Trend pipeline in our Gulf
segment.
Operating income increased $32.1 million, or 28%,
due primarily to higher
per-unit NGL
margins on slightly lower sales volumes, an $11.6 million
involuntary conversion gain in 2008, higher other fee revenue
and higher condensate sales margins in our West segment,
combined with higher fractionation and storage revenues in our
NGL Services segment and a $4.2 million lower impairment
loss on the Carbonate Trend pipeline in our Gulf segment.
Partially offsetting these favorable variances were lower
fee-based gathering revenues and higher operating and
maintenance expenses in our West segment.
53
Equity earnings Wamsutter increased
$12.3 million, or 16%, due primarily to higher average
per-unit NGL
margins on increased NGL sales volumes.
Discovery investment income decreased $6.5 million,
or 22%, due primarily to lower equity earnings caused by
Hurricanes Ike and Gustav, partially offset by hurricane-related
receipts under our Discovery-related business interruption
policy.
Interest expense increased $8.9 million, or 15%, due
primarily to interest on our $250.0 million term loan
issued in December 2007 to finance a portion of our acquisition
of ownership interests in Wamsutter.
Interest income decreased $2.3 million, or 76%, due
primarily to significantly lower daily interest rates on higher
fourth-quarter 2008 cash balances compared to fourth quarter
2007.
2007 vs.
2006
Revenues increased $9.4 million, or 2%, due
primarily to higher product sales, partially offset by lower
fee-based gathering and processing in our West segment, slightly
offset by lower revenues in our NGL Services segment.
Product cost and shrink replacement increased
$6.2 million, or 4%, due primarily to increased NGL
purchases from producers in our West segment, partially offset
by lower shrink requirements from the fire at Ignacio and
decreased product sales volumes in our NGL Services segment.
Operating and maintenance expense increased
$7.1 million, or 5%, due primarily to higher expense in our
West segment from increased fuel, rent and leased compression
expense, partially offset by lower expense in our NGL Services
segment from lower fuel and power costs on lower fractionator
throughput.
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 net changed from
$2.5 million income in 2006 to $12.1 million expense
in 2007 due primarily to the 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
West segment.
Operating income declined $28.1 million, or 20%, due
primarily to the impact of the 2007 Ignacio plant fire in our
West segment, the 2007 impairment of the Carbonate trend
pipeline and higher general and administrative expense. These
unfavorable variances were slightly offset by higher revenues
and lower operating and maintenance expenses in our NGL Services
segment.
Equity earnings Wamsutter increased
$14.5 million, or 24%, due primarily to higher NGL margins
and fee-based gathering and processing revenues, partially
offset by higher general and administrative expenses.
Discovery investment income 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.
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.
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.
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Segment revenues
|
|
$
|
560,138
|
|
|
$
|
513,787
|
|
|
$
|
502,313
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
189,192
|
|
|
|
170,434
|
|
|
|
159,997
|
|
Operating and maintenance expense
|
|
|
156,713
|
|
|
|
135,782
|
|
|
|
124,763
|
|
Depreciation, amortization and accretion
|
|
|
41,215
|
|
|
|
41,523
|
|
|
|
40,055
|
|
General and administrative expense direct
|
|
|
8,333
|
|
|
|
7,790
|
|
|
|
11,920
|
|
Taxes other than income
|
|
|
8,770
|
|
|
|
8,869
|
|
|
|
8,245
|
|
Other (income) expense net
|
|
|
(9,709
|
)
|
|
|
1,698
|
|
|
|
(2,476
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses, including interest income
|
|
|
394,514
|
|
|
|
366,096
|
|
|
|
342,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
165,624
|
|
|
|
147,691
|
|
|
|
159,809
|
|
Equity earnings Wamsutter
|
|
|
88,538
|
|
|
|
76,212
|
|
|
|
61,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
254,162
|
|
|
$
|
223,903
|
|
|
$
|
221,499
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Four
Corners
2008 vs.
2007
Revenues increased $46.4 million, or 9%, due
primarily to $43.0 million higher product sales revenues
and $9.0 million improved other fee revenue, slightly
offset by $7.1 million lower gathering revenues. The
significant components of the revenue fluctuations are addressed
more fully below.
Product sales revenues increased $43.0 million due
primarily to:
|
|
|
|
|
$35.3 million from 22% higher average
per-unit NGL
sales prices realized on NGL volumes we received under
keep-whole and percent-of-liquids processing contracts. NGL
sales prices were sharply higher in the first three quarters of
2008 compared to 2007; however, NGL sales prices declined
significantly in the fourth quarter of 2008.
|
|
|
|
$6.6 million higher sales of NGLs on behalf of third-party
producers. Under these arrangements, we purchase NGLs from the
third-party producers and sell them to an affiliate. This
increase is offset by higher associated product costs of
$6.9 million discussed below.
|
|
|
|
$4.6 million higher condensate sales resulting primarily
from higher prices.
|
These increases in product sales revenues were slightly offset
by a $4.4 million impact of 3% lower NGL sales volumes.
Other fee revenue improved $9.0 million due primarily to a
$4.4 million fourth-quarter 2008 insurance reimbursement
for lost profits under our business interruption insurance
related to the November 2007 Ignacio plant fire and the absence
of a $3.5 million third-quarter 2007 unfavorable revenue
recognition correction for electronic flow measurement fees.
Fee-based gathering revenues decreased $7.1 million, or 4%,
due primarily to a $7.6 million decline in revenue from
lower gathering volumes. This resulted from the prolonged,
severe weather during early 2008 which inhibited both our and
our customers abilities to access facilities, connect new
wells and maintain production. The 2007 volumes were reduced by
the fire at the Ignacio gas processing plant in late November
2007.
Product cost and shrink replacement increased
$18.8 million, or 11%, due primarily to $10.7 million
from higher average natural gas prices for shrink replacement
and $6.9 million higher NGL purchases from third-party
producers who elected to have us purchase their NGLs (offset by
the corresponding increase in product sales discussed above).
55
Operating and maintenance expense increased
$20.9 million, or 15%, due primarily to $12.0 million
higher system and imbalance losses and $9.1 million higher
repairs and maintenance and materials and supplies expense.
During 2008 our volumetric system loss, as a percentage of total
volume received, was significantly higher than in 2007. While
our system losses are generally an unpredictable component of
our operating costs, they can be higher during periods of
prolonged, severe weather, such as those we experienced during
early 2008. Additionally, operating inefficiencies caused by the
fire at Ignacio plant unfavorably impacted our system losses.
Other (income) expense net improved
$11.4 million due primarily to an $11.6 million
involuntary conversion gain recognized in 2008 related to the
November 2007 Ignacio plant fire.
Segment operating income increased $17.9 million, or
12%, due primarily to:
|
|
|
|
|
$20.0 million higher NGL margins resulting primarily higher
per-unit NGL
margins. Record NGL margins experienced during the first three
quarters were impacted unfavorably in the fourth-quarter 2008
when NGL sales prices declined significantly.
|
|
|
|
$11.6 million of 2008 involuntary conversion gains.
|
|
|
|
$9.0 million higher other revenues.
|
Partially offsetting these increases were $20.9 million
higher operating and maintenance expenses and $7.1 million
lower fee-based gathering revenues.
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. 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.
|
|
|
|
$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 a decrease in NGL
sales volumes. 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.
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. 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.
Product cost and shrink replacement increased
$10.4 million, or 7%, due primarily to a $15.3 million
increase from third-party producers who elected to have us
purchase their NGLs, offset by the corresponding increase in
product sales revenues discussed above. This increase was
partially offset by $6.4 million from lower volumetric
shrink requirements under 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.
|
56
|
|
|
|
|
$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.
|
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.
Segment operating income decreased $12.1 million, or
8%, due primarily to an 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 and
$4.2 million lower other (income) expense.
Outlook
for 2009
|
|
|
|
|
NGL and natural gas commodity prices. Because
NGL prices, especially ethane, have recently declined, we expect
significantly lower
per-unit NGL
margins in 2009 compared to 2008. We also anticipate periods
when it will not be economical to recover ethane, which will
reduce our margins. We have no hedges in place in 2009 for
either our NGL sales or our natural gas shrink replacement
purchases. As evidenced by recent events, NGL, crude and natural
gas prices are highly volatile. NGL price changes have
historically tracked with changes in the price of crude oil,
however ethane prices have recently disassociated from crude
prices.
|
|
|
|
Gathering and processing volumes. We expect
average gathering and processing volumes for 2009 to be slightly
below 2008. Drilling activity by producers is expected to
decline in 2009 due to the current credit crisis and economic
downturn, together with the low commodity price environment.
However, when drilling activity increases, we anticipate that
capital investments we completed in 2008 will support producer
customers drilling activity, expansion opportunities and
production enhancement activities.
|
|
|
|
Drilling in Paradox Basin. Third-party
producers are drilling in the Paradox Basin in Colorado and we
expect to be successful in competing for processing contracts
for this gas.
|
|
|
|
Operating costs. We expect and will pursue
reductions in certain costs as demand for these resources
declines.
|
|
|
|
Assets on Jicarilla land. As previously
discussed, we concluded our negotiations with the Jicarilla
Apache Nation (JAN) during February 2009 with the execution of a
20-year
right-of-way agreement. These terms represent a significant
increase over our 2008 JAN expense, including the cost of
our special business licenses with the JAN, of
$3.5 million. We paid an initial payment of
$7.3 million upon execution of the agreement. Beginning in
2010, we will make annual payments of approximately
$7.5 million and an additional annual payment which varies
depending on
per-unit NGL
margins and the volume of gas gathered by our gathering
facilities subject to the agreement. Throughout 2009, we will
record an estimate of the additional annual payment to be paid
in 2010, based on 2009 NGL margins. Depending primarily on the
per-unit NGL
margins for any given year, the additional annual payments could
approximate the fixed amount.
|
57
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. Please read Note 6, Equity Investments, of
our Notes to Consolidated Financial Statements for discussion of
how Wamsutter allocates its net income between its member owners
including us.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Revenues
|
|
$
|
239,534
|
|
|
$
|
175,309
|
|
|
$
|
176,546
|
|
Costs and expenses, including interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
78,809
|
|
|
|
46,039
|
|
|
|
71,088
|
|
Operating and maintenance expense
|
|
|
20,973
|
|
|
|
18,257
|
|
|
|
17,047
|
|
Depreciation and accretion
|
|
|
21,182
|
|
|
|
18,424
|
|
|
|
16,189
|
|
General and administrative expense
|
|
|
13,507
|
|
|
|
12,623
|
|
|
|
8,866
|
|
Taxes other than income
|
|
|
1,868
|
|
|
|
1,637
|
|
|
|
1,411
|
|
Other (income) expense, net
|
|
|
(569
|
)
|
|
|
944
|
|
|
|
255
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
135,770
|
|
|
|
97,924
|
|
|
|
114,856
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
103,764
|
|
|
$
|
77,385
|
|
|
$
|
61,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest
|
|
$
|
88,538
|
|
|
$
|
76,212
|
|
|
$
|
61,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 vs.
2007
Revenues increased $64.2 million, or 37%, due
primarily to $61.6 million higher sales of NGLs which
Wamsutter received under keep-whole processing contracts. This
increase reflects $39.5 million related to higher average
sales prices and $22.1 million related to 23% higher sales
volumes. This volumetric increase was due primarily to a lower
volume of gas delivered by Wamsutters fee-based customers
in the first quarter of 2008 due to inclement weather which
allowed Wamsutter to process additional keep-whole gas at the
Echo Springs plant. Additionally, Wamsutter benefited from the
ability to process additional keep-whole gas at CIGs
Rawlins natural gas processing plant.
Product cost and shrink replacement increased
$32.8 million, or 71%, due primarily to a
$24.2 million increase from higher average natural gas
prices and $9.5 million from higher volumetric shrink
requirements due to higher volumes processed under
Wamsutters keep-whole processing contracts. Gas prices in
2007 were impacted by very low local natural gas costs compared
with other natural gas markets.
Operating and maintenance expense increased
$2.7 million, or 15%, due primarily to higher gathering
fuel, third-party processing, and material and supply costs,
substantially offset by $5.0 million higher system gains.
Depreciation and accretion increased $2.8 million,
or 15%, due primarily to new assets placed into service.
Net income increased $26.4 million, or 34%, due
primarily to $27.9 million higher NGL margin resulting from
increased
per-unit
margins on higher NGL sales volumes.
58
As described in Note 6, Equity Investments, of our Notes to
Consolidated Financial Statements, Wamsutters net income
is allocated based upon the allocation, distribution, and
liquidation provisions of its limited liability company
agreement. The following table presents the allocation of
Wamsutters 2008 net income to its unitholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our Share
|
|
|
Other
|
|
|
Wamsutter
|
|
Wamsutter Net Income Allocation
|
|
Class A
|
|
|
Class C
|
|
|
WPZ Total
|
|
|
Class C
|
|
|
Net Income
|
|
|
|
|
|
|
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
Net income, beginning December 1, 2007 up to
$70.0 million.*
|
|
$
|
62.6
|
|
|
$
|
|
|
|
$
|
62.6
|
|
|
$
|
|
|
|
$
|
62.6
|
|
Net income allocation related to 5% of amount over
$70.0 million
|
|
|
2.1
|
|
|
|
|
|
|
|
2.1
|
|
|
|
|
|
|
|
2.1
|
|
Net income for December 2008
|
|
|
1.0
|
|
|
|
|
|
|
|
1.0
|
|
|
|
|
|
|
|
1.0
|
|
Net income allocation related to transition support payments
paid to us
|
|
|
7.6
|
|
|
|
|
|
|
|
7.6
|
|
|
|
|
|
|
|
7.6
|
|
Remainder net income allocated to Class C members
|
|
|
|
|
|
|
15.2
|
|
|
|
15.2
|
|
|
|
15.2
|
|
|
|
30.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
$
|
73.3
|
|
|
$
|
15.2
|
|
|
$
|
88.5
|
|
|
$
|
15.2
|
|
|
$
|
103.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
$7.4 million of the $70.0 million was recognized in
2007. |
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 $20.8 million from 20%
lower NGL volumes 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. These
product sales decreases were partially offset by a
$12.1 million increase related to higher average NGL sales
prices.
|
|
|
|
Gathering and fee-based processing revenue increased
$5.6 million due to a 9% increase in the average fee and
$4.4 million due to an 8% increase in average volumes.
|
Product cost and shrink replacement decreased
$25.0 million, or 35%, due primarily to an
$11.2 million decrease from lower average natural gas
prices and a $10.4 million decrease from lower volumetric
shrink requirements under Wamsutters keep-whole processing
contracts following the election of one customer to switch to
fee-based processing discussed above.
Operating and maintenance expense increased
$1.2 million, or 7%, due primarily to higher materials and
supplies and outside services expense caused primarily by
increased equipment maintenance activity, partially offset by
$4.9 million higher system gains.
Depreciation and accretion expense increased
$2.2 million, or 14%, due primarily to new assets placed
into service.
General and administrative expense 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 NGL 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.
59
Outlook
for 2009
|
|
|
|
|
NGL margins. We expect significantly lower
cash distributions from Wamsutter in 2009 as compared to 2008,
primarily as a result of lower
per-unit NGL
margins. As evidenced by recent events, NGL, crude and natural
gas prices are highly volatile. NGL price changes have
historically tracked with changes in the price of crude oil,
however ethane prices have recently disassociated from crude
prices. As NGL prices, especially ethane, have declined,
Wamsutter is experiencing lower
per-unit NGL
margins in 2009 compared to 2008. Natural gas prices in the
Rockies basins have been lower than other areas of the
country, and we expect this trend to continue. Because natural
gas cost is a component of Wamsutters NGL margins,
Wamsutter expects that
per-unit NGL
margins may be higher than some other areas of the country.
However, Wamsutter may still experience periods when it is not
economical to recover ethane, which will reduce its margins.
|
|
|
|
Gathering and processing volumes. We
anticipate that our 2009 average gathering volumes will increase
slightly over 2008 levels as a result of our well connect
activity, producers sustained drilling activity, expansion
opportunities and production enhancement activities that should
be sufficient to more than offset the historical production
decline.
|
|
|
|
Third-party processing. In 2008, we executed a
new agreement that extended our ability to send excess
unprocessed gas to Colorado Interstates Rawlins natural
gas processing plant through October 2010. This agreement
provides Wamsutter with third-party processing of
80 MMcf/d.
We expect a full year of natural gas processing in 2009 under
this agreement. As a result, total gas processed will increase,
Wamsutter will be able to sell higher volumes of NGLs, and
operating costs will increase approximately $2 million.
|
|
|
|
Operating costs. We expect and will pursue
reductions in certain costs as demand for these resources
declines.
|
Results
of operations Gathering and Processing
Gulf
The Gulf segment includes the Carbonate Trend gathering pipeline
and our 60% ownership interest in Discovery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Segment revenues
|
|
$
|
2,096
|
|
|
$
|
2,119
|
|
|
$
|
2,656
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
1,668
|
|
|
|
1,875
|
|
|
|
1,660
|
|
Depreciation, amortization and accretion
|
|
|
751
|
|
|
|
1,249
|
|
|
|
1,200
|
|
General and administrative expense direct
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Other, net
|
|
|
6,187
|
|
|
|
10,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
8,606
|
|
|
|
13,530
|
|
|
|
2,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating loss
|
|
|
(6,510
|
)
|
|
|
(11,411
|
)
|
|
|
(205
|
)
|
Discovery investment income
|
|
|
22,357
|
|
|
|
28,842
|
|
|
|
18,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
15,847
|
|
|
$
|
17,431
|
|
|
$
|
17,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carbonate
Trend
2008 vs.
2007
Segment operating loss improved $4.9 million because
the impairment loss recognized on the Carbonate Trend assets was
$4.2 million lower in 2008 than in 2007. (See Note 7,
Other (Income) Expense, of our Notes to Consolidated Financial
Statements.)
60
2007 vs.
2006
Segment operating loss increased $11.2 million due
primarily to a $10.4 million impairment of the Carbonate
Trend pipeline recognized in 2007. (See Note 7, Other
(Income) Expense, of our Notes to Consolidated Financial
Statements.)
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Revenues
|
|
$
|
241,248
|
|
|
$
|
260,672
|
|
|
$
|
197,313
|
|
Costs and expenses, including interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
146,998
|
|
|
|
155,704
|
|
|
|
119,552
|
|
Operating and maintenance expense
|
|
|
36,670
|
|
|
|
28,988
|
|
|
|
23,049
|
|
Depreciation and accretion
|
|
|
21,324
|
|
|
|
25,952
|
|
|
|
25,562
|
|
General and administrative expense
|
|
|
4,500
|
|
|
|
2,280
|
|
|
|
2,150
|
|
Interest income
|
|
|
(650
|
)
|
|
|
(1,799
|
)
|
|
|
(2,404
|
)
|
Other (income) expense, net
|
|
|
(1,994
|
)
|
|
|
1,476
|
|
|
|
(679
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
206,848
|
|
|
|
212,601
|
|
|
|
167,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
34,400
|
|
|
$
|
48,071
|
|
|
$
|
30,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest
|
|
$
|
20,641
|
|
|
$
|
28,842
|
|
|
$
|
18,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 vs.
2007
Revenues decreased $19.4 million, or 7%, due
primarily to $13.1 million lower product sales described
below and $8.0 million lower fee-based gathering,
processing, fractionation and transportation revenue resulting
from third and fourth quarter lost revenues in the aftermath of
Hurricanes Ike and Gustav. The lower product sales revenues are
due primarily to:
|
|
|
|
|
$21.5 million lower sales of NGLs on behalf of third-party
producers as a result of the hurricanes which is offset by lower
associated product costs of $21.5 million discussed below.
|
|
|
|
$16.8 million decrease from lower NGL volumes processed
under keep-whole and percent-of-liquids arrangements, including
lower NGL volumes following Hurricanes Ike and Gustav.
|
These decreases were partially offset by $26.3 million
higher product sales from higher average NGL sales prices
realized on sales of NGLs which Discovery received under certain
processing contracts.
Product cost and shrink replacement decreased
$8.7 million, or 6%, due primarily to a $21.5 million
decrease in product purchased from third-party producers as a
result of the impact of the hurricanes, partially offset by
$15.9 million from higher average natural gas prices.
Operating and maintenance expense increased
$7.7 million, or 27%, due primarily to 2008 hurricane
survey and repair costs on the gathering system damaged by
Hurricane Ike that are not recoverable from insurance.
Depreciation and accretion decreased $4.6 million,
or 18%, due primarily to a change in the estimated remaining
useful lives of the Larose processing plant and the regulated
pipeline and gathering system.
General and administrative expense increased
$2.2 million, or 97%, due to an increase in
Discoverys management fee charged by Williams.
61
Other (income) expense, net improved $3.5 million
due to a recently approved Federal Energy Regulatory Commission
(FERC) settlement filing that allowed the 2008 reversal of a
$3.5 million reserve for system fuel and lost and
unaccounted for gas related to 1998 through 2003.
Net income decreased $13.7 million, or 28%, due
primarily to $8.0 million lower fee-based gathering,
processing, fractionation and transportation revenue resulting
from third and fourth quarter lost revenues in the aftermath of
Hurricanes Ike and Gustav, $7.7 million higher operating
and maintenance expense and $5.4 million lower NGL sales
margins, slightly offset by $4.6 million lower depreciation
and accretion expense.
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.
Product sales increased $73.8 million primarily due to a
$36.8 million increase in NGL sales volumes received under
certain processing contracts, including an October 2006 TETCO
percent-of-liquids processing agreement, $26.2 million from
higher average NGL prices and an $8.1 million increase in
NGL sales related to processing customers elections to
have Discovery purchase their NGLs.
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 and $7.8 million higher product
purchase costs for the processing customers who elected to have
Discovery purchase their NGLs.
Operating and maintenance expense increased
$5.9 million, or 26%, due primarily to higher property
insurance premiums related to increased hurricane activity in
the Gulf Coast region in prior years and other costs related to
decommissioning two pipelines.
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 prices, partially
offset by $9.9 million lower fee-based transportation,
gathering, processing and fractionation revenues and
$5.9 million higher operating and maintenance expense.
Outlook
for 2009
|
|
|
|
|
Gross processing margins. We expect
significantly lower cash distributions from Discovery in 2009
compared to 2008 primarily as a result of lower
per-unit NGL
margins. As evidenced by recent events, NGL, crude and natural
gas prices are highly volatile. NGL price changes have
historically tracked with changes in the price of crude oil,
however ethane prices have recently disassociated from crude
prices. As NGL prices, especially ethane, have declined,
Discovery is experiencing significantly lower gross processing
margins in 2009 compared to 2008. We anticipate periods when it
is not economical to recover ethane, which will reduce
Discoverys margins.
|
|
|
|
Plant inlet volumes. Discoverys Larose
gas processing plant is currently processing approximately 400
BBtu/d from all sources and we expect this volume to be similar
through the first quarter due to the current unfavorable
economic processing environment. This represents a decrease from
the 600 BBtu/d being processed prior to Hurricanes
Gustav and Ike in 2008. Throughout the pipeline repair period,
Discovery continued to process approximately 200 BBtu/d of
on-shore gas from third-party pipelines. In the late third
quarter of 2009, we expect ATP Oil and Gas Corporation will
begin
|
62
|
|
|
|
|
delivering volumes of approximately 30 BBtu/d from the dedicated
blocks in their Gomez prospect and their Mirage and Morgas
prospects.
|
|
|
|
|
|
Hurricane Damage Impact. We expect little, if
any, ongoing impact beyond February 2009 from the 2008
hurricanes. Discoverys
30-inch
mainline gathering system was repaired and returned to service
in mid-January 2009. We expect business interruption insurance
to largely mitigate lost profits associated with outages beyond
the 60-day
deductible period which ended in 2008.
|
|
|
|
First Quarter Discovery Distribution. As a
result of lower margins and reduced volumes flowing through
Discoverys offshore gathering system in the first quarter
of 2009, we do not expect to receive a cash distribution in
April 2009 from Discoverys first-quarter 2009 operating
cash flows.
|
|
|
|
Tahiti Production. Discovery expects to begin
receiving revenues from its Tahiti pipeline lateral by the third
quarter of 2009 based on Chevrons announcement regarding
expected timing of first production. Any delays Chevron
experiences in bringing their production online will further
impact the initial timing of revenues for Discovery. Discovery
expects approximately 50 BBtu/d from Tahiti.
|
|
|
|
Other new supplies. During 2009, Discovery
expects to add approximately 75 BBtu/d of throughput volumes
from the Clipper, Daniel Boone, Pegasus, Valley Forge and
Yosemite prospects.
|
|
|
|
Operating costs. As a result of the damage
caused by the 2008 hurricanes, Discovery expects a significant
increase in property damage insurance premiums in 2009.
|
Results
of operations NGL Services
The NGL Services segment includes our three NGL storage
facilities near Conway, Kansas and our 50% undivided interest in
the Conway fractionator.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Segment revenues
|
|
$
|
74,826
|
|
|
$
|
56,911
|
|
|
$
|
58,441
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost
|
|
|
16,886
|
|
|
|
11,264
|
|
|
|
15,511
|
|
Operating and maintenance expense
|
|
|
27,520
|
|
|
|
24,686
|
|
|
|
28,791
|
|
Depreciation and accretion
|
|
|
3,063
|
|
|
|
3,720
|
|
|
|
2,437
|
|
General and administrative expense direct
|
|
|
2,582
|
|
|
|
2,190
|
|
|
|
1,149
|
|
Other, net
|
|
|
737
|
|
|
|
746
|
|
|
|
719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
50,788
|
|
|
|
42,606
|
|
|
|
48,607
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
24,038
|
|
|
$
|
14,305
|
|
|
$
|
9,834
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 vs.
2007
Segment revenues increased $17.9 million, or 31%,
due primarily to higher fractionation, product sales and storage
revenues. The significant components of the revenue fluctuations
are addressed more fully below.
|
|
|
|
|
Fractionation revenues increased $7.8 million due primarily
to a 59% higher average fractionation rate and 6% higher
volumes. The higher average rate is due primarily to the
December 2007 expiration of a fractionation contract with a cap
on the
per-unit
fee, which limited our ability to pass through increases in
fractionation fuel expense to this customer.
|
|
|
|
Product sales increased $5.4 million due to higher sales
volumes and an increase in average product sales prices. This
increase was slightly offset by the related increase in product
cost discussed below.
|
|
|
|
Storage revenues increased $3.4 million due primarily to
higher storage revenues from new storage leases.
|
63
Product cost increased $5.6 million, or 50%, due to
the higher product sales volumes and prices discussed above.
Operating and maintenance expense increased
$2.8 million, or 11%, due primarily to $4.0 million
unfavorable storage product losses, $2.5 million higher
maintenance costs and $1.3 million higher fractionation
fuel costs. These increases were partially offset by a
$2.9 million product imbalance adjustment in 2008 and
$2.0 million of fractionation blending gains.
Segment profit increased $9.7 million, or 68%, due
primarily to higher fractionation and storage revenues,
partially offset by higher operating and maintenance expenses.
2007 vs.
2006
Segment revenues decreased $1.5 million, or 3%, due
primarily to $4.7 million lower product sales revenues and
a $2.1 million decrease in fractionation revenues resulting from
lower volumes and rates, partially offset by $2.8 million
higher storage revenues and $2.5 million higher product
upgrade fee revenues.
Product cost decreased $4.2 million, or 27%, due to
the lower product sales volumes.
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.
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.
Segment profit increased $4.5 million, or 45%, due
primarily to higher storage and product upgrade fee revenues and
lower repair and maintenance costs. These increases were
partially offset by higher depreciation and accretion expense
and higher general and administrative expense.
Outlook
for 2009
|
|
|
|
|
We expect 2009 storage revenues will remain approximately
consistent with 2008 due to continued strong demand for propane
and natural gasoline 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 2009 to ensure that we
meet the regulatory compliance requirements.
|
Financial
Condition and Liquidity
The global recession and resulting drop in demand and prices for
NGLs has significantly reduced the profitability and cash flows
of our gathering and processing businesses including Four
Corners, Wamsutter and Discovery. We expect low NGL margins
during 2009 and periods when it is not economical to recover
ethane, which will further reduce our margins. As a result, we
expect cash flow from operations, including cash distributions
from Wamsutter and Discovery, to be significantly lower in 2009
than 2008. While our goal is to maintain the current level of
distributions, we may need to reduce distributions if energy
prices and margins decline further or remain at low levels for a
prolonged period of time,
and/or if
other unexpected events adversely affect cash flows.
Additionally, the recent instability in financial markets has
created global concerns about the liquidity of financial
institutions and is having overarching impacts on the economy as
a whole. However, we have no debt maturities until 2011, and as
of February 23, 2009, we have approximately
$70.0 million of cash and cash equivalents and
$208 million of available capacity under our credit
facilities. The availability of the capacity under the credit
facilities may be restricted under certain circumstances as
discussed below under Credit Facilities.
Therefore, we believe we have the financial resources and
liquidity necessary to meet requirements for working capital,
capital and investment expenditures, debt service and quarterly
cash distributions.
64
We anticipate our more significant sources of liquidity
will include:
|
|
|
|
|
Cash and cash equivalents on hand;
|
|
|
|
Cash generated from operations, including cash distributions
from Wamsutter and Discovery; and
|
|
|
|
Credit facilities, as needed and available.
|
We anticipate our more significant liquidity requirements
to be:
|
|
|
|
|
Maintenance and expansion capital expenditures for our Four
Corners and Conway assets;
|
|
|
|
Contributions we must make to Wamsutter to fund certain of its
capital expenditures;
|
|
|
|
Cash calls from Discovery for hurricane damage repairs, which
generally should be reimbursed by insurance;
|
|
|
|
Interest on our long-term debt; and
|
|
|
|
Quarterly distributions to our unitholders.
|
Additionally, we plan to continue pursuing select value-adding
growth opportunities in a prudent manner.
Available Liquidity at December 31, 2008 (in
millions):
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
116.2
|
|
Available capacity under our $450 million five-year senior
unsecured credit facility(1)
|
|
|
188.0
|
|
Available capacity under our $20 million revolving credit
facility with Williams as lender
|
|
|
20.0
|
|
|
|
|
|
|
Total
|
|
$
|
324.2
|
|
|
|
|
|
|
|
|
|
(1) |
|
The original amount has been reduced by $12.0 million due
to the bankruptcy of the parent company and certain affiliates
of Lehman Brothers Commercial Bank (Lehman). See Note 10,
Long-Term Debt, Credit Facilities and Leasing Activities, of our
Notes to Consolidated Financial Statements. The committed
amounts of other participating banks under this agreement remain
in effect and are not impacted by this reduction. Additionally,
availability of our capacity under this credit facility in
future periods could be constrained by compliance with required
covenants. |
These liquidity sources and cash requirements are discussed in
greater detail below.
Wamsutter
Distributions
Wamsutter expects to make quarterly distributions of available
cash to its members pursuant to the terms of its limited
liability company agreement. 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
has made the following distributions to its members for 2008
(all amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our Share
|
|
|
|
|
Date of Distribution
|
|
Total Distribution to Members
|
|
|
Class A
|
|
|
Class C
|
|
|
Other Class C
|
|
|
3/28/08
|
|
$
|
25,000
|
|
|
$
|
17,876
|
|
|
$
|
3,562
|
|
|
$
|
3,562
|
|
6/30/08
|
|
|
30,500
|
|
|
|
18,150
|
|
|
|
6,175
|
|
|
|
6,175
|
|
9/30/08
|
|
|
35,500
|
|
|
|
18,400
|
|
|
|
8,550
|
|
|
|
8,550
|
|
12/30/08
|
|
|
20,000
|
|
|
|
17,624
|
|
|
|
1,188
|
|
|
|
1,188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
111,000
|
|
|
$
|
72,050
|
|
|
$
|
19,475
|
|
|
$
|
19,475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We expect significantly lower cash distributions from our
Wamsutter investment as a result of sharply lower expected NGL
margins in 2009.
65
See Note 6, Equity Investments, of our Notes to
Consolidated Financial Statements for a description of how
Wamsutter distributes its available cash. Generally, as holder
of the Class A membership interests we are entitled to the
first $17.5 million that Wamsutter distributes each quarter.
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
2008-2009
distributions to its members (all amounts in thousands):
|
|
|
|
|
|
|
|
|
Date of Distribution
|
|
Total Distribution to Members
|
|
Our 60% Share
|
|
1/30/08
|
|
$
|
28,000
|
|
|
$
|
16,800
|
|
4/30/08
|
|
$
|
26,000
|
|
|
$
|
15,600
|
|
7/30/08
|
|
$
|
22,000
|
|
|
$
|
13,200
|
|
10/30/08
|
|
$
|
18,000
|
|
|
$
|
10,800
|
|
1/30/09
|
|
$
|
|
|
|
$
|
|
|
As a result of disruptions and damage from Hurricanes Gustav and
Ike, Discovery did not make a distribution for the fourth
quarter of 2008 in January 2009. We also expect significantly
lower cash distributions from our Discovery investment as a
result of sharply lower expected NGL margins in 2009.
Insurance
Recoveries
On September 13, 2008, Hurricane Ike hit the Gulf Coast
area, and Discoverys offshore gathering system sustained
damage. Inspections revealed that an
18-inch
lateral was severed from its connection to the
30-inch
mainline in 250 feet of water. The estimated total cost to
repair the gathering system is approximately $60.5 million,
including $52.1 million in potentially reimbursable
expenditures in excess of the insurance deductible and
$2.0 million in unreimbursable expenditures. Of the total
amount, $33.5 million has been incurred through
December 31, 2008. Discovery funded the $6.4 million
deductible amount with cash on hand and filed for and received a
prepayment of $23.6 million from the insurance provider.
Repair costs in excess of the deductible, net of any insurance
prepayments, may be funded with cash calls from its members,
including us. Once Discovery receives the related insurance
proceeds, it will make special distributions back to its
members. We have filed for reimbursement from our insurance
carrier for lost profits under our Discovery-related business
interruption policy, which has a
60-day
deductible period, and have received $4.4 million to date.
Credit
Facilities
We have a $200.0 million revolving credit facility with
Citibank, N.A. as administrative agent available for borrowings
and letters of credit. The parent company and certain affiliates
of Lehman, who is committed to fund up to $12.0 million of
our revolving credit facility, have filed for bankruptcy. We
expect that our ability to borrow under this facility is reduced
by this committed amount. The committed amounts of other
participating banks under this agreement remain in effect and
are not impacted by this reduction. Borrowings under this
agreement must be repaid on or before December 11, 2012.
There were no amounts outstanding at December 31, 2008
under the revolving credit facility.
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, or make distributions or other payments other than
distributions of available cash under certain conditions.
Significant financial covenants under the credit agreement
include the following:
|
|
|
|
|
We 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 fiscal quarter
in which the acquisition occurs and three fiscal quarter-periods
following such acquisition. At
|
66
|
|
|
|
|
December 31, 2008, our ratio of consolidated indebtedness
to the consolidated EBITDA, as calculated under this covenant,
of approximately 2.98 is in compliance with this covenant.
|
|
|
|
|
|
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
agency is not less than Ba1 or BB+, as applicable. At
December 31, 2008, our ratio of consolidated EBITDA to
consolidated interest expense, as calculated under this
covenant, of approximately 5.13 is in compliance with this
covenant.
|
Although it is difficult to predict future commodity pricing, we
expect to remain in compliance with the credit agreement ratios
described above throughout 2009 given the current energy
commodity price and NGL margin environment. Inasmuch as the
ratios are calculated on a rolling four-quarter basis, the
ratios at December 31, 2008, do not reflect a full-year
impact of the lower earnings we experienced in the fourth
quarter of 2008. If unexpected events happen or economic
conditions or energy commodity prices and NGL margins decline
further for a prolonged period of time, our financial covenant
ratios may fall below required levels. If such a situation
appeared likely, we would take actions necessary to avoid a
breach of our covenants, including seeking covenant relief
through waivers or the restructuring or replacement of our
facility, reducing our indebtedness or seeking assistance from
our general partner. Market conditions could make these
alternatives challenging, and no assurances can be given that we
would be successful in our efforts. Even if successful, we could
experience increased borrowing costs and reduced liquidity which
could limit our ability to fund capital expenditures and make
cash distributions to unitholders. In the event that despite our
efforts we breach our financial covenants causing an event of
default, the lenders could, among other things, accelerate the
maturity of any borrowings under the facility (including our
$250 million term loan) and terminate their commitments to
lend.
In addition, our ability to borrow the remaining
$188 million currently available under the credit facility
could be restricted by the impact of weaker energy commodity
prices or future borrowings. Either could limit our ability to
borrow the full amount under the credit agreement because
incremental future borrowings are only permitted if the
financial ratios would be met when calculated with the inclusion
of the new borrowing.
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 and have
reduced 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. Borrowings
under the credit facility mature on June 20, 2009 and bear
interest at the one-month LIBOR. As of December 31, 2008,
we had no outstanding borrowings under the working capital
credit facility.
Wamsutter has a $20.0 million revolving credit facility
with Williams as the lender. The credit facility is available
exclusively to fund Wamsutters working capital
requirements. Borrowings under the credit facility mature on
December 12, 2009 with four, one-year automatic extensions
unless terminated by either party. Wamsutter pays a commitment
fee to Williams on the unused portion of the credit facility of
0.125% annually. Interest on any borrowings under the facility
will be calculated upon a periodic fixed rate equal to LIBOR
plus an applicable margin, or a base rate plus the applicable
margin. As of December 31, 2008, Wamsutter had no
outstanding borrowings under the credit facility.
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 9, 2007
|
|
Stable
|
|
BBB-
|
Moodys Investor Service
|
|
November 6, 2008
|
|
Negative
|
|
Ba2
|
Fitch Ratings
|
|
May 8, 2008
|
|
Stable
|
|
BB+
|
67
At December 31, 2008, the evaluation of our credit rating
is stable outlook from Standard and Poors and
Fitch Ratings agencies. On November 6, 2008, Moodys
Investors Service (Moodys) changed the ratings outlook for
Williams and each of Williams rated subsidiaries,
including WPZ, from stable to negative
following the announcement that Williams management and
board of directors were evaluating a variety of structural
changes to Williams. On February 26, 2009, Moodys
revised Williams, and certain Williams rated subsidiaries,
excluding us, to stable from negative.
With respect to Moodys, a rating of Baa or
above indicates an investment grade rating. A rating below
Baa is considered to have speculative elements. A
Ba rating indicates an obligation that is judged to
have speculative elements and is subject to substantial credit
risk. The 1, 2 and 3
modifiers show the relative standing within a major category. A
1 indicates that an obligation ranks in the higher
end of the broad rating category, 2 indicates a
mid-range ranking, and 3 indicates a ranking at the
lower end of the category.
With respect to Standard and Poors, a rating of
BBB or above indicates an investment grade rating. A
rating below BBB indicates that the security has
significant speculative characteristics. A BB rating
indicates that Standard and Poors believes the issuer has
the capacity to meet its financial commitment on the obligation,
but adverse business conditions could lead to insufficient
ability to meet financial commitments. Standard and Poors
may modify its ratings with a + or a -
sign to show the obligors relative standing within a major
rating category.
With respect to Fitch, a rating of BBB or above
indicates an investment grade rating. A rating below
BBB is considered speculative grade. A
BB rating from Fitch indicates that there is a
possibility of credit risk developing, particularly as the
result of adverse economic change over time; however, business
or financial alternatives may be available to allow financial
commitments to be met. Fitch may add a + or a
- sign to show the obligors relative standing
within a major rating category.
Credit rating agencies perform independent analyses when
assigning credit ratings. No assurance can be given that the
credit rating agencies will assign us investment grade ratings
even if we meet or exceed their current criteria for investment
grade ratios. A downgrade of our credit rating might increase
our future cost of borrowing.
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,
including certain well connection expenditures, and to extend
their useful lives including expenditures which are mandatory
and/or
essential for maintaining the reliability of our
operations; and
|
|
|
|
Expansion capital expenditures, which tend to be more
discretionary than maintenance capital expenditures, include
expenditures 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.
|
Actual and estimated capital expenditures for the years ending
December 31, 2008 and 2009, respectively, are as follows
(all amounts in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual Expenditures
|
|
|
|
|
December 31, 2008
|
|
Estimated Expenditures for 2009
|
Company
|
|
Maintenance
|
|
Expansion
|
|
Total
|
|
Maintenance
|
|
Expansion
|
|
Total
|
|
Four Corners
|
|
$
|
18.9
|
|
|
$
|
3.7
|
|
|
$
|
22.6
|
|
|
$15 20
|
|
$
|
5 10
|
|
|
$20 30
|
Conway
|
|
|
2.9
|
|
|
|
6.1
|
|
|
|
9.0
|
|
|
3 6
|
|
|
8 12
|
|
|
11 18
|
Wamsutter (our share)
|
|
|
21.4
|
|
|
|
3.5
|
|
|
|
24.9
|
|
|
20 25
|
|
|
|
|
|
20 25
|
Discovery (our share)
|
|
|
0.7
|
|
|
|
9.0
|
|
|
|
9.7
|
|
|
1 3
|
|
|
1 3
|
|
|
2 6
|
68
The table above does not include capital expenditures related to
the replacement of capital assets destroyed by the November 2007
fire at Four Corners Ignacio gas processing plant nor
repairs to Discoverys offshore-gathering system damaged by
Hurricane Ike. We expect those expenditures that exceed the
property insurance deductible will be reimbursed by insurance.
Our 2008 Statement of Cash Flows includes $14.3 million of
these reimbursed or reimbursable capital expenditures for the
Ignacio plant.
We expect to fund Four Corners and Conways
maintenance and expansion capital expenditures with cash flows
from operations. Four Corners estimated maintenance
capital expenditures for 2009 include a range of
$12.0 million to $14.0 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. Four Corners actual
maintenance expenditures for 2008 have been reduced
$3.5 million for amounts reimbursed by producers for
prior-year well connect costs. Conways expansion capital
expenditures relate to two projects: first, the drilling of five
new ethane/propane mix caverns and conversion of certain
ethane/propane caverns for use as propane storage caverns and
second, the completion of a project to improve our flexibility
and storage capabilities with respect to refinery grade butane.
Wamsutters estimated maintenance capital expenditures for
2009 include a range of $20.0 million to $22.0 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. Wamsutter
will issue Class C units to us for the expansion capital
projects we fund.
Discovery will fund its maintenance and expansion capital
expenditures either by cash calls to its members or from its
cash flows from operations. We expect that Discovery will cash
call us for $4.2 million in February 2009 for the Tahiti
project and we expect to receive a $1.8 million
reimbursement of those costs pursuant to the requirements of our
omnibus agreement with Williams. Also, we expect that in 2009,
Discovery may cash call us for up to $6.3 million for
repair costs on the offshore-gathering system damaged by
Hurricane Ike. We expect to be reimbursed by Discovery after it
receives the property insurance proceeds.
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.
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.
We have a $250.0 million floating-rate term loan
outstanding under a $450.0 million senior unsecured credit
agreement with Citibank, N.A. as administrative agent. As
previously discussed in Credit Facilities, we also
have a revolving credit facility under this same credit
agreement. 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 $41.6 million was paid on February 13,
2009 to the general partner interest and common and subordinated
unitholders of record at the close of business on
February 6, 2009. This distribution included an incentive
distribution to our general partner of approximately
$7.3 million. As previously disclosed, sustained lower NGL
margins, which are
69
significantly reducing our profitability and cash flows, could
result in a reduction in our cash distribution to unitholders.
Results
of Operations Cash Flows
Williams
Partners L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
(In thousands)
|
|
Net cash provided by operating activities
|
|
$
|
247,390
|
|
|
$
|
179,104
|
|
|
$
|
169,450
|
|
Net cash used by investing activities
|
|
|
(15,097
|
)
|
|
|
(385,871
|
)
|
|
|
(624,213
|
)
|
Net cash provided (used) by financing activities
|
|
|
(152,325
|
)
|
|
|
185,423
|
|
|
|
505,465
|
|
Net cash
provided by operating activities:
Net cash provided by operating activities increased
$68.3 million in 2008 as compared to 2007 due primarily to
$95.9 million higher distributions related to our Wamsutter
ownership interests purchased in December 2007 and
$9.8 million higher operating income excluding non-cash
items.
Partially offsetting these increases was an additional
$26.7 million of interest paid due primarily to our
$250.0 million term loan issued in December 2007 and timing
of interest payments on our $600.0 million senior unsecured
notes. Additionally, distributions related to our Discovery
investment decreased $5.6 million and changes in working
capital excluding accrued interest decreased $5.0 million.
Net cash provided by operating activities increased
$9.7 million in 2007 as compared to 2006 due primarily to
$40.2 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
$17.8 million in higher accounts payable between periods.
We also had $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.
Net cash
used by investing activities:
Net cash used by investing activities in 2008 includes
$14.3 million of capital expenditures for the replacement
of capital assets destroyed by the November 2007 fire at Four
Corners Ignacio gas processing plant, partially offset by
$13.1 million of related insurance proceeds. Additionally,
net cash used by investing activities in 2008, 2007 and 2006
includes maintenance and expansion capital expenditures and
related change in accrued liabilities.
Net cash used by investing activities in 2007 also 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.
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
provided (used) by financing activities:
Net cash used by financing activities in 2008 includes
distributions to unitholders and our general partner of
$155.4 million.
70
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
interests less the related amounts distributed to Williams in
excess of Wamsutters contributed basis and
$87.3 million of distributions to unitholders and our
general partner.
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. It also includes a
$114.5 million pass through of Four Corners net cash
flows to Williams under the cash management program in place
prior to the purchase of Four Corners by us and
$25.5 million of contributions from our general partner,
partially offset by $30.0 million of distributions to
unitholders and our general partner.
Wamsutter
100%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
(In thousands)
|
|
Net cash provided by operating activities
|
|
$
|
133,641
|
|
|
$
|
85,541
|
|
|
$
|
75,641
|
|
Net cash used by investing activities
|
|
|
(57,539
|
)
|
|
|
(31,624
|
)
|
|
|
(36,040
|
)
|
Net cash used by financing activities
|
|
|
(76,102
|
)
|
|
|
(53,917
|
)
|
|
|
(39,601
|
)
|
Net cash provided by operating activities increased
$48.1 million from 2008 to 2007 due primarily to a
$27.7 million increase in operating income, as adjusted for
non-cash expenses, and a $20.4 million increase in cash
provided primarily by changes in accounts receivable.
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.
Net cash used by investing activities in 2008 is
primarily comprised of capital expenditures related to plant
expansion projects and connection of new wells. Net cash used by
investing activities in 2007 and 2006 is primarily comprised of
capital expenditures related to the connection of new wells.
Net cash used by financing activities for 2008 is almost
entirely related to cash distributions to Wamsutters
members pursuant to the distribution provisions of
Wamsutters limited liability company agreement. Net cash
used by financing activities in 2007 and 2006 is primarily
distributions of Wamsutters net cash flows to Williams
pursuant to its participation in Williams cash management
program.
Discovery
100%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
(In thousands)
|
|
Net cash provided by operating activities
|
|
$
|
91,654
|
|
|
$
|
62,092
|
|
|
$
|
63,456
|
|
Net cash used by investing activities
|
|
|
(7,187
|
)
|
|
|
(5,914
|
)
|
|
|
(17,162
|
)
|
Net cash used by financing activities
|
|
|
(80,924
|
)
|
|
|
(55,252
|
)
|
|
|
(30,089
|
)
|
Net cash provided by operating activities increased
$29.6 million in 2008 as compared to 2007 due primarily to
a $49.1 million increase in cash provided by working capital
changes resulting from the impact of the hurricanes, partially
offset by $18.7 million lower net income as adjusted for
non-cash items.
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 used by investing activities includes
$9.9 million, $29.1 million and $32.9 million of
capital spending in 2008, 2007 and 2006, respectively. The 2008
expenditures were for the Tahiti lateral and other smaller
projects. The 2007 and 2006 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.
71
Net cash used by financing activities include normal cash
distributions to Discoverys members of $94.0 million,
$59.2 million and $43.6 million in 2008, 2007 and
2006, respectively. Net cash used by financing activities in
2008 also includes $13.1 million of capital contributions
from Discoverys members for the Tahiti pipeline lateral
expansion, other capital expansion projects and hurricane damage
repair. Net cash used by financing activities in 2006 includes
$13.5 million of capital contributions related to the
Tahiti pipeline lateral expansion.
Contractual
Obligations
A summary of our contractual obligations as of December 31,
2008, is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010-2011
|
|
|
2012-2013
|
|
|
2014+
|
|
|
Total
|
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal
|
|
$
|
|
|
|
$
|
150,000
|
|
|
$
|
250,000
|
|
|
$
|
600,000
|
|
|
$
|
1,000,000
|
|
Interest
|
|
|
67,804
|
(a)
|
|
|
130,014
|
|
|
|
99,517
|
|
|
|
152,250
|
|
|
|
449,585
|
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases(b)
|
|
|
1,357
|
|
|
|
1,276
|
|
|
|
90
|
|
|
|
|
|
|
|
2,723
|
|
Purchase obligations
|
|
|
15,958
|
(c)
|
|
|
240
|
|
|
|
240
|
|
|
|
120
|
(d)
|
|
|
16,558
|
|
Other long term liabilities(e)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
85,119
|
|
|
$
|
281,530
|
|
|
$
|
349,847
|
|
|
$
|
752,370
|
|
|
$
|
1,468,866
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The assumed interest rate on our $250.0 million term loan
is based on the forecasted forward LIBOR plus the applicable
margin. |
|
(b) |
|
Subsequent to year end, we entered into a
20-year
right-of-way agreement with the JAN, which is considered an
operating lease. We are required to make a fixed payment of
$7.5 million annually and an additional annual payment,
which varies depending on
per-unit NGL
margins and the volume of gas gathered by our gathering
facilities subject to the right-of-way agreement. The table
above does not include any amounts related to this agreement. |
|
(c) |
|
Includes the open purchase orders as of December 31, 2008
to be paid in 2009. |
|
(d) |
|
Year 2014 represents one year of payments associated with an
operating agreement whose term is tied to the life of the
underlying gas reserves. |
|
(e) |
|
Subsequent to year end, we entered into a five-year agreement
for compression services. Payments under this agreement will
vary depending upon the extent and amount of compression
services needed to meet producer service requirements. The table
above does not include any amounts related to this agreement,
which are estimated to be approximately $24.0 million
annually. |
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, 2008, is
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010-2011
|
|
|
2012-2013
|
|
|
2014+
|
|
|
Total
|
|
|
Notes payable/long-term debt
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
1,362
|
|
|
|
1,429
|
|
|
|
50
|
|
|
|
10
|
|
|
|
2,851
|
|
Purchase obligations(a)
|
|
|
74,058
|
|
|
|
47,313
|
|
|
|
|
|
|
|
|
|
|
|
121,371
|
|
Other long-term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
75,420
|
|
|
$
|
48,742
|
|
|
$
|
50
|
|
|
$
|
10
|
|
|
$
|
124,222
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes the open purchase orders as of December 31, 2008
to be paid in 2009 and 2010. This amount includes large growth
projects of $120.0 million that will be funded by
contributions from Wamsutters Class B membership,
which we do not own. |
72
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, 2008, is
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010-2011
|
|
|
2012-2013
|
|
|
2014+
|
|
|
Total
|
|
|
Notes payable/long-term debt
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
1,241
|
|
|
|
2,482
|
|
|
|
2,482
|
|
|
|
2,105
|
|
|
|
8,310
|
|
Purchase obligations
|
|
|
7,917
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,917
|
|
Other long-term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
9,158
|
|
|
$
|
2,482
|
|
|
$
|
2,482
|
|
|
$
|
2,105
|
|
|
$
|
16,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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. A significant portion 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 and some
gathering are subject to rate regulation by the FERC under the
Natural Gas Act. For more information on federal and state
regulations affecting our business, please read Risk
Factors and FERC Regulation elsewhere in this
report.
Environmental
We are a participant in certain hydrocarbon removal and
groundwater monitoring activities associated with certain well
sites in New Mexico. Of nine remaining active sites, product
removal is ongoing at four 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 seven years. As of
December 31, 2008, we had accrued liabilities totaling
$1.5 million for these environmental activities. Actual
costs incurred will depend on the actual number of contaminated
sites identified, the amount and extent of contamination
discovered, the final cleanup standards mandated by governmental
authorities and other factors.
Our Conway storage facilities are subject to strict
environmental regulation by the Kansas Department of Health and
Environment (KDHE) under the Underground Hydrocarbon and Natural
Gas 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.
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
73
continue to coordinate with the 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
six years. Under an omnibus agreement with Williams entered into
at the closing of the IPO, Williams agreed to indemnify us for
certain remediation expenditures, including Conway plumes and
required wellhead control equipment and well meters. At
December 31, 2008, approximately $7.3 million remains
available for this indemnification. We had accrued liabilities
totaling $3.3 million for these costs at December 31,
2008. 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
$19.9 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 completed the project, began during 2005 and was
completed in October 2008.
|
|
Item 7A.
|
Qualitative
and Quantitative Disclosures About Market Risk
|
Market risk is the risk of loss arising from adverse changes in
market rates and prices. The principal market risks to which we
are exposed are commodity price risk and interest rate risk.
Commodity
Price Risk
We are exposed to the impact of fluctuations in the market price
of NGLs 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. In 2007 and 2008, we managed a portion of the risks
associated with these market fluctuations using various
derivative contracts. All of our derivatives expired as of
December 31, 2008.
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.
74
The tables below provide information about our interest
rate-sensitive instruments as of December 31, 2008 and
2007. 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
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
December 31,
|
|
|
2011
|
|
2012
|
|
2017
|
|
Total
|
|
2008
|
|
2007
|
|
|
(Dollars in millions)
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate
|
|
$
|
150.0
|
|
|
$
|
|
|
|
$
|
600.0
|
|
|
$
|
750.0
|
|
|
$
|
591.9
|
|
|
$
|
777.5
|
|
Interest rate
|
|
|
7.50
|
%
|
|
|
|
|
|
|
7.25
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable rate
|
|
$
|
|
|
|
$
|
250.0
|
|
|
$
|
|
|
|
$
|
250.0
|
|
|
$
|
233.4
|
|
|
$
|
250.0
|
|
Interest rate(1)
|
|
|
|
|
|
|
1.221
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The weighted-average interest rate for 2008 is LIBOR plus
.75 percent. |
75
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
MANAGEMENTS
ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Management 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). Our internal
controls over financial reporting are 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 including the possibility of human error
and the circumvention or overriding of controls. Therefore, even
those systems determined to be effective can provide only
reasonable assurance with respect to financial statement
preparation and presentation.
Under the supervision and with the participation of our
management, including our general partners Chief Executive
Officer and Chief Financial Officer, we assessed the
effectiveness of our internal control over financial reporting
as of December 31, 2008, based on the criteria set forth by
the Committee of Sponsoring Organizations of the Treadway
Commission (COSO) in Internal Control Integrated
Framework. Based on our assessment we believe that, as of
December 31, 2008, our internal control over financial
reporting was effective.
Ernst & Young LLP, our independent registered public
accounting firm, has audited our internal control over financial
reporting, as stated in their report which is included in this
Annual Report on
Form 10-K.
76
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, 2008, 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, 2008, 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, 2008 and 2007, and the related
consolidated statements of income, partners capital, and
cash flows for each of the three years in the period ended
December 31, 2008, and our report dated February 23,
2009 expressed an unqualified opinion thereon.
Tulsa, Oklahoma
February 23, 2009
77
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, 2008 and 2007,
and the related consolidated statements of income,
partners capital, and cash flows for each of the three
years in the period ended December 31, 2008. 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, 2008 and 2007, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2008, in conformity with
U.S. generally accepted accounting principles.
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, 2008, 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 23, 2009 expressed
an unqualified opinion thereon.
Tulsa, Oklahoma
February 23, 2009
78
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
116,165
|
|
|
$
|
36,197
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Trade
|
|
|
16,279
|
|
|
|
12,860
|
|
Affiliate
|
|
|
11,652
|
|
|
|
20,402
|
|
Other
|
|
|
2,919
|
|
|
|
2,543
|
|
Product imbalance
|
|
|
6,344
|
|
|
|
20,660
|
|
Prepaid expenses
|
|
|
4,102
|
|
|
|
4,056
|
|
Reimbursable projects
|
|
|
|
|
|
|
8,989
|
|
Other current assets
|
|
|
3,642
|
|
|
|
3,805
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
161,103
|
|
|
|
109,512
|
|
Investment in Wamsutter
|
|
|
277,707
|
|
|
|
284,650
|
|
Investment in Discovery Producer Services
|
|
|
184,466
|
|
|
|
214,526
|
|
Gross property, plant and equipment
|
|
|
1,265,153
|
|
|
|
1,239,792
|
|
Less accumulated depreciation
|
|
|
(624,633
|
)
|
|
|
(597,503
|
)
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
640,520
|
|
|
|
642,289
|
|
Other noncurrent assets
|
|
|
28,023
|
|
|
|
32,500
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
1,291,819
|
|
|
$
|
1,283,477
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
22,348
|
|
|
$
|
35,947
|
|
Affiliate
|
|
|
11,122
|
|
|
|
17,676
|
|
Product imbalance
|
|
|
8,926
|
|
|
|
21,473
|
|
Deferred revenue
|
|
|
4,916
|
|
|
|
4,569
|
|
Derivative liabilities affiliate
|
|
|
|
|
|
|
2,718
|
|
Accrued interest
|
|
|
18,705
|
|
|
|
19,500
|
|
Other accrued liabilities
|
|
|
6,172
|
|
|
|
8,243
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
72,189
|
|
|
|
110,126
|
|
Long-term debt
|
|
|
1,000,000
|
|
|
|
1,000,000
|
|
Environmental remediation liabilities
|
|
|
2,321
|
|
|
|
2,599
|
|
Other noncurrent liabilities
|
|
|
13,699
|
|
|
|
9,265
|
|
Commitments and contingent liabilities (Note 14)
|
|
|
|
|
|
|
|
|
Partners capital:
|
|
|
|
|
|
|
|
|
Common unitholders (52,777,452 and 45,774,728 units
outstanding at December 31, 2008 and 2007)
|
|
|
1,619,954
|
|
|
|
1,473,814
|
|
Subordinated unitholders (7,000,000 units outstanding at
December 31, 2007)
|
|
|
|
|
|
|
109,542
|
|
Accumulated other comprehensive loss
|
|
|
|
|
|
|
(2,487
|
)
|
General partner
|
|
|
(1,416,344
|
)
|
|
|
(1,419,382
|
)
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
203,610
|
|
|
|
161,487
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
1,291,819
|
|
|
$
|
1,283,477
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands, except per-unit amounts)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
314,299
|
|
|
$
|
267,970
|
|
|
$
|
255,075
|
|
Third-party
|
|
|
24,981
|
|
|
|
22,962
|
|
|
|
16,919
|
|
Gathering and processing:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
37,893
|
|
|
|
35,819
|
|
|
|
42,228
|
|
Third-party
|
|
|
195,056
|
|
|
|
202,775
|
|
|
|
206,432
|
|
Storage
|
|
|
31,429
|
|
|
|
28,016
|
|
|
|
25,237
|
|
Fractionation
|
|
|
17,441
|
|
|
|
9,622
|
|
|
|
11,698
|
|
Other
|
|
|
15,961
|
|
|
|
5,653
|
|
|
|
5,821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
637,060
|
|
|
|
572,817
|
|
|
|
563,410
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
85,372
|
|
|
|
73,475
|
|
|
|
78,201
|
|
Third-party
|
|
|
120,706
|
|
|
|
108,223
|
|
|
|
97,307
|
|
Operating and maintenance expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
76,735
|
|
|
|
61,633
|
|
|
|
53,627
|
|
Third-party
|
|
|
109,166
|
|
|
|
100,710
|
|
|
|
101,587
|
|
Depreciation, amortization and accretion
|
|
|
45,029
|
|
|
|
46,492
|
|
|
|
43,692
|
|
General and administrative expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
44,065
|
|
|
|
42,038
|
|
|
|
34,295
|
|
Third-party
|
|
|
2,994
|
|
|
|
3,590
|
|
|
|
5,145
|
|
Taxes other than income
|
|
|
9,508
|
|
|
|
9,624
|
|
|
|
8,961
|
|
Other (income) expense net
|
|
|
(3,523
|
)
|
|
|
12,095
|
|
|
|
(2,473
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
490,052
|
|
|
|
457,880
|
|
|
|
420,342
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
147,008
|
|
|
|
114,937
|
|
|
|
143,068
|
|
Equity earnings Wamsutter
|
|
|
88,538
|
|
|
|
76,212
|
|
|
|
61,690
|
|
Discovery investment income
|
|
|
22,357
|
|
|
|
28,842
|
|
|
|
18,050
|
|
Interest expense
|
|
|
(67,220
|
)
|
|
|
(58,348
|
)
|
|
|
(9,833
|
)
|
Interest income
|
|
|
706
|
|
|
|
2,988
|
|
|
|
1,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
191,389
|
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income for calculation of earnings per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
191,389
|
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
Allocation of net income to general partner
|
|
|
56,554
|
|
|
|
85,190
|
|
|
|
182,380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income to limited partners
|
|
$
|
134,835
|
|
|
$
|
79,441
|
|
|
$
|
32,195
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted earnings per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
2.55
|
|
|
$
|
1.97
|
|
|
$
|
1.62
|
|
Weighted average number of units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units(a)
|
|
|
52,775,710
|
|
|
|
40,131,195
|
(b)
|
|
|
18,986,368
|
(b)
|
|
|
|
(a) |
|
Includes subordinated units converted to common on
February 19, 2008. |
|
(b) |
|
Includes Class B units converted to common on May 21,
2007. |
See accompanying notes to consolidated financial statements.
80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other
|
|
|
Total
|
|
|
|
|
|
|
Limited Partners
|
|
|
General
|
|
|
Comprehensive
|
|
|
Partners
|
|
|
|
Common
|
|
|
Class B
|
|
|
Subordinated
|
|
|
Partner
|
|
|
Loss
|
|
|
Capital
|
|
|
|
(In thousands)
|
|
|
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
|
|
Net income 2008
|
|
|
163,917
|
|
|
|
|
|
|
|
1,556
|
|
|
|
25,916
|
|
|
|
|
|
|
|
191,389
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized gains on cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,903
|
|
|
|
2,903
|
|
Reclassification into earnings of derivative instrument gains
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(416
|
)
|
|
|
(416
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,487
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
193,876
|
|
Cash distributions
|
|
|
(124,483
|
)
|
|
|
|
|
|
|
(4,025
|
)
|
|
|
(26,874
|
)
|
|
|
|
|
|
|
(155,382
|
)
|
Conversion of subordinated units into common
(7,000,000 units)
|
|
|
107,073
|
|
|
|
|
|
|
|
(107,073
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Contributions pursuant to the omnibus agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,981
|
|
|
|
|
|
|
|
2,981
|
|
Issuance of units to public (800,000 common units)
|
|
|
28,992
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28,992
|
|
Repurchase of units from Williams (800,000 common units)
|
|
|
(28,992
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(28,992
|
)
|
Other
|
|
|
(367
|
)
|
|
|
|
|
|
|
|
|
|
|
1,015
|
|
|
|
|
|
|
|
648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2008
|
|
$
|
1,619,954
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(1,416,344
|
)
|
|
$
|
|
|
|
$
|
203,610
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
191,389
|
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
Adjustments to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, amortization and accretion
|
|
|
45,029
|
|
|
|
46,492
|
|
|
|
43,692
|
|
Provision for loss on property, plant and equipment
|
|
|
6,827
|
|
|
|
11,306
|
|
|
|
|
|
Gain on sale of property, plant and equipment
|
|
|
|
|
|
|
|
|
|
|
(3,055
|
)
|
Amortization of gas purchase contract affiliate
|
|
|
|
|
|
|
4,754
|
|
|
|
5,320
|
|
Gain on involuntary conversion
|
|
|
(11,604
|
)
|
|
|
|
|
|
|
|
|
Equity earnings of Wamsutter
|
|
|
(88,538
|
)
|
|
|
(76,212
|
)
|
|
|
(61,690
|
)
|
Equity earnings of Discovery Producer Services
|
|
|
(20,641
|
)
|
|
|
(28,842
|
)
|
|
|
(18,050
|
)
|
Distributions related to equity earnings of Wamsutter
|
|
|
95,926
|
|
|
|
|
|
|
|
|
|
Distributions related to equity earnings of Discovery Producer
Services
|
|
|
20,641
|
|
|
|
26,240
|
|
|
|
12,033
|
|
Cash provided (used) by changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
4,955
|
|
|
|
11,830
|
|
|
|
(13,564
|
)
|
Prepaid expenses
|
|
|
(46
|
)
|
|
|
(369
|
)
|
|
|
(1,023
|
)
|
Reimbursable projects
|
|
|
8,989
|
|
|
|
(8,989
|
)
|
|
|
|
|
Other current assets
|
|
|
(1,373
|
)
|
|
|
(1,041
|
)
|
|
|
(920
|
)
|
Accounts payable
|
|
|
(8,280
|
)
|
|
|
7,206
|
|
|
|
(10,600
|
)
|
Product imbalance
|
|
|
1,769
|
|
|
|
162
|
|
|
|
(1,114
|
)
|
Accrued liabilities
|
|
|
(2,344
|
)
|
|
|
15,914
|
|
|
|
6,395
|
|
Deferred revenue
|
|
|
59
|
|
|
|
1,709
|
|
|
|
(170
|
)
|
Other, including changes in noncurrent assets and liabilities
|
|
|
4,632
|
|
|
|
4,313
|
|
|
|
(2,379
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
247,390
|
|
|
|
179,104
|
|
|
|
169,450
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
)
|
|
|
|
|
Cumulative distributions in excess of equity earnings of
Wamsutter
|
|
|
3,213
|
|
|
|
|
|
|
|
|
|
Cumulative distributions in excess of equity earnings of
Discovery Producer Services
|
|
|
35,759
|
|
|
|
229
|
|
|
|
4,367
|
|
Capital expenditures
|
|
|
(45,853
|
)
|
|
|
(48,481
|
)
|
|
|
(32,270
|
)
|
Receipt of insurance proceeds
|
|
|
13,140
|
|
|
|
|
|
|
|
|
|
Change in accrued liabilities and accounts payable
capital expenditures
|
|
|
(11,998
|
)
|
|
|
8,704
|
|
|
|
5,078
|
|
Contribution to Wamsutter
|
|
|
(3,658
|
)
|
|
|
|
|
|
|
|
|
Contribution to Discovery Producer Services
|
|
|
(5,700
|
)
|
|
|
|
|
|
|
(1,600
|
)
|
Proceeds from sales of property, plant and equipment
|
|
|
|
|
|
|
|
|
|
|
7,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(15,097
|
)
|
|
|
(385,871
|
)
|
|
|
(624,213
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sales of common units
|
|
|
28,992
|
|
|
|
492,393
|
|
|
|
867,263
|
|
Proceeds from debt issuances
|
|
|
|
|
|
|
250,000
|
|
|
|
750,000
|
|
Redemption of common units from general partner
|
|
|
(28,992
|
)
|
|
|
|
|
|
|
|
|
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
|
)
|
Distributions to The Williams Companies, Inc.
|
|
|
|
|
|
|
|
|
|
|
(114,497
|
)
|
Distributions to unitholders and general partner
|
|
|
(155,382
|
)
|
|
|
(87,281
|
)
|
|
|
(29,994
|
)
|
General partner contributions
|
|
|
|
|
|
|
10,334
|
|
|
|
18,614
|
|
Contributions per omnibus agreement
|
|
|
2,981
|
|
|
|
5,362
|
|
|
|
6,840
|
|
Other
|
|
|
76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities
|
|
|
(152,325
|
)
|
|
|
185,423
|
|
|
|
505,465
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents
|
|
|
79,968
|
|
|
|
(21,344
|
)
|
|
|
50,702
|
|
Cash and cash equivalents at beginning of year
|
|
|
36,197
|
|
|
|
57,541
|
|
|
|
6,839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
116,165
|
|
|
$
|
36,197
|
|
|
$
|
57,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
82
WILLIAMS
PARTNERS L. P.
Unless the context clearly indicates otherwise, references in
this report to we, our, us
or similar language 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 publicly-traded Delaware limited partnership. Williams
Partners GP LLC, a Delaware limited liability company and wholly
owned by The Williams Companies, Inc. (Williams), serves as our
general partner and owns a 2% general partner interest, a 6%
limited partner interest and incentive distribution rights in
the partnership. All of our activities are conducted through
Williams Partners Operating LLC, an operating limited liability
company (wholly owned by us).
|
|
Note 2.
|
Description
of Business
|
We are principally engaged in the business of gathering,
transporting, processing and treating natural gas and
fractionating and storing natural gas liquids (NGL). 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) an approximately
3,800-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 765 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 removal
capacity of
67 MMcf/d.
Wamsutter owns (1) an approximate 1,800-mile natural gas
gathering system in the Washakie Basin in south-central Wyoming
that currently connects approximately 2,000 wells, with a
typical operating capacity of approximately
500 MMcf/d
at current operating pressures, and (2) 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) an
approximate
300-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.
83
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. We operate 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. We have prepared the
consolidated financial statements based upon accounting
principles generally accepted in the United States and have
included the accounts of the parent and our wholly owned
subsidiaries. We eliminated all intercompany accounts and
transactions and reclassified certain amounts 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 amounts primarily invested in funds with
high-quality, short-term securities and instruments that are
issued or guaranteed by the U.S. government. These have
maturities of three months or less when acquired.
84
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. We do not recognize an allowance for
doubtful accounts 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. We consider receivables past due if full
payment is not received by the contractual due date. Past due
accounts are generally written off against the allowance for
doubtful accounts only after all collection attempts have been
unsuccessful.
Product Imbalances. In the course of providing
gathering, processing and treating services to our customers, we
realize over and under deliveries of our customers
products and over and under purchases of shrink replacement gas
when our purchases vary from operational requirements. In
addition, in the course of providing gathering, processing,
treating, fractionation and storage services to our customers,
we realize gains and losses due to (1) the product blending
process at the Conway fractionator, (2) the periodic
emptying of storage caverns at Conway and (3) inaccuracies
inherent in the gas measurement process. These gains and losses
impact our results of operations and are included in operating
and maintenance expense in the Consolidated Statements of
Income. These imbalance positions are reflected as product
imbalance receivables and payables on the Consolidated Balance
Sheets. We value product imbalance receivables 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. We
value product imbalance payables at current market prices. The
majority of Four Corners product imbalance 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.
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. We capitalize land and
right-of-way lease payments made at the time of initial
construction or placement of plant and equipment on leased land
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.
Reimbursable Projects. We recorded
expenditures incurred for the repair of the Ignacio natural gas
processing plant damaged by a fire in November 2007, which were
probable of recovery when incurred, as reimbursable projects.
Expenditures up to the insurance deductible and amounts
subsequently determined not to be recoverable were expensed.
Derivative Instruments and Hedging
Activities. We may 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 those for which the
normal purchases and normal sales exception has been elected, on
the Consolidated Balance Sheets in other current assets,
derivative liabilities affiliate, 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
85
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 physical
energy commodities. 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 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.
Investments. At December 31, 2008, our
ownership interests in Wamsutter consist 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). 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. Discoverys underlying equity exceeds
the carrying value of our investment at December 31, 2008
and 2007 due to an other-than-temporary impairment of that
investment that we recognized in 2004.
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. We remove the cost of
property, plant and equipment sold or retired and the related
accumulated depreciation 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.
86
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
corresponding accretion expense.
Revenue Recognition. The nature of our
businesses results in various forms of revenue recognition. Our
Gathering and Processing segments recognize (1) revenue
from fee-based 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
or investments 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, and are not discounted. Environmental contingencies
are recorded independently of any potential claim for recovery.
Capitalized Interest. We capitalize interest
during construction on major projects with construction periods
of at least three months and a total project cost in excess of
$1.0 million. Interest is capitalized based on our average
interest rate on debt to the extent we incur interest expense.
Capitalized interest for the periods presented is immaterial.
Income Taxes. We are not a taxable entity for
federal and state income tax purposes. The tax on our net income
is borne by the individual partners through the allocation of
taxable income. Net income for financial statement purposes may
differ significantly from taxable income of unitholders as a
result of differences
87
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 March 2008,
the Financial Accounting Standards Board (FASB) issued
SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities an amendment of
FASB Statement No. 133. SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities, currently establishes the disclosure
requirements for derivative instruments and hedging activities.
SFAS 161 amends and expands the disclosure requirements of
Statement 133 with enhanced quantitative, qualitative and credit
risk disclosures. The Statement requires quantitative disclosure
in a tabular format about the fair values of derivative
instruments, gains and losses on derivative instruments and
information about where these items are reported in the
financial statements. Also required in the tabular presentation
is a separation of hedging and nonhedging activities.
Qualitative disclosures include outlining objectives and
strategies for using derivative instruments in terms of
underlying risk exposures, use of derivatives for risk
management and other purposes and accounting designation, and an
understanding of the volume and purpose of derivative activity.
Credit risk disclosures provide information about credit risk
related contingent features included in derivative agreements.
SFAS No. 161 also amends SFAS No. 107,
Disclosures about Fair Value of Financial
Instruments, to clarify that disclosures about
concentrations of credit risk should include derivative
instruments. This Statement is effective for financial
statements issued for fiscal years and interim periods beginning
after November 15, 2008, with early application encouraged.
We plan to apply this Statement beginning in 2009. This
Statement encourages, but does not require, comparative
disclosures for earlier periods at initial adoption. The
application of this Statement will increase the disclosures in
our Consolidated Financial Statements.
In March 2008, the FASB ratified the decisions reached by the
EITF with respect to EITF Issue
No. 07-4,
Application of the Two-Class Method under FASB
Statement No. 128, Earnings per Share, to Master
Limited Partnerships. EITF Issue
No. 07-4 states,
among other things, that the calculation of earnings per unit
should not reflect an allocation of undistributed earnings to
the incentive distribution right (IDR) holders beyond amounts
distributable to IDR holders under the terms of the partnership
agreement. As described in Note 4, under current generally
accepted accounting principles, we calculate earnings per unit
as if all the earnings for the period had been distributed. This
results in an additional allocation of income to the general
partner (the IDR holder) in quarterly periods where an assumed
incentive distribution, calculated as if all earnings for the
period had been distributed, exceeds the actual incentive
distribution. Following the adoption of the guidance in EITF
Issue
No. 07-4,
we will no longer calculate assumed incentive distributions. The
final consensus is effective beginning with the first interim
period of the fiscal year beginning after December 15,
2008, and must be retrospectively applied to all periods
presented. Early application is prohibited. Retrospective
application of this guidance will result in a decrease in the
income allocated to the general partner and an increase in the
income allocated to limited partners for the amount that any
assumed incentive distribution exceeded the actual incentive
distribution paid during that period. The application of this
Statement will increase our earnings per unit $0.52 for 2008
from $2.55 per limited partner unit to $3.07 per limited partner
unit. The impact on earnings per unit for 2007 and 2006 is not
material. The application of this Statement does not affect net
income, cash flows or total partners equity.
88
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In November 2008, the FASB ratified EITF Issue
No. 08-6,
Accounting for Equity Method Investments
Considerations. This Issue clarifies that an equity method
investor is required to continue to recognize an
other-than-temporary impairment of their investment in
accordance with APB Opinion No. 18. Also, an equity method
investor should not separately test an investees
underlying assets for impairment. However, an equity method
investor should recognize their share of an impairment charge
recorded by an investee. This Issue will be effective on a
prospective basis in fiscal years beginning on or after
December 15, 2008 and interim periods within those fiscal
years. Earlier application by an entity that has previously
adopted an alternative accounting policy would not be permitted.
Beginning January 1, 2009, we will apply the guidance
provided in this Consensus as required.
|
|
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,
2008, 2007 and 2006 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Allocation of net income to general partner:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
191,389
|
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
Net income applicable to pre-partnership operations allocated to
general partner
|
|
|
|
|
|
|
(71,426
|
)
|
|
|
(184,157
|
)
|
Beneficial conversion of Class B units*
|
|
|
|
|
|
|
(5,308
|
)
|
|
|
|
|
Charges allocated directly to general partner:
|
|
|
|
|
|
|
|
|
|
|
|
|
Reimbursable general and administrative costs
|
|
|
1,600
|
|
|
|
2,400
|
|
|
|
3,200
|
|
Carbonate Trend overburden indemnified costs
|
|
|
112
|
|
|
|
|
|
|
|
|
|
Core drilling indemnified costs
|
|
|
|
|
|
|
|
|
|
|
784
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total charges allocated directly to general partner
|
|
|
1,712
|
|
|
|
2,400
|
|
|
|
3,984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income subject to 2% allocation of general partner interest
|
|
|
193,101
|
|
|
|
90,297
|
|
|
|
34,402
|
|
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
|
|
|
3,861
|
|
|
|
1,806
|
|
|
|
688
|
|
Incentive distributions paid to general partner**
|
|
|
23,767
|
|
|
|
5,046
|
|
|
|
272
|
|
Charges allocated directly to general partner
|
|
|
(1,712
|
)
|
|
|
(2,400
|
)
|
|
|
(3,984
|
)
|
Pre-partnership net income allocated to general partner interest
|
|
|
|
|
|
|
71,426
|
|
|
|
184,157
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to general partner
|
|
$
|
25,916
|
|
|
$
|
75,878
|
|
|
$
|
181,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
191,389
|
|
|
$
|
164,631
|
|
|
$
|
214,575
|
|
Net income allocated to general partner
|
|
|
25,916
|
|
|
|
75,878
|
|
|
|
181,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to limited partners
|
|
$
|
165,473
|
|
|
$
|
88,753
|
|
|
$
|
33,442
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
The $5.3 million allocation of income to the Class B
units reflects the Class B unit beneficial conversion
feature resulting from the May 2007 conversion of these
units into common units on a one-for-one basis. We computed the
$5.3 million beneficial conversion feature 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). |
89
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
** |
|
Under the two class method of computing earnings per
share prescribed by SFAS No. 128, Earnings Per
Share, we allocate earnings 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
additional allocation of income to the general partner for the
years ended December 31, 2008, 2007 and 2006 was
$30.6 million, $9.3 million and $1.2 million,
respectively. |
Pursuant to the partnership agreement, we allocate income on a
quarterly basis; therefore, we calculate earnings per limited
partner unit for each year as the sum of the quarterly earnings
per limited partner unit for each of the four quarters in the
year. Common and subordinated unitholders shared equally, on a
per-unit
basis, in the net income allocated to limited partners before
the conversion of the subordinated units into common units in
2008.
The reimbursable general and administrative, core drilling and
Carbonate Trend overburden costs represent the costs charged
against our income that our general partner is required to
reimburse us under the terms of the omnibus agreement.
We paid or have authorized payment of the following cash
distributions during 2006, 2007 and 2008 (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
|
|
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
|
|
$
|
0.5750
|
|
|
$
|
26,321
|
|
|
$
|
4,025
|
|
|
$
|
|
|
|
$
|
706
|
|
|
$
|
4,231
|
|
|
$
|
35,283
|
|
5/15/2008
|
|
$
|
0.6000
|
|
|
$
|
31,665
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
758
|
|
|
$
|
5,499
|
|
|
$
|
37,922
|
|
8/14/2008
|
|
$
|
0.6250
|
|
|
$
|
32,984
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
811
|
|
|
$
|
6,765
|
|
|
$
|
40,560
|
|
11/14/2008
|
|
$
|
0.6350
|
|
|
$
|
33,513
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
832
|
|
|
$
|
7,272
|
|
|
$
|
41,617
|
|
2/13/2009(a)
|
|
$
|
0.6350
|
|
|
$
|
33,513
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
832
|
|
|
$
|
7,272
|
|
|
$
|
41,617
|
|
|
|
|
(a) |
|
On February 13, 2009, we paid a cash distribution of $0.635
per unit on our outstanding common units to unitholders of
record on February 6, 2009. |
|
|
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. We charge back certain of the payroll
costs associated with the operations employees to the other
Conway fractionator co-owners. Our share of those costs is
charged to us through affiliate billings and reflected in
Operating and maintenance expense Affiliate in the
accompanying Consolidated Statements of Income.
90
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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. We charge certain of
these costs 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 capital contributions from our general partner. The annual
amounts of the credits are as follows: $3.2 million in
2006, $2.4 million in 2007, $1.6 million in 2008 and
$0.8 million in 2009.
At December 31, 2008 and 2007 we have a contribution
receivable from our general partner of $0.2 million and
$0.5 million, respectively, for amounts reimbursable to us
under the omnibus agreement. We net this receivable against
Partners capital on the Consolidated Balance Sheets.
Williams has agreed to reimburse us for certain capital
expenditures, subject to limits, including for certain
excess capital expenditures in connection with
Discoverys Tahiti pipeline lateral expansion project.
We 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.
We reflect the amortization of this contract in Operating and
maintenance expense Affiliate in the accompanying
Consolidated Statements of Income. 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. Williams Flexible
Generation, LLC, an affiliate of Williams, owns the
co-generation plant. 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. Prior to
2007, the natural gas cost charged to us by WGM had been
favorably impacted by WGMs fixed price natural gas fuel
contracts which expired in the fourth quarter of 2006. This
impact was approximately $9.0 million during 2006 as
compared to estimated market prices. We reflect this cost in
Operations and maintenance expense Affiliate.
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. WGM conducts these purchase and sales transactions at
current market prices at each location. These transactions are
included in Product sales Affiliate and Product cost
and shrink replacement Affiliate on the Consolidated
Statements of Income.
91
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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. We reflect revenues associated with
these activities as Product sales Affiliate on the
Consolidated Statements of Income. We conduct these transactions
at current market prices for the products.
We periodically 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 Other current assets 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
adjusted annually based on changes in the average price of
natural gas. We reflect revenues associated with these
activities in the Gathering and processing Affiliate
on the Consolidated Statements of Income.
We sell Conways surplus propane and other NGLs to WNGLM,
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 WNGLM to replenish deficit
product inventory positions. We conduct transactions between us
and WNGLM 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. 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.
Under our stand-alone cash management program, we reflect
amounts owed by us or to us by Williams or its subsidiaries as
Accounts receivable Affiliate or Accounts
payable Affiliate in the accompanying Consolidated
Balance Sheets.
|
|
Note 6.
|
Equity
Investments
|
Wamsutter
We account for our Wamsutter Ownership Interests using the
equity method of accounting due to the voting provisions of
Wamsutters limited liability company agreement (LLC
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 purchases natural gas for fuel and shrink replacement
from WGM and sells NGLs to WNGLM. We conduct these transactions
at current market prices for the products.
Wamsutter participates in Williams cash management program
and, therefore, carries no cash balances. Prior to
December 1, 2007, Wamsutter had net advances to Williams,
which were classified as a component of their members
capital because although the advances were due on demand,
Williams had not historically required repayment or repaid
amounts owed to Wamsutter. Upon our acquisition of the Wamsutter
Ownership Interests, the outstanding advances were distributed
to Williams.
92
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Wamsutter LLC Agreement provides for quarterly distributions
of available cash 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 distributes 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. At
December 31, 2008, we owned 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 distribution year for Wamsutter commences each year on
December 1 and ends on November 30.
Wamsutter allocates net income (equity earnings) to us based
upon the allocation, distribution, and liquidation provisions of
its limited liability company agreement applied as though
liquidation occurs at book value. In general, the agreement
allocates income in a manner that will maintain capital account
balances reflective of the amounts each membership interest
would receive if Wamsutter were dissolved and liquidated at
carrying value. The income allocation for the quarterly periods
during a year reflects the preferential rights of the
Class A member to any distributions made to the
Class C member until the Class A member has received
$70.0 million in distributions for the year. The
Class B member receives no income or loss allocation. As
the owner of 100% of the Class A membership interest, we
will receive 100% of Wamsutters annual net income up to
$70.0 million. Income in excess of $70.0 million will
be shared between the Class A member and Class C
member, of which we owned 50% throughout 2008. For annual
periods in which Wamsutters net income exceeds
$70.0 million, this will result in a higher allocation of
equity earnings to us early in the year and a lower allocation
of equity earnings to us later in the year. Wamsutters net
income allocation does not
93
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
affect the amount of available cash it distributes for any
quarter. The following table presents the allocation of
Wamsutters 2008 net income to its unitholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our Share
|
|
|
Other
|
|
|
Wamsutter
|
|
Wamsutter Net Income Allocation
|
|
Class A
|
|
|
Class C
|
|
|
WPZ Total
|
|
|
Class C
|
|
|
Net Income
|
|
|
|
(Dollars in millions)
|
|
|
Net income, beginning December 1, 2007 up to
$70.0 million.*
|
|
$
|
62.6
|
|
|
$
|
|
|
|
$
|
62.6
|
|
|
$
|
|
|
|
$
|
62.6
|
|
Net income allocation related to 5% of amount over
$70.0 million
|
|
|
2.1
|
|
|
|
|
|
|
|
2.1
|
|
|
|
|
|
|
|
2.1
|
|
Net income for December 2008
|
|
|
1.0
|
|
|
|
|
|
|
|
1.0
|
|
|
|
|
|
|
|
1.0
|
|
Net income allocation related to transition support payments
paid to us
|
|
|
7.6
|
|
|
|
|
|
|
|
7.6
|
|
|
|
|
|
|
|
7.6
|
|
Remainder net income allocated to Class C members
|
|
|
|
|
|
|
15.2
|
|
|
|
15.2
|
|
|
|
15.2
|
|
|
|
30.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
$
|
73.3
|
|
|
$
|
15.2
|
|
|
$
|
88.5
|
|
|
$
|
15.2
|
|
|
$
|
103.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
$7.4 million of the $70.0 million was recognized in
2007. |
Wamsutters LLC agreement provides that it receive a
transition support payment related to a cap on general and
administrative expenses from its Class B membership
interest each quarter during 2008 through 2012. Although the
full amount of expenses are recorded by Wamsutter, this support
increases the cash distributable and income allocable to the
Class A membership interest.
During 2008, we made $3.7 million in capital contributions
to Wamsutter for capital projects and received total cash
distributions of $91.5 million from Wamsutter, as well as
transition support payments of $7.6 million.
In January 2009, Wamsutter issued an additional 70.8 and 28.8
Class C units to us and Williams, respectively, related to
the funding of expansion capital expenditures placed in service
during 2008. As a result, we currently own 65% and Williams owns
35% of Wamsutters outstanding Class C units. As of
December 31, 2008, Williams contributed an additional
$28.8 million for an expansion capital project that is
expected to be placed in service during 2010. Williams will
receive Class C units related to these expenditures after
the assets are placed in service.
The summarized financial position and results of operations for
100% of Wamsutter are presented below (in thousands).
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Current assets
|
|
$
|
17,147
|
|
|
$
|
27,114
|
|
Property, plant and equipment
|
|
|
318,072
|
|
|
|
275,163
|
|
Non-current assets
|
|
|
468
|
|
|
|
191
|
|
Current liabilities
|
|
|
(16,960
|
)
|
|
|
(13,016
|
)
|
Non-current liabilities
|
|
|
(4,353
|
)
|
|
|
(2,740
|
)
|
|
|
|
|
|
|
|
|
|
Members capital
|
|
$
|
314,374
|
|
|
$
|
286,712
|
|
|
|
|
|
|
|
|
|
|
94
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
134,776
|
|
|
$
|
93,744
|
|
|
$
|
113,484
|
|
Third-party
|
|
|
27,384
|
|
|
|
7,447
|
|
|
|
|
|
Gathering and processing services
|
|
|
68,670
|
|
|
|
67,904
|
|
|
|
57,859
|
|
Other revenues
|
|
|
8,704
|
|
|
|
6,214
|
|
|
|
5,203
|
|
Costs and expenses excluding depreciation and accretion:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
74,388
|
|
|
|
46,834
|
|
|
|
68,041
|
|
Third-party
|
|
|
40,200
|
|
|
|
32,666
|
|
|
|
30,626
|
|
Depreciation and accretion
|
|
|
21,182
|
|
|
|
18,424
|
|
|
|
16,189
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
103,764
|
|
|
$
|
77,385
|
|
|
$
|
61,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest equity earnings
|
|
$
|
88,538
|
|
|
$
|
76,212
|
|
|
$
|
61,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery
Producer Services
We account for our 60% investment in Discovery 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 operations related 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.
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.
Our Consolidated Statement of Partners Capital reflects
the total of these transactions as an adjustment in the basis of
our investment in Discovery. A summary of these transactions is
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Cash distributions from Discovery to Williams
|
|
$
|
(9,035
|
)
|
|
$
|
(8,200
|
)
|
Williams capital contributions to Discovery
|
|
|
|
|
|
|
800
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(9,035
|
)
|
|
$
|
(7,400
|
)
|
|
|
|
|
|
|
|
|
|
During 2008, we made $5.7 million in capital contributions
to Discovery for capital projects. In October 2006, we made a
$1.6 million capital contribution to Discovery for a
substantial portion of our then 40% share of the estimated
future capital expenditures for the Tahiti pipeline lateral
expansion project.
95
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
During 2008, 2007, and 2006 we received total cash distributions
of $56.4 million, $35.5 million, and
$16.4 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,
|
|
|
|
2008
|
|
|
2007
|
|
|
Current assets
|
|
$
|
50,978
|
|
|
$
|
78,035
|
|
Non-current restricted cash
|
|
|
3,470
|
|
|
|
6,222
|
|
Property, plant and equipment
|
|
|
370,482
|
|
|
|
368,228
|
|
Current liabilities
|
|
|
(45,234
|
)
|
|
|
(33,820
|
)
|
Non-current liabilities
|
|
|
(19,771
|
)
|
|
|
(12,216
|
)
|
|
|
|
|
|
|
|
|
|
Members capital
|
|
$
|
359,925
|
|
|
$
|
406,449
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
209,994
|
|
|
$
|
220,960
|
|
|
$
|
160,825
|
|
Third-party
|
|
|
31,254
|
|
|
|
39,712
|
|
|
|
36,488
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
96,912
|
|
|
|
101,581
|
|
|
|
74,316
|
|
Third-party
|
|
|
110,508
|
|
|
|
113,207
|
|
|
|
97,394
|
|
Interest income
|
|
|
(650
|
)
|
|
|
(1,799
|
)
|
|
|
(2,404
|
)
|
Foreign exchange (gain) loss
|
|
|
78
|
|
|
|
(388
|
)
|
|
|
(2,076
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
34,400
|
|
|
$
|
48,071
|
|
|
$
|
30,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery investment income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest equity earnings
|
|
$
|
20,641
|
|
|
$
|
28,842
|
|
|
$
|
18,050
|
|
Investing income
|
|
|
1,716
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
22,357
|
|
|
$
|
28,842
|
|
|
$
|
18,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 7.
|
Other
(Income) Expense
|
Other (income) expense net reflected on the
Consolidated Statements of Income consists of the following
items (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Involuntary conversion gain
|
|
$
|
(11,604
|
)
|
|
$
|
|
|
|
$
|
|
|
Impairment of Carbonate Trend pipeline
|
|
|
6,187
|
|
|
|
10,406
|
|
|
|
|
|
Gain on sale of LaMaquina carbon dioxide treating facility
|
|
|
|
|
|
|
|
|
|
|
(3,619
|
)
|
Other
|
|
|
1,894
|
|
|
|
1,689
|
|
|
|
1,146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
(3,523
|
)
|
|
$
|
12,095
|
|
|
$
|
(2,473
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
96
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Involuntary conversion gain. On
November 28, 2007, the Ignacio gas processing plant
sustained significant damage from a fire. The involuntary
conversion gain results from insurance proceeds received to
replace the capital assets destroyed by the fire in excess of
the net book value of those assets being replaced.
Impairment of Carbonate Trend Pipeline. During
2007 and again in 2008, 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 impairment charges of $6.2 million and
$10.4 million in 2008 and 2007, respectively, to reduce the
carrying value to managements estimate of fair value. As
of December 31, 2008, the carrying value of this asset has
been written down to zero. We estimated fair value using
discounted cash flow projections.
LaMaquina Carbon Dioxide Treating Facility. In
2006, we completed the sale of our LaMaquina carbon dioxide
treating facility in the Four Corners area and recognized a gain
on the sale. The December 31, 2005 carrying value resulted
from the recognition of impairments of $7.6 million and
$4.2 million in 2004 and 2003, respectively, following the
2002 shut down of the facility and reflected the then estimated
fair value less cost to sell.
|
|
Note 8.
|
Property,
Plant and Equipment
|
Property, plant and equipment, at cost, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Estimated
|
|
|
|
2008
|
|
|
2007
|
|
|
Depreciable Lives
|
|
|
|
(In thousands)
|
|
|
|
|
|
Land and right of way
|
|
$
|
43,246
|
|
|
$
|
42,657
|
|
|
|
0-30 years
|
|
Gathering pipelines and related equipment
|
|
|
838,214
|
|
|
|
830,437
|
|
|
|
20-30 years
|
|
Processing plants and related equipment
|
|
|
183,222
|
|
|
|
149,855
|
|
|
|
30 years
|
|
Fractionation plant and related equipment
|
|
|
16,540
|
|
|
|
16,720
|
|
|
|
30 years
|
|
Storage plant and related equipment
|
|
|
87,803
|
|
|
|
80,837
|
|
|
|
30 years
|
|
Buildings and other equipment
|
|
|
77,287
|
|
|
|
90,356
|
|
|
|
3-45 years
|
|
Construction work in progress
|
|
|
18,841
|
|
|
|
28,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
1,265,153
|
|
|
|
1,239,792
|
|
|
|
|
|
Accumulated depreciation
|
|
|
624,633
|
|
|
|
597,503
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
640,520
|
|
|
$
|
642,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
97
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A rollforward of our asset retirement obligation for 2008 and
2007 is presented below.
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Balance, January 1
|
|
$
|
8,743
|
|
|
$
|
4,476
|
|
Liabilities incurred during the period
|
|
|
355
|
|
|
|
2,950
|
|
Liabilities settled during the period
|
|
|
|
|
|
|
(64
|
)
|
Accretion expense
|
|
|
752
|
|
|
|
1,474
|
|
Estimate revisions
|
|
|
3,615
|
|
|
|
(93
|
)
|
|
|
|
|
|
|
|
|
|
Balance, December 31
|
|
$
|
13,465
|
|
|
$
|
8,743
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 9.
|
Major
Customers and Concentrations of Credit Risk
|
Major
customers
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 49%, 49%, and 43% of
revenues in 2008, 2007 and 2006, respectively. The remaining
largest customer, ConocoPhillips, from our Gathering and
Processing West segment, accounted for 17%, 22%, and
21% of revenues in 2008, 2007 and 2006, respectively.
Concentrations
of Credit Risk
Our cash equivalent balance is primarily invested in funds with
high-quality, short-term securities and instruments that are
issued or guaranteed by the U.S. government. The
counterparties to our derivative contracts are affiliates of
Williams, which minimized our credit risk exposure.
The following table summarizes the concentration of accounts
receivable by service and segment.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Gathering and Processing West:
|
|
|
|
|
|
|
|
|
Natural gas gathering and processing
|
|
$
|
14,516
|
|
|
$
|
11,512
|
|
Other
|
|
|
801
|
|
|
|
471
|
|
Gathering and Processing Gulf:
|
|
|
|
|
|
|
|
|
Natural gas gathering
|
|
|
203
|
|
|
|
324
|
|
Other
|
|
|
|
|
|
|
881
|
|
NGL Services:
|
|
|
|
|
|
|
|
|
Fractionation services
|
|
|
1,025
|
|
|
|
303
|
|
Amounts due from fractionator partners
|
|
|
1,439
|
|
|
|
1,068
|
|
Storage
|
|
|
681
|
|
|
|
735
|
|
Other
|
|
|
34
|
|
|
|
|
|
Accrued interest and other
|
|
|
499
|
|
|
|
109
|
|
Affiliate
|
|
|
11,652
|
|
|
|
20,402
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
30,850
|
|
|
$
|
35,805
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2008 and 2007, a substantial portion of our
accounts receivable results from product sales and gathering and
processing services provided to two of our customers. One
customer is an affiliate of
98
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Williams which minimizes our credit risk exposure. The remaining
customer may impact our overall credit risk either positively or
negatively, in that this entity may be 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.
|
|
Note 10.
|
Long-Term
Debt, Credit Facilities and Leasing Activities
|
Long-Term
Debt
Long-term debt at December 31, 2008 and 2007 includes the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
|
December 31,
|
|
|
|
Rate
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(Millions)
|
|
|
Credit agreement term loan, adjustable rate, due 2012
|
|
|
(a
|
)
|
|
$
|
250.0
|
|
|
$
|
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
|
|
|
$
|
1,000.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
1.2213% at December 31, 2008 |
The terms of the senior unsecured notes are governed by
indentures that contain covenants that, among other things,
limit (1) our ability and the ability of our subsidiaries
to incur indebtedness or liens securing indebtedness and
(2) mergers, consolidations and transfers of all or
substantially all of our properties or assets. 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.
Credit
Facilities
We have 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. The parent company and certain affiliates of Lehman
Brothers Commercial Bank, who is committed to fund up to
$12.0 million of this credit facility, have filed for
bankruptcy. We expect that our ability to borrow under this
facility is reduced by this committed amount. The committed
amounts of the other participating banks under this agreement
remain in effect and are not impacted by this reduction.
However, debt covenants may restrict the full use of the credit
facility. We must repay borrowings under this agreement by
December 11, 2012. At December 31, 2008 and 2007, we
had a $250.0 million term loan outstanding under the term
loan provisions and no amounts outstanding under the revolving
credit facility.
99
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Interest on borrowings under this agreement are 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 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 or make distributions or other payments other than
distributions of available cash under certain conditions.
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 fiscal quarter in
which the acquisition occurs and three fiscal quarter-periods
following such acquisition. At December 31, 2008, our ratio
of consolidated indebtedness to consolidated EBITDA, as
calculated under this covenant, of approximately 2.98 is in
compliance with this covenant.
|
|
|
|
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. At
December 31, 2008, our ratio of consolidated EBITDA to
consolidated interest expense, as calculated under this
covenant, of approximately 5.13 is in compliance with this
covenant.
|
Inasmuch as the ratios are calculated on a rolling four-quarter
basis, the ratios at December 31, 2008 do not reflect a
full-year impact of the lower earnings we experienced in the
fourth quarter of 2008. In the event that despite our efforts we
breach our financial covenants causing an event of default, the
lenders could, among other things, accelerate the maturity of
any borrowings under the facility (including our
$250.0 million term loan) and terminate their commitments
to lend.
We also have a $20.0 million revolving credit facility with
Williams as the lender. The 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, 2008, we have no outstanding borrowings under
the working capital credit facility.
Cash payments for interest during 2008, 2007 and 2006 were
$65.5 million, $38.8 million and $5.5 million,
respectively.
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. A significant Indian tribal lease in Colorado will
expire at the end of 2022.
We concluded our negotiations with the Jicarilla Apache Nation
(JAN) during February 2009 with the execution of a
20-year
right-of-way agreement. Under the new agreement, the JAN granted
rights-of-way for Four Corners existing natural gas
gathering system on JAN land as well as a significant
geographical area for additional growth of the system. We paid
an initial payment of $7.3 million upon execution of the
agreement. Beginning in 2010, we will make annual payments of
approximately $7.5 million and an additional annual
100
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
payment which varies depending on the prior years
per-unit NGL
margins and the volume of gas gathered by our gathering
facilities subject to the agreement. Depending primarily on the
per-unit NGL
margins for any given year, the additional annual payments could
approximate the fixed amount. Additionally, five years from the
effective date of the agreement, the JAN will have the option to
acquire up to a 50% joint venture interest for 20 years in
certain of Four Corners assets existing at the time the
option is exercised. The joint venture option includes Four
Corners gathering assets subject to the agreement and
portions of Four Corners gathering and processing assets
located in an area adjacent to the JAN lands. If the JAN selects
the joint venture option, the value of the assets contributed by
each party to the joint venture will be based upon a market
value determined by a neutral third party at the time the joint
venture is formed. This right-of-way agreement is subject to the
consent of the United States Secretary of the Interior before it
may become effective.
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, 2008 are payable as follows:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2009
|
|
$
|
1,357
|
|
2010
|
|
|
880
|
|
2011
|
|
|
396
|
|
2012
|
|
|
90
|
|
2013 and thereafter
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,723
|
|
|
|
|
|
|
Total rent expense was $24.4 million, $21.2 million
and $19.4 million for 2008, 2007 and 2006, respectively.
|
|
Note 11.
|
Partners
Capital
|
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
pursuant to our common unit offering in December 2007 used to
finance our acquisition of the Wamsutter Ownership Interests. We
used the net proceeds from the partial exercise of the
underwriters option to redeem 800,000 common units from an
affiliate of Williams at a price per common unit of $36.24
($37.75, net of underwriter discount).
At December 31, 2008, the public held 76% of our total
units outstanding, and affiliates of Williams held the remaining
units.
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 control 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.
|
101
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Subordinated
Units
Our subordination period ended on February 19, 2008 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 now participate pro rata with the other common units in
distributions of available cash.
Class B
Units
On May 21, 2007, the Class B units were converted into
common units on a one-for-one basis and now participate pro rata
with the other common units in distributions of available cash.
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 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 12.
|
Financial
Instruments and Fair Value Measurements
|
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 publicly
traded long-term debt is valued using indicative year-end traded
bond market prices. We base the fair value of our private
long-term debt on market rates and the prices of similar
securities with similar terms and credit ratings. We consider
our non-performance risk in estimating fair value.
Energy commodity swap agreements. We base the
fair value of our swap agreements 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.
102
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Carrying
amounts and fair values of our financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
Fair
|
Asset (Liability)
|
|
Amount
|
|
Value
|
|
Amount
|
|
Value
|
|
|
(In thousands)
|
|
Cash and cash equivalents
|
|
$
|
116,165
|
|
|
$
|
116,165
|
|
|
$
|
36,197
|
|
|
$
|
36,197
|
|
Long-term debt
|
|
|
(1,000,000
|
)
|
|
|
(825,289
|
)
|
|
|
(1,000,000
|
)
|
|
|
(1,027,499
|
)
|
Energy commodity swap agreements
|
|
|
|
|
|
|
|
|
|
|
(2,487
|
)
|
|
|
(2,487
|
)
|
Fair
Value Measurements
Adoption
of SFAS No. 157
On January 1, 2008, we adopted SFAS No. 157,
Fair Value Measurements, for our assets and
liabilities which are measured at fair value on a recurring
basis (our commodity derivatives). Upon applying
SFAS No. 157, we changed our valuation methodology to
consider our nonperformance risk in estimating the fair value of
our liabilities. Applying SFAS No. 157 did not
materially impact our consolidated financial statements. In
February 2008, the FASB issued Financial Staff Position (FSP)
FAS 157-2
permitting entities to delay application of
SFAS No. 157 to fiscal years beginning after
November 15, 2008 for nonfinancial assets and nonfinancial
liabilities, except for items that are recognized or disclosed
at fair value in the financial statements on a recurring basis
(at least annually). On January 1, 2009, we adopted
SFAS No. 157 fair value requirements for nonfinancial
assets and nonfinancial liabilities, such as long-lived assets
measured at fair value for impairment purposes and initial
measurement of fair value for asset retirement obligations, that
are not recognized or disclosed at fair value on a recurring
basis when such fair value measurements are required. Applying
SFAS No. 157 at January 1, 2009 did not impact
our consolidated financial statements. Upon adopting
SFAS No. 157, we applied a prospective transition as
we did not have financial instrument transactions that required
a cumulative-effect adjustment to beginning retained earnings.
Fair value is the price that would be received in the sale of an
asset or the amount paid to transfer a liability in an orderly
transaction between market participants (an exit price) at the
measurement date. Fair value is a market-based measurement from
the perspective of a market participant. We use market data or
assumptions that market participants would use in pricing the
asset or liability, including assumptions about risk and the
risks inherent in the inputs to the valuation. These inputs can
be readily observable, market corroborated, or unobservable. We
primarily apply a market approach for recurring fair value
measurements using the best available information while
utilizing valuation techniques that maximize the use of
observable inputs and minimize the use of unobservable inputs.
SFAS No. 157 establishes a fair-value hierarchy that
prioritizes the inputs used to measure fair value. The hierarchy
gives the highest priority to quoted prices in active markets
for identical assets or liabilities (Level 1 measurement)
and the lowest priority to unobservable inputs (Level 3
measurement). We classify fair-value balances based on the
observability of those inputs. The three levels of the
fair-value hierarchy are as follows:
|
|
|
|
|
Level 1 Quoted prices in active markets for
identical assets or liabilities that we have the ability to
access. Active markets are those in which transactions for the
asset or liability occur in sufficient frequency and volume to
provide pricing information on an ongoing basis.
|
|
|
|
Level 2 Inputs are other than quoted prices in
active markets included in Level 1, that are either
directly or indirectly observable. These inputs are either
directly observable in the marketplace or indirectly observable
through corroboration with market data for substantially the
full contractual term of the asset or liability being measured.
|
|
|
|
Level 3 Includes inputs that are not observable
for which there is little, if any, market activity for the asset
or liability being measured. These inputs reflect
managements best estimate of the assumptions
|
103
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
market participants would use in determining fair value. Our
Level 3 consists of instruments valued with valuation
methods that utilize unobservable pricing inputs that are
significant to the overall fair value.
|
In valuing certain contracts, the inputs used to measure fair
value may fall into different levels of the fair-value
hierarchy. For disclosure purposes, assets and liabilities are
classified in their entirety in the fair-value hierarchy level
based on the lowest level of input that is significant to the
overall fair value measurement. Our assessment of the
significance of a particular input to the fair-value measurement
requires judgment and may affect the placement within the
fair-value hierarchy levels.
At December 31, 2008 we had no assets or liabilities
measured at fair value on a recurring basis. At
December 31, 2007, our only assets or liabilities measured
at fair value on a recurring basis were derivative assets and
liabilities, and these were contracted entirely with Williams.
These commodity-based financial swap contracts were classified
as Level 3 valuations.
The following table sets forth a reconciliation of changes in
the fair value of net derivatives classified as Level 3 in
the fair-value hierarchy for the twelve months ended
December 31, 2008.
Level 3
Fair-Value Measurements Using Significant Unobservable Inputs
Twelve Months Ended December 31, 2008
(In thousands)
|
|
|
|
|
|
|
Net Derivative
|
|
|
|
Asset (Liability)
|
|
|
Balance as of January 1, 2008
|
|
$
|
(2,487
|
)
|
Total gains (losses) recognized in earnings:
|
|
|
|
|
Hedge ineffectiveness
|
|
|
(200
|
)
|
Reclassification from other comprehensive income
|
|
|
416
|
|
Unrealized gains (losses) deferred in other comprehensive
income, net of amounts reclassified
|
|
|
2,487
|
|
(Gains) losses realized in settlements
|
|
|
(216
|
)
|
Purchases, issuances and transfers in/(out) of Level 3
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008
|
|
$
|
|
|
|
|
|
|
|
Unrealized gains included in net income relating to instruments
still held at December 31, 2008
|
|
$
|
|
|
|
|
|
|
|
Realized and unrealized gains (losses) included in net income
are reported in revenues in our Consolidated Statement of Income.
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 volatility in revenues from
the sale of these NGL volumes from fluctuations in NGL market
prices, we entered into financial swap contracts. We designated
these derivatives as cash flow hedges under
SFAS No. 133. These derivatives were highly effective
in offsetting cash flows attributable to the hedged risk during
the term of the hedge. We recognized a $0.2 million net
loss from hedge ineffectiveness in our Consolidated Statements
of Income during 2008. No net gains or losses from hedge
ineffectiveness are included in the Consolidated Statements of
Income during 2007 or 2006, and there were no derivative gains
or
104
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
losses excluded from the assessment of hedge effectiveness for
the periods presented. We have no cash flow hedges outstanding
at December 31, 2008.
|
|
Note 13.
|
Long-Term
Incentive Plan
|
Our general partner maintains 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 2008, 2007, and 2006 our general partner granted 2,724,
2,403 and 2,130 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 $98,000,
$77,000 and $229,000 associated with the Plan in 2008, 2007, and
2006, respectively, based on the market price of our common
units at the date of grant.
|
|
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
$16.0 million at December 31, 2008.
In January 2009, we entered into a
5-year
Master Compression Services Contract with Exterran Holdings,
Inc. Under the agreement, Exterran will provide compressor units
including operations and maintenance services. Payments under
this agreement will vary depending upon the extent and amount of
compressors needed to meet producer service requirements and are
expected to approximate $24.0 million in 2009.
Environmental Matters-Four Corners. Current
federal regulations require that certain unlined liquid
containment pits located near named rivers and catchment areas
be taken out of use, and current state regulations required all
unlined, earthen pits to be either permitted or closed by
December 31, 2005. Operating under a New Mexico Oil
Conservation Division-approved work plan, we have physically
closed all of our pits that were slated for closure under those
regulations. We are presently awaiting agency approval of the
closures for 40 to 50 of those pits. We are also a participant
in certain hydrocarbon removal and groundwater monitoring
activities associated with certain well sites in New Mexico. Of
nine remaining active sites, product removal is ongoing at four
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 seven years.
In April 2007, the New Mexico Environment Departments Air
Quality Bureau (NMED) issued a Notice of Violation (NOV) 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. In July 2008, the NMED issued an
NOV that alleged air emissions permit exceedances for three
glycol dehydrators at our Pump Mesa central delivery point
compressor facility and proposed a penalty of approximately
$103,000. We are discussing the basis for and scope of the
calculation of the proposed penalties with the NMED.
In March 2008, the Environmental Protection Agency (EPA)
proposed a penalty of $370,000 for alleged violations relating
to leak detection and repair program delays at our Ignacio gas
plant in Colorado and for alleged permit violations at one of
our compressor stations. We met with the EPA and are exchanging
information in order to resolve the issues.
We have accrued liabilities totaling $1.5 million at
December 31, 2008 for these environmental activities. It is
reasonably possible that we will incur losses in excess of our
accrual for these matters. However, a reasonable estimate of
such amounts cannot be determined at this time because actual
costs incurred will
105
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
depend on the actual number of contaminated sites identified,
the amount and extent of contamination discovered, the final
cleanup standards mandated by governmental authorities,
negotiations with the applicable agencies, and other factors.
We are subject to extensive federal, state and local
environmental laws and regulations which affect our operations
related to the construction and operation of our facilities.
Appropriate governmental authorities may enforce these laws and
regulations with a variety of civil and criminal enforcement
measures, including monetary penalties, assessment and
remediation requirements and injunctions as to future
compliance. We have not been notified and are not currently
aware of any material noncompliance under the various applicable
environmental laws and regulations.
Environmental Matters-Conway. We are a
participant in certain environmental remediation activities
associated with soil and groundwater contamination at our Conway
storage facilities. These activities relate to four projects
that are in various remediation stages including assessment
studies, cleanups
and/or
remedial operations and monitoring. We continue to coordinate
with the Kansas Department of Health and Environment (KDHE) to
develop screening, sampling, cleanup and monitoring programs.
The costs of such activities will depend upon the program scope
ultimately agreed to by the KDHE and are expected to be paid
over the next two to six years. At December 31, 2008, we
had accrued liabilities totaling $3.3 million for these
costs. It is reasonably possible that we will incur losses in
excess of our accrual for these matters. However, a reasonable
estimate of such amounts cannot be determined at this time
because actual costs incurred will depend on the actual number
of contaminated sites identified, the amount and extent of
contamination discovered, the final cleanup standards mandated
by KDHE and other governmental authorities and other factors.
Under an omnibus agreement with Williams entered into at the
closing of our IPO, Williams agreed to indemnify us for certain
Conway environmental remediation costs. At December 31,
2008, approximately $7.3 million remains available for
future indemnification. Payments received under this
indemnification are accounted for as a capital contribution to
us by Williams as the costs are reimbursed.
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 the
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 U.S. 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 and 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 had 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 would not
intervene in any of the Grynberg cases. 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. The District Court dismissed all
claims against us. The matter is on appeal to the Tenth Circuit
Court of Appeals. The amount of any possible liability cannot be
reasonably estimated at this time.
GEII 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
106
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2006 we filed suit in federal court in Tulsa, Oklahoma against
GEII, GE Energy Services, Inc., and Qualified Contractors, Inc.
We 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 in the amount of
$1.9 million against us that alleged breach of contract and
breach of the duty of good faith and fair dealing. Trial has
been set for July 2009.
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 material impact upon our future financial position.
|
|
Note 15.
|
Segment
Disclosures
|
Our reportable segments are strategic business units that offer
different products and services. We manage the segments
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.
107
WILLIAMS
PARTNERS L. P.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering &
|
|
|
Gathering &
|
|
|
|
|
|
|
|
|
|
Processing -
|
|
|
Processing -
|
|
|
NGL
|
|
|
|
|
|
|
West
|
|
|
Gulf
|
|
|
Services
|
|
|
Total
|
|
|
|
(In thousands)
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales
|
|
$
|
322,583
|
|
|
$
|
|
|
|
$
|
16,697
|
|
|
$
|
339,280
|
|
Gathering and processing
|
|
|
230,853
|
|
|
|
2,096
|
|
|
|
|
|
|
|
232,949
|
|
Storage
|
|
|
|
|
|
|
|
|
|
|
31,429
|
|
|
|
31,429
|
|
Fractionation
|
|
|
|
|
|
|
|
|
|
|
17,441
|
|
|
|
17,441
|
|
Other
|
|
|
6,702
|
|
|
|
|
|
|
|
9,259
|
|
|
|
15,961
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
560,138
|
|
|
|
2,096
|
|
|
|
74,826
|
|
|
|
637,060
|
|
Product cost and shrink replacement
|
|
|
189,192
|
|
|
|
|
|
|
|
16,886
|
|
|
|
206,078
|
|
Operating and maintenance expense
|
|
|
156,713
|
|
|
|
1,668
|
|
|
|
27,520
|
|
|
|
185,901
|
|
Depreciation, amortization and accretion
|
|
|
41,215
|
|
|
|
751
|
|
|
|
3,063
|
|
|
|
45,029
|
|
Direct general and administrative expenses
|
|
|
8,333
|
|
|
|
|
|
|
|
2,582
|
|
|
|
10,915
|
|
Other, net
|
|
|
(939
|
)
|
|
|
6,187
|
|
|
|
737
|
|
|
|
5,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss)
|
|
|
165,624
|
|
|
|
(6,510
|
)
|
|
|
24,038
|
|
|
|
183,152
|
|
Investment income
|
|
|
88,538
|
|
|
|
22,357
|
|
|
|
|
|
|
|
110,895
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$
|
254,162
|
|
|
$
|
15,847
|
|
|
$
|
24,038
|
|
|
$
|
294,047
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statement of Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
183,152
|
|
General and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(33,707
|
)
|
Third-party direct
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,437
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
147,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets
|
|
$
|
1,248,110
|
|
|
$
|
379,060
|
|
|
$
|
127,315
|
|
|
$
|
1,754,485
|
|
Other assets and eliminations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(462,666
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,291,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity method investments
|
|
$
|
277,707
|
|
|
$
|
184,466
|
|
|
$
|
|
|
|
$
|
462,173
|
|
Additions to long-lived assets
|
|
$
|
36,833
|
|
|
$
|
|
|
|
$
|
9,020
|
|
|
$
|
45,853
|
|
108
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
|
|
109
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
|
|
|
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
|
|
110
QUARTERLY
FINANCIAL DATA
(Unaudited)
Summarized quarterly financial data are as follows (thousands,
except
per-unit
amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
Quarter
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
150,362
|
|
|
$
|
178,245
|
|
|
$
|
175,713
|
|
|
$
|
132,740
|
|
Costs and operating expenses
|
|
|
124,050
|
|
|
|
136,033
|
|
|
|
127,737
|
|
|
|
102,232
|
|
Net income
|
|
|
43,629
|
|
|
|
71,822
|
|
|
|
60,833
|
|
|
|
15,105
|
(a)(b)
|
Basic and diluted net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
0.66
|
|
|
$
|
0.92
|
|
|
$
|
0.82
|
|
|
$
|
0.15
|
|
Subordinated units(c)
|
|
$
|
0.66
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
(d)
|
Basic and diluted net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting
principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
0.31
|
|
|
$
|
0.48
|
(e)
|
|
$
|
0.62
|
|
|
$
|
0.56
|
|
Subordinated units
|
|
$
|
0.31
|
|
|
$
|
0.48
|
(e)
|
|
$
|
0.62
|
|
|
$
|
0.56
|
|
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$
|
0.31
|
|
|
$
|
0.48
|
(e)
|
|
$
|
0.62
|
|
|
$
|
0.56
|
|
Subordinated units
|
|
$
|
0.31
|
|
|
$
|
0.48
|
(e)
|
|
$
|
0.62
|
|
|
$
|
0.56
|
|
|
|
|
(a) |
|
During September 2008, Discoverys offshore gathering
system sustained hurricane damage and was unable to accept gas
from producers while repairs were being made through the end of
2008. In addition, throughout the fourth quarter of 2008 we have
seen significantly lower
per-unit
margins as NGL prices, especially ethane, declined along with
the price of crude oil. These lower NGL margins have
significantly reduced the profitability of our gathering and
processing businesses including Four Corners and our ownership
interests in Wamsutter and Discovery. |
|
(b) |
|
The fourth quarter of 2008 includes a $6.2 million
impairment of the Carbonate Trend pipeline (see Note 7
Other (Income) Expense). |
|
(c) |
|
Subordinated units converted to common on February 19, 2008. |
|
(d) |
|
The fourth quarter of 2007 included a $10.4 million
impairment of the Carbonate Trend pipeline (see Note 7
Other (Income) Expense) and reduction in operating income from
the shutdown of the Ignacio gas processing plant resulting from
a fire. |
|
(e) |
|
We retrospectively adjusted earnings per unit for the second
quarter of 2007 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. |
111
The following table presents the allocation of net income for
purposes of calculating earnings per unit for each quarter in
2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
(Dollars in thousands)
|
|
Net income allocated to limited partners by quarter:
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
$
|
34,718
|
|
|
$
|
12,225
|
|
|
$
|
4,898
|
|
Second quarter
|
|
|
48,814
|
|
|
|
19,017
|
|
|
|
3,795
|
|
Third quarter
|
|
|
43,378
|
|
|
|
24,492
|
|
|
|
12,213
|
|
Fourth quarter
|
|
|
7,925
|
|
|
|
23,707
|
|
|
|
11,289
|
|
Weighted average common units outstanding by quarter:
|
|
|
|
|
|
|
|
|
|
|
|
|
First quarter
|
|
|
52,774,728
|
|
|
|
39,358,798
|
|
|
|
14,006,146
|
|
Second quarter
|
|
|
52,774,728
|
|
|
|
39,358,798
|
|
|
|
14,923,619
|
|
Third quarter
|
|
|
52,775,912
|
|
|
|
39,359,555
|
|
|
|
21,597,072
|
|
Fourth quarter
|
|
|
52,777,452
|
|
|
|
42,422,444
|
|
|
|
25,266,210
|
|
112
|
|
Item 9.
|
Changes
In and Disagreements With Accountants on Accounting and
Financial Disclosure
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None.
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Item 9A.
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Controls
and Procedures
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Disclosure
Controls and Procedures
Our management, including our general partners Chief
Executive Officer and Chief Financial Officer, does not expect
that our disclosure controls and procedures (as defined in
Rules 13a 15(e) and 15d 15(e) of
the Securities Exchange Act) (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 Williams
Partners L.P. 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.
An evaluation of the effectiveness of the design and operation
of our 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
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.
Managements
Annual Report on Internal Control over Financial
Reporting
See report set forth above in Item 8, Financial
Statements and Supplementary Data.
Report of
Independent Registered Public Accounting Firm on Internal
Control Over Financial Reporting
See report set forth above in Item 8, Financial
Statements and Supplementary Data.
Changes
in Internal Controls Over Financial Reporting
There have been no changes during the fourth quarter of 2008
that have materially affected, or are reasonably likely to
materially affect, our Internal Controls over financial
reporting.
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Item 9B.
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Other
Information
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There have been no events that occurred in the fourth quarter of
2008 that would need to be reported on
Form 8-K
that have not been previously reported.
PART III
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Item 10.
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Directors,
Executive Officers and Corporate Governance
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As a limited partnership, we have no directors or officers.
Instead, our general partner, Williams Partners GP LLC, manages
our operations and activities. Our general partner is not
elected by our unitholders and is
113
not subject to re-election on a regular basis in the future.
Unitholders are not entitled to elect the directors of our
general partner or directly or indirectly participate in our
management or operation.
We are managed and operated by the directors and officers of our
general partner. All of our operational personnel are employees
of an affiliate of our general partner.
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, 2009.
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Name
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Age
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Position with Williams Partners GP LLC
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Steven J. Malcolm
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60
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Chairman of the Board and Chief Executive Officer
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Donald R. Chappel
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57
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Chief Financial Officer and Director
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Alan S. Armstrong
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46
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Chief Operating Officer and Director
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James J. Bender
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52
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General Counsel
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H. Michael Krimbill
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55
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Director and Member of Audit and Conflicts Committees
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Bill Z. Parker
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61
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Director and Member of Audit and Conflicts Committees
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Alice M. Peterson
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56
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Director and Member of Audit and Conflicts Committees
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Rodney J. Sailor
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50
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Director and Treasurer
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The directors of our general partner are elected for one-year
terms and hold office until the earlier of their death,
resignation, removal or disqualification or until their
successors have been elected and qualified. Officers serve at
the discretion of the board of directors of our general partner.
There are no family relationships among any of the directors or
executive officers of our general partner.
Steven J. Malcolm has served as the chairman of the board
of directors and chief executive officer of our general partner
since February 2005. Mr. Malcolm has served as president of
Williams since September 2001, chief executive officer 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 has served as a member of the board of
directors of BOK Financial Corporation and Bank of Oklahoma,
N.A. 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.
Alan S. Armstrong has served as the chief operating
officer and a director of our general partner since February
2005. Since February 2002, Mr. Armstrong has served as a
senior vice president of Williams responsible for heading
Williams midstream business unit. From 1999 to February
2002, Mr. Armstrong was vice president, gathering and
processing in Williams midstream business unit and from
1998 to 1999 was vice president, commercial development, in
Williams midstream business unit.
114
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. From June 2000 to June 2002, Mr. Bender was
senior vice president and general counsel with NRG Energy, Inc.
Mr. Bender was vice president, general counsel and
secretary of NRG Energy from June 1997 to June 2000.
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 in January, 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 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 Navistar Financial Corporation, a wholly owned subsidiary of
Navistar International, since June 2006. 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 in oil and gas exploration and production in Argentina,
since September 2006, and as a director and treasurer of the
general partner of Williams Pipeline Partners L.P. since August
2007.
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.
115
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 has adopted
director independence standards, which are included in our
governance guidelines and set forth below. Our governance
guidelines are available on our Internet website at
http://www.williamslp.com
under the Investor Relations caption. Under the
director independence 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 $120,000 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 (other than an executive officer) 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 is a current partner or employee of a firm
that is the present or former internal or external auditor for
the Partnership Group, (ii) the director has an immediate
family member who is a current partner of such a firm,
(iii) the director has an immediate family member who is a
current employee of such a firm and personally works on the
Partnership Groups audit (iv) the director or an
immediately family member was within the last three years a
partner or employee of such a firm and personally worked on an
audit for the Partnership Group within that time.
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if the director or an immediate family member is, or has been
within the last three years, employed as an executive officer of
another company where any of the Partnership Groups
present executive officers at the same time serves or served on
that companys compensation committee.
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if the board of directors determines that a discretionary
contribution made by any member of the Partnership Group to a
non-profit organization with which a director, or a
directors spouse, has a relationship, impacts the
directors independence.
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Our general partners board of directors has affirmatively
determined that each of Ms. Peterson and
Messrs. Krimbill and Parker is an independent
director under the current listing standards of the New
York Stock Exchange and our director independence 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 transactions and relationships between
each director and the Partnership Group, 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. 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 noted that, since
116
Mr. Krimbill does not serve as executive officer and does
not own a significant amount of voting securities of Seminole
Energy Services LLC, this relationship is 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, and Sailor 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 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.
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:
lafleur.browne@williams.com
117
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, 2009.
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.
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.
118
Section 16(a)
Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934
requires our general partners executive 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. Executive officers and directors
of our general partner and greater than 10% 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, 2008 our general partners
officers, our directors and our greater than 10% common
unitholders filed all reports they were required to file under
Section 16(a) on a timely basis.
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, 2008. 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.
119
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 from
Ernst & Young LLP required by applicable requirements
of the Public Company Accounting Oversight Board regarding the
independent accountants communications with the audit
committee concerning independence, and discussed with
Ernst & Young LLP its independence;
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discussed with Ernst & Young LLP the matters required
to be discussed by the statement on Auditing Standards
No. 61, as amended, as adopted by the Public Company
Accounting Oversight Board in Rule 3200T;
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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, 2008, 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 17, 2009
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.
120
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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 with
us 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 2009 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, our
principal financial officer, Donald R. Chappel, who also serves
as the chief financial officer of Williams, and Alan S.
Armstrong, our chief operating officer, who also serves as a
senior vice president of Williams, will be set forth in the
proxy statement for Williams 2009 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. 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.
121
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. In 2008, non-employee directors
each received 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.
In addition to the annual compensation package, each
non-employee director received a one-time grant of restricted
units valued at $25,000 on the date of first election to the
board of directors. In 2009, non-employees directors will
receive an annual compensation package consisting of the
following: (a) $75,000 cash retainer; and (b) $5,000
cash for service on the conflicts or audit committees of the
board of directors. In addition to the annual compensation
package, each non-employee director will receive a one-time
payment of $25,000 on the date of first election to the board of
directors and each non-employee director serving as a member of
the conflicts committee of the board of directors receives
$1,250 cash for each conflicts committee meeting attended by
such director. 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. Fees for attendance
at meetings of the conflicts committee are paid on August 22 and
February 1 of each year for meetings held during the preceding
months. Restricted units awarded to non-employee directors under
the annual compensation package or upon first election to the
board of directors were granted under the Williams Partners GP
LLC Long-Term Incentive Plan and vested 180 days after the
date of grant. Cash distributions were 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 2008:
Director
Compensation Fiscal Year 2008
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Change in Pension
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Value and
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Nonqualified
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Non-Equity
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Deferred
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Fees Earned or Paid
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Unit
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Option
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Incentive Plan
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Compensation
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All Other
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Name
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in Cash
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Awards(1)
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Awards
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Compensation
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Earnings
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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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47,628
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(2)
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$
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107,628
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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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24,995
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(3)
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$
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84,995
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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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24,995
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(4)
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$
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84,995
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122
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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 2008 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 2008 restricted units for
Mr. Krimbill is $24,988. At fiscal year end,
Mr. Krimbill had an aggregate of 908 restricted units
outstanding. |
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(3) |
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The grant date fair value for the 2008 restricted units for
Mr. Parker is $24,988. At fiscal year end, Mr. Parker
had an aggregate of 908 restricted units outstanding. |
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(4) |
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The grant date fair value for the 2008 restricted units for
Ms. Peterson is $24,988. At fiscal year end,
Ms. Peterson had an aggregate of 908 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. On
December 2, 2008, the board of directors of our general
partner approved an amendment to the long-term incentive plan to
comply with Section 409A of the Internal Revenue Code of
1986 and its relevant regulations. 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, except for specific adjustment
rights detailed in the plan, 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
A restricted unit is a common unit subject to forfeiture prior
to the vesting of the award. The board of directors of our
general partner may determine to make grants under the plan of
restricted 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 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 will vest upon a change of
control (as defined by the plan) of Williams Partners L.P., our
general partner or Williams, unless provided otherwise by the
board of directors or in the applicable award agreement.
If a grantees employment, service relationship or
membership on the board of directors terminates for any reason,
the grantees restricted units will be automatically
forfeited unless, and to the extent, the board of directors
provides otherwise in the award agreement or other written
agreement. The board of directors may, in its discretion, waive
in whole or in part such forfeiture provided that such waiver
does not cause adverse tax consequences to the participant under
Section 409A of the Internal Revenue Code. Common units to
be delivered in connection with the grant of restricted 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
123
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 will be borne by
us. If we issue new common units in connection with the grant of
restricted units, the total number of common units outstanding
will increase. The board of directors of our general partner, in
its discretion, may grant tandem distribution rights with
respect to restricted units.
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Item 12.
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Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
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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 executive officers of our general partner; and
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all directors and executive officers of our general partner as a
group.
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The amounts and percentage of units beneficially owned are
reported on the basis of regulations of the SEC governing the
determination of beneficial ownership of securities. Under the
rules of the SEC, a person is deemed to be a beneficial
owner of a security if that person has or shares
voting power, which includes the power to vote or to
direct the voting of such security, or investment
power, which includes the power to dispose of or to direct
the disposition of such security. A person is also deemed to be
a beneficial owner of any securities of which that person has a
right to acquire beneficial ownership within 60 days. Under
these rules, more than one person may be deemed a beneficial
owner of the same securities and a person may be deemed a
beneficial owner of securities as to which he has no economic
interest.
Except as indicated by footnote, the persons named in the table
below have sole voting and investment power with respect to all
units shown as beneficially owned by them, subject to community
property laws where applicable.
Percentage of total units beneficially owned is based on
52,777,452 units outstanding. Unless otherwise noted below,
the address for the beneficial owners listed below is One
Williams Center, Tulsa, Oklahoma
74172-0172.
124
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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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22.00
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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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5.36
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%
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Kayne Anderson Capital Advisors,
L.P./Richard A. Kayne(b)
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4,198,808
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7.96
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%
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Prudential Financial, Inc.(c)
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3,099,864
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5.87
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%
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Jennison Associates LLC(d)
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3,098,249
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5.87
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%
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Alan S. Armstrong(e)
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20,000
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*
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James J. Bender
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10,000
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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
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47,151
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*
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Steven J. Malcolm(f)
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25,100
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*
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Bill Z. Parker
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9,524
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*
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Alice M. Peterson
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4,524
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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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126,299
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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
February 28, 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. The address of these companies is One Williams Center,
Tulsa, Oklahoma 74172. |
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(b) |
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Based solely on the Schedule 13G filed with the SEC on
February 12, 2009, Kayne Anderson Capital Advisors, L.P.
(Kayne Capital), an investment advisor registered under
Section 203 of the Investment Advisors Act of 1940, and
Richard A. Kayne, a U.S. citizen, may be deemed to be the
beneficial owner of units owned by investment accounts
(investment limited partnerships, a registered investment
company and institutional accounts) managed, with discretion to
purchase or sell securities, by Kayne Capital. The
Schedule 13G notes that Mr. Kayne is the controlling
shareholder of the corporate owner of Kayne Anderson Investment
Management, Inc., the general partner of Kayne Capital, and is
also a limited partner of each of the limited partnerships and a
shareholder of the registered investment company. The address of
Kayne Capital and Mr. Kayne is 1800 Avenue of the Stars,
Second Floor, Los Angeles, California 90067. |
125
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(c) |
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Based solely on the Schedule 13G/A filed with the SEC on
February 6, 2009, 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
and/or investment discretion 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 3,098,749 common units. The
Schedule 13G/A 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. |
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(d) |
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Based solely on the Schedule 13G/A filed with the SEC on
February 17, 2009, 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 (managed portfolios) for which it acts as
an investment advisor. The 13G/A indicates that one such managed
portfolio, Prudential Sector Funds, Inc., d/b/a JennisonDryden
Sector Funds, Jennison Utility Fund, owns more than 5% of the
class of securities which are the subject of this report. The
Schedule 13G/A notes that Prudential 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/A further notes that Jennison does not file
jointly with Prudential and the common units reported by
Jennison in its Schedule 13G/A may be included in the
common units reported in the Schedule 13G/A filed by
Prudential. The address of Jennison is 466 Lexington Avenue, New
York, New York 10017. |
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(e) |
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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, 10,000 common units that are held by
the trust. |
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(f) |
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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 17, 2009,
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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150,918
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219,489
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370,407
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*
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James J. Bender
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137,900
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123,670
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261,570
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*
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Donald R. Chappel
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290,567
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396,145
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686,712
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*
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Steven J. Malcolm
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904,524
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1,917,876
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2,822,400
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*
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Rodney J. Sailor
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33,583
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53,530
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87,113
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*
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Bill Z. Parker
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Alice M. Peterson
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H. Michael Krimbill
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All directors and executive officers as a group (eight persons)
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1,517,492
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2,710,710
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4,228,202
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*
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* |
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Less than 1%. |
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(a) |
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Includes shares held under the terms of incentive and investment
plans as follows: Mr. Armstrong, 15 shares in The
Williams Companies Investment Plus Plan, 107,259 restricted
stock units and 43,644 beneficially owned shares;
Mr. Bender, 2,800 shares owned by children, 101,538
restricted stock units and |
126
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33,562 beneficially owned shares; Mr. Chappel, 171,433
restricted stock units and 119,134 beneficially owned shares;
Mr. Malcolm, 46,680 shares in The Williams Companies
Investment Plus Plan, 292,192 restricted stock units and 565,652
beneficially owned shares; and Mr. Sailor,
6,241 shares in The Williams Investment Plus Plan, 25,641
restricted stock units and 1,701 beneficially owned shares.
Restricted stock units do not provide the holder with voting or
investment power. |
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(b) |
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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 17, 2009. 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,
2008. 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
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Remaining Available
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Number of Securities
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Weighted-Average
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for Future Issuance
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to be Issued Upon
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Exercise Price of
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Under Equity
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Exercise of Outstanding
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Outstanding
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Compensation Plan
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Options, Warrants
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Options, Warrants
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(Excluding Securities
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and Rights
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and Rights
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Reflected in Column(a))
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Plan Category
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(a)
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(b)
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(c)
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Equity compensation plans approved by security holders
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Equity compensation plans not approved by security holders
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(1)
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686,597
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Total
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686,597
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(1) |
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2,724 unvested restricted units granted pursuant to the Williams
Partners GP LLC Long-Term Incentive Plan were outstanding as of
December 31, 2008. All of these restricted units vested on
February 18, 2009. No value is shown in column (b) of
the table because the restricted units do not have an exercise
price. To date, the only grants under the plan have been grants
of restricted units. |
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Item 13.
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Certain
Relationships and Related Transactions, and Director
Independence
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Transactions
with Related Persons
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.
127
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 Williams Partners L.P.
These distributions and payments were determined by and among
affiliated entities and, consequently, are not the result of
arms-length negotiations.
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Operational Stage |
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Distributions of available cash to our general partner and its
affiliates
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We will generally make cash distributions 98% to unitholders,
including our general partner and its affiliates as holders of
an aggregate of 11,613,527 common units and the remaining 2% to
our general partner. |
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In addition, if distributions exceed the minimum quarterly
distribution and other higher target levels, our general partner
will be entitled to increasing percentages of the distributions,
up to 50% of the distributions above the highest target level.
We refer to the rights to the increasing distributions as
incentive distribution rights. For further
information about distributions, please read Market for
Registrants Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities. |
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Reimbursement of expenses to our general partner and its
affiliates
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Our general partner does not receive a management fee or other
compensation for the management of our partnership. Our general
partner and its affiliates are reimbursed, however, for all
direct and indirect expenses incurred on our behalf. Our general
partner determines the amount of these expenses. |
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Withdrawal or removal of our general partner
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If our general partner withdraws or is removed, its general
partner interest and its incentive distribution rights will
either be sold to the new general partner for cash or converted
into common units, in each case for an amount equal to the fair
market value of those interests. |
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Liquidation Stage |
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Liquidation
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Upon our liquidation, the partners, including our general
partner, will be entitled to receive liquidating distributions
according to their particular capital account balances. |
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, 2008, our general
partner allocated $240,903 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, $108,935 of salary and non-equity incentive plan
compensation expense to us for Donald R. Chappel, the chief
financial officer of our general partner, $270,063 of salary and
128
non-equity incentive plan compensation expense to us for Alan S.
Armstrong, the chief operating officer of our general partner,
$74,112 of salary and non-equity incentive plan compensation
expense to us for James J. Bender, the general counsel of our
general partner and $34,084 of salary and non-equity incentive
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
$121,051 for Mr. Malcolm, $70,021 for Mr. Chappel,
$132,759 for Mr. Armstrong, $32,969 for Mr. Bender and
$16,713 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, Bender 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 2007 or 2008. 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, Mr. Chappel, the chief financial officer of our
general partner who is also the chief financial officer of
Williams, and Mr. Armstrong, the chief operating officer of
our general partner who is also a senior vice president of
Williams, will be set forth in the proxy statement for
Williams 2009 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, 2008, we incurred
approximately $120.8 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;
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indemnification for certain environmental liabilities, tax
liabilities and right-of-way defects;
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reimbursement for certain expenditures; and
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a license for the use of certain software and intellectual
property.
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General
and Administrative Expenses
Williams will provide us with a five-year partial credit for
general and administrative (G&A) expenses incurred on our
behalf. In 2006, 2007 and 2008, the amounts of the G&A
credit were $3.2 million,$2.4 million and $1.6,
respectively, and in 2009 the amount of the credit will be
$0.8 million. After 2009, we will no longer receive any
credit and will be required to reimburse Williams for all of the
general and administrative expenses incurred on our behalf.
Indemnification
for Environmental and Related Liabilities
Williams agreed to indemnify us after the closing of our initial
public offering against certain environmental and related
liabilities arising out of or associated with the operation of
the assets before the closing date of our initial public
offering. These liabilities include both known and unknown
environmental and related liabilities, including:
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remediation costs associated with the KDHE Consent Orders and
certain NGLs associated with our Conway storage facilities;
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129
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the costs associated with the installation of wellhead control
equipment and well meters at our Conway storage facility;
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KDHE-related cavern compliance at our Conway storage
facility; and
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the costs relating to the restoration of the overburden along
our Carbonate Trend pipeline in connection with erosion caused
by Hurricane Ivan in September 2004.
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Williams will not be required to indemnify us for any project
management or monitoring costs. This indemnification obligation
terminated 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
certain income tax liabilities attributable to the operation of
the assets contributed to us in connection with our initial
public offering prior to the time they were contributed.
For the year ended December 31, 2008, Williams indemnified
us $1.3 million, primarily for Discoverys marshland
mitigation and Conways KDHE-related compliance. Including
2008, Williams has indemnified us for an aggregate of
$6.7 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 $72.9 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.
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.
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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.
Wamsutter
Credit Facility
Wamsutter also has a $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 December 12,
2009 with four, one-year automatic extensions unless terminated
by either party. Wamsutter pays a commitment fee to Williams on
the unused portion of the credit facility of 0.125% annually.
Interest on any borrowings under the facility will be calculated
upon a periodic fixed rate equal to LIBOR plus an applicable
margin, or a base rate plus the applicable margin. As of
December 31, 2008, Wamsutter had no outstanding borrowings
under the credit facility.
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, Wamsutters limited liability company
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 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, 2008, Discovery reimbursed
Williams $4.8 million for direct payroll and employee
benefit costs, as well as $0.3 million for capitalized
labor costs, pursuant to the operating and maintenance
agreements and paid Williams $4.5 million for operation and
management fees, as well as a $0.4 million fee for managing
capitalized projects, pursuant to the operating and maintenance
agreements.
131
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 NGLs 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.
For the year ended December 31, 2008, we sold
$314.3 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 $134.8 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 $207.7 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.
These contracts expired in December 2008.
Gathering,
Processing and Treating Contracts
We have a gas gathering and treating contract and a gas
gathering and processing contract with an affiliate of Williams.
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. 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. 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
$37.9 million in 2008.
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
$140.7 million of natural gas from Williams Gas Marketing
during 2008. Wamsutter purchased approximately
$54.1 million and Discovery purchased approximately
$57.2 million of natural gas for fuel and shrink
replacement from Williams Gas Marketing during 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
this waste heat. We purchase this natural gas from Williams Gas
Marketing. Included in the $140.7 million presented in the
immediately preceding paragraph is $22.3 million of natural
gas purchases made to pursuant to this arrangement.
132
For the year ended December 31, 2008 we purchased a gross
amount of $22.5 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 for 2008 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.
These contracts expired in December 2008.
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 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, 2008:
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we distributed $55.2 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 $15.2 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
133
consider any factors it determines in good faith to consider
when resolving a conflict. When our partnership agreement
requires someone to act in good faith, it requires that person
to reasonably believe that he is acting in the best interests of
the partnership, unless the context otherwise requires. See
Directors, Executive Officers and Corporate
Governance Governance Board Committees
Conflict Committee.
In addition, our code of business conduct and ethics requires
that all employees, including employees of affiliates of
Williams who perform services for us and our general partner,
avoid or disclose any activity that may interfere, or have the
appearance of interfering, with their responsibilities to us and
our unitholders. Conflicts of interest that cannot be avoided
must be disclosed to a supervisor who is then responsible for
establishing and monitoring procedures to ensure that we are not
disadvantaged.
Director
Independence
Please read Directors, Executive Officers and Corporate
Governance Governance Director
Independence above for information about the independence
of our general partners board of directors and its
committees, which information is incorporated herein by
reference in its entirety.
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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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2008
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2007
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(Thousands)
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Audit Fees
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$
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1,066
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$
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1,416
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Audit-Related Fees
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Tax Fees
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35
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35
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All Other Fees
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$
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1,101
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$
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1,451
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Fees for audit services in 2008 and 2007 include fees associated
with the annual audit, the reviews of our quarterly reports on
Form 10-Q,
the audit of our assessment of internal controls as required by
Section 404 of the Sarbanes-Oxley Act of 2002 and services
provided in connection with other filings with the SEC. The
audit fees for 2007 in the table above also include
$0.3 million for services provided in connection with the
acquisition of interests in Discovery and Wamsutter. The fees
for audit services do not include audit costs for stand-alone
audits for equity investees, including Discovery or Wamsutter.
Tax fees for 2008 and 2007 include fees for review of our
federal tax return. Ernst & Young LLP does not provide
tax services to our general partners executive officers.
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 2008 and
2007, 100% of Ernst & Young LLPs fees were
pre-approved by the audit committee.
134
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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79
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80
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81
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82
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83
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Not covered by reports of independent auditors:
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111
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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 following documents are included as exhibits
to this 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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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, 3 and 4
(attached as Exhibit 3.1 to Williams Partners L.P.s
quarterly report on Form 10-Q (File No. 001-32599) filed with
the SEC on May 1, 2008).
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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).
|
|
*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).
|
|
*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
|
|
|
|
Amendment No. 2 to the Williams Partners GP LLC Long-Term
Incentive Plan, dated December 2, 2008.
|
|
*Exhibit 10
|
.5
|
|
|
|
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
|
.6
|
|
|
|
Third Amended and Restated Limited Liability Company Agreement
for Discovery Producer Services LLC (attached as Exhibit 10.7 to
Amendment No. 1 to Williams Partners L.P.s registration
statement on Form S-1 (File No. 333-124517) filed with the SEC
on June 24, 2005).
|
|
*Exhibit 10
|
.7
|
|
|
|
Amendment No. 1 to Third Amended and Restated Limited Liability
Company Agreement for Discovery Producer Services LLC (attached
as Exhibit 10.6 to Williams Partners L.P.s quarterly
report on Form 10-Q (File No. 001-32599) filed with the SEC on
August 8, 2006).
|
136
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
+#Exhibit 10
|
.8
|
|
|
|
Director Compensation Policy dated November 29, 2005, as revised
January 26, 2009.
|
|
*#Exhibit 10
|
.9
|
|
|
|
Form of Grant Agreement for Restricted Units (attached as
Exhibit 10.2 to Williams Partners L.P.s current report on
Form 8-K (File No. 001-32599) filed with the SEC on December 1,
2005).
|
|
*Exhibit 10
|
.10
|
|
|
|
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
|
.11
|
|
|
|
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
|
.12
|
|
|
|
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
|
.13
|
|
|
|
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
|
.14
|
|
|
|
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
|
.15
|
|
|
|
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
|
.16
|
|
|
|
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
|
.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 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.
|
|
+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.
|
137
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
+Exhibit 32
|
|
|
|
|
Section 1350 Certifications of Chief Executive Officer and Chief
Financial Officer.
|
|
+Exhibit 99.1
|
|
|
|
|
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 |
138
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, 2008 and 2007, and the related
statements of income, members capital, and cash flows for
each of the three years in the period ended December 31,
2008. 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, 2008 and 2007, and the
results of its operations and its cash flows for each of the
three years in the period ended December 31, 2008 in
conformity with U.S. generally accepted accounting
principles.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 23, 2009
139
WAMSUTTER
LLC
BALANCE
SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
8,755
|
|
|
$
|
7,644
|
|
Affiliate
|
|
|
7,178
|
|
|
|
13,299
|
|
Other
|
|
|
100
|
|
|
|
2,424
|
|
Product imbalance
|
|
|
1,032
|
|
|
|
2,038
|
|
Reimbursable capital projects
|
|
|
82
|
|
|
|
1,709
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
17,147
|
|
|
|
27,114
|
|
Gross property, plant and equipment
|
|
|
462,979
|
|
|
|
398,903
|
|
Less accumulated depreciation
|
|
|
(144,907
|
)
|
|
|
(123,740
|
)
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
318,072
|
|
|
|
275,163
|
|
Other noncurrent assets
|
|
|
468
|
|
|
|
191
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
335,687
|
|
|
$
|
302,468
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
9,582
|
|
|
$
|
4,627
|
|
Affiliate
|
|
|
2,407
|
|
|
|
5,153
|
|
Product imbalance
|
|
|
1,753
|
|
|
|
2,296
|
|
Accrued liabilities
|
|
|
3,218
|
|
|
|
940
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
16,960
|
|
|
|
13,016
|
|
Deferred revenue
|
|
|
2,567
|
|
|
|
2,239
|
|
Other noncurrent liabilities
|
|
|
1,786
|
|
|
|
501
|
|
Commitments and contingencies (Note 10)
|
|
|
|
|
|
|
|
|
Members capital
|
|
|
314,374
|
|
|
|
286,712
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members capital
|
|
$
|
335,687
|
|
|
$
|
302,468
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
140
WAMSUTTER
LLC
STATEMENTS
OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
134,776
|
|
|
$
|
93,744
|
|
|
$
|
113,484
|
|
Third-party
|
|
|
27,384
|
|
|
|
7,447
|
|
|
|
|
|
Gathering and processing services
|
|
|
68,670
|
|
|
|
67,904
|
|
|
|
57,859
|
|
Other revenues
|
|
|
8,704
|
|
|
|
6,214
|
|
|
|
5,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
239,534
|
|
|
|
175,309
|
|
|
|
176,546
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
63,064
|
|
|
|
34,973
|
|
|
|
55,206
|
|
Third-party
|
|
|
15,745
|
|
|
|
11,066
|
|
|
|
15,882
|
|
Operating and maintenance expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
(1,513
|
)
|
|
|
36
|
|
|
|
3,969
|
|
Third-party
|
|
|
22,486
|
|
|
|
18,221
|
|
|
|
13,078
|
|
Depreciation and accretion
|
|
|
21,182
|
|
|
|
18,424
|
|
|
|
16,189
|
|
General and administrative expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
12,837
|
|
|
|
11,825
|
|
|
|
8,866
|
|
Third-party
|
|
|
670
|
|
|
|
798
|
|
|
|
|
|
Taxes other than income
|
|
|
1,868
|
|
|
|
1,637
|
|
|
|
1,411
|
|
Other (income) expense net
|
|
|
(569
|
)
|
|
|
944
|
|
|
|
255
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
135,770
|
|
|
|
97,924
|
|
|
|
114,856
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
103,764
|
|
|
$
|
77,385
|
|
|
$
|
61,690
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
141
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, 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
|
|
|
|
|
|
Net income December 2007
|
|
|
|
|
|
|
7,362
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,362
|
|
Capital contributions
|
|
|
|
|
|
|
|
|
|
|
1,088
|
|
|
|
|
|
|
|
|
|
|
|
1,088
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007
|
|
|
|
|
|
|
283,624
|
|
|
|
1,088
|
|
|
|
1,000
|
|
|
|
1,000
|
|
|
|
286,712
|
|
Net income 2008
|
|
|
|
|
|
|
73,312
|
|
|
|
|
|
|
|
15,226
|
|
|
|
15,226
|
|
|
|
103,764
|
|
Capital contributions
|
|
|
|
|
|
|
3,658
|
|
|
|
31,240
|
|
|
|
|
|
|
|
|
|
|
|
34,898
|
|
Transition support payment (distribution)
|
|
|
|
|
|
|
(7,614
|
)
|
|
|
7,614
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
|
|
|
|
|
|
|
(72,050
|
)
|
|
|
|
|
|
|
(19,475
|
)
|
|
|
(19,475
|
)
|
|
|
(111,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2008
|
|
$
|
|
|
|
$
|
280,930
|
|
|
$
|
39,942
|
|
|
$
|
(3,249
|
)
|
|
$
|
(3,249
|
)
|
|
$
|
314,374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Williams and Williams Partners each held 20 Class C units
throughout 2007 and 2008. |
See accompanying notes to financial statements.
142
WAMSUTTER
LLC
STATEMENTS
OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
103,764
|
|
|
$
|
77,385
|
|
|
$
|
61,690
|
|
Adjustments to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and accretion
|
|
|
21,182
|
|
|
|
18,424
|
|
|
|
16,189
|
|
Provision for loss on property plant & equipment
|
|
|
|
|
|
|
1,392
|
|
|
|
|
|
Cash provided (used) by changes in current assets and
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
7,334
|
|
|
|
(16,655
|
)
|
|
|
(1,118
|
)
|
Reimbursable capital projects
|
|
|
1,627
|
|
|
|
(29
|
)
|
|
|
(1,662
|
)
|
Accounts payable
|
|
|
(753
|
)
|
|
|
6,113
|
|
|
|
(659
|
)
|
Product imbalance
|
|
|
463
|
|
|
|
(1,335
|
)
|
|
|
(8
|
)
|
Accrued liabilities
|
|
|
115
|
|
|
|
(662
|
)
|
|
|
473
|
|
Deferred revenue
|
|
|
335
|
|
|
|
882
|
|
|
|
682
|
|
Other, including changes in other noncurrent assets and
liabilities
|
|
|
(426
|
)
|
|
|
26
|
|
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
133,641
|
|
|
|
85,541
|
|
|
|
75,641
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(62,656
|
)
|
|
|
(29,450
|
)
|
|
|
(36,133
|
)
|
Change in accounts payable capital expenditures
|
|
|
2,961
|
|
|
|
(2,174
|
)
|
|
|
93
|
|
Change in accrued liabilities capital expenditures
|
|
|
2,156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(57,539
|
)
|
|
|
(31,624
|
)
|
|
|
(36,040
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
|
|
|
(111,000
|
)
|
|
|
(55,005
|
)
|
|
|
(39,601
|
)
|
Capital contributions
|
|
|
34,898
|
|
|
|
1,088
|
|
|
|
|
|
Transition support payments received from Class B member
|
|
|
7,614
|
|
|
|
|
|
|
|
|
|
Transition support payments distributed to Class A member
|
|
|
(7,614
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by financing activities
|
|
|
(76,102
|
)
|
|
|
(53,917
|
)
|
|
|
(39,601
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
143
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. In June
2007, Williams Field Services Company, LLC (WFSC) formed
Wamsutter LLC, and on December 11, 2007, WFSC conveyed a
natural gas gathering and processing system in Wyoming
previously held by WFSC (the Wamsutter assets) into Wamsutter
LLC in connection with the acquisition of certain ownership
interests in Wamsutter LLC by Williams Partners L.P. (the
Partnership). WFSC is a wholly owned subsidiary of The Williams
Companies, Inc (Williams). The Partnership owned 100% of our
Class A membership interests and 50% of our initial
Class C units (or 20 Class C units). WFSC owned 100%
of our Class B membership interests and the remaining 50%
of our initial Class C units (or 20 Class C units). In
January 2009 we issued an additional 70.8 and 28.8 Class C
units to the Partnership and WFSC, respectively, related to
their funding of expansion capital expenditures placed in
service during 2008. Therefore, the Partnership now owns 65% and
WFSC owns 35% of our outstanding 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. The system includes approximately 1,800 miles of
natural gas gathering pipelines with typical operating capacity
of approximately 500 million cubic feet per day (MMcf/d) at
current operating pressures. The system has total compression of
approximately 69,000 horsepower. The assets also include the
Echo Springs natural gas processing plant, which has an inlet
capacity of 390 MMcf/d 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. 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 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. We do not recognize an allowance for
doubtful accounts 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. We consider receivables 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
144
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 estimates, assumptions and judgments relative to
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. We remove the cost of property, plant and
equipment sold or retired and the related accumulated
depreciation 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 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
corresponding accretion expense included in operating income.
Revenue Recognition. We recognize revenue for
sales of products when the product has been delivered, and we
generally recognize revenues 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. 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.
|
|
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. Our share of these costs is
charged to us through affiliate billing and 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, Inc. 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.
145
WAMSUTTER
LLC
NOTES TO
FINANCIAL STATEMENTS (Continued)
A summary of affiliate operating and maintenance expense
directly charged to us for the periods stated is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Operating and maintenance expense Affiliate:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas fuel purchases and system (gains) losses
|
|
$
|
(7,287
|
)
|
|
$
|
(5,225
|
)
|
|
$
|
(323
|
)
|
Salaries, benefits and other
|
|
|
5,774
|
|
|
|
5,261
|
|
|
|
4,292
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,513
|
)
|
|
$
|
36
|
|
|
$
|
3,969
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
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, 2008
and 2007 we had receivables from Williams of $4.7 million
and $1.3 million, respectively. 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.
146
WAMSUTTER
LLC
NOTES TO
FINANCIAL STATEMENTS (Continued)
|
|
Note 5.
|
Property,
Plant and Equipment
|
Property, plant and equipment, at cost, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
|
December 31,
|
|
|
Depreciable
|
|
|
|
2008
|
|
|
2007
|
|
|
Lives
|
|
|
|
(In thousands)
|
|
|
|
|
|
Land, rights of way and other
|
|
$
|
22,365
|
|
|
$
|
18,613
|
|
|
|
0- 30 years
|
|
Gathering pipelines and related equipment
|
|
|
336,041
|
|
|
|
313,283
|
|
|
|
10-30 years
|
|
Processing plants and related equipment
|
|
|
50,771
|
|
|
|
48,673
|
|
|
|
30 years
|
|
Buildings and related equipment
|
|
|
11,476
|
|
|
|
11,122
|
|
|
|
3-30 years
|
|
Construction work in progress
|
|
|
42,326
|
|
|
|
7,212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
462,979
|
|
|
|
398,903
|
|
|
|
|
|
Accumulated depreciation
|
|
|
144,907
|
|
|
|
123,740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
318,072
|
|
|
$
|
275,163
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our asset retirement obligation relates 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.
A rollforward of our asset retirement obligation for 2008 and
2007 is presented below.
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Balance, January 1
|
|
$
|
221
|
|
|
$
|
209
|
|
Liabilities incurred during the period
|
|
|
|
|
|
|
|
|
Liabilities settled during the period
|
|
|
|
|
|
|
|
|
Accretion expense
|
|
|
15
|
|
|
|
10
|
|
Estimate revisions
|
|
|
1,420
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31
|
|
$
|
1,656
|
|
|
$
|
221
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 6.
|
Accrued
Liabilities
|
Accrued liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Taxes other than income
|
|
$
|
933
|
|
|
$
|
818
|
|
Construction retainage
|
|
|
2,206
|
|
|
|
50
|
|
Deferred revenue
|
|
|
79
|
|
|
|
72
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,218
|
|
|
$
|
940
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 7.
|
Credit
Facilities and Leasing Activities
|
We have a $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 December 12, 2009 with
four, one-year automatic extensions unless terminated by either
party. We pay a
147
WAMSUTTER
LLC
NOTES TO
FINANCIAL STATEMENTS (Continued)
commitment fee to Williams on the unused portion of the credit
facility of 0.125% annually. Interest on any borrowings under
the facility will be based upon a periodic fixed rate equal to
LIBOR plus an applicable margin, or a base rate plus the
applicable margin. As of December 31, 2008, 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. We also lease vehicles under non-cancelable
leases, which are for lease terms of about 45 months. In
addition, we lease compression units under a lease agreement
with Caterpillar Financial Services on a
60-month
term that began on November 18, 2005. These leases are
accounted for as operating leases. The future minimum annual
rentals under these non-cancelable leases as of
December 31, 2008 are payable as follows:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2009
|
|
$
|
1,362
|
|
2010
|
|
|
1,300
|
|
2011
|
|
|
129
|
|
2012
|
|
|
40
|
|
2013 and thereafter
|
|
|
20
|
|
|
|
|
|
|
|
|
$
|
2,851
|
|
|
|
|
|
|
Total rent expense for the years ended 2008, 2007 and 2006 was
$2.1 million, $2.0 million and $1.7 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,
(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, if needed, to the holder of our
Class A membership interests 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
148
WAMSUTTER
LLC
NOTES TO
FINANCIAL STATEMENTS (Continued)
member receiving $70.0 million, the shortfall will not
carry forward to the next distribution year. Our initial
distribution year began on December 1, 2007 and ended on
November 30, 2008. Subsequent distribution years commence
on December 1 and end on November 30.
Our LLC agreement provides that we will receive a transition
support payment, related to a cap on general and administrative
expenses, from our Class B membership interest each quarter
during 2008 through 2012. This payment is distributed directly
to our Class A membership interest who receives allocated
income equal to the distribution. The reimbursement is treated
as a capital contribution by our Class B membership
interest.
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 membership interests in a manner
that will maintain capital account balances reflective of the
amounts each membership interest would receive if we were
dissolved and liquidated at our carrying value. The Class A
membership interest will receive 100% of our annual net income
up to $70.0 million. Income in excess of $70 million
will be shared between the Class A membership interest and
Class C membership interest. Our net income allocation does
not affect the amount of available cash we distribute for any
quarter.
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 member. Our
Class A member 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. As of
December 31, 2008 Williams has contributed an additional
$28.8 million for an expansion capital project that is
expected to be placed in service during 2010. Williams will
receive Class C units related to these expenditures after
the asset is placed in service.
Limitations of members liability. Our
LLC agreement provides that we will indemnify and hold harmless
each member from and against all losses, claims, damages,
liabilities, expenses (including attorneys fees), and
other amounts, that arise out of or are incidental to our
business or the members status as a member, unless
incurred due to the actual fraud or willful misconduct of the
member. The LLC agreement further provides that no member will
be personally liable for any of our debts, liabilities or
obligations with the exception of certain capital contributions
provided by the terms of our LLC agreement and the amount of any
distribution made to such member that must be returned to us
pursuant to the Delaware Limited Liability Company Act.
Liquidation preferences. Our LLC agreement
provides that proceeds from liquidation would be distributed in
preferential order to the Class B, A and C members with
each of these members fully recovering their unrecovered capital
account balance before moving to the next class of ownership.
Any remaining proceeds would be distributed 5% to the
Class A membership interest and 95% to the Class C
membership interest.
|
|
Note 9.
|
Major
Customers and Concentrations of Credit Risk
|
At December 31, 2008 and 2007, substantially all of our
accounts receivable result from product sales and gathering and
processing services provided to our five largest customers. One
customer is an affiliate of Williams which minimizes our credit
risk exposure. The remaining 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
149
WAMSUTTER
LLC
NOTES TO
FINANCIAL STATEMENTS (Continued)
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%, 56% and 66% of
revenues in 2008, 2007 and 2006, respectively. The percentages
for the remaining three largest customers are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Customer A
|
|
|
15
|
%
|
|
|
20
|
%
|
|
|
16
|
%
|
Customer B
|
|
|
7
|
|
|
|
10
|
|
|
|
10
|
|
Customer C
|
|
|
10
|
|
|
|
4
|
|
|
|
|
|
|
|
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
the 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 U.S. 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 and 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 had 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 would not
intervene in any of the Grynberg cases. 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. The District Court dismissed all
claims against us. The matter is on appeal to the Tenth Circuit
Court of Appeals. The amount of any possible liability cannot be
reasonably estimated at this time.
150
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, 2008 and
2007, and the related consolidated statements of income,
members capital, and cash flows for each of the three
years in the period ended December 31, 2008. 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, 2008 and 2007, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2008, in conformity with
U.S. generally accepted accounting principles.
Tulsa, Oklahoma
February 23, 2009
151
DISCOVERY
PRODUCER SERVICES LLC
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
42,052
|
|
|
$
|
38,509
|
|
Trade accounts receivable:
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
202
|
|
|
|
22,467
|
|
Other
|
|
|
1,899
|
|
|
|
5,847
|
|
Insurance receivable
|
|
|
3,373
|
|
|
|
5,692
|
|
Inventory
|
|
|
519
|
|
|
|
483
|
|
Other current assets
|
|
|
2,933
|
|
|
|
5,037
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
50,978
|
|
|
|
78,035
|
|
Restricted cash
|
|
|
3,470
|
|
|
|
6,222
|
|
Property, plant, and equipment, net
|
|
|
370,482
|
|
|
|
368,228
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
424,930
|
|
|
$
|
452,485
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
3,125
|
|
|
$
|
8,106
|
|
Other
|
|
|
34,779
|
|
|
|
17,617
|
|
Accrued liabilities
|
|
|
5,714
|
|
|
|
6,439
|
|
Other current liabilities
|
|
|
1,616
|
|
|
|
1,658
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
45,234
|
|
|
|
33,820
|
|
Noncurrent accrued liabilities
|
|
|
19,771
|
|
|
|
12,216
|
|
Members capital
|
|
|
359,925
|
|
|
|
406,449
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and members capital
|
|
$
|
424,930
|
|
|
$
|
452,485
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
152
DISCOVERY
PRODUCER SERVICES LLC
CONSOLIDATED
STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$
|
207,706
|
|
|
$
|
216,889
|
|
|
$
|
148,385
|
|
Third-party
|
|
|
1,324
|
|
|
|
5,251
|
|
|
|
|
|
Gas and condensate transportation services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
782
|
|
|
|
979
|
|
|
|
3,835
|
|
Third-party
|
|
|
13,308
|
|
|
|
15,553
|
|
|
|
14,668
|
|
Gathering and processing services:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
1,506
|
|
|
|
3,092
|
|
|
|
8,605
|
|
Third-party
|
|
|
12,709
|
|
|
|
17,767
|
|
|
|
19,473
|
|
Other revenues
|
|
|
3,913
|
|
|
|
1,141
|
|
|
|
2,347
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
241,248
|
|
|
|
260,672
|
|
|
|
197,313
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
83,576
|
|
|
|
93,722
|
|
|
|
66,890
|
|
Third-party
|
|
|
63,422
|
|
|
|
61,982
|
|
|
|
52,662
|
|
Operating and maintenance expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
8,836
|
|
|
|
5,579
|
|
|
|
5,276
|
|
Third-party
|
|
|
27,834
|
|
|
|
23,409
|
|
|
|
17,773
|
|
Depreciation and accretion
|
|
|
21,324
|
|
|
|
25,952
|
|
|
|
25,562
|
|
Taxes other than income
|
|
|
1,439
|
|
|
|
1,330
|
|
|
|
1,114
|
|
General and administrative expenses affiliate
|
|
|
4,500
|
|
|
|
2,280
|
|
|
|
2,150
|
|
Other (income) expense, net
|
|
|
(3,511
|
)
|
|
|
534
|
|
|
|
283
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
207,420
|
|
|
|
214,788
|
|
|
|
171,710
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
33,828
|
|
|
|
45,884
|
|
|
|
25,603
|
|
Interest income
|
|
|
(650
|
)
|
|
|
(1,799
|
)
|
|
|
(2,404
|
)
|
Foreign exchange (gain) loss
|
|
|
78
|
|
|
|
(388
|
)
|
|
|
(2,076
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
34,400
|
|
|
$
|
48,071
|
|
|
$
|
30,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
153
DISCOVERY
PRODUCER SERVICES LLC
CONSOLIDATED
STATEMENT OF MEMBERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners
|
|
|
DCP Assets
|
|
|
|
|
|
|
Williams
|
|
|
Operating
|
|
|
Holding,
|
|
|
|
|
|
|
Energy, L.L.C.
|
|
|
LLC
|
|
|
LP
|
|
|
Total
|
|
|
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
|
|
Contributions
|
|
|
|
|
|
|
5,700
|
|
|
|
7,376
|
|
|
|
13,076
|
|
Distributions
|
|
|
|
|
|
|
(56,400
|
)
|
|
|
(37,600
|
)
|
|
|
(94,000
|
)
|
Net income
|
|
|
|
|
|
|
20,641
|
|
|
|
13,759
|
|
|
|
34,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
$
|
|
|
|
$
|
214,871
|
|
|
$
|
145,054
|
|
|
$
|
359,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
154
DISCOVERY
PRODUCER SERVICES LLC
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
34,400
|
|
|
$
|
48,071
|
|
|
$
|
30,083
|
|
Adjustments to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and accretion
|
|
|
21,324
|
|
|
|
25,952
|
|
|
|
25,562
|
|
Net loss on disposal of equipment
|
|
|
175
|
|
|
|
603
|
|
|
|
|
|
Cash provided (used) by changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade accounts receivable
|
|
|
26,213
|
|
|
|
(9,389
|
)
|
|
|
26,599
|
|
Insurance receivable
|
|
|
2,319
|
|
|
|
6,931
|
|
|
|
(12,147
|
)
|
Inventory
|
|
|
(36
|
)
|
|
|
93
|
|
|
|
348
|
|
Other current assets
|
|
|
2,104
|
|
|
|
(802
|
)
|
|
|
(1,911
|
)
|
Accounts payable
|
|
|
5,932
|
|
|
|
(7,540
|
)
|
|
|
(6,062
|
)
|
Accrued liabilities
|
|
|
(725
|
)
|
|
|
1,320
|
|
|
|
(1,086
|
)
|
Other current liabilities
|
|
|
(52
|
)
|
|
|
(3,147
|
)
|
|
|
2,070
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
91,654
|
|
|
|
62,092
|
|
|
|
63,456
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in restricted cash
|
|
|
2,752
|
|
|
|
22,551
|
|
|
|
15,786
|
|
Property, plant, and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(16,188
|
)
|
|
|
(31,739
|
)
|
|
|
(33,516
|
)
|
Proceeds from sale of property, plant and equipment
|
|
|
|
|
|
|
649
|
|
|
|
|
|
Change in accounts payable capital expenditures
|
|
|
6,249
|
|
|
|
2,625
|
|
|
|
568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(7,187
|
)
|
|
|
(5,914
|
)
|
|
|
(17,162
|
)
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to members
|
|
|
(94,000
|
)
|
|
|
(59,172
|
)
|
|
|
(43,598
|
)
|
Capital contributions
|
|
|
13,076
|
|
|
|
3,920
|
|
|
|
13,509
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by financing activities
|
|
|
(80,924
|
)
|
|
|
(55,252
|
)
|
|
|
(30,089
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in cash and cash equivalents
|
|
|
3,543
|
|
|
|
926
|
|
|
|
16,205
|
|
Cash and cash equivalents at beginning of period
|
|
|
38,509
|
|
|
|
37,583
|
|
|
|
21,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
42,052
|
|
|
$
|
38,509
|
|
|
$
|
37,583
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
155
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
Note 1.
|
Organization
and Description of Business
|
Our company consists of Discovery Producer Services LLC (DPS) a
Delaware limited liability company formed on June 24, 1996,
and its wholly owned subsidiary, Discovery Gas Transmission LLC
(DGT) a Delaware limited liability company 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 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 mainline has a design
capacity of
600 MMcf/d
and consists of approximately 105 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.
At the beginning of the periods presented, we were owned 20% by
Williams Energy, L.L.C. (a wholly owned subsidiary of The
Williams Companies, Inc.), 40% by DCP Assets, LP (DCP) and 40%
by Williams Partners Operating LLC (a wholly owned subsidiary of
Williams Partners L.P) (WPZ). Williams Energy, L.L.C. is our
operator. Herein, The Williams Companies, Inc. and its
subsidiaries are collectively referred to as
Williams.
On June 28, 2007, WPZ acquired the 20% interest in us
previously held by Williams Energy, L.L.C. Hence, 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.
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. The cash and cash
equivalent balance is primarily invested in funds with
high-quality, short term securities and instruments that are
issued or guaranteed by the U.S. government. These
securities have 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. We do not recognize an
allowance for doubtful accounts at the time the revenue that
generates the accounts receivable is recognized. We estimate the
allowance for doubtful accounts based on existing economic
conditions, the financial condition of the customers, and the
amount and age of past due accounts. Receivables are considered
past due if full payment is not received by the contractual due
date. Past due accounts are generally written off against the
allowance for doubtful accounts only after all collection
attempts have been exhausted. There was no allowance for
doubtful accounts at December 31, 2008 and 2007.
Insurance Receivable. Hurricane Katrina
damaged our pipeline and onshore facilities in 2005, and
Hurricane Ike damaged the 30 mainline and 18 lateral
in 2008. Expenditures incurred for the repair of these damages
which are probable for recovery when incurred are recorded as
insurance receivable. We expense expenditures up to the
insurance deductible ($6.4 million in 2008), amounts not
covered by insurance ($2.0 million in 2008) and
amounts subsequently determined not to be recoverable.
156
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 weighted average 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. Pursuant to a settlement with our
shippers issued by the Federal Energy Regulatory Commission on
February 5, 2008, if a cash-out refund is due and payable
to a shipper during any year pursuant to Transporters FERC
Gas Tariff, shipper will be deemed to have immediately assigned
its right to the refund amount to us.
Inventory. Inventory includes fractionated
products at our Paradis facility and is carried at the lower of
cost or market. Cost is determined based on the weighted average
natural gas shrink replacement cost.
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 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. 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
property, plant and equipment is provided on a straight-line
basis over the estimated useful lives of 25 to 35 years.
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 the 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
corresponding accretion expense included in operating income.
Revenue Recognition. Revenue for sales of
products is 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 its and
other third parties regulatory proceedings, advice of counsel,
estimated total exposure as discounted and risk weighted, and
collection and other risks. There were no rate refund
liabilities accrued at December 31, 2008 or 2007.
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.
157
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
|
|
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 and
|
|
|
|
processing and sales of natural gas liquids and transportation
of gas and condensate for DCPs affiliates, Texas Eastern
Corporation and ConocoPhillips Company.
|
The following table summarizes these related-party revenues
during 2008, 2007 and 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Williams
|
|
$
|
207,782
|
|
|
$
|
217,012
|
|
|
$
|
148,543
|
|
Texas Eastern Corporation
|
|
|
1,953
|
|
|
|
3,912
|
|
|
|
12,282
|
|
ConocoPhillips
|
|
|
259
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
209,994
|
|
|
$
|
220,960
|
|
|
$
|
160,825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 under a
10-year
leasing agreement for pipeline capacity through 2015 from Texas
Eastern Transmission, LP (an affiliate of DCP)
|
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.
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Capitalized labor
|
|
$
|
317
|
|
|
$
|
222
|
|
|
$
|
373
|
|
Capitalized project fee
|
|
|
375
|
|
|
|
651
|
|
|
|
538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
692
|
|
|
$
|
873
|
|
|
$
|
911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
158
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 4.
|
Property,
Plant, and Equipment
|
Property, plant, and equipment consisted of the following at
December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
|
Years Ended December 31,
|
|
|
Depreciable
|
|
|
|
2008
|
|
|
2007
|
|
|
Lives
|
|
|
|
(In thousands)
|
|
|
|
|
|
Property, plant, and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Construction work in progress
|
|
$
|
76,302
|
|
|
$
|
66,550
|
|
|
|
|
|
Buildings
|
|
|
5,054
|
|
|
|
4,950
|
|
|
|
25 35 years
|
|
Land and land rights
|
|
|
5,575
|
|
|
|
2,491
|
|
|
|
0 35 years
|
|
Transportation lines
|
|
|
305,172
|
|
|
|
311,368
|
|
|
|
25 35 years
|
|
Plant and other equipment
|
|
|
216,189
|
|
|
|
200,722
|
|
|
|
25 35 years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant, and equipment
|
|
|
608,292
|
|
|
|
586,081
|
|
|
|
|
|
Less accumulated depreciation
|
|
|
237,810
|
|
|
|
217,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant, and equipment
|
|
$
|
370,482
|
|
|
$
|
368,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective July 1, 2008, we revised our estimate of the
useful lives of the Larose processing plant and the regulated
pipeline and gathering system. The annual depreciation expense
will decrease $13 million.
Commitments for construction and acquisition of property, plant,
and equipment for the Tahiti pipeline lateral expansion are
approximately $1.5 million at December 31, 2008.
Our asset retirement 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 2008 and
2007 is presented below.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Balance at January 1
|
|
$
|
12,118
|
|
|
$
|
3,728
|
|
Accretion expense
|
|
|
1,082
|
|
|
|
422
|
|
Estimate revisions
|
|
|
3,327
|
|
|
|
7,554
|
|
Liabilities incurred
|
|
|
3,157
|
|
|
|
414
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
19,684
|
|
|
$
|
12,118
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 5.
|
Leasing
Activities
|
We lease the land on which the Paradis fractionator 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 also have a ten-year leasing agreement for
pipeline capacity from Texas Eastern Transmission, LP that
includes renewal options and options to increase capacity which
would also increase rentals. On September 12, 2008, we
filed an amendment to the capacity lease agreement increasing
the leased capacity and resulting in a lease payment
159
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
increase of $380,000 annually. The future minimum annual rentals
under these non-cancelable leases as of December 31, 2008
are payable as follows:
|
|
|
|
|
|
|
(In thousands)
|
|
|
2009
|
|
$
|
1,241
|
|
2010
|
|
|
1,241
|
|
2011
|
|
|
1,241
|
|
2012
|
|
|
1,241
|
|
2013
|
|
|
1,241
|
|
Thereafter
|
|
|
2,105
|
|
|
|
|
|
|
|
|
$
|
8,310
|
|
|
|
|
|
|
Total rent expense for 2008, 2007 and 2006, including a
cancelable platform space lease and
month-to-month
leases, was $1.6 million, $1.4 million and
$1.4 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
|
Amount
|
|
Value
|
|
Amount
|
|
Value
|
|
|
|
|
(In thousands)
|
|
|
|
Cash and cash equivalents
|
|
$
|
42,052
|
|
|
$
|
42,052
|
|
|
$
|
38,509
|
|
|
$
|
38,509
|
|
Restricted cash
|
|
|
3,470
|
|
|
|
3,470
|
|
|
|
6,222
|
|
|
|
6,222
|
|
Concentrations
of Credit Risk
Our cash equivalent balance is primarily invested in funds with
high-quality, short-term securities and instruments that are
issued or guaranteed by the U.S. government.
At December 31, 2008, substantially all of our customer
accounts receivable result from gas transmission services
provided for our largest three 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 2008 and 2007.
Major Customers. Williams accounted for
approximately $208.0 million (86%), $217.0 million
(83%), $149.8 million (75%) respectively, of our total
revenues in 2008, 2007 and 2006. These revenues were for the
sale of NGLs received as compensation under processing contracts
with third-party producers.
160
DISCOVERY
PRODUCER SERVICES LLC
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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Note 7.
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Rate and
Regulatory Matters
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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 30, 2008, DGT
filed to maintain a
lost-and-unaccounted-for
percentage of zero percent until July 1, 2009 and to retain
the 2007 net system gains of $2.3 million that are
unrelated to the
lost-and-unaccounted-for
gas over recovered from its shippers. By Order dated
June 26, 2008 the filing was approved. The approval was
subject to a
30-day
protest period, which passed without protest. As of
December 31, 2008, and 2007, DGT has deferred amounts of
$5.5 million and $5.8 million, respectively, included
in current accrued liabilities in the accompanying Consolidated
Balance Sheets. The December 31, 2008 balance includes 2008
unrecognized net system gains. The December 31, 2007
balance represents amounts collected from customers pursuant to
prior years lost and unaccounted for gas percentage and
unrecognized net system gains.
On October 16, 2008, the FERC issued Order No. 717,
implementing standards of conduct for interstate pipelines and
marketing function employees of the interstate pipeline or of
the pipelines affiliates. The standards of conduct
preclude an interstate pipeline from any actions that might
provide any of its or its affiliates marketing function
employees with an unfair market advantage. The 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 DGTs pipeline; therefore, the standards of
conduct are not currently applicable to DGT.
On November 16, 2007, DGT filed a petition for approval of
a settlement in lieu of a general rate change filing with FERC.
One shipper, ExxonMobil Gas & Power Marketing Company,
filed a protest. 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 settlement allowed Discovery to recognize the amounts
collected from customers pursuant to prior years lost and
unaccounted for gas of $3.5 million. The order is now final
and no longer subject to rehearing. DGT implemented the
settlement rates and surcharges effective January 1, 2008.
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 material
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.
161
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)
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By:
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Williams Partners
GP LLC,
its general partner
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By:
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/s/ Ted
T. Timmermans
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Ted T. Timmermans
Controller (Duly Authorized Officer
and Principal Accounting Officer)
Date: February 26, 2009
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.
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Signature
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Title
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Date
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/s/ STEVEN
J. MALCOLM
Steven
J. Malcolm
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President, Chief Executive Officer and Chairman of the Board
(Principal Executive Officer)
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February 26, 2009
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/s/ DONALD
R. CHAPPEL
Donald
R. Chappel
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Chief Financial Officer and Director (Principal Financial
Officer)
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February 26, 2009
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/s/ TED
T. TIMMERMANS
Ted
T. Timmermans
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Chief Accounting Officer and Controller (Principal Accounting
Officer)
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February 26, 2009
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/s/ ALAN
S. ARMSTRONG*
Alan
S. Armstrong
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Director
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February 26, 2009
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/s/ BILL
Z. PARKER*
Bill
Z. Parker
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Director
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February 26, 2009
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/s/ ALICE
M. PETERSON*
Alice
M. Peterson
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Director
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February 26, 2009
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/s/ H.
MICHAEL KRIMBILL*
H.
Michael Krimbill
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Director
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February 26, 2009
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/s/ RODNEY
J. SAILOR*
Rodney
J. Sailor
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Director
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February 26, 2009
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*By: /s/ WILLIAM
H. GAULT
William
H. Gault
Attorney-in-fact
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February 26, 2009
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162
INDEX TO
EXHIBITS
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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, 3 and 4
(attached as Exhibit 3.1 to Williams Partners L.P.s
quarterly report on
Form 10-Q
(FileNo. 001-32599)
filed with the SEC on May 1, 2008).
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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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163
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Exhibit
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Number
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Description
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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 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).
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*#Exhibit 10
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.2
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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).
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*#Exhibit 10
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.3
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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).
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+#Exhibit 10
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.4
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Amendment No. 2 to the Williams Partners GP LLC Long-Term
Incentive Plan, dated December 2, 2008.
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*Exhibit 10
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.5
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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).
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*Exhibit 10
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.6
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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).
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*Exhibit 10
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.7
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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).
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+#Exhibit 10
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.8
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Director Compensation Policy dated November 29, 2005, as
revised January 26, 2009.
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*#Exhibit 10
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.9
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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).
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*Exhibit 10
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.10
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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).
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*Exhibit 10
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.11
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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).
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*Exhibit 10
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.12
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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).
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164
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Exhibit
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Number
|
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Description
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*Exhibit 10
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.13
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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).
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*Exhibit 10
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.14
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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).
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*Exhibit 10
|
.15
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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).
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*Exhibit 10
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.16
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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).
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*Exhibit 10
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.17
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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).
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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
|
.1
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Consent of Independent Registered Public Accounting Firm,
Ernst & Young LLP.
|
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+Exhibit 23
|
.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.
|
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+Exhibit 31
|
.1
|
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Rule 13a-14(a)/15d-14(a)
Certification of Chief Executive Officer.
|
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+Exhibit 31
|
.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
|
.1
|
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|
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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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Filed herewith. |
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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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Management contract or compensatory plan or arrangement. |
165