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Williams Partners L.P. 10-K 2009 Documents found in this filing:Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C. 20549
Commission file number 1-32599
918-573-2000
Securities registered pursuant to Section 12(b) of the
Act:
Securities registered pursuant to Section 12(g) of the
Act:
None
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 registrant’s 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):
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 registrant’s 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 registrant’s 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
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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
well’s 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.
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WILLIAMS
PARTNERS L.P.
FORM 10-K
PART I
Unless the context clearly indicates otherwise, references in
this report to “we,” “our,” “us”
or like terms refer to Williams Partners L.P. and its
subsidiaries. Unless the context clearly indicates otherwise,
references to “we,” “our,” and
“us” include the operations of Wamsutter LLC
(Wamsutter) and Discovery Producer Services LLC (Discovery) in
which we own interests accounted for as equity investments that
are not consolidated in our financial statements. When we refer
to Wamsutter or Discovery by name, we are referring exclusively
to their businesses and operations.
We 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 SEC’s 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 SEC’s 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 partner’s
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 partner’s secretary at Williams Partners L.P., One
Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
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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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.
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, Discovery’s 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 year’s
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
Wamsutter’s 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.
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.
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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Our Four Corners natural gas gathering pipeline system consists
of:
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
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.
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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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:
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.
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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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
customer’s contract with the competing gathering system
expired.
We own the Wamsutter Ownership Interests and account for this
investment under the equity method of accounting due to the
voting provisions of Wamsutter’s 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
Wamsutter’s 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.
The Wamsutter natural gas gathering pipeline system consists of:
Wamsutter’s 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 Wamsutter’s 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.
Wamsutter’s Class B member, Williams, will fund this
project.
Customers. Three of Wamsutter’s producer
customers (BP America Production Company, Devon Energy
Corporation and Anadarko Petroleum Corporation) accounted for
approximately 78% of Wamsutter’s 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
Wamsutter’s 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
Wamsutter’s 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 Wamsutter’s processing volumes were under fee-based and
keep-whole contracts, respectively.
Wamsutter has three primary competitors. Anadarko’s 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
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.
The Wamsutter LLC Agreement provides for distributions of
available cash to be made quarterly, with available cash defined
as Wamsutter’s 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.
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Wamsutter will distribute its available cash as follows:
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 Wamsutter’s 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.
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:
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.
Most decisions regarding Wamsutter’s 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,
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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.
We own a 60% interest in Discovery and account for this
investment under the equity method of accounting due to the
voting provisions of Discovery’s 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.
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). Discovery’s
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:
Deepwater Gathering. Discovery’s
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 Discovery’s 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
Discovery’s deepwater laterals.
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Discovery’s cryogenic gas processing plant is located near
Larose, Louisiana at the onshore terminus of Discovery’s
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.
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.
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.”
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 Discovery’s 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.
Discovery’s 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 Discovery’s total revenues
less related product costs related to Discovery’s 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 Discovery’s 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 Discovery’s
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. Discovery’s 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.”
Discovery’s portfolio of processing contracts includes the
following types of contracts:
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.
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
Discovery’s contracts that include a bypass option,
Discovery’s 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.
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,
Discovery’s 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.
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.
Hurricane Katrina’s emergency connections to TETCO and TGP
have continued to flow gas through December 2008.
Discovery’s 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
Transmission’s (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.
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 Chevron’s production platform
located at Viosca Knoll Block 251 to an interconnection
point with Shell’s 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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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 Trend’s total throughput and
71% of Carbonate Trend’s 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.
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.
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.
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.
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.
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 Conway’s 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.
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.
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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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.
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.
Discovery’s 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 Discovery’s 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.
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 pipeline’s 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. Discovery’s 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 pipeline’s 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.
The Carbonate Trend pipeline and the Four Corners and Wamsutter
systems are gathering pipelines, and are not subject to the
FERC’s 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 Discovery’s 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
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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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 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
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations —
Environmental.”
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.
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.”
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. 2’s 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 Management’s 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.
Our real property falls into two categories: (1) parcels
that we own in fee, such as land at the Conway fractionation and
storage facility, and (2) parcels in which our interest
derives from leases, easements, rights-of-way, permits or
licenses from landowners or governmental authorities permitting
the use of such land for our operations. The fee sites upon
which major facilities are located have been owned by us or our
predecessors in title for many years without any material
challenge known to us relating to the title to the land upon
which the assets are located, and we believe that we have
satisfactory title to such fee sites. We have no knowledge of
any challenge to the underlying fee title of any material lease,
easement, right-of-way or license held by us or to our title to
any material lease, easement, right-of-way, permit or lease, and
we believe that we have satisfactory title to all of our
material leases, easements, right-of-way and licenses. Our loss
of these rights, through our inability to renew right-of-way
contracts or otherwise, could have a material adverse effect on
our business, results of operations and financial condition and
our ability to make cash distributions to unitholders.
We 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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We have no revenue or segment profit/loss attributable to
international activities.
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:
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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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.
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 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:
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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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.
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 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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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.
Higher natural gas prices over the long term could result in a
decline in the demand for natural gas and, therefore, in
Discovery’s long-term transportation and storage contracts
or throughput on Discovery’s 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 Discovery’s system. As a result, significant
prolonged changes in natural gas prices could have a material
adverse effect on Discovery’s business, financial
condition, results of operations and cash flows, and on our
ability to make distributions to unitholders.
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
Discovery’s 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.
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
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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 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 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.
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.
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
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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.
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 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.
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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
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations — Liquidity and
Capital Resources.”
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:
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
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could also be limited by a downgrade of our credit rating and
other disruptions. Such disruptions could include:
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 Moody’s Investor Service is Ba2, for
Standard & Poor’s is BBB-, and for Fitch Ratings
is BB+. On November 6, 2008, Moody’s 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.
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.
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 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.
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.
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.
Discovery’s and Wamsutter’s 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 Wamsutter’s 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 Discovery’s 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.
Discovery’s interstate natural gas transportation
operations are subject to federal, state and local regulatory
authorities. Specifically, Discovery’s interstate pipeline
transportation service is subject to regulation by FERC. The
federal regulation extends to such matters as:
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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 Discovery’s interstate
pipeline services are set forth in its FERC-approved tariff.
Pursuant to the terms of Discovery’s 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 Discovery’s customers to look for alternative ways to
transport their natural gas.
Discovery’s 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 Discovery’s business, financial
condition, results of operations and cash flows, and on our
ability to make distributions to unitholders.
There are operational risks associated with the gathering,
transporting, processing and treating of natural gas and the
fractionation and storage of NGLs, including:
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.
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 Earth’s 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.
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:
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.
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 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 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.
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.
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.
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.
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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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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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.
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
management’s 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.
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.
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
management’s 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, 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.
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.
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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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.
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 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.
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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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.
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 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
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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. 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.
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 counsel’s 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 counsel’s conclusions or the positions we take. A court
may not agree with some or all of our counsel’s 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.
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.
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
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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.
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.
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.
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
unitholder’s 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.
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 unitholder’s 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.
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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 unitholder’s sale of common units and could
have a negative impact on the value of the common units or
result in audit adjustments to the unitholder’s tax returns.
None.
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.
None.
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.
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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.
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:
We will make distributions of available cash from operating
surplus for any quarter in the following manner:
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Our general partner is entitled to incentive distributions if
the amount we distribute with respect to any quarter exceeds
specified target levels shown below:
If the unitholders remove our general partner other than for
cause and units held by our general partner and its affiliates
are not voted in favor of such removal:
The 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 “Management’s Discussion and Analysis of
Financial Condition and Results of Operations —
Financial Condition and Liquidity.”
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.
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The table should also be read together with
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations” for information
concerning significant trends in the financial condition and
results of operations.
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47
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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.
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:
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 Discovery’s operations in September and
limited its operations throughout the fourth quarter.
Discovery’s 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.
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.
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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, Discovery’s 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 year’s
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
Wamsutter’s 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.
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:
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Gathering, processing and throughput volumes on the following
assets are important components of maximizing our profitability
and the profitability of Wamsutter and Discovery:
We gather approximately 36% of the San Juan Basin’s
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
Discovery’s 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.
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.
We view total gross processing margins as an important measure
of Discovery’s ability to maximize the profitability of its
processing operations. Gross processing margins include revenue
derived from:
The associated costs, primarily shrink replacement gas and fuel
gas, are deducted from these revenues to determine gross
processing margin. Discovery’s mix of processing contract
types and its operation and contract optimization activities are
determinants in processing revenues and gross margins.
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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 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 Discovery’s gross processing margins.
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.
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 management’s 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
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to Consolidated Financial Statements.) Our most recent analysis
utilized judgments and assumptions in the following areas:
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,
Conway’s 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.)
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
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consolidated overview discussion and relate to the segment
tables in Note 15, Segment Disclosures, in our Notes to
Consolidated Financial Statements.
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.
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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.
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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:
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
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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:
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:
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:
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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.
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Wamsutter is accounted for using the equity method of
accounting. As such, our interest in Wamsutter’s 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.
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 Wamsutter’s 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 CIG’s
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
Wamsutter’s 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.
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As described in Note 6, Equity Investments, of our Notes to
Consolidated Financial Statements, Wamsutter’s 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
Wamsutter’s 2008 net income to its unitholders:
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 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 Wamsutter’s 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.
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Results
of operations — Gathering and Processing —
Gulf
The Gulf segment includes the Carbonate Trend gathering pipeline
and our 60% ownership interest in Discovery.
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.)
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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 is accounted for using the equity method of
accounting. As such, our interest in Discovery’s 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 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:
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
Discovery’s management fee charged by Williams.
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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.
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The NGL Services segment includes our three NGL storage
facilities near Conway, Kansas and our 50% undivided interest in
the Conway fractionator.
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.
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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.
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.
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We anticipate our more significant sources of liquidity
will include:
We anticipate our more significant liquidity requirements
to be:
Additionally, we plan to continue pursuing select value-adding
growth opportunities in a prudent manner.
Available Liquidity at December 31, 2008 (in
millions):
These liquidity sources and cash requirements are discussed in
greater detail below.
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 Wamsutter’s 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):
We expect significantly lower cash distributions from our
Wamsutter investment as a result of sharply lower expected NGL
margins in 2009.
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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 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):
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.
On September 13, 2008, Hurricane Ike hit the Gulf Coast
area, and Discovery’s 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.
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:
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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 Wamsutter’s 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.
The table below presents our current credit ratings on our
senior unsecured long-term debt.
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At December 31, 2008, the evaluation of our credit rating
is “stable outlook” from Standard and Poor’s and
Fitch Ratings agencies. On November 6, 2008, Moody’s
Investors Service (Moody’s) 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, Moody’s
revised Williams, and certain Williams’ rated subsidiaries,
excluding us, to “stable” from “negative.”
With respect to Moody’s, 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 Poor’s, 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 Poor’s 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 Poor’s
may modify its ratings with a “+” or a “-”
sign to show the obligor’s 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 obligor’s 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.
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:
Actual and estimated capital expenditures for the years ending
December 31, 2008 and 2009, respectively, are as follows
(all amounts in millions):
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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 Discovery’s 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 Conway’s
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. Conway’s 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.
Wamsutter’s 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.
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.
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
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significantly reducing our profitability and cash flows, could
result in a reduction in our cash distribution to unitholders.
Results
of Operations — Cash Flows
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 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.
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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 Wamsutter’s 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.
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 Wamsutter’s
members pursuant to the distribution provisions of
Wamsutter’s limited liability company agreement. Net cash
used by financing activities in 2007 and 2006 is primarily
distributions of Wamsutter’s net cash flows to Williams
pursuant to its participation in Williams’ cash management
program.
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.
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Net cash used by financing activities include normal cash
distributions to Discovery’s 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 Discovery’s 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):
Our equity investee, Wamsutter, also has contractual obligations
for which we are not contractually liable. These contractual
obligations, however, will impact Wamsutter’s ability to
make cash distributions to us. A summary of Wamsutter’s
total contractual obligations as of December 31, 2008, is
as follows (in thousands):
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Our equity investee, Discovery, also has contractual obligations
for which we are not contractually liable. These contractual
obligations, however, will impact Discovery’s ability to
make cash distributions to us. A summary of Discovery’s
total contractual obligations as of December 31, 2008, is
as follows (in thousands):
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 Wamsutter’s 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.
Discovery’s 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.
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
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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 Discovery’s
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.
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.
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.
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.
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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.
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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 partner’s 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.
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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 Management’s Report
on Internal Control Over Financial Reporting. Our responsibility
is to express an opinion on the Company’s 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 company’s 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 company’s
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
company’s 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.
/s/ Ernst &
Young LLP
Tulsa, Oklahoma
February 23, 2009
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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
Company’s 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.
/s/ Ernst &
Young LLP
Tulsa, Oklahoma
February 23, 2009
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WILLIAMS
PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
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WILLIAMS
PARTNERS L.P.
CONSOLIDATED STATEMENTS OF INCOME
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