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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
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(Mark One) |
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1933 |
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For the fiscal year ended December 31, 2005 |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
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For the transition period
from to |
Commission file number 1-32599
Williams Partners L.P.
(Exact name of Registrant as Specified in Its Charter)
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Delaware |
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20-2485124 |
(State or Other Jurisdiction of
Incorporation or Organization) |
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(IRS Employer
Identification No.) |
One Williams Center, Tulsa, Oklahoma |
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74172-0172 |
(Address of Principal Executive Offices) |
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(Zip Code) |
918-573-2000
(Registrants Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class |
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Name of Each Exchange on Which Registered |
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Common Units |
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the
Act:
None
(Title of Class)
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant: (1) has
filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K is
not contained herein, and will not be contained, to the best of
registrants knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this
Form 10-K or any
amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of accelerated filer and large
accelerated filer in
Rule 12b-2 of the
Exchange Act.
Large accelerated
filer o Accelerated
filer o Non-accelerated
filer þ
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2 of the
Exchange Act). Yes o No
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The registrants common units were not publicly traded as
of the last business day of the registrants most recently
completed second fiscal quarter. The aggregate market value of
the registrants common units held by non-affiliates of the
registrant as of February 28, 2006 was $188,534,290 based
on the closing sale price of such units as reported on the New
York Stock Exchange on such date. This figure excludes common
units beneficially owned by the directors and executive officers
of Williams Partners GP LLC, our general partner.
The registrant had 7,006,146 common units and 7,000,000
subordinated units outstanding as of February 28, 2006.
DOCUMENTS INCORPORATED BY REFERENCE
None
WILLIAMS PARTNERS L.P.
FORM 10-K
TABLE OF CONTENTS
DEFINITIONS
We use the following oil and gas measurements and industry terms
in this report:
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Barrel: One barrel of petroleum products equals 42
U.S. gallons. |
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bpd: Barrels per day. |
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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. |
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¢/ MMBtu: Cents per one million Btus. |
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Fractionation: The process by which a mixed stream of
natural gas liquids is separated into its constituent products. |
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MMBtu: One million Btus. |
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MMBtu/d: One million Btus per day. |
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MMcf: One million cubic feet of natural gas. |
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MMcf/d: One million cubic feet of natural gas per day. |
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NGLs: Natural gas liquids. |
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Recompletions: After the initial completion of a well,
the action and techniques of reentering the well and redoing or
repairing the original completion to restore the wells
productivity. |
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Throughput: The volume of product transported or passing
through a pipeline, plant, terminal or other facility. |
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Workover: Operations on a completed production well to
clean, repair and maintain the well for the purposes of
increasing or restoring production. |
WILLIAMS PARTNERS L.P.
FORM 10-K
PART I
Items 1 and 2. Business
and Properties
References in this report to Williams Partners L.P.,
we, our, us or like terms,
when used in a historical context prior to our initial public
offering of common units on August 23, 2005 refer to the
assets of The Williams Companies, Inc. and its subsidiaries that
were contributed to Williams Partners L.P. and its subsidiaries
in connection with that offering. When used in the context
following the offering or prospectively, those terms refer to
Williams Partners L.P. and its subsidiaries. In either case,
unless the context clearly indicates otherwise, references to
we, our and us include the
operations of Discovery Producer Services LLC, or Discovery, in
which we own a 40 percent interest. When we refer to
Discovery by name, we are referring exclusively to its
businesses and operations.
WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION
We file our annual report on
Form 10-K,
quarterly reports on
Form 10-Q, current
reports on
Form 8-K and other
documents electronically with the SEC under the Securities
Exchange Act of 1934, as amended. From
time-to-time, we may
also file registration and related statements pertaining to
equity or debt offerings. You may read and copy any materials
that we file with the U.S. Securities and Exchange
Commission (SEC) at the SECs Public Reference
Room at 450 Fifth Street, N.W., Washington, DC 20549. You
may obtain information on the operation of the Public Reference
Room by calling the SEC at
1-800-SEC-0330. You may
also obtain such reports from the SECs Internet website at
http://www.sec.gov.
We make available free of charge on or through our Internet
website at http://www.williamslp.com, our annual report
on Form 10-K,
quarterly reports on
Form 10-Q, current
reports on
Form 8-K and
amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Exchange Act as soon as
reasonably practicable after we electronically file such
material with, or furnish it to, the SEC. Our Corporate
Governance Guidelines, Code of Business Conduct and Ethics and
the charters of the audit and compensation committees of our
general partners board of directors are also available on
the Internet website.
Our principal executive offices are located at One Williams
Center, Tulsa, Oklahoma 74172. Our telephone number is
918-573-2000.
GENERAL
We are a Delaware limited partnership formed by The Williams
Companies, Inc., or Williams, in February 2005 to own, operate
and acquire a diversified portfolio of complementary energy
assets. Williams is an integrated energy company with 2005
revenues in excess of $12.5 billion that trades on the New
York Stock Exchange under the symbol WMB. Williams
operates in a number of segments of the energy industry,
including natural gas exploration and production, interstate
natural gas transportation and midstream services. Williams has
been in the midstream natural gas and NGL industry for more than
20 years.
We are principally engaged in the business of gathering,
transporting and processing natural gas and the fractionating
and storing of natural gas liquids. Fractionation is the process
by which a mixed stream of natural gas liquids is separated into
its constituent products, such as ethane, propane and butane.
These natural gas liquids result from natural gas processing and
crude oil refining and are used as petrochemical feedstocks,
heating fuels and gasoline additives, among other applications.
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Our asset portfolio consists of:
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a 40 percent interest in Discovery, which owns an
integrated natural gas gathering and transportation pipeline
system extending from offshore in the Gulf of Mexico to a
natural gas processing facility and a natural gas liquids
fractionator in Louisiana; |
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the Carbonate Trend natural gas gathering pipeline off the coast
of Alabama; and |
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three integrated natural gas liquids storage facilities and a
50 percent interest in a natural gas liquids fractionator
near Conway, Kansas. |
These assets were owned by Williams prior to the initial public
offering (IPO) of our common units in August 2005.
Williams indirectly owns an approximate 59 percent limited
partnership interest in us and all of our two percent general
partner interest.
Initial Public Offering and Concurrent Transactions
On August 23, 2005, we completed our IPO of 5,000,000
common units representing limited partner interests in us at a
price of $21.50 per unit. Concurrent with the closing of
the IPO, a 40 percent interest in Discovery and all of the
interests in Carbonate Trend Pipeline LLC and Mid-Continent
Fractionation and Storage, LLC were contributed to us by
Williams subsidiaries in exchange for an aggregate of
2,000,000 common units and 7,000,000 subordinated units.
The public, through the underwriters of the offering,
contributed $107.5 million ($100.2 million net of the
underwriters discount and a structuring fee) to us in
exchange for 5,000,000 common units, representing a
35 percent limited partner interest in us. Additionally, at
the closing of the IPO the underwriters fully exercised their
option to purchase 750,000 common units from Williams
subsidiaries at the IPO price of $21.50 per unit, less the
underwriters discount and a structuring fee. The proceeds
were used to redeem in equal amount of common units redeemed by
Williams, leaving Williams with 1,250,000 common units.
RECENT EVENTS
Discovery Open Season
In October 2005, Discovery offered firm transportation capacity
through two expedited open seasons to help ensure natural gas
that was stranded as a result of Gulf Coast hurricanes could
quickly reach domestic markets. The first open season, offering
up to 250,000 MMBtu/d of firm transportation, included the
construction of a new receipt point, which was completed on
December 2, 2005. Under this open season natural gas flows
from the Venice, Louisiana area of Texas Eastern
Transmissions interstate pipeline network to
Discoverys Larose, Louisiana plant for processing. The
processed gas is then transported back to Texas Eastern through
an existing delivery point. Approximately 300,000 MMBtu/d
is now flowing pursuant to this first open season. As a result
of the second open season, an additional 175,000 MMBtu/d
was subscribed and approximately 91,000 MMbtu/d flowed for
2005. Under this open season natural gas flowed via the reversal
of an existing interconnection. Throughput under this second
open season has fallen to approximately 35,000 MMBtu/d as
some of the processing facilities on Tennessee gas Pipeline have
returned to service. Discovery plans to provide the
transportation and processing services associated with the open
seasons at least through the first quarter of 2006.
Potential Acquisition Candidate Identified
On November 1, 2005, we announced that we and Williams had
identified an approximate 25 percent interest in
Williams existing gathering and processing assets in the
Four Corners area as our initial candidate to be considered for
acquisition. The terms of this proposed transaction, including
price, will be subject to approval by the boards of directors of
our general partner and of Williams.
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FINANCIAL INFORMATION ABOUT SEGMENTS
See Part II, Item 8 Financial Statements
and Supplementary Data
NARRATIVE DESCRIPTION OF BUSINESS
We are principally engaged in the business of gathering,
transporting and processing natural gas and fractionating and
storing NGLs. Operations of our businesses are located in the
United States and are organized into two reporting segments:
(1) Gathering and Processing and (2) NGL Services. Our
Gathering and Processing segment includes our equity investment
in Discovery and the Carbonate Trend gathering pipeline. Our NGL
Services segment includes the Conway fractionation and storage
operations.
Gathering and Processing The Discovery Assets
We own a 40 percent interest in Discovery, which in turn
owns:
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a 273-mile natural gas
gathering and transportation pipeline system, located primarily
off the coast of Louisiana in the Gulf of Mexico, with a
capacity, certified by the U.S. Federal Energy Regulatory
Commission (FERC), of approximately 600 MMcf/d
on its mainline; |
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a cryogenic natural gas processing plant in Larose, Louisiana
with a capacity of approximately 600 MMcf/d; |
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a fractionator in Paradis, Louisiana with a current capacity of
approximately 32,000 bpd (which can be expanded to
42,000 bpd); and |
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two onshore liquids pipelines, including a
22-mile mixed NGL
pipeline connecting the gas processing plant to the fractionator
and a 10-mile
condensate pipeline connecting the gas processing plant to a
third party oil gathering facility. |
Although Discovery includes fractionation operations, which
would normally fall within the NGL Services segment, it is
primarily engaged in gathering and processing and is managed as
such. Accordingly, this equity investment is considered part of
the Gathering and Processing segment.
Additionally, Discovery recently signed definitive agreements
with Chevron, Shell and Statoil to construct an approximate
35-mile gathering
pipeline lateral to connect Discoverys existing pipeline
system to these producers production facilities for the
Tahiti prospect in the deepwater region of the Gulf of Mexico.
The Tahiti pipeline lateral expansion is expected to have a
design capacity of approximately 200 MMcf/d, and its
anticipated completion date is May 2007.
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Discovery Natural Gas Pipeline System |
Transportation and Gathering Natural Gas Pipeline. The
mainline of the Discovery pipeline system consists of a
105-mile,
30-inch diameter
natural gas and condensate pipeline, which begins at a platform,
owned by a third party, located in the offshore Louisiana Outer
Continental Shelf at Ewing Bank 873 and extends northerly to the
Larose gas processing plant and a four-mile,
20-inch natural gas
pipeline that connects the Larose plant to the Texas Eastern
Pipeline. Approximately 66 miles of the mainline is located
offshore, in water depths ranging from approximately 40 to
800 feet. Producers have dedicated their production from
approximately 60 offshore blocks to Discovery. Each block
represents an area of 5,760 square acres. The mainline has
a FERC-certificated capacity of approximately 600 MMcf/d.
The Discovery system connects to five natural gas pipeline
systems, two of which provide 1.3 Bcf/d of takeaway
capacity: the Bridgeline system, which serves southern Louisiana
and connects to the Henry Hub natural gas market point, and the
Texas Eastern Pipeline system, which serves markets from Texas
to the northeastern United States. Additionally,
Discoverys recently completed market expansion project
connects Discovery to the following pipeline systems: Tennessee
Gas Pipeline, Columbia Gulf Transmission and
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Transcontinental Gas Pipe Line, or Transco. Together, these
three pipeline systems provide up to an additional
500 MMcf/d of takeaway capacity. This market expansion
project, consisting of approximately 40 miles of
20-inch diameter pipe
extending from the Larose processing plant to Pointe Au Chien,
Louisiana and Old Lady Lake, Louisiana commenced operations in
June 2005 and has a FERC-certificated capacity of approximately
150 MMcf/d. Discoverys interconnections allow
producers to benefit from flexible and diversified access to a
variety of natural gas markets from the Gulf of Mexico to the
eastern United States.
Shallow Water/ Onshore Gathering. Discovery also owns
shallow water and onshore gathering assets that consist of:
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90 miles of offshore laterals with pipeline diameters
ranging from 12 inches to 20 inches with connections
to the mainline. These shallow water laterals are located in
water depths ranging from approximately 50 to 360 feet. Of
the 90 miles of shallow water laterals, 60 miles are
regulated by FERC; |
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a fixed-leg shelf production handling facility installed along
the mainline at Grand Isle 115. The platform facility allows for
the injection of condensate into the pipeline and is equipped
with a production handling facility; and |
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a five-mile onshore gathering lateral with
20-inch diameter pipe
that extends from a production area north of the Larose gas
processing plant directly to the plant. This lateral is not
regulated by FERC. |
A Chevron-owned gathering system also connects to the Larose gas
processing plant.
Deepwater Gathering. Discoverys deepwater gathering
assets, which are located in water depths of greater than
1,000 feet, consist of 73 miles of gathering laterals,
with pipeline diameters ranging from eight inches to
16 inches that extend to deepwater producing areas in the
Gulf of Mexico such as the Morpeth prospect, Allegheny prospect
and Front Runner prospect. The maximum water depth of these
deepwater laterals is approximately 3,200 feet.
Additionally, Discovery recently signed definitive agreements to
construct a gathering pipeline lateral to connect
Discoverys existing pipeline system to certain
producers production facilities for the Tahiti prospect
described above. None of Discoverys deepwater laterals are
regulated by FERC.
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Larose Gas Processing Plant |
Discoverys cryogenic gas processing plant is located near
Larose, Louisiana at the onshore terminus of Discoverys
natural gas pipeline and has a design capacity of approximately
600 MMcf/d. The plant was placed in service in January 1998
and is located on land that Discovery leases from a third party.
The initial term of the lease is 20 years and is renewable
for ten-year intervals thereafter at Discoverys option for
up to a total of 50 years.
We believe that the Larose plant is one of the most efficient
and flexible gas processing plants in south Louisiana. The
Larose plant is able to recover over 90 percent of the
ethane contained in the natural gas stream and effectively
100 percent of the propane and heavier liquids. In
addition, the processing plant is able to reject ethane down to
effectively zero percent when justified by market
economics, while retaining a propane recovery rate of over
95 percent and butanes and heavier liquids recovery rates
of effectively 100 percent. We believe that the Larose
plant consumes very low amounts of natural gas as fuel, using
only approximately 1.4 percent of the volume of natural gas
processed.
In addition to its gas processing activities, the Larose plant
generates additional revenues by charging separate fees for
ancillary services, such as dehydration and condensate
separation and stabilization. Producers may also contract with
Discovery for transportation of condensate from offshore
production handling facilities and upon separation and
stabilization, through Discoverys
ten-mile condensate
pipeline to a third partys oil gathering facility.
Discovery also provides compression services for a third
partys onshore gathering system that connects to
Discoverys onshore lateral.
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Paradis Fractionation Facility |
The fractionator is located onshore near Paradis, Louisiana. The
fractionator and mixed NGL pipeline went into service in January
1998. The initial term of the lease is 20 years and is
renewable for ten-year intervals thereafter at Discoverys
option for up to a total of 50 years. The Paradis
fractionator is designed to fractionate 32,000 bpd of mixed
NGLs and is expandable to 42,000 bpd. In 2005, Discovery
fractionated an average of approximately 9,600 bpd of mixed
NGLs. All products can be delivered through the Chevron TENDS
NGL pipeline system and propane and heavier products may be
transported by truck or railway.
Discovery fractionates NGLs for third party customers and for
itself, and typically it receives title to approximately
one-half of the mixed NGL volumes leaving the Larose plant. A
subsidiary of Williams markets substantially all of the NGLs and
excess natural gas to which Discovery takes title by purchasing
them from Discovery and reselling them to end-users. Discovery
fractionates third party NGL volumes for a fractionation fee,
which typically includes a base fractionation fee per gallon,
that is subject to adjustment for changes in certain
fractionation expenses, including natural gas fuel costs on a
monthly basis and labor costs on an annual basis, which are the
principal variable costs in NGL fractionation. As a result,
Discovery is generally able to pass through increases in those
fractionation expenses to its customers.
Currently, Discovery is owned 40 percent by us,
20 percent by Williams and 40 percent by Duke Energy
Field Services. Discovery is managed by a three member
management committee consisting of representation from each of
the three owners. The members of the management committee have
voting power that corresponds to the ownership interest of the
owner they represent. However, except under limited
circumstances, all actions and decisions relating to Discovery
require the unanimous approval of the owners. Discovery must
make quarterly distributions of available cash (generally, cash
from operations less required and discretionary reserves) to its
owners. The management committee, by majority approval, will
determine the amount of such distributions. In addition, the
owners are required to offer to Discovery all opportunities to
construct pipeline laterals within an area of
interest.
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Discovery Customers and Contracts |
Customers. Discoverys customers are primarily
offshore natural gas producers. Discovery provides these
customers with wellhead to market delivery options
by offering a full range of services including gathering,
transportation, processing and fractionation. Discovery also has
the ability to provide its customers with other specialized
services, such as offshore production handling, condensate
separation and stabilization and dehydration. Five offshore
producer customers accounted for approximately 21 percent
of Discoverys revenues in 2005. No customer accounted for
over 10% of Discoverys revenues in 2005. Additionally, a
subsidiary of Williams, which markets substantially all of the
NGLs and excess natural gas to which Discovery takes title,
accounted for approximately 57.7 percent of
Discoverys revenues in 2005 even though it does not
produce any of the natural gas that is supplied to Discovery.
Contracts. Discovery provides a complete range of
wellhead to market services for its customers who
are offshore producers in the Gulf of Mexico. The principal
services provided include gathering, transportation, processing
and fractionation. Discovery also provides ancillary services
such as dehydration and condensate transportation, separation
and stabilization. Each of these services is usually supported
by a separate customer contract.
The mainline and the FERC-regulated laterals generate revenues
through FERC-regulated tariffs for several types of
service firm transportation service on a commodity
basis with reserve dedication, firm transportation service on a
commodity basis without reserve dedication to accommodate
temporary outages due to Hurricane Katrina and traditional
interruptible transportation service. Discovery also offers
another type of service, traditional firm service with
reservation fees, but none of Discoverys customers
currently contracts for this transportation service. Please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Our
Operations Gathering and Processing Segment.
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Discoverys maximum regulated rate for mainline
transportation is scheduled to decrease in 2008. At that time,
Discovery may be required to reduce its mainline transportation
rate on all of its contracts that have rates above the new
reduced rate. This could reduce the revenues generated by
Discovery. Discovery may elect to file a rate case with FERC to
alter this scheduled reduction. However, if filed, we cannot
assure you that a rate case would be successful in even
partially preventing the scheduled rate reduction. Please read
FERC Regulation.
Discoverys portfolio of processing contracts includes the
following types of contracts:
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Fee-based. Under fee-based contracts, Discovery receives
revenue based on the volume of natural gas processed and the
per-unit fee charged. |
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Percent-of-liquids.
Under
percent-of-liquids gas
processing contracts, Discovery (1) processes natural gas
for customers, (2) delivers to customers an agreed upon
percentage of the NGLs extracted in processing and
(3) retains a portion of the extracted NGLs. Discovery
generates revenue from the sale of these retained NGLs to third
parties at market prices. Some of Discoverys
percent-of-liquids
contracts have a bypass option. Under contracts with
a bypass option, if customers elect not to process their natural
gas due to unfavorable processing economics, Discovery retains a
portion of the customers natural gas in lieu of NGLs as a
fee. Discovery may choose to process gas that a customer has
elected to bypass, but then must deliver natural gas with an
equivalent Btu content to the customer. |
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations Our
Operations Gathering and Processing
Segment Processing and Fractionation Contracts
for additional information on Discoverys contracts.
The Discovery pipeline system competes with other wellhead
to market delivery options available to offshore producers
in the Gulf of Mexico. While Discovery offers integrated
gathering, transportation, processing and fractionation services
through a single provider, it generally competes with other
offshore Gulf of Mexico gathering systems and interconnecting
gas processing and fractionation facilities, some of which may
have the same owner. On the continental shelf in shallow water,
Discoverys pipeline system competes primarily with the
MantaRay/ Nautilus system, the Trunkline system, the Tennessee
System and the Venice Gathering System. These competing shallow
water gathering systems connect to the following gas processing
and fractionation facilities: the MantaRay/ Nautilus System
connects to the Neptune gas processing plant, the Trunkline
pipeline connects to the Patterson and Calumet gas processing
plants, the Tennessee pipeline connects to the Yscloskey gas
processing plant, and the Venice Gathering System connects to
the Venice gas processing plant. In the deepwater region of the
Gulf of Mexico, the Discovery pipeline system competes primarily
with the Enterprise pipeline and the Cleopatra pipeline. The
Enterprise pipeline connects to the ANR/ Pelican gas processing
plant near Patterson, Louisiana, and the Cleopatra pipeline
connects to the Neptune plant in Centerville, Louisiana.
Approximately 60 offshore production blocks are currently
dedicated to the Discovery system. Recently connected blocks
include Murphys Front Runner discovery, Energy
Partners Rock Creek discovery, and Apaches Tarantula
discovery. Additionally, Discovery recently signed definitive
agreements with certain producers to construct an approximate
35-mile gathering
pipeline lateral to connect Discoverys existing pipeline
system to these producers production facilities for the
Tahiti prospect described above. Furthermore, in areas that we
believe are accessible to the Discovery pipeline system,
approximately 600 deepwater blocks are currently leased and
approximately 100 have related exploration plans filed with the
Minerals Management Service of the U.S. Department of the
Interior, or the MMS, or are named prospects. A named prospect
is an individual lease or group of adjacent leases that are
generally considered by a producer to have some economic
potential for production.
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Gathering and Processing The Carbonate Trend
Pipeline
Our Carbonate Trend gathering pipeline is a sour gas gathering
pipeline consisting of approximately 34 miles of
12-inch diameter pipe
that is used to gather sour gas production from the Carbonate
Trend area off the coast of Alabama. Our Carbonate Trend
pipeline is not regulated under the Natural Gas Act but is
regulated under the Outer Continental Shelf Lands Act, which
requires us to transport gas supplies on the Outer Continental
Shelf on an open and non-discriminatory access basis.
Sour gas is natural gas that has relatively high
concentrations of acidic gases such as hydrogen sulfide and
carbon dioxide. Our pipeline is designed to transport gas with a
hydrogen sulfide and carbon dioxide content that exceeds normal
gas transportation specifications. The pipeline was built and
placed in service in 2000 and has a maximum design throughput
capacity of approximately 120 MMcf/d. For the year ended
December 31, 2005, our average transportation volume was
approximately 35 MMcf/d.
Gas is shipped through our pipeline to Shells offshore
sour gas gathering pipeline and Yellowhammer sour gas treating
facility located onshore in Coden, Alabama. From the
Yellowhammer facility, treated gas can be delivered to the
Williams-owned Mobile Bay gas processing plant, which has
multiple pipeline interconnections to Transco, Florida Gas
Transmission, Gulfstream, Mobile Gas Services and GulfSouth
pipelines. Treated gas may also be delivered directly into the
GulfSouth or the Transco pipelines at the tailgate of the
Yellowhammer facility without processing.
Our pipeline extends from Chevrons production platform
located at Viosca Knoll Block 251 to an interconnection
point with Shells offshore sour gas gathering facility
located at Mobile Bay Block 113. The pipeline is operated
by Chevron under an operating agreement. We contract with
Williams for the formulation of a corrosion control program to
ensure the maintenance and reliability of our pipeline. Due to
the corrosive nature of the sour gas, Williams has formulated
and Chevron has implemented a corrosion control program for the
Carbonate Trend pipeline. Please read Safety
and Maintenance.
Revenue from the Carbonate Trend pipeline is generated through
negotiated fees that we charge our customers to transport gas to
the Shell offshore sour gas gathering system. These fees
typically depend on the volume of gas we transport.
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Carbonate Trend Customers and Contracts |
Customers. Our primary customer on the Carbonate Trend
pipeline is Chevron, which, together with Noble Energy, has
large lease positions in the Carbonate Trend area. Chevron and
Noble Energy own an interest in more than 30 federal leases in
the Carbonate Trend area and Chevron is the operator for the
majority of these leases. For the year ended December 31,
2005, volumes from these Chevron leases represented
approximately 67 percent of Carbonate Trends total
throughput and 74 percent of Carbonate Trends total
revenue with volumes from Noble Energy constituting the
remainder.
Contracts. We have long-term transportation agreements
with Chevron and Noble Energy. Pursuant to these agreements,
Chevron and Noble Energy have agreed to transport on our
pipeline all gas produced on their 27 Carbonate Trend leases for
the life of the leases or the economic life of the underlying
reserves. There is no minimum volume requirement, and if the
leases held by Chevron and Noble Energy expire or the underlying
reserves are depleted, Chevron and Noble Energy will not be
committed to ship any natural gas on our pipeline. In addition,
if any lease expires, and is reacquired by the same company
within ten years of such expiration, all production from that
lease must again be transported via our pipeline. Under these
agreements Chevron and Noble Energy may make an annual election
to utilize capacity along a segment of Transco. When Chevron or
Noble Energy utilize this capacity, our per-unit gathering fee
is determined by subtracting the FERC tariff-based rate charged
by Transco for this capacity from the total negotiated fee. If
these customers elect not to utilize the capacity along this
segment of Transco, we can make no assurance that this capacity
will be made available to these customers in the future. We have
the option to terminate these agreements if expenses exceed
certain levels or if revenues fall below certain levels and we
are not compensated for these expenses or shortfalls.
7
Other than the producer gathering lines that connect to the
Carbonate Trend pipeline, there are no other sour gas gathering
and transportation pipelines in the Carbonate Trend area, and we
know of no current plans to build competing pipelines. As a
result, as other blocks in the Carbonate Trend are developed, we
believe that producers will find it more cost effective to
connect to our pipeline than to construct or commission new sour
gas pipelines of their own.
Chevron developed the Viosca Knoll Carbonate Trend area in the
shallow waters of the Mobile and Viosca Knoll areas in the
eastern Gulf of Mexico. Chevron has filed several exploration
plans with the MMS that we believe could result in the discovery
of additional amounts of natural gas. Other producers may also
transport gas on the Carbonate Trend pipeline. If the
Yellowhammer facility becomes unavailable for the treatment of
our customers sour gas, we believe that we can construct
pipeline connections to access either of two third party-owned
treating facilities also located in Coden, Alabama.
NGL Services The Conway Assets
Our Conway assets are strategically located at one of the two
major NGL trading hubs in the continental United States and
consist of:
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three integrated NGL storage facilities; and |
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a 50 percent interest in an NGL fractionator. |
General. We believe we are the largest NGL storage
facility, in terms of capacity, in the Mid-Continent Region. We
own and operate three integrated underground NGL storage
facilities in the Conway, Kansas area with an aggregate capacity
of approximately 20 million barrels, which we refer to as
the Conway West, Conway East and Mitchell storage facilities.
Each facility is comprised of a network of caverns located
several hundred feet below ground, and all three facilities are
connected by pipeline. The caverns hold large volumes of NGLs
and other hydrocarbons, such as propylene and naphtha. We
operate these assets as one coordinated facility. Three lines
connect the Mitchell facility to the Conway West facility and
two lines connect the Conway East facility to the Conway West
Facility. These facilities have a total brine pond capacity of
approximately 13 million barrels.
Our Conway storage facilities interconnect directly with two
end-use interstate NGL pipelines: MAPL and the Kinder Morgan
pipeline. We also, through connections of less than a mile,
indirectly interconnect to two additional end-use interstate NGL
pipelines: the Kaneb pipeline and the ONEOK pipeline. Through
these pipelines and other storage facilities we can provide our
customers interconnectivity to additional interstate NGL
pipelines. We believe that the attributes of our storage
facilities, such as the number and size of our caverns and well
bores and our extensive brine system, coupled with our direct
connectivity to MAPL through multiple meters allows our
customers to inject, withdraw and deliver all of their products
stored in our facilities more rapidly than products stored with
our competitors.
Conway West. The Conway West facility located adjacent to
the Conway fractionation facility in McPherson County, Kansas is
our primary storage facility. This facility has an aggregate
storage capacity of approximately ten million barrels.
Conway East. The Conway East facility is located
approximately four miles east of the Conway West facility in
McPherson County, Kansas. The Conway East facility has an
aggregate storage capacity of approximately five million
barrels. The Conway East facility also has an active truck
loading and unloading facility, each with two spots, and a rail
loading and unloading facility with 20 spots.
8
Mitchell. The Mitchell facility is located approximately
14 miles west of the Conway West facility in Rice County,
Kansas and has an aggregate storage capacity of approximately
five million barrels.
Customers. Our NGL storage customers include NGL
producers, NGL pipeline operators, NGL service providers and NGL
end-users. Our three largest customers, which accounted for
65 percent of our storage revenues in 2005, are SemStream,
Enterprise and ONEOK. Enterprise is an NGL pipeline operator,
ONEOK is an NGL service provider, while SemStream is principally
involved in propane marketing and distribution.
Contracts. Our storage year for customer contracts runs
from April 1 to March 31. We lease capacity on varying
terms from less than six months to a year or more and have
additional capacity available to contract. Our storage revenues
are not generally affected by seasonality because our customers
generally pay for storage capacity, not injected or withdrawn
volumes.
We have long-term contracts with SemStream, Enterprise and
ONEOK. These three customers contract for approximately seven
million barrels of storage capacity per year for terms that
expire between 2009 and 2018. Each of these contracts is based
on a percentage of our published price of storage in our Conway
facilities, which we adjust annually.
Aside from our long-term contracts, most of our contracts are
for a period of one year. In addition, we also enter into
contracts for fungible product storage in increments of six
months, three months or one month. For contracts of one year or
less, our customers are required to remit the full contract
price at the time the contract is signed, which makes us less
susceptible to credit risks. One of our customers is the
beneficiary of an agreement, which terminates in 2019, that
provides this customer with a yearly $177,000 credit against
storage fees that it may incur in excess of the fees that it
incurs for its contracted storage.
We currently offer our customers four types of storage
contracts single product fungible, two product
fungible, multi-product fungible and segregated product
storage in various quantities and at varying terms.
Single product fungible storage allows customers to store a
single product. Two-product fungible storage allows customers to
store any combination of two fungible products. Multi-product
fungible storage allows customers to store any combination of
fungible products. In the case of two-product and multi-product
storage, the customer designates the quantity of storage space
for each product at the beginning of the lease period. Customers
may change their quantity configurations throughout the year
based upon our ability to accommodate each change. Segregated
storage also is available to customers who desire to store
non-fungible products at Conway, such as propylene, refinery
grade butane and naphtha. We evaluate pricing, volume and
availability for segregated storage on a case-by-case basis.
Segregated storage allows a customer to lease an entire storage
cavern and have its own product injected and withdrawn without
having its product commingled with the products of our other
customers. In addition to the fees we charge for fungible
product storage and segregated product storage, we also receive
fees for overstorage.
We compete with other salt cavern storage facilities. Our most
direct competitor is a ONEOK-owned Bushton, Kansas storage
facility that is directly connected to a Kinder Morgan pipeline.
Other competitors include a ONEOK-owned facility in Conway,
Kansas, a NCRA-owned facility in Conway, Kansas, a ONEOK-owned
facility in Hutchinson, Kansas and an Enterprise Products
Partners-owned facility in Hutchinson, Kansas. We also compete
with storage facilities on the Gulf Coast and in Canada to the
extent that NGL product commodity prices differ between the
Mid-Continent region and those areas and interstate pipelines to
the extent that they offer storage services.
An increase in competition in the market could arise from new
ventures or expanded operations from existing competitors. Other
competitive factors include (1) the quantity, location and
physical flow characteristics of interconnected pipelines,
(2) the ability to offer service from multiple storage
locations,
9
(3) the costs of service and rates of our competitors and
(4) NGL product commodity prices in the Mid-Continent
region as compared to prices in other regions.
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NGL Sources and Transportation Options |
We generally receive the NGLs that we inject into our
facilities, and our customers generally choose to transport the
NGLs that we withdraw from our facilities, through the
interstate NGL pipelines that interconnect with our storage
facilities, including MAPL, a Kinder Morgan pipeline, a Kaneb
pipeline and a ONEOK pipeline. We also receive substantially all
of the separated NGLs from our fractionator for storage and
further transportation through these interstate pipelines.
Additionally, our customers have the option to have NGLs
delivered to or transported from our storage facility, through
our active truck loading and unloading facility, each with two
spots, or our rail loading and unloading facility with 20 spots.
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The Conway Fractionation Facility |
General. The Conway fractionation facility is
strategically located at the junction of the south, east and
west legs of MAPL and has interconnections with the BP
Wattenberg pipeline and the ConocoPhillips Chisholm pipeline,
each of which transports mixed NGLs to our facility. The Conway
fractionation facility began operations in 1973 with a single
production train. In 1977, a second train was added and the
capacity of the first train was upgraded, which brought the
total design capacity of the Conway fractionation facility to
approximately 107,000 bpd.
We own a 50 percent undivided interest in the Conway
fractionation facility, representing capacity of approximately
53,500 bpd. ConocoPhillips owns a 40 percent undivided
interest, representing capacity of approximately
42,800 bpd, and ONEOK owns a 10 percent undivided
interest, representing capacity of approximately
10,700 bpd. Each joint owner markets its own capacity
independently. Each owner can also contract with the other
owners for additional capacity at the Conway fractionation
facility, if necessary. We are the operator of the facility
pursuant to an operating agreement that extends until May 2011.
We primarily fractionate NGLs for third party customers for a
fee based on the volumes of mixed NGLs fractionated. The
per-unit fee we charge is generally subject to adjustment for
changes in certain fractionation expenses, including natural
gas, electricity and labor costs, which are the principal
variable costs in NGL fractionation. As a result, we are
generally able to pass through increases in those fractionation
expenses to our customers. However, under one of our long-term
fractionation contracts described below, there is a cap on the
per-unit fee and, under current natural gas market conditions,
we are not able to pass through the full amount of increases in
variable expenses to this customer. In order to mitigate the
fuel price risk with respect to our purchases of natural gas
needed to perform under this contract, upon the closing of our
initial public offering, Williams transferred to us a contract
for the purchase of a sufficient quantity of natural gas from a
wholly owned subsidiary of Williams at a price not to exceed a
specified price to satisfy our fuel requirements under this
fractionation contract. Please read Managements
Discussion and Analysis of Financial Condition and Results of
Operations Our Operations NGL Services
Segment Fractionation Contracts.
The results of operations of the Conway fractionation facility
are dependent upon the volume of mixed NGLs fractionated and the
level of fractionation fees charged. Overall, the NGL
fractionation business exhibits little to no seasonal variation
as NGL production is relatively constant throughout the year. We
have capacity available at our fractionation facility to
accommodate additional volumes.
Customers. We have long-term fractionation agreements
with BP and Enterprise, which together accounted for
approximately 64 percent of our NGL fractionation capacity
at the Conway facility for the year ended December 31,
2005. Our other fractionation customers include Duke and
Coffeyville Resources.
Contracts. We have a long-term contract with BP which
requires BP to deliver all of its proprietary mixed NGLs from
its Wattenberg pipeline, which runs from eastern Colorado to
Bushton, Kansas, and its
10
Hugoton, Kansas gas processing plant to the Conway fractionator.
There is no minimum volume requirement, however, and if
BPs Hugoton processing plant and the Wattenberg pipeline
were to cease operations for any reason, BP would not be
required to deliver any mixed NGLs for fractionation under this
agreement. BP accounted for approximately 13.5 percent,
16.1 percent and 24.6 percent of our total revenue in
2005, 2004 and 2003 respectively. The term of the agreement with
respect to deliveries from the Wattenberg pipeline expires on
January 1, 2008 but will automatically be renewed on a
year-to-year basis
unless otherwise terminated by the parties. The term of the
agreement with respect to deliveries from Hugoton expires on
January 1, 2013 and may be terminated effective
January 1, 2008 if either party provides notice of
termination before December 31, 2005. Pursuant to the terms
of this agreement, we provided notice of termination to BP in
July 2005.
Another long-term contract requires a customer to deliver all of
the mixed NGLs that customer purchases from Pioneers Texas
Panhandle and southwestern Kansas natural gas processing
facilities to the Conway fractionator if it chooses to ship its
mixed NGLs to the Mid-Continent region, as defined in the
agreement. However, if the customer chooses to ship its mixed
NGLs to another region, it has the right, on a
month-to-month basis,
to deliver its mixed NGLs elsewhere. The customers
decision on whether to ship its products to the Mid-Continent
region or to another region depends on factors including supply
and demand in the respective regions and the current price being
paid for fractionated products in each region. Deliveries of
mixed NGL products under this agreement have remained consistent
during the term of this agreement. This agreement expires in
2009.
We generally enter into contracts that cover a portion of our
remaining capacity at the Conway facility for periods of one
year or less.
Although competition for NGL fractionation services is primarily
based on the fractionation fee, the ability of an NGL
fractionator to obtain mixed NGLs and distribute NGL products
are also important competitive factors and are determined by the
existence of the necessary pipeline and storage infrastructure.
NGL fractionators connected to extensive storage, transportation
and distribution systems such as ours have direct access to
larger markets than those with less extensive connections. Our
principal competitors are a ONEOK-owned fractionator located in
Medford, Oklahoma, a ONEOK-owned fractionator located in
Hutchinson, Kansas and a ONEOK-owned fractionator located in
Bushton, Kansas. We compete with the two other joint owners of
the Conway fractionation facility for third party customers. We
also compete with fractionation facilities on the Gulf Coast, to
the extent that NGL product commodity prices differ between the
Mid-Continent region and the Gulf Coast.
An increase in competition in the market could arise from new
ventures or expanded operations from existing competitors. Other
competitive factors include (1) the quantity and location
of interconnected pipelines, (2) the costs and rates of our
competitors, (3) whether fractionation providers offer to
purchase a customers mixed NGLs instead of providing fee based
fractionation services and (4) NGL product commodity prices
in the Mid-Continent region as compared to prices in other
regions.
Based on EIA projections of relatively stable production levels
of natural gas in the Mid-Continent region over the next ten
years, we believe that sufficient volumes of mixed NGLs will be
available for fractionation in the foreseeable future. In
addition, through connections with MAPL and the BP Wattenberg
pipeline, the Conway fractionation facility has access to mixed
NGLs from additional major supply basins in North America,
including additional major supply basins in the Rocky Mountain
production area.
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NGL Transportation Options |
After the mixed NGLs are separated at the fractionator, the NGL
products are typically transported to our storage facilities. At
our storage facilities, the NGLs may be stored or transported on
one of the interconnected NGL pipelines. Our customers also have
the option to have their NGL products transported
11
through our truck loading and rail loading facilities.
Additionally, when market conditions dictate, we have the
ability to place propane directly into MAPL from our
fractionator, providing our customers with expedited access to
interstate markets.
Safety and Maintenance
Discoverys natural gas pipeline system is subject to
regulation by the United States Department of Transportation,
referred to as DOT, under the Accountable Pipeline and Safety
Partnership Act of 1996, referred to as the Hazardous Liquid
Pipeline Safety Act, and comparable state statutes with respect
to design, installation, testing, construction, operation,
replacement and management. The Hazardous Liquid Pipeline Safety
Act covers petroleum and petroleum products and requires any
entity that owns or operates pipeline facilities to comply with
such regulations, to permit access to and copying of records and
to file certain reports and provide information as required by
the United States Secretary of Transportation. These regulations
include potential fines and penalties for violations.
Discoverys gas pipeline system is also subject to the
Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety
Improvement Act of 2002. The Natural Gas Pipeline Safety Act
regulates safety requirements in the design, construction,
operation and maintenance of gas pipeline facilities while the
Pipeline Safety Improvement Act establishes mandatory
inspections for all United States oil and natural gas
transportation pipelines and some gathering lines in
high-consequence areas within ten years. The DOT has developed
regulations implementing the Pipeline Safety Improvement Act
that will require pipeline operators to implement integrity
management programs, including more frequent inspections and
other safety protections in areas where the consequences of
potential pipeline accidents pose the greatest risk to people
and their property. We currently estimate we will incur costs of
approximately $1.7 million between 2006 and 2008 to
implement integrity management program testing along certain
segments of Discoverys 16, 20, and
30-inch diameter
natural gas pipelines and its 10, 14, and
18-inch diameter NGL
pipelines. This does not include the costs, if any, of any
repair, remediation, preventative or mitigating actions that may
be determined to be necessary as a result of the testing program.
States are largely preempted by federal law from regulating
pipeline safety but may assume responsibility for enforcing
federal intrastate pipeline regulations and inspection of
intrastate pipelines. In practice, states vary considerably in
their authority and capacity to address pipeline safety. We do
not anticipate any significant problems in complying with
applicable state laws and regulations in those states in which
we or the entities in which we own an interest operate.
Our natural gas pipelines have continuous inspection and
compliance programs designed to keep its facilities in
compliance with pipeline safety and pollution control
requirements. In compliance with applicable permit requirements,
we completed a survey of portions of our Carbonate Trend
pipeline. As a result of this survey, we have determined that it
will be necessary for us to undertake certain restoration
activities to repair the partial erosion of the pipeline
overburden caused by Hurricane Ivan in September 2004. We
estimate that the cost of these restoration activities will be
between $3.4 and $4.6 million and that they will be
completed by the end of 2006. In the omnibus agreement, Williams
agreed to reimburse us for the cost of these restoration
activities. We believe that our natural gas pipelines are in
material compliance with the applicable requirements of these
safety regulations.
Our Carbonate Trend pipeline requires a corrosion control
program to protect the integrity of the pipeline and prolong its
life. The corrosion control program consists of continuous
monitoring and injection of corrosion inhibitor into the
pipeline, periodic chemical treatments and annual detailed
comprehensive inspections. We believe that this is an aggressive
and proactive corrosion control program that will reduce metal
loss, limit corrosion and possibly extend the service life of
the pipe by 15 to 20 years.
In addition, we are subject to a number of federal and state
laws and regulations, including the federal Occupational Safety
and Health Act, referred to as OSHA, and comparable state
statutes, whose purpose is to protect the health and safety of
workers, both generally and within the pipeline industry. In
addition, the OSHA hazard communication standard, the EPA
community right-to-know
regulations under Title III of the federal Superfund
Amendment and Reauthorization Act and comparable state statutes
require that informa-
12
tion be maintained about hazardous materials used or produced in
our operations and that this information be provided to
employees, state and local government authorities and citizens.
We and the entities in which we own an interest are also subject
to OSHA Process Safety Management regulations, which are
designed to prevent or minimize the consequences of catastrophic
releases of toxic, reactive, flammable or explosive chemicals.
These regulations apply to any process which involves a chemical
at or above the specified thresholds or any process which
involves flammable liquid or gas, pressurized tanks, caverns and
wells in excess of 10,000 pounds at various locations. Flammable
liquids stored in atmospheric tanks below their normal boiling
point without the benefit of chilling or refrigeration are
exempt. We have an internal program of inspection designed to
monitor and enforce compliance with worker safety requirements.
We believe that we are in material compliance with the OSHA
regulations.
FERC Regulation
The Carbonate Trend sour gas gathering pipeline and the offshore
portion of Discoverys natural gas pipeline are subject to
regulation under the Outer Continental Shelf Lands Act, which
calls for nondiscriminatory transportation on pipelines
operating in the outer continental shelf region of the Gulf of
Mexico.
Portions of Discoverys natural gas pipeline are also
subject to regulation by FERC, under the Natural Gas Act. The
Natural Gas Act requires, among other things, that the rates be
just and reasonable and nondiscriminatory. Under the
Natural Gas Act, FERC has authority over the construction,
operation and expansion of interstate pipeline facilities, as
well as the terms and conditions of service provided by the
operator of such facilities. In general, Discovery must receive
prior FERC approval to construct, operate or expand its
FERC-regulated facilities, to initiate new service using such
facilities, to alter the terms and conditions of service
provided on such facilities, and to abandon service provided by
its FERC-regulated facilities. With respect to certain types of
construction activities and certain types of service, FERC has
issued rules that allow regulated pipelines to obtain blanket
authorizations that obviate the need for prior specific FERC
approvals for initiating and abandoning service. Commencing in
1992, FERC issued a series of orders (Order
No. 636), which require interstate pipelines to
provide transportation service separate or unbundled
from the pipelines sales of gas. Order No. 636 also
required interstate pipelines, such as Discovery to provide open
access transportation on a non-discriminatory basis that is
equal for all similarly situated shippers. The Natural Gas Act
also gives FERC the authority to regulate the rates that
Discovery charges for service on portions of its natural gas
pipeline system. The natural gas pipeline industry has
historically been heavily regulated by federal and state
governments, and we cannot predict what further actions FERC,
state regulators, or federal and state legislators may take in
the future.
The Discovery 105-mile
mainline, approximately 60 miles of laterals and its market
expansion project are subject to regulation by FERC. The
following table shows the maximum transportation tariffs that
Discovery can charge on its regulated transportation pipelines:
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Discovery Asset |
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Maximum FERC Rate |
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Mainline
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$0.1569/MMBtu through January 2008; |
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$0.08 thereafter |
FERC-regulated laterals
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$0.039/MMBtu |
Market expansion project
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$0.08/MMBtu |
Under Discoverys current FERC-approved tariff, the maximum
rate that Discovery may charge its customers for the
transportation of natural gas along its mainline is $0.1569/
MMBtu. This maximum rate is scheduled to decrease in 2008 to
$0.08/ MMBtu. At that time, Discovery may be required to reduce
its mainline transportation rate on all of its contracts that
have rates above the new maximum rate. This could reduce the
revenues generated by Discovery. Discovery may elect to file a
rate case with FERC seeking to alter this scheduled reduction.
13
However, if filed, we cannot assure you that a rate case would
be successful in even partially preventing the scheduled rate
reduction.
In connection with a rate case filed by Discovery, all aspects
of its cost of service and rate design of its rates could be
reviewed, including the following:
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the overall cost of service, including operating costs and
overhead; |
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the allocation of overhead and other administrative and general
expenses to the rate; |
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the appropriate capital structure to be utilized in calculating
rates; |
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the appropriate rate of return on equity; |
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the cost of debt; |
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the rate base, including the proper starting rate base; |
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the throughput underlying the rate; and |
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the proper allowance for federal and state income taxes. |
In a decision issued in July 2004 involving an oil pipeline
limited partnership, BP West Coast Products, LLC v.
FERC, the United States Court of Appeals for the District of
Columbia Circuit upheld, among other things, the FERCs
determination that certain rates of an interstate petroleum
products pipeline, SFPP, L.P., or SFPP, were grandfathered rates
under the Energy Policy Act of 1992 and that SFPPs
shippers had not demonstrated substantially changed
circumstances that would justify modification of those rates.
The court also vacated the portion of the FERCs decision
applying the Lakehead policy. In its Lakehead
decision, the FERC allowed an oil pipeline publicly traded
partnership to include in its
cost-of-service an
income tax allowance to the extent that its unitholders were
corporations subject to income tax. In May and June 2005, the
FERC issued a statement of general policy, as well as an order
on remand of BP West Coast, respectively, in which it
stated it will permit pipelines to include in cost of service a
tax allowance to reflect actual or potential tax liability on
their public utility income attributable to all partnership or
limited liability company interests, if the ultimate owner of
the interest has an actual or potential income tax liability on
such income. Whether a pipelines owners have such actual
or potential income tax liability will be reviewed by the FERC
on a case-by-case basis. Although the new policy is generally
favorable for pipelines that are organized as pass-through
entities, it still entails rate risk due to the
case-by-case review
requirement. In December 2005, the FERC issued its first
case-specific oil pipeline review of the income tax allowance
issue in the SFPP proceeding, reaffirming its new income tax
allowance policy and directing SFPP to provide certain evidence
necessary for the pipeline to determine its income allowance.
The FERCs BP West Coast remand decision and the new
tax allowance policy have been appealed to the D.C. Circuit, and
rehearing requests have been filed with respect to the December
2005 order. Therefore, the ultimate outcome of these proceedings
is not certain and could result in changes to the FERCs
treatment of income tax allowances in cost of service. If FERC
were to disallow a substantial portion of Discoverys
income tax allowance, it may be more difficult for Discovery to
justify its rates.
These aspects of Discoverys rates also could be reviewed
if FERC or a shipper initiated a complaint proceeding. However,
we do not believe that it is likely that there will be a
challenge to Discoverys rates by a current shipper that
would materially affect its revenues or cash flows.
In 2000, FERC issued Order No. 637 which, among other
things:
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required pipelines to implement imbalance management services; |
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restricted the ability of pipelines to impose penalties for
imbalances, overruns and non-compliance with operational flow
orders; and |
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implemented a number of new pipeline reporting requirements. |
In addition, FERC implemented new regulations governing the
procedure for obtaining authorization to construct new pipeline
facilities and has issued a policy statement, which it largely
affirmed in a recent order
14
on rehearing, establishing a presumption in favor of requiring
owners of new pipeline facilities to charge rates based solely
on the costs associated with such new pipeline facilities. We
cannot predict what further action FERC will take on these
matters. However, we do not believe that Discovery will be
affected by any action taken previously or in the future on
these matters materially differently than other natural gas
gatherers and processors with which it competes.
Commencing in 2003, FERC issued a series of orders adopting
rules for new Standards of Conduct for Transmission Providers
(Order No. 2004) which apply to interstate natural gas
pipelines such as Discovery. Order No. 2004 became
effective in 2004. Among other matters, Order No. 2004
requires interstate pipelines to operate independently from
their energy affiliates, prohibits interstate pipelines from
providing non-public transportation or shipper information to
their energy affiliates; prohibits interstate pipelines from
favoring their energy affiliates in providing service; and
obligates interstate pipelines to post on their websites a
number of items of information concerning the pipeline,
including its organizational structure, facilities shared with
energy affiliates, discounts given for transportation service,
and instances in which the pipeline has agreed to waive
discretionary terms of its tariff. Discovery requested and
received a partial waiver from certain portions of Order
No. 2004. Since the effective date of Order No. 2004,
Discovery has determined that additional waivers from compliance
with Order No. 2004 are necessary to accommodate the
management committee structure under which Discovery operates.
Discovery filed for additional limited waivers from Order
No. 2004 compliance on May 6, 2005 requesting a
limited waiver to permit three Duke Energy Field Services
(DEFS) employees to be shared between Discovery and
DEFS and to provide information necessary for DEFS to carry out
its responsibilities as an owner of Discovery. FERC has not yet
acted on this filing.
Additional proposals and proceedings that might affect the
natural gas industry are pending before Congress, FERC and the
courts. The natural gas industry historically has been heavily
regulated. Accordingly, we cannot assure you that the less
stringent and pro-competition regulatory approach recently
pursued by FERC and Congress will continue.
The Carbonate Trend pipeline is a gathering pipeline, and is not
subject to FERC jurisdiction under the Natural Gas Act.
The primary function of Discoverys natural gas processing
plant is the extraction of NGLs and the conditioning of natural
gas for marketing into the natural gas pipeline grid. FERC has
traditionally maintained that a processing plant that primarily
extracts NGLs is not a facility for transportation or sale of
natural gas for resale in interstate commerce and therefore is
not subject to its jurisdiction under the Natural Gas Act. We
believe that the natural gas processing plant is primarily
involved in removing NGLs and, therefore, is exempt from the
jurisdiction of FERC.
Environmental Regulation
Our operation of pipelines, plants and other facilities for
gathering, transporting, processing or storing natural gas, NGLs
and other products is subject to stringent and complex federal,
state, and local laws and regulations governing the discharge of
materials into the environment, or otherwise relating to the
protection of the environment. Due to the myriad of complex
federal, state and local laws and regulations that may affect
us, directly or indirectly, you should not rely on the following
discussion of certain laws and regulations as an exhaustive
review of all regulatory considerations affecting our operations.
As with the industry generally, compliance with existing and
anticipated laws and regulations increases our overall cost of
business, including our capital costs to construct, maintain,
and upgrade equipment and facilities. While these laws and
regulations affect our maintenance capital expenditures and net
income, we believe that they do not affect our competitive
position in that the operations of our competitors are similarly
affected. We believe that our operations are in material
compliance with applicable environmental laws and regulations.
However, these laws and regulations are subject to frequent, and
often times more stringent,
15
change by regulatory authorities and we are unable to predict
the ongoing cost to us of complying with these laws and
regulations or the future impact of these laws and regulations
on our operations. Violation of environmental laws, regulations
and permits can result in the imposition of significant
administrative, civil and criminal penalties, remedial
obligations, injunctions and construction bans or delays. A
discharge of hydrocarbons or hazardous substances into the
environment could, to the extent the event is not insured,
subject us to substantial expense, including both the cost to
comply with applicable laws and regulations and claims made by
neighboring landowners and other third parties for personal
injury and property damage.
We or the entities in which we own an interest inspect the
pipelines regularly using equipment rented from third party
suppliers. Third parties also assist us in interpreting the
results of the inspections.
In the omnibus agreement executed in connection with our IPO,
Williams agreed to indemnify us in an aggregate amount not to
exceed $14.0 million, including any amounts recoverable
under our insurance policy covering remediation costs and
unknown claims at Conway, generally for three years after the
closing of our initial public offering in August 2005, for
certain environmental noncompliance and remediation liabilities
associated with the assets transferred to us and occurring or
existing before the closing date of our initial public offering.
Our operations are subject to the Clean Air Act and comparable
state and local statutes. Amendments to the Clean Air Act
enacted in late 1990 require or will require most industrial
operations in the United States to incur capital expenditures in
order to meet air emission control standards developed by the
U.S. Environmental Protection Agency, or EPA, and state
environmental agencies. As a result of these amendments, our
facilities that emit volatile organic compounds or nitrogen
oxides are subject to increasingly stringent regulations,
including requirements that some sources install maximum or
reasonably available control technology. In addition, the 1990
Clean Air Act Amendments established a new operating permit for
major sources. Although we can give no assurances, we believe
that the expenditures needed for us to comply with the 1990
Clean Air Act Amendments will not have a material adverse effect
on our financial condition or results of operations.
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Hazardous Substances and Waste |
To a large extent, the environmental laws and regulations
affecting our operations relate to the release of hazardous
substances or solid wastes into soils, groundwater and surface
water, and include measures to control pollution of the
environment. These laws generally regulate the generation,
storage, treatment, transportation and disposal of solid and
hazardous waste. They also require corrective action, including
the investigation and remediation of certain units, at a
facility where such waste may have been released or disposed.
For instance, the Comprehensive Environmental Response,
Compensation, and Liability Act, referred to as CERCLA or the
Superfund law and comparable state laws impose liability,
without regard to fault or the legality of the original conduct,
on certain classes of persons that contributed to the release of
a hazardous substance into the environment. These
persons include the owner or operator of the site where the
release occurred and companies that disposed or arranged for the
disposal of the hazardous substances found at the site. Under
CERCLA, these persons may be subject to joint and several strict
liability for the costs of cleaning up the hazardous substances
that have been released into the environment, for damages to
natural resources and for the costs of certain health studies.
CERCLA also authorizes the EPA and, in some instances, third
parties to act in response to threats to the public health or
the environment and to seek to recover from the responsible
classes of persons the costs they incur. It is not uncommon for
neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by
hazardous substances or other pollutants released into the
environment. Despite the petroleum exclusion of
CERCLA Section 101(14) that currently encompasses natural
gas, we may nonetheless handle hazardous substances
within the meaning of CERCLA, or similar state statutes, in the
course of our ordinary operations and, as a result, may be
jointly and severally liable under CERCLA for all or part of the
costs required to clean up sites at which these hazardous
substances have been released into the environment.
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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 CERCLA, RCRA and analogous
state laws. Under these laws, we could be required to remove or
remediate previously disposed wastes (including wastes disposed
of or released by prior owners or operators), to clean up
contaminated property (including contaminated groundwater) or to
perform remedial operations to prevent future contamination.
The Federal Water Pollution Control Act of 1972, as renamed and
amended as the Clean Water Act, also referred to as the CWA, and
analogous state laws impose restrictions and strict controls
regarding the discharge of pollutants into navigable waters.
Pursuant to the CWA and analogous state laws, permits must be
obtained to discharge pollutants into state and federal waters.
The CWA imposes substantial potential civil and criminal
penalties for non-compliance. State laws for the control of
water pollution also provide varying civil and criminal
penalties and liabilities. In addition, some states maintain
groundwater protection programs that require permits for
discharges or operations that may impact groundwater conditions.
The EPA has promulgated regulations that require us to have
permits in order to discharge certain storm water run-off. The
EPA has entered into agreements with certain states in which we
operate whereby the permits are issued and administered by the
respective states. These permits may require us to monitor and
sample the storm water run-off. We believe that compliance with
existing permits and compliance with foreseeable new permit
requirements will not have a material adverse effect on our
financial condition or results of operations.
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Hazardous Materials Transportation Requirements |
The DOT regulations affecting pipeline safety require pipeline
operators to implement measures designed to reduce the
environmental impact of discharge from onshore pipelines. These
regulations require operators to maintain comprehensive spill
response plans, including extensive spill response training for
pipeline personnel. In addition, the DOT regulations contain
detailed specifications for pipeline operation and maintenance.
We believe our operations are in substantial compliance with
these regulations. Please read Safety and
Maintenance.
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Kansas Department of Health and Environment
Obligations |
We currently own and operate underground storage caverns near
Conway, Kansas that have been created by solution mining the
caverns in the Hutchinson salt formation. These storage caverns
are used to store NGLs and other liquid hydrocarbons. These
caverns are subject to strict environmental regulation by the
Underground Storage Unit within the Bureau of Water, Geology
Section of the KDHE under the Underground Hydrocarbon and
Natural Gas Storage Program. The current revision of the
Underground Hydrocarbon and Natural Gas Storage regulations
became effective on April 1, 2003 (temporary) and
August 8, 2003 (permanent); these rules regulate the
storage of liquefied petroleum gas, hydrocarbons and natural gas
in bedded salt for the purpose of protecting public health and
safety, property and the environment
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and regulates the construction, operation and closure of brine
ponds associated with our storage caverns. The regulations
specify several compliance deadlines including the final permit
application for existing hydrocarbon storage wells by
April 1, 2006, certain equipment requirements no later than
April 1, 2008 and mechanical integrity and casing testing
requirements by April 1, 2010. Failure to comply with the
Underground Hydrocarbon and Natural Gas Storage Program may lead
to the assessment of administrative, civil or criminal penalties.
We are in the process of modifying our Conway storage
facilities, including the caverns and brine ponds, and we
believe that our storage operations will be in compliance with
the Underground Hydrocarbon and Natural Gas Storage Program
regulations by the applicable compliance dates. In 2003, we
began to complete workovers on approximately 30 to 35 salt
caverns per year and install, on average, a double liner on one
brine pond per year. The incremental costs of these activities
is approximately $5.5 million per year to complete the
workovers and approximately $900,000 per year to install a
double liner on a brine pond. In response to these increased
costs, we raised our storage rates by an amount sufficient to
preserve our margins in this business. Accordingly, we do not
believe that these increased costs have had a material effect on
our business or results of operations. We expect on average to
complete workovers on each of our caverns every five to ten
years and install double liners on each of our brine ponds every
18 years.
Furthermore, the KDHE has advised us that a regulation relating
to the metering of NGL volumes that are injected and withdrawn
from our caverns may be interpreted to require the installation
of meters at each of our well bores. We have informed the KDHE
that we disagree with this interpretation, and the KDHE has
asked us to provide it with additional information. We have made
a proposal to install individual cavern meters at 12 caverns
that are connected to the fractionator and NGL pipelines. The
estimated cost for this work is $220,000. If this proposal is
not accepted, we estimate that the cost of installing a meter at
each of our well bores at Conway West and Mitchell would be
approximately $3.9 million over three years.
Additionally, we are currently undergoing remedial activities
pursuant to KDHE Consent Orders issued in the early 1990s. The
Consent Orders were issued after elevated concentrations of
chlorides were discovered in various
on-site and off-site
shallow groundwater resources at each of our Conway storage
facilities. With KDHE approval, we are currently installing and
implementing a containment and monitoring system to delineate
further the scope of and to arrest the continued migration of
the chloride plume at the Mitchell facility. Investigation and
delineation of chloride impacts is ongoing at the two Conway
area facilities as specified in their respective consent orders.
One of these facilities is located near the Groundwater
Management District No. 2s jurisdictional boundary of
the Equus Beds aquifer. At the other Conway area facility,
remediation of residual hydrocarbon derivatives from a historic
pipeline release is included in the consent order required
activities.
Although not mandated by any consent order, we are currently
cooperating with the KDHE and other area operators in an
investigation of fugitive NGLs observed in the subsurface at the
Conway Underground East facility. In addition, we have also
recently detected fugitive NGLs in groundwater monitoring wells
adjacent to two abandoned storage caverns at the Conway West
facility. Although the complete extent of the contamination
appears to be limited and appears to have been arrested, we are
continuing to work to delineate further the scope of the
contamination. To date, the KDHE has not undertaken any
enforcement action related to the releases around the abandoned
storage caverns.
We are continuing to evaluate our assets to prevent future
releases. While we maintain an extensive inspection and audit
program designed, as appropriate, to prevent and to detect and
address such releases promptly, there can be no assurance that
future environmental releases from our assets will not have a
material effect on us.
Title to Properties and
Rights-of-Way
Our real property falls into two categories: (1) parcels
that we own in fee, such as land at the Conway fractionation and
storage facility, and (2) parcels in which our interest
derives from leases, easements,
rights-of-way, permits
or licenses from landowners or governmental authorities
permitting the use of such land for our operations. The fee
sites upon which major facilities are located have been owned by
us or our
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predecessors in title for many years without any material
challenge known to us relating to the title to the land upon
which the assets are located, and we believe that we have
satisfactory title to such fee sites. We have no knowledge of
any challenge to the underlying fee title of any material lease,
easement, right-of-way
or license held by us or to our title to any material lease,
easement, right-of-way,
permit or lease, and we believe that we have satisfactory title
to all of our material leases, easements,
right-of-way and
licenses.
Employees
We do not have any employees. We are managed and operated by the
directors and officers of our general partner. To carry out our
operations, as of December 31, 2005, our general partner or
its affiliates employed approximately 36 people who will spend
at least a majority of their time operating the Conway and
Carbonate Trend facilities and approximately 30 general and
administrative full-time equivalent employees in support of
these operations. Discovery is operated by Williams pursuant to
an operating and maintenance agreement and the employees who
operate the Discovery assets are therefore not included in the
above numbers. For further information, please read
Directors and Officers of the Registrant
Reimbursement of Expenses of our General Partner and
Certain Relationships and Related Transactions.
FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
We have no revenue or segment profit/loss attributable to
international activities.
Item 1A. Risk
Factors
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 following risk factors in addition
to the other information in this annual report. If any of the
following risks were actually to occur, our business, results of
operations and financial condition could be materially adversely
affected. In that case, we might not be able to pay
distributions on our common units and the trading price of our
common units could decline and unitholders could lose all or
part of their investment.
Risks Inherent in Our Business
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We may not have sufficient cash from operations to enable
us to pay the minimum quarterly distribution following
establishment of cash reserves and payment of fees and expenses,
including payments to our general partner. |
We may not have sufficient available cash each quarter to pay
the minimum quarterly distribution. The amount of cash we can
distribute on our common units principally depends upon the
amount of cash we generate from our operations, which will
fluctuate from quarter to quarter based on, among other things:
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the prices we obtain for our services; |
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the prices of, level of production of, and demand for, natural
gas and NGLs; |
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the volumes of natural gas we gather, transport and process and
the volumes of NGLs we fractionate and store; |
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the level of our operating costs, including payments to our
general partner; and |
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prevailing economic conditions. |
In addition, the actual amount of cash we will have available
for distribution will depend on other factors such as:
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the level of capital expenditures we make; |
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the restrictions contained in our and Williams debt
agreements and our debt service requirements; |
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the cost of acquisitions, if any; |
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fluctuations in our working capital needs; |
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our ability to borrow for working capital or other purposes; |
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the amount, if any, of cash reserves established by our general
partner; |
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the amount of cash that Discovery distributes to us; and |
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reimbursement payments to us by, and credits from, Williams
under the omnibus agreement. |
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.
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Because of the natural decline in production from existing
wells, the success of our gathering and transportation
businesses depends on our ability to obtain new sources of
natural gas supply, which is dependent on factors beyond our
control. Any decrease in supplies of natural gas could adversely
affect our business and operating results. |
Our and Discoverys pipelines receive natural gas directly
from offshore producers. The production from existing wells
connected to Discoverys pipelines will naturally decline
over time, which means that our cash flows associated with these
wells will also decline over time. We do not produce an
aggregate reserve report on a regular basis or regularly obtain
or update independent reserve evaluations. The amount of natural
gas reserves underlying these wells may be less than we
anticipate, and the rate at which production will decline from
these reserves may be greater than we anticipate. Accordingly,
to maintain or increase throughput levels on these pipelines and
the utilization rate of Discoverys natural gas processing
plant and fractionator, we and Discovery must continually obtain
new supplies of natural gas. The primary factors affecting our
ability to obtain new supplies of natural gas and attract new
customers to our pipelines include: (1) the level of
successful drilling activity near these pipelines; (2) our
ability to compete for volumes from successful new wells and
(3) our and Discoverys ability to successfully
complete lateral expansion projects to connect to new wells.
We have no current significant lateral expansion projects
planned, and Discovery has only one currently planned
significant lateral expansion project. Discovery recently signed
definitive agreements with Chevron, Shell and Statoil to
construct an approximate
35-mile gathering
pipeline lateral to connect Discoverys existing pipeline
system to these producers production facilities for the
Tahiti prospect in the deepwater region of the Gulf of Mexico.
Initial production is expected in April 2008.
The level of drilling activity in the fields served by our and
Discoverys pipelines is dependent on economic and business
factors beyond our control. The primary factors that impact
drilling decisions are oil and natural gas prices. A sustained
decline in oil and natural gas prices could result in a decrease
in exploration and development activities in these fields, which
would lead to reduced throughput levels on our pipelines. Other
factors that impact production decisions include producers
capital budget limitations, the ability of producers to obtain
necessary drilling and other governmental permits and regulatory
changes. Because of these factors, even if new oil or natural
gas reserves are discovered in areas served by our pipelines,
producers may choose not to develop those reserves. If we were
not able to obtain new supplies of natural gas to replace the
natural decline in volumes from existing wells, due to
reductions in drilling activity, competition, or difficulties in
completing lateral expansion projects to connect to new supplies
of natural gas, throughput on our pipelines and the utilization
rates of Discoverys natural gas processing plant and
fractionator would decline, which could have a material adverse
effect on our business, results of operations, financial
condition and ability to make cash distributions to unitholders.
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Lower natural gas and oil prices could adversely affect
our fractionation and storage businesses. |
Lower natural gas and oil prices could result in a decline in
the production of natural gas and NGLs resulting in reduced
throughput on our pipelines. 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 unitholders.
In general terms, the prices of natural gas, NGLs and other
hydrocarbon products fluctuate in response to changes in supply,
changes in demand, market uncertainty and a variety of
additional factors that are impossible to control. These factors
include:
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worldwide economic conditions; |
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weather conditions and seasonal trends; |
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the levels of domestic production and consumer demand; |
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the availability of imported natural gas and NGLs; |
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the availability of transportation systems with adequate
capacity; |
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the price and availability of alternative fuels; |
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the effect of energy conservation measures; |
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the nature and extent of governmental regulation and
taxation; and |
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the anticipated future prices of natural gas, NGLs and other
commodities. |
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Our processing, fractionation and storage businesses could
be affected by any decrease in NGL prices or a change in NGL
prices relative to the price of natural gas. |
Lower NGL prices would reduce the revenues we generate from the
sale of NGLs for our own account. Under certain gas processing
contracts, referred to as
percent-of-liquids
contracts, Discovery receives NGLs removed from the natural gas
stream during processing. Discovery can then choose to either
fractionate and sell the NGLs or to sell the NGLs directly. In
addition, product optimization at our Conway fractionator
generally leaves us with excess propane, an NGL, which we sell.
We also sell excess storage volumes resulting from measurement
variances at our Conway storage facilities.
The relationship between natural gas prices and NGL prices may
also affect our profitability. When natural gas prices are low
relative to NGL prices, it is more profitable for Discovery and
its customers to process natural gas. When natural gas prices
are high relative to NGL prices, it is less profitable to
process natural gas both because of the higher value of natural
gas and of the increased cost (principally that of natural gas
as a feedstock and a fuel) of separating the mixed NGLs from the
natural gas. As a result, Discovery may experience periods in
which higher natural gas prices reduce the volumes of natural
gas processed at its Larose plant, which would reduce its gross
processing 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.
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We depend on certain key customers and producers for a
significant portion of our revenues and supply of natural gas
and NGLs. The loss of any of these key customers or producers
could result in a decline in our revenues and cash available to
pay distributions. |
We rely on a limited number of customers for a significant
portion of our revenues. Our three largest customers for the
year ended December 31, 2005, other than a subsidiary of
Williams that markets NGLs for Conway, were BP Products North
America, Inc., SemStream, L.P. and Enterprise Products Partners,
all customers of our Conway facilities. These customers
accounted for approximately 45 percent of our revenues for
the year ended December 31, 2005.
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In addition, although some of these customers are subject to
long-term contracts, we may be unable to negotiate extensions or
replacements of these contracts, on favorable terms, if at all.
The loss of all or even a portion of the volumes of natural gas
or NGLs, as applicable, supplied by these customers, as a result
of competition or otherwise, could have a material adverse
effect on our business, results of operations, financial
condition and our ability to make cash distributions to
unitholders, unless we are able to acquire comparable volumes
from other sources.
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If third-party pipelines and other facilities
interconnected to our pipelines and facilities become
unavailable to transport natural gas and NGLs or to treat
natural gas, our revenues and cash available to pay
distributions could be adversely affected. |
We depend upon third party pipelines and other facilities that
provide delivery options to and from our pipelines and
facilities for the benefit of our customers. For example, MAPL
delivers its customers mixed NGLs to our Conway
fractionator and provides access to multiple end markets for the
NGL products of our storage customers. If MAPL were to become
temporarily or permanently unavailable for any reason, or if
throughput were reduced because of testing, line repair, damage
to pipelines, reduced operating pressures, lack of capacity or
other causes, our customers would be unable to store or deliver
NGL products and we would be unable to receive deliveries of
mixed NGLs at our Conway fractionator. This would have an
immediate adverse impact on our ability to enter into short-term
storage contracts and our ability to fractionate sufficient
volumes of mixed NGLs at Conway.
As another example, Shells Yellowhammer sour gas treating
facility in Coden, Alabama is the only sour gas treating
facility currently connected to our Carbonate Trend pipeline.
Natural gas produced from the Carbonate Trend area must pass
through a Shell-owned pipeline and Shells Yellowhammer
sour gas treating facility before delivery to end markets. If
the Shell-owned pipeline or the Yellowhammer facility were to
become unavailable for current or future volumes of natural gas
delivered to it through the Carbonate Trend pipeline due to
repairs, damages to the facility, lack of capacity or any other
reason, our Carbonate Trend customers would be unable to
continue shipping natural gas to end markets. Since we generally
receive revenues for volumes shipped on the Carbonate Trend
pipeline, this would reduce our revenues.
Any temporary or permanent interruption in operations at MAPL,
Yellowhammer or any other third party pipelines or facilities
that would cause a material reduction in volumes transported on
our pipelines or 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.
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Williams revolving credit facility and
Williams public indentures contain financial and operating
restrictions that may limit our access to credit. In addition,
our ability to obtain credit in the future will be affected by
Williams credit ratings. |
We have the ability to incur up to $75 million of
indebtedness under Williams $1.275 billion revolving
credit facility. However, this $75 million of borrowing
capacity will only be available to us to the extent that
sufficient amounts remain unborrowed by Williams and its other
subsidiaries. As a result, borrowings by Williams could restrict
our access to credit. As of December 31, 2005, letters of
credit totaling $378 million had been issued on behalf of
Williams by the participating institutions under the facility
and we did not have any revolving credit loans outstanding. In
addition, Williams public indentures contain covenants
that restrict Williams and our ability to incur liens to
support indebtedness. As a result, if Williams were not in
compliance with these covenants, we could be unable to make any
borrowings under our $75 million borrowing limit, even if
capacity were otherwise available. These covenants could
adversely affect our ability to finance our future operations or
capital needs or engage in, expand or pursue our business
activities and prevent us from engaging in certain transactions
that might otherwise be considered beneficial to us.
Williams ability to comply with the covenants contained in
its debt instruments may be affected by events beyond our
control, including prevailing economic, financial and industry
conditions. If market or other economic conditions deteriorate,
Williams ability to comply with these covenants may be
impaired. While we
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are not individually subject to any financial covenants or
ratios under Williams revolving credit facility, Williams
and its subsidiaries as a whole are subject to these tests.
Accordingly, any breach of these or other covenants, ratios or
tests, would terminate our and Williams and its other
subsidiaries ability to make additional borrowings under
the credit facility and, as a result, could limit our ability to
finance our operations, make acquisitions or pay distributions
to unitholders. In addition, a breach of these covenants by
Williams would cause the acceleration of Williams and, in
some cases, our outstanding borrowings under the facility. In
the event of acceleration of indebtedness, Williams, the other
borrowers or we might not have, or be able to obtain, sufficient
funds to make required repayments of the accelerated
indebtedness. For more information regarding our debt
agreements, please read Managements Discussion and
Analysis of Financial Condition and Results of
Operations Liquidity and Capital Resources.
Due to our relationship with Williams, our ability to obtain
credit will be affected by Williams credit ratings. If we
obtain our own credit rating, any future down grading of a
Williams credit rating would likely also result in a down
grading of our credit rating. Regardless of whether we have our
own credit rating, a down grading of a Williams credit
rating could limit our ability to obtain financing in the future
upon favorable terms, if at all.
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Discovery is not prohibited from incurring indebtedness,
which may affect our ability to make distributions to
unitholders. |
Discovery is not prohibited by the terms of its limited
liability company agreement from incurring indebtedness. If
Discovery were to incur significant amounts of indebtedness, it
may inhibit their ability to make distributions to us. An
inability by Discovery to make distributions to us would
materially and adversely affect our ability to make
distributions to unitholders because we expect distributions we
receive from Discovery to represent a significant portion of the
cash we distribute to our unitholders.
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We do not own all of the interests in the Conway
fractionator and in Discovery, which could adversely affect our
ability to respond to operate and control these assets in a
manner beneficial to us. |
Because we do not wholly own the Conway fractionator and
Discovery, we may have limited flexibility to control the
operation of, dispose of, encumber or receive cash from these
assets. Any future disagreements with the other co-owners of
these assets could adversely affect our ability to respond to
changing economic or industry conditions, which could have a
material adverse effect on our business, results of operations,
financial condition and ability to make cash distributions to
unitholders.
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Discovery may reduce its cash distributions to us in some
situations |
Discoverys limited liability company agreement provides
that Discovery will distribute its available cash to its members
on a quarterly basis. Discoverys available cash includes
cash on hand less any reserves that may be appropriate for
operating its business. As a result, reserves established by
Discovery, including those for working capital, will reduce the
amount of available cash. The amount of Discoverys
quarterly distributions, including the amount of cash reserves
not distributed, are to be determined by the members of
Discoverys management committee representing a
majority-in-interest in
Discovery.
We own a 40.0 percent interest in Discovery and an
affiliate of Williams owns a 20 percent interest in
Discovery. In addition, to the extent Discovery requires working
capital in excess of applicable reserves, the Williams member
must make working capital advances to Discovery of up to the
amount of Discoverys two most recent prior quarterly
distributions of available cash, but Discovery must repay any
such advances before it can make future distributions to its
members. As a result, the repayment of advances could reduce the
amount of cash distributions we would otherwise receive from
Discovery. In addition, if the Williams member cannot advance
working capital to Discovery as described above,
Discoverys business and financial condition may be
adversely affected.
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We do not operate all of our assets. This reliance on
others to operate our assets and to provide other services could
adversely affect our business and operating results. |
Williams operates all of our assets other than the Carbonate
Trend pipeline, which is operated by Chevron, and our Conway
fractionator and storage facilities, which we operate. We have a
limited ability to control our operations or the associated
costs of these operations. The success of these operations is
therefore dependent upon a number of factors that are outside
our control, including the competence and financial resources of
the operators.
We also rely on Williams for services necessary for us to be
able to conduct our business. Williams may outsource some or all
of these services to third parties, and a failure of all or part
of Williams relationships with its outsourcing providers
could lead to delays in or interruptions of these services. Our
reliance on Williams as an operator and on Williams
outsourcing relationships, our reliance on Chevron 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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Our industry is highly competitive, and increased
competitive pressure could adversely affect our business and
operating results. |
We compete with similar enterprises in our respective areas of
operation. Some of our competitors are large oil, natural gas
and petrochemical companies that have greater financial
resources and access to supplies of natural gas and NGLs than we
do.
Discovery competes with other natural gas gathering and
transportation and processing facilities and other NGL
fractionation facilities located in south Louisiana, offshore in
the Gulf of Mexico and along the Gulf Coast, including the Manta
Ray/ Nautilus systems, the Trunkline pipeline and the Venice
Gathering System and the processing and fractionation facilities
that are connected to these pipelines.
Our Conway fractionation facility competes for volumes of mixed
NGLs with a ONEOK-owned fractionator located in Hutchinson,
Kansas, a ONEOK-owned fractionator located in Medford, Oklahoma,
a ONEOK-owned fractionator located in Bushton, Kansas, the other
joint owners of the Conway fractionation facility and, to a
lesser extent, with fractionation facilities on the Gulf Coast.
Our Conway storage facilities compete with ONEOK-owned storage
facilities in Bushton, Kansas and in Conway, Kansas, an
NCRA-owned facility in Conway, Kansas, a ONEOK-owned facility in
Hutchinson, Kansas and an Enterprise Products Partners-owned
facility in Hutchinson, Kansas and, to a lesser extent, with
storage facilities on the Gulf Coast and in Canada.
In addition, our customers who are significant producers or
consumers of NGLs may develop their own processing,
fractionation and storage facilities in lieu of using ours.
Also, competitors may establish new connections with pipeline
systems that would create additional competition for services we
provide to our customers. For example, other than the producer
gathering lines that connect to the Carbonate Trend pipeline,
there are no other sour gas pipelines near our Carbonate Trend
pipeline, but the producers that are currently our customers
could construct or commission such pipelines in the future. Our
ability to renew or replace existing contracts with our
customers at rates sufficient to maintain current revenues and
cash flows could be adversely affected by the activities of our
competitors. All of these competitive pressures could have a
material adverse effect on our business, results of operations,
financial condition and ability to make cash distributions to
unitholders.
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Our results of storage and fractionation operations are
dependent upon the demand for propane and other NGLs. A
substantial decrease in this demand could adversely affect our
business and operating results. |
Our Conway storage and fractionation operations are impacted by
demand for propane more than any other NGLs. Conway, Kansas is
one of the two major trading hubs for propane and other NGLs in
the continental United States. Demand for propane at Conway is
principally driven by demand for its use as a heating fuel.
However, propane is also used as an engine and industrial fuel
and as a petrochemical feedstock
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in the production of ethylene and propylene. Demand for propane
as a heating fuel is significantly affected by weather
conditions and the availability of alternative heating fuels
such as natural gas. Weather-related demand is subject to normal
seasonal fluctuations, but an unusually warm winter could cause
demand for propane as a heating fuel to decline significantly.
Demand for other NGLs, which include ethane, butane, isobutane
and natural gasoline, could be adversely impacted by general
economic conditions, a reduction in demand by customers for
plastics and other end products made from NGLs, an increase in
competition from petroleum-based products, government
regulations or other reasons. Any decline in demand for propane
or other NGLs could cause a reduction in demand for our Conway
storage and fractionation services.
When prices for the future delivery of propane and other NGLs
that we store at our Conway facilities fall below current
prices, customers are less likely to store these products, which
could reduce our storage revenues. This market condition is
commonly referred to as backwardation. When the
market for propane and other NGLs is in backwardation, the
demand for storage capacity at our Conway facilities may
decrease. While this would not impact our long-term capacity
leases, customers could become less likely to enter into
short-term storage contracts.
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We may not be able to grow or effectively manage our
growth. |
A principal focus of our strategy is to continue to grow by
expanding our business. Our future growth will depend upon a
number of factors, some of which we can control and some of
which we cannot. These factors include our ability to:
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identify businesses engaged in managing, operating or owning
pipeline, processing, fractionation and storage assets, or other
midstream assets for acquisitions, joint ventures and
construction projects; |
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control costs associated with acquisitions, joint ventures or
construction projects; |
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consummate acquisitions or joint ventures and complete
construction projects, including Discoverys Tahiti lateral
expansion project; |
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integrate any acquired or constructed business or assets
successfully with our existing operations and into our operating
and financial systems and controls; |
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hire, train and retain qualified personnel to manage and operate
our growing business; and |
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obtain required financing for our existing and new operations. |
A failure to achieve any of these factors would adversely affect
our ability to achieve anticipated growth in the level of cash
flows or realize anticipated benefits. Furthermore, competition
from other buyers could reduce our acquisition opportunities or
cause us to pay a higher price than we might otherwise pay. In
addition, Williams is not restricted from competing with us.
Williams may acquire, construct or dispose of midstream or other
assets in the future without any obligation to offer us the
opportunity to purchase or construct those assets.
We may acquire new facilities or expand our existing facilities
to capture anticipated future growth in natural gas production
that does not ultimately materialize. As a result, our new or
expanded facilities may not achieve profitability. In addition,
the process of integrating newly acquired or constructed assets
into our operations may result in unforeseen operating
difficulties, may absorb significant management attention and
may require financial resources that would otherwise be
available for the ongoing development and expansion of our
existing operations. Future acquisitions or construction
projects could result in the incurrence of indebtedness and
additional liabilities and excessive costs that could have a
material adverse effect on our business, results of operations,
financial condition and ability to make cash distributions to
unitholders. Further, if we issue additional common units in
connection with future acquisitions, unitholders interest
in the partnership will be diluted and distributions to
unitholders may be reduced.
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Discoverys interstate tariff rates are subject to
review and possible adjustment by federal regulators, which
could have a material adverse effect on our business and
operating results. Moreover, because Discovery is a
non-corporate entity, it may be disadvantaged in calculating its
cost of service for
rate-making
purposes. |
The Federal Energy Regulatory Commission, or FERC, pursuant to
the Natural Gas Act, regulates Discoverys interstate
pipeline transportation service. Under the Natural Gas Act,
interstate transportation rates must be just and reasonable and
not unduly discriminatory. If the tariff rates Discovery is
permitted to charge its customers are lowered by FERC, on its
own initiative, or as a result of challenges raised by
Discoverys customers or third parties, FERC could require
refunds of amounts collected under rates which it finds
unlawful. An adverse decision by FERC in approving
Discoverys regulated rates could adversely affect our cash
flows. Although FERC generally does not regulate the natural gas
gathering operations of Discovery under the Natural Gas Act,
federal regulation influences the parties that gather natural
gas on the Discovery gas gathering system.
Discoverys maximum regulated rate for mainline
transportation is scheduled to decrease in 2008. At that time,
Discovery may be required to reduce its mainline transportation
rate on all of its contracts that have rates above the new
maximum rate. This could reduce the revenues generated by
Discovery. Discovery may elect to file a rate case with FERC
seeking to alter this scheduled maximum rate reduction. However,
if filed, a rate case may not be successful in even partially
preventing the rate reduction. If Discovery makes such a filing,
all aspects of Discoverys cost of service and rate design
could be reviewed, which could result in additional reductions
to its regulated rates.
In July 2004, the United States Court of Appeals for the
District of Columbia Circuit, or the D.C. Circuit, issued its
opinion in BP West Coast Products, LLC v. FERC,
which upheld, among other things, the FERCs determination
that certain rates of an interstate petroleum products pipeline,
SFPP, L.P., or SFPP, were grandfathered rates under the Energy
Policy Act of 1992 and that SFPPs shippers had not
demonstrated substantially changed circumstances that would
justify modification of those rates. The court also vacated the
portion of the FERCs decision applying the Lakehead
policy. In the Lakehead decision, the FERC allowed an
oil pipeline publicly traded partnership to include in its
cost-of-service an
income tax allowance to the extent that its unitholders were
corporations subject to income tax. In May and June 2005, the
FERC issued a statement of general policy, as well as an order
on remand of BP West Coast, respectively, in which the
FERC stated it will permit pipelines to include in
cost-of-service a tax
allowance to reflect actual or potential tax liability on their
public utility income attributable to all partnership or limited
liability company interests, if the ultimate owner of the
interest has an actual or potential income tax liability on such
income. Whether a pipelines owners have such actual or
potential income tax liability will be reviewed by the FERC on a
case-by-case basis. Although the new policy is generally
favorable for pipelines that are organized as pass-through
entities, it still entails rate risk due to the
case-by-case review
requirement. In December 2005, the FERC issued its first
case-specific oil pipeline review of the income tax allowance
issue in the SFPP proceeding, reaffirming its new income tax
allowance policy and directing SFPP to provide certain evidence
necessary for the pipeline to determine its income allowance.
The FERCs BP West Coast remand decision and the new
tax allowance policy have been appealed to the D.C. Circuit, and
rehearing requests have been filed with respect to the December
16 order. As a result, the ultimate outcome of these proceedings
is not certain and could result in changes to the FERCs
treatment of income tax allowances in
cost-of-service. If
Discovery were to file a rate case, as discussed above, it would
be required to prove pursuant to the new policys standard
that the inclusion of an income tax allowance in
Discoverys
cost-of-service was
permitted. If the FERC were to disallow a substantial portion of
Discoverys income tax allowance, it may be more difficult
for Discovery to justify its rates.
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Our operations are subject to operational hazards and
unforeseen interruptions for which we may not be adequately
insured. |
There are operational risks associated with the gathering,
transporting and processing of natural gas and the fractionation
and storage of NGLs, including:
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hurricanes, tornadoes, floods, fires, extreme weather conditions
and other natural disasters and acts of terrorism; |
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damages to pipelines and pipeline blockages; |
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leakage of natural gas (including sour gas), NGLs, brine or
industrial chemicals; |
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collapse of NGL storage caverns; |
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operator error; |
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pollution; |
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fires, explosions and blowouts; |
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risks related to truck and rail loading and unloading; and |
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risks related to operating in a marine environment. |
Any of these or any other similar occurrences could result in
the disruption of our operations, substantial repair costs,
personal injury or loss of life, property damage, damage to the
environment or other significant exposure to liability. For
example, in 2004 we experienced a temporary interruption of
service on one of our pipelines due to an influx of seawater
while connecting a new lateral. In addition, the Carbonate Trend
pipeline is scheduled to be temporarily shut down in the second
half of 2006 in connection with restoration activities due to
the partial erosion of the pipeline overburden caused by
Hurricane Ivan in September 2004. We believe the cost of these
restoration activities will be between $3.4 and
$4.6 million.
In addition, in anticipation of Hurricane Katrina, the Discovery
and Carbonate Trend assets were temporarily shut down on
August 27, 2005. The Carbonate Trend assets were off-line
for ten days and then experienced a gradual return to
pre-hurricane throughput rates by September 19, 2005. In
anticipation of Hurricane Rita, the Discovery assets, which were
already at reduced throughput from Hurricane Katrina, were
temporarily shut down on September 21, 2005. The Discovery
assets were off-line for seven days and then continued to
experience lower throughput rates through the end of October. We
estimate the unfavorable impact of these hurricanes on our
2005 net income was approximately $1.5 million due
primarily to the impact of these hurricanes on Discoverys
results. Discoverys net income was unfavorably impacted by
an approximate loss of $2.3 million in revenue and
$1.0 million in uninsured expenses. Discoverys
property insurance policy includes a $1.0 million
deductible per occurrence. Please read Managements
Discussion and Analysis of Financial Condition
Recent Events.
Insurance may be inadequate, and in some instances, we may be
unable to obtain insurance on commercially reasonable terms, if
at all. A significant disruption in operations or a significant
liability for which we were not fully insured could have a
material adverse effect on our business, results of operations
and financial condition and our ability to make cash
distributions to unitholders.
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Pipeline integrity programs and repairs may impose
significant costs and liabilities on us. |
In December 2003, the U.S. Department of Transportation
issued a final rule requiring pipeline operators to develop
integrity management programs for gas transportation pipelines
located where a leak or rupture could do the most harm in
high consequence areas. The final rule requires
operators to:
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perform ongoing assessments of pipeline integrity; |
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identify and characterize applicable threats to pipeline
segments that could impact a high consequence area; |
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improve data collection, integration and analysis; |
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repair and remediate the pipeline as necessary; and |
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implement preventive and mitigating actions. |
The final rule incorporates the requirements of the Pipeline
Safety Improvement Act of 2002. The final rule became effective
on January 14, 2004. In response to this new Department of
Transportation rule, we have initiated pipeline integrity
testing programs that are intended to assess pipeline integrity.
In addition, we have voluntarily initiated a testing program to
assess the integrity of the brine pipelines of our Conway
storage facilities. In 2005, Conway replaced two sections of
brine systems at a cost of $0.2 million. This work is in
anticipation of integrity testing scheduled to begin in 2006.
The results of these testing programs could cause us to incur
significant capital and operating expenditures in response to
any repair, remediation, preventative or mitigating actions that
are determined to be necessary.
Additionally, the transportation of sour gas in our Carbonate
Trend pipeline necessitates a corrosion control program in order
to protect the integrity of the pipeline and prolong its life.
Our corrosion control program may not be successful and the sour
gas could compromise pipeline integrity. Our inability to reduce
corrosion on our Carbonate Trend pipeline to acceptable levels
could significantly reduce the service life of the pipeline and
could have a material adverse effect on our business, results of
operations, financial condition and ability to make cash
distributions to unitholders. Please read
Business The Carbonate Trend
Pipeline General.
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We do not own all of the land on which our pipelines and
facilities are located, which could disrupt our
operations. |
We do not own all of the land on which our pipelines and
facilities have been constructed, and we are therefore subject
to the possibility of increased costs to retain necessary land
use. We obtain the rights to construct and operate our pipelines
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.
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Our operations are subject to governmental laws and
regulations relating to the protection of the environment, which
may expose us to significant costs and liabilities. |
The risk of substantial environmental costs and liabilities is
inherent in natural gas gathering, transportation and
processing, and in the fractionation and storage of NGLs, and we
may incur substantial environmental costs and liabilities in the
performance of these types of operations. Our operations are
subject to stringent federal, state and local laws and
regulations relating to protection of the environment. These
laws include, for example:
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the Federal Clean Air Act and analogous state laws, which impose
obligations related to air emissions; |
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the Federal Water Pollution Control Act of 1972, as renamed and
amended as the Clean Water Act, or CWA, and analogous state
laws, which regulate discharge of wastewaters from our
facilities to state and federal waters; |
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the federal Comprehensive Environmental Response, Compensation,
and Liability Act, also known as CERCLA or the Superfund law,
and analogous state laws that regulate the cleanup of hazardous
substances that may have been released at properties currently
or previously owned or operated by us or locations to which we
have sent wastes for disposal; and |
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the federal Resource Conservation and Recovery Act, also known
as RCRA, and analogous state laws that impose requirements for
the handling and discharge of solid and hazardous waste from our
facilities. |
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Various governmental authorities, including the
U.S. Environmental Protection Agency, or EPA, have the
power to enforce compliance with these laws and regulations and
the permits issued under them, and violators are subject to
administrative, civil and criminal penalties, including civil
fines, injunctions or both. Joint and several, strict liability
may be incurred without regard to fault under CERCLA, RCRA and
analogous state laws for the remediation of contaminated areas.
There is inherent risk of the incurrence of environmental costs
and liabilities in our business due to our handling of the
products we gather, transport, process, fractionate and store,
air emissions related to our operations, historical industry
operations, waste disposal practices, and the prior use of flow
meters containing mercury, some of which may be material.
Private parties, including the owners of properties through
which our pipeline systems pass, may have the right to pursue
legal actions to enforce compliance as well as to seek damages
for non-compliance with environmental laws and regulations or
for personal injury or property damage arising from our
operations. Some sites we operate are located near current or
former third party hydrocarbon storage and processing operations
and there is a risk that contamination has migrated from those
sites to ours. In addition, increasingly strict laws,
regulations and enforcement policies could significantly
increase our compliance costs and the cost of any remediation
that may become necessary, some of which may be material.
For example, the Kansas Department of Health and Environment, or
the KDHE, regulates the storage of NGLs and natural gas in the
state of Kansas. This agency also regulates the construction,
operation and closure of brine ponds associated with such
storage facilities. In response to a significant incident at a
third party facility, the KDHE recently promulgated more
stringent regulations regarding safety and integrity of brine
ponds and storage caverns. These regulations are subject to
interpretation and the costs associated with compliance with
these regulations could vary significantly depending upon the
interpretation of these regulations. The KDHE has advised us
that one such regulation relating to the metering of NGL volumes
that are injected and withdrawn from our caverns may be
interpreted and enforced to require the installation of meters
at each of our well bores. We have informed the KDHE that we
disagree with this interpretation, and the KDHE has asked us to
provide it with additional information. We have made a proposal
to install individual cavern meters at 13 caverns that are
connected to the fractionator and NGL pipelines. The estimated
cost for this work is $220,000. If this proposal is not accepted
we estimate that the cost of installing a meter at each of our
well bores at two of our Conway storage facilities would total
approximately $3.9 million over three years. Additionally,
incidents similar to the incident at a third party facility that
prompted the recent KDHE regulations could prompt the issuance
of even stricter regulations.
Our insurance may not cover all environmental risks and costs or
may not provide sufficient coverage in the event an
environmental claim is made against us. Our business may be
adversely affected by increased costs due to stricter pollution
control requirements or liabilities resulting from
non-compliance with required operating or other regulatory
permits. Also, new environmental regulations might adversely
affect our products and activities, including processing,
fractionation, storage and transportation, as well as waste
management and air emissions. Federal and state agencies also
could impose additional safety requirements, any of which could
affect our profitability.
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Potential changes in accounting standards might cause us
to revise our financial results and disclosure in the
future. |
Recently-discovered accounting irregularities in various
industries have forced regulators and legislators to take a
renewed look at accounting practices, financial disclosure, the
relationships between companies and their independent auditors,
and retirement plan practices. It remains unclear what new laws
or regulations will be adopted, and we cannot predict the
ultimate impact that any such new laws or regulations could
have. In addition, the Financial Accounting Standards Board or
the SEC could enact new accounting standards that 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.
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Terrorist attacks have resulted in increased costs, and
attacks directed at our facilities or those of our suppliers and
customers could disrupt our operations. |
On September 11, 2001, the United States was the target of
terrorist attacks of unprecedented scale. Since the September 11
attacks, the United States government has issued warnings that
energy assets may be the future target of terrorist
organizations. These developments have subjected our operations
to increased risks and costs. The long-term impact that
terrorist attacks and the threat of terrorist attacks may have
on our industry in general, and on us in particular, is not
known at this time. Uncertainty surrounding continued
hostilities in the Middle East or other sustained military
campaigns may affect our operations in unpredictable ways. In
addition, uncertainty regarding future attacks and war cause
global energy markets to become more volatile. Any terrorist
attack on our facilities or those of our suppliers or customers
could have a material adverse effect on our business, results of
operations, financial condition and ability to make cash
distributions to unitholders.
Changes in the insurance markets attributable to terrorists
attacks may make certain types of insurance more difficult for
us to obtain. Moreover, the insurance that may be available to
us may be significantly more expensive than our existing
insurance coverage. Instability in financial markets as a result
of terrorism or war could also affect our ability to raise
capital.
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We are exposed to the credit risk of our customers and our
credit risk management may not be adequate to protect against
such risk. |
We are subject to the risk of loss resulting from nonpayment
and/or nonperformance by our customers. Our credit procedures
and policies may not be adequate to fully eliminate customer
credit risk. If we fail to adequately assess the
creditworthiness of existing or future customers, unanticipated
deterioration in their creditworthiness and any resulting
increase in nonpayment and/or nonperformance by them could have
a material adverse effect on our business, results of
operations, financial condition and ability to make cash
distributions to unitholders.
Risks Inherent in an Investment in Us
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Our general partner and its affiliates have conflicts of
interest and limited fiduciary duties, which may permit them to
favor their own interests to the detriment of our
unitholders. |
Williams owns the two percent general partner interest and a
59 percent limited partner interest in us and owns and
controls our general partner. Although our general partner has a
fiduciary duty to manage us in a manner beneficial to us and our
unitholders, the directors and executive officers of our general
partner have a fiduciary duty to manage our general partner in a
manner beneficial to its owner, Williams. Conflicts of interest
may arise between our general partner and its affiliates, on the
one hand, and us and our unitholders, on the other hand. In
resolving these conflicts, our general partner may favor its own
interests and the interests of its affiliates over the interests
of our unitholders. These conflicts include, among others, the
following situations:
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neither our partnership agreement nor any other agreement
requires Williams or its affiliates to pursue a business
strategy that favors us; |
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our general partner is allowed to take into account the
interests of parties other than us, such as Williams, in
resolving conflicts of interest, which has the effect of
limiting its fiduciary duty to our unitholders; |
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Williams and its affiliates may engage in competition with us; |
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our general partner has limited its liability and reduced its
fiduciary duties, and has also restricted the remedies available
to our unitholders for actions that, without the limitations,
might constitute breaches of fiduciary duty; |
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our general partner determines the amount and timing of our cash
reserves, asset purchases and sales, capital expenditures,
borrowings and issuances of additional partnership securities,
each of which can affect the amount of cash that is distributed
to our unitholders; |
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our general partner determines the amount and timing of any
capital expenditures, as well as whether a capital expenditure
is a maintenance capital expenditure, which reduces operating
surplus, or an expansion capital expenditure, which does not,
which determination can affect the amount of cash that is
distributed to our unitholders and the ability of the
subordinated units to convert to common units; |
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in some instances, our general partner may cause us to borrow
funds in order to permit the payment of cash distributions, even
if the purpose or effect of the borrowing is to make a
distribution on the subordinated units, to make incentive
distributions or to accelerate the expiration of the
subordination period; |
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our general partner determines which costs incurred by it and
its affiliates are reimbursable by us; |
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our partnership agreement does not restrict our general partner
from causing us to pay it or its affiliates for any services
rendered to us or entering into additional contractual
arrangements with any of these entities on our behalf; |
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our general partner intends to limit its liability regarding our
contractual and other obligations; |
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our general partner may exercise its limited right to call and
purchase common units if it and its affiliates own more than
80 percent of the common units; |
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our general partner controls the enforcement of obligations owed
to us by it and its affiliates; and |
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our general partner decides whether to retain separate counsel,
accountants or others to perform services for us. |
Please read Certain Relationships and Related
Transactions Omnibus Agreement.
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Our partnership agreement limits our general
partners fiduciary duties to unitholders and restricts the
remedies available to unitholders for actions taken by our
general partner that might otherwise constitute breaches of
fiduciary duty. |
Our partnership agreement contains provisions that reduce the
standards to which our general partner would otherwise be held
by state fiduciary duty law. For example, our partnership
agreement:
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permits our general partner to make a number of decisions in its
individual capacity, as opposed to in its capacity as our
general partner. This entitles our general partner to consider
only the interests and factors that it desires, and it has no
duty or obligation to give any consideration to any interest of,
or factors affecting, us, our affiliates or any limited partner.
Examples include the exercise of its limited call right, its
voting rights with respect to the units it owns, its
registration rights and its determination whether or not to
consent to any merger or consolidation of the partnership; |
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provides that our general partner will not have any liability to
us or our unitholders for decisions made in its capacity as a
general partner so long as it acted in good faith, meaning it
believed the decision was in the best interests of our
partnership; |
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provides that resolutions of conflicts of interest not approved
by the conflicts committee of the board of directors of our
general partner and not involving a vote of unitholders must be
on terms no less favorable to us than those generally being
provided to or available from unrelated third parties or be
fair and reasonable to us, as determined by our
general partner in good faith, and that, in determining whether
a transaction or resolution is fair and reasonable,
our general partner may consider the totality of the
relationships between the parties involved, including other
transactions that may be particularly advantageous or beneficial
to us; and |
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provides that our general partner, its affiliates and their
officers and directors will not be liable for monetary damages
to us or our limited partners for any acts or omissions unless
there has been a final |
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and non-appealable judgment entered by a court of competent
jurisdiction determining that our general partner or those other
persons acted in bad faith or engaged in fraud or willful
misconduct. |
By purchasing a common unit, a common unitholder will be bound
by the provisions in the partnership agreement, including the
provisions discussed above.
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Even if unitholders are dissatisfied, they cannot
currently remove our general partner without its consent. |
Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our
business and, therefore, limited ability to influence
managements decisions regarding our business. Unitholders
will have no right to elect our general partner or its board of
directors on an annual or other continuing basis. The board of
directors of our general partner is chosen by Williams. As a
result of these limitations, the price at which our common units
will trade could be diminished because of the absence or
reduction of a takeover premium in the trading price.
Furthermore, if our unitholders are dissatisfied with the
performance of our general partner, they will have little
ability to remove our general partner. The vote of the holders
of at least
662/3 percent
of all outstanding common and subordinated units voting together
as a single class is required to remove our general partner.
Accordingly, our unitholders are currently unable to remove our
general partner without its consent because affiliates of our
general partner own sufficient units to be able to prevent the
general partners removal. Also, if our general partner is
removed without cause during the subordination period and units
held by our general partner and its affiliates are not voted in
favor of that removal, all remaining subordinated units will
automatically be converted into common units and any existing
arrearages on the common units will be extinguished. A removal
of our general partner under these circumstances would adversely
affect the common units by prematurely eliminating their
distribution and liquidation preference over the subordinated
units, which would otherwise have continued until we had met
certain distribution and performance tests.
Cause is narrowly defined in our partnership agreement to mean
that a court of competent jurisdiction has entered a final,
non-appealable judgment finding our general partner liable for
actual fraud, gross negligence or willful or wanton misconduct
in its capacity as our general partner. Cause does not include
most cases of charges of poor management of the business, so the
removal of our general partner because of the unitholders
dissatisfaction with our general partners performance in
managing our partnership will most likely result in the
termination of the subordination period.
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The control of our general partner may be transferred to a
third party without unitholder consent. |
Our general partner may transfer its general partner interest to
a third party in a merger or in a sale of all or substantially
all of its assets without the consent of the unitholders.
Furthermore, our partnership agreement does not restrict the
ability of the members of our general partner from transferring
their member interest in our general partner to a third party.
The new members of our general partner would then be in a
position to replace the board of directors and officers of the
general partner with their own choices and to control the
decisions taken by the board of directors and officers of the
general partner. In addition, pursuant to the omnibus agreement
with Williams, any new owner of the general partner would be
required to change our name so that there would be no further
reference to Williams.
|
|
|
Increases in interest rates may cause the market price of
our common units to decline. |
An increase in interest rates may cause a corresponding decline
in demand for equity investments in general, and in particular
for yield-based equity investments such as our common units. Any
such increase in interest rates or reduction in demand for our
common units resulting from other more attractive investment
opportunities may cause the trading price of our common units to
decline.
32
|
|
|
We may issue additional common units without unitholder
approval, which would dilute unitholder ownership
interests. |
Our general partner, without the approval of our unitholders,
may cause us to issue an unlimited number of additional units
subject to the limitations imposed by the New York Stock
Exchange. The issuance by us of additional common units or other
equity securities of equal or senior rank will have the
following effects:
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|
|
|
our unitholders proportionate ownership interest in us
will decrease; |
|
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|
the amount of cash available to pay distributions on each unit
may decrease; |
|
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|
because a lower percentage of total outstanding units will be
subordinated units, the risk that a shortfall in the payment of
the minimum quarterly distribution will be borne by our common
unitholders will increase; |
|
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|
the relative voting strength of each previously outstanding unit
may be diminished; and |
|
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|
the market price of the common units may decline. |
|
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|
Williams and its affiliates may compete directly with us
and have no obligation to present business opportunities to
us. |
The omnibus agreement does not prohibit Williams and its
affiliates from owning assets or engaging in businesses that
compete directly or indirectly with us. Williams may acquire,
construct or dispose of additional midstream or other assets in
the future without any obligation to offer us the opportunity to
purchase or construct any of those assets. In addition, under
our partnership agreement, the doctrine of corporate
opportunity, or any analogous doctrine, will not apply to
Williams and its affiliates. As a result, neither Williams nor
any of its affiliates has any obligation to present business
opportunities to us. Please read Certain Relationships and
Related Transactions Omnibus Agreement.
|
|
|
Our general partner has a limited call right that may
require unitholders to sell their common units at an undesirable
time or price. |
If at any time our general partner and its affiliates own more
than 80 percent of the common units, our general partner
will have the right, but not the obligation, which it may assign
to any of its affiliates or to us, to acquire all, but not less
than all, of the common units held by unaffiliated persons at a
price not less than their then-current market price. As a
result, non-affiliated unitholders may be required to sell their
common units at an undesirable time or price and may not receive
any return on their investment. Such unitholders may also incur
a tax liability upon a sale of their units. Our general partner
is not obligated to obtain a fairness opinion regarding the
value of the common units to be repurchased by it upon exercise
of the limited call right. There is no restriction in our
partnership agreement that prevents our general partner from
issuing additional common units and exercising its call right.
If our general partner exercised its limited call right, the
effect would be to take us private and, if the units were
subsequently deregistered, we would not longer be subject to the
reporting requirements of the Securities Exchange Act of 1934.
|
|
|
Our partnership agreement restricts the voting rights of
unitholders owning 20 percent or more of our common
units. |
Our partnership agreement restricts unitholders voting
rights by providing that any units held by a person that owns
20 percent or more of any class of units then outstanding,
other than our general partner and its affiliates, their
transferees and persons who acquired such units with the prior
approval of the board of directors of our general partner,
cannot vote on any matter. The partnership agreement also
contains provisions limiting the ability of unitholders to call
meetings or to acquire information about our operations, as well
as other provisions limiting the unitholders ability to
influence the manner or direction of management.
33
|
|
|
Cost reimbursements due our general partner and its
affiliates will reduce cash available to pay distributions to
unitholders. |
Prior to making any distribution on the common units, we will
reimburse our general partner and its affiliates for all
expenses they incur on our behalf, which will be determined by
our general partner. These expenses will include all costs
incurred by the general partner and its affiliates in managing
and operating us, including costs for rendering corporate staff
and support services to us. Please read Certain
Relationships and Related Transactions. The reimbursement
of expenses and payment of fees, if any, to our general partner
and its affiliates could adversely affect our ability to pay
cash distributions to unitholders.
|
|
|
Unitholders may not have limited liability if a court
finds that unitholder action constitutes control of our
business. Unitholders may also have liability to repay
distributions. |
As a limited partner in a partnership organized under Delaware
law, unitholders could be held liable for our obligations to the
same extent as a general partner if they participate in the
control of our business. Our general partner
generally has unlimited liability for the obligations of the
partnership, such as its debts and environmental liabilities,
except for those contractual obligations of the partnership that
are expressly made without recourse to our general partner. In
addition, Section 17-607 of the Delaware Revised Uniform
Limited Partnership Act provides that, under some circumstances,
a unitholder may be liable to us for the amount of a
distribution for a period of three years from the date of the
distribution. The limitations on the liability of holders of
limited partner interests for the obligations of a limited
partnership have not been clearly established in some of the
other states in which we do business.
|
|
|
Common units held by affiliates of Williams eligible for
future sale may have adverse effects on the price of our common
units. |
As of February 28, 2006, affiliates of Williams held
1,250,000 common units and 7,000,000 subordinated units,
representing a 59 percent limited partnership interest in
us. The affiliates of Williams may, from time to time, sell all
or a portion of their common units or subordinated units. Sales
of substantial amounts of their common units or subordinated
units, or the anticipation of such sales, could lower the market
price of our common units and may make it more difficult for us
to sell our equity securities in the future at a time and at a
price that we deem appropriate.
Tax Risks
|
|
|
Our tax treatment depends on our status as a partnership
for federal income tax purposes, as well as our not being
subject to entity-level taxation by states. If the IRS were to
treat us as a corporation or if we were to become subject to
entity-level taxation for state tax purposes, then our cash
available to pay distributions to unitholders would be
substantially reduced. |
The anticipated after-tax benefit of an investment in the common
units depends largely on our being treated as a partnership for
federal income tax purposes. We have not requested, and do not
plan to request, a ruling from the IRS on this or any other
matter affecting us.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our income at the
corporate tax rate, which is currently a maximum of
35 percent. 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. For example, because of
widespread state budget deficits, several states are evaluating
ways to subject partnerships to entity-level taxation through
the imposition of state income, franchise or other forms of
taxation. If any state were to impose a tax upon us as an
entity, the
34
cash available to pay distributions to unitholders would be
reduced. The partnership agreement provides that if a law is
enacted or existing law is modified or interpreted in a manner
that subjects us to taxation as a corporation or otherwise
subjects us to entity-level taxation for federal, state or local
income tax purposes, then the minimum quarterly distribution
amount and the target distribution amounts will be adjusted to
reflect the impact of that law on us.
|
|
|
A successful IRS contest of the federal income tax
positions we take may adversely impact the market for our common
units, and the costs of any contest will be borne by our
unitholders and our general partner. |
We have not requested any ruling from the IRS with respect to
our treatment as a partnership for federal income tax purposes
or any other matter affecting us. The IRS may adopt positions
that differ from our counsels conclusions. It may be
necessary to resort to administrative or court proceedings to
sustain some or all of our counsels conclusions or the
positions we take. A court may not agree with some or all of our
counsels conclusions or the positions we take. Any contest
with the IRS may materially and adversely impact the market for
our common units and the price at which they trade. In addition,
the costs of any contest with the IRS will result in a reduction
in cash available to pay distributions to our unitholders and
our general partner and thus will be borne indirectly by our
unitholders and our general partner.
|
|
|
Unitholders may be required to pay taxes on their share of
our income even if unitholders do not receive any cash
distributions from us. |
Unitholders are required to pay federal income taxes and, in
some cases, state and local income taxes on their share of our
taxable income, whether or not they receive cash distributions
from us. Unitholders may not receive cash distributions from us
equal to their share of our taxable income or even equal to the
actual tax liability that results from their share of our
taxable income.
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|
The tax gain or loss on the disposition of our common
units could be different than expected. |
If a unitholder sell its common units, it will recognize gain or
loss equal to the difference between the amount realized and its
tax basis in those common units. Prior distributions to a
unitholder in excess of the total net taxable income it was
allocated for a common unit, which decreased its tax basis in
that common unit, will, in effect, become taxable income to the
unitholder if the common unit is sold at a price greater than
its tax basis in that common unit, even if the price the
unitholder receives is less than its original cost. A
substantial portion of the amount realized, whether or not
representing gain, may be ordinary income to the unitholder.
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|
Tax-exempt entities and foreign persons face unique tax
issues from owning common units that may result in adverse tax
consequences to them. |
Investment in common units by tax-exempt entities, such as
individual retirement accounts (known as IRAs), regulated
investment companies (known as mutual funds), and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to organizations exempt from federal income
tax, including individual retirement accounts and other
retirement plans, will be unrelated business taxable income and
will be taxable to them. Distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
will be required to file United States federal income tax
returns and pay tax on their share of our taxable income.
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|
We will treat each purchaser of units as having the same
tax benefits without regard to the units purchased. The IRS may
challenge this treatment, which could adversely affect the value
of the common units. |
Because we cannot match transferors and transferees of common
units, we will adopt depreciation and amortization positions
that may not conform will all aspects of existing Treasury
regulations. A successful IRS challenge to those positions could
adversely affect the amount of tax benefits available to
unitholders. It also
35
could affect the timing of these tax benefits or the amount of
gain from the sale of common units and could have a negative
impact on the value of our common units or result in audit
adjustments to unitholder tax returns.
|
|
|
Unitholders will likely be subject to state and local
taxes and return filing requirements as a result of investing in
our common units. |
In addition to federal income taxes, unitholders will likely be
subject to other taxes, such as state and local income taxes,
unincorporated business taxes and estate, inheritance, or
intangible taxes that are imposed by the various jurisdictions
in which we do business or own property. Unitholders will likely
be required to file state and local income tax returns and pay
state and local income taxes in some or all of these various
jurisdictions. Further, unitholders may be subject to penalties
for failure to comply with those requirements. We own property
and conduct business in Kansas, Louisiana and Alabama. We may
own property or conduct business in other states or foreign
countries in the future. It is the unitholders
responsibility to file all federal, state and local tax returns.
Our counsel has not rendered an opinion on the state and local
tax consequences of an investment in our common units.
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|
The sale or exchange of 50 percent or more of our
capital and profits interests will result in the termination of
our partnership for federal income tax purposes. |
We will be considered to have terminated for federal income tax
purposes if there is a sale or exchange of 50 percent or
more of the total interests in our capital and profits within a
12-month period. Our
termination would, among other things, result in the closing of
our taxable year for all unitholders and could result in a
deferral of depreciation deductions allowable in computing our
taxable income.
FORWARD LOOKING STATEMENTS AND CAUTIONARY STATEMENT
FOR PURPOSES OF THE SAFE HARBOR PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Certain matters discussed in this annual report, excluding
historical information, include forward-looking
statements statements that discuss our expected
future results based on current and pending business operations.
We make these forward-looking statements in reliance on the safe
harbor protections provided under the Private Securities
Litigation Reform Act of 1995.
All statements, other than statements of historical facts,
included in this report which address activities, events or
developments which we expect, believe or anticipate will or may
occur in the future are forward-looking statements.
Forward-looking statements can be identified by words such as
may, anticipates, believes,
expects, planned, scheduled,
could, continues, estimates,
forecasts, might, potential,
projects or similar expressions. Similarly,
statements that describe our future plans, objectives or goals
are also forward-looking statements.
Although we believe these forward-looking statements are based
on reasonable assumptions, statements made regarding future
results are subject to a number of assumptions, uncertainties
and risks that may cause future results to be materially
different from the results stated or implied in this document.
These risks and uncertainties include, among other things:
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We may not have sufficient cash from operations to enable us to
pay the minimum distribution following establishment of cash
reserves and payment of fees and expenses, including payments to
our general partner. |
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|
Because of the natural decline in production from existing
wells, the success of our gathering business depends on our
ability to obtain new sources of natural gas supply, which is
dependent on factors beyond our control. Any decrease in
supplies of natural gas could adversely affect our business and
operating results. |
36
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Our processing, fractionation and storage businesses could be
affected by any decrease in the price of natural gas liquids or
a change in the price of natural gas liquids relative to the
price of natural gas. |
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|
Williams revolving credit facility and Williams
public indentures contain financial and operating restrictions
that may limit our access to credit. In addition, our ability to
obtain credit in the future will be affected by Williams
credit ratings. |
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|
Our general partner and its affiliates have conflicts of
interest and limited fiduciary duties, which may permit them to
favor their own interests to the detriment of our unitholders. |
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Even if unitholders are dissatisfied, they cannot currently
remove our general partner without its consent. |
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Unitholders may be required to pay taxes on their share of our
income even if they do not receive any cash distributions from
us. |
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Our operations are subject to operational hazards and unforeseen
interruptions for which we may or may not be adequately insured. |
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Lower natural gas and oil prices could adversely affect our
fractionation and storage businesses. |
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We depend on certain key customers and producers for a
significant portion of our revenues and supply of natural gas
and natural gas liquids. The loss of any of these key customers
or producers could result in a decline in our revenues and cash
available to pay distributions. |
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|
If third-party pipelines and other facilities interconnected to
our pipelines and facilities become unavailable to transport
natural gas and natural gas liquids or to treat natural gas, our
revenues and cash available to pay distributions could be
adversely affected. |
When considering these forward-looking statements, you should
keep in mind the risk factors and other cautionary statements in
this report. The risk factors discussed in this Item 1A and
other factors noted throughout this report could cause our
actual results to differ materially from those contained in any
forward-looking statement. The forward-looking statements
included in this report are only made as of the date of this
report and we undertake no obligation to publicly update
forward-looking statements to reflect subsequent events or
circumstances.
Item 1B. Unresolved
Staff Comments
None.
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Item 3. |
Legal Proceedings |
The information called for by this item is provided in
Note 13, Commitments and Contingencies included in the
Notes to Consolidated Financial Statements of this report, which
information is incorporated into this Item 3 by reference.
37
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Item 4. |
Submission of Matters to a Vote of Security Holders |
None.
PART II
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Item 5. |
Market for Registrants Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity
Securities |
Market Information, Holders and Distributions
Our common units are listed on the New York Stock Exchange under
the symbol WPZ. At the close of business on
March 1, 2006, there were 7,006,146 common units
outstanding, held by approximately 3,494 holders, including
common units held in street name and by affiliates of Williams.
The high and low sales price ranges (New York Stock Exchange
composite transactions) and distributions declared by quarter
for each of the last two fiscal quarters of 2005 since the IPO
of our common units in August 2005 are as follows:
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2005 | |
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| |
Quarter |
|
High | |
|
Low | |
|
Distribution(2) | |
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| |
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| |
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| |
3rd(1)
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|
$ |
32.75 |
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|
$ |
24.89 |
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|
$ |
0.1484 |
(3) |
4th
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|
$ |
34.46 |
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$ |
29.75 |
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$ |
0.35 |
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(1) |
For the period from August 23, 2005 through
September 30, 2005. |
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(2) |
Represents cash distributions attributable to the quarter and
declared and paid or to be paid within 45 days after
quarter end. We paid cash distributions to our general partner
with respect to its two percent general partner interest that
totaled $42,400 for the period from August 23, 2005 through
September 30, 2005. We declared cash distributions to our
general partner with respect to its two percent general partner
interest that totaled $142,400 for the period from
August 23, 2005 through December 31, 2005. |
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(3) |
The distribution for the third quarter of 2005 represents a
proration of the minimum quarterly distribution per common and
subordinated unit for the period from August 23, 2005, the
date of the closing of our initial public offering of common
units, through September 30, 2005. |
Distributions of Available Cash
Within 45 days after the end of each quarter (beginning
with the quarter ending September 30, 2005) we will
distribute all of our available cash, as defined in our
partnership agreement, to unitholders of record on the
applicable record date. Available cash generally means, for each
fiscal quarter all cash on hand at the end of the quarter:
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less the amount of cash reserves established by our general
partner to: |
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provide for the proper conduct of our business (including
reserves for future capital expenditures and for our anticipated
credit needs); |
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comply with applicable law, any of our debt instruments or other
agreements; or |
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provide funds for distribution to our unitholders and to our
general partner for any one or more of the next four quarters; |
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plus all cash on hand on the date of determination of available
cash for the quarter resulting from working capital borrowings
made after the end of the quarter for which the determination is
being made. Working capital borrowings are generally borrowings
that will be made under our working capital facility with
Williams and in all cases are used solely for working capital
purposes or to pay distributions to partners. |
38
Upon the closing of our IPO, affiliates of Williams received an
aggregate of 7,000,000 subordinated units. During the
subordination period, the common units will have the right to
receive distributions of available cash from operating surplus
in an amount equal to the minimum quarterly distribution of
$0.35 per quarter, plus any arrearages in the payment of
the minimum quarterly distribution on the common units from
prior quarters, before any distributions of available cash from
operating surplus may be made on the subordinated units. The
purpose of the subordinated units is to increase the likelihood
that during the subordination period there will be available
cash to be distributed on the common units.
The subordination period will extend until the first day of any
quarter beginning after June 30, 2008 that each of the
following tests are met: (i) distributions of available
cash from operating surplus on each of the outstanding common
units and subordinated units equaled or exceeded the minimum
quarterly distribution for each of the three consecutive,
non-overlapping four-quarter periods immediately preceding that
date; (ii) the adjusted operating surplus (as
defined in its partnership agreement) generated during each of
the three consecutive, non-overlapping four-quarter periods
immediately preceding that date equaled or exceeded the sum of
the minimum quarterly distributions on all of the outstanding
common units and subordinated units during those periods on a
fully diluted basis and the related distribution on the general
partner interest during those periods; and (iii) there are
no arrearages in payment of the minimum quarterly distribution
on the common units.
In addition, the subordination period may terminate before
June 30, 2008 if the following tests are met:
(i) distributions of available cash from operating surplus
on each of the outstanding common units and subordinated units
equaled or exceeded $2.10 (150 percent of the annualized
minimum quarterly distribution) for the immediately preceding
four-quarter period; (ii) the adjusted operating surplus
generated during such four-quarter period equaled or exceeded
$2.10 (150 percent of the annualized minimum quarterly
distribution) on all of the outstanding common units and
subordinated units during such four-quarter period on a fully
diluted basis and the related distribution on the general
partner interest during such four-quarter period; and
(iii) there are no arrearages in payment of the minimum
quarterly distribution on the common units.
If the unitholders remove the general partner without cause, the
subordination period may also end before June 30, 2008.
We will make distributions of available cash from operating
surplus for any quarter during any subordination period in the
following manner: (i) first, 98 percent to the common
unitholders, pro rata, and two percent to the general partner,
until we distribute for each outstanding common unit an amount
equal to the minimum quarterly distribution for that quarter;
(ii) second, 98 percent to the common unitholders, pro
rata, and two percent to the general partner, until we
distribute for each outstanding common unit an amount equal to
any arrearages in payment of the minimum quarterly distribution
on the common units for any prior quarters during the
subordination period; (iii) third, 98 percent to the
subordinated unitholders, pro rata, and two percent to the
general partner, until we distribute for each subordinated unit
an amount equal to the minimum quarterly distribution for that
quarter; and (iv) thereafter, cash in excess of the minimum
quarterly distributions is distributed to the unitholders and
the general partner based on the percentages below.
Our general partner is entitled to incentive distributions if
the amount we distribute with respect to any quarter exceeds
specified target levels shown below:
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Marginal Percentage Interest in | |
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Distributions | |
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Total Quarterly Distribution Target | |
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| |
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|
Amount | |
|
Unitholders | |
|
General Partner | |
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| |
|
| |
|
| |
Minimum Quarterly Distribution
|
|
|
$0.35 |
|
|
|
98 |
% |
|
|
2 |
% |
First Target Distribution
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|
up to $0.4025 |
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|
98 |
% |
|
|
2 |
% |
Second Target Distribution
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above $0.4025 up to $0.4375 |
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|
85 |
% |
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|
15 |
% |
Third Target distribution
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|
above $0.4375 up to $0.5250 |
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75 |
% |
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25 |
% |
Thereafter
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|
Above $0.5250 |
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|
|
50 |
% |
|
|
50 |
% |
39
|
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Item 6. |
Selected Financial and Operational Data |
The following table shows selected financial and operating data
of Williams Partners L.P. and of Discovery Producer Services LLC
for the periods and as of the dates indicated. We derived the
financial data as of December 31, 2005 and 2004 and for the
years ended December 31, 2005, 2004 and 2003 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.
The table should also be read together with
Managements Discussion and Analysis of Financial
Condition and Results of Operations for information
concerning significant trends in the financial condition and
results of operations.
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Year Ended December 31, | |
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| |
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2005 | |
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2004 | |
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2003 | |
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2002 | |
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2001 | |
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| |
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(Dollars in thousands, except per unit amounts) | |
Statement of Income Data:
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|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
51,769 |
|
|
$ |
40,976 |
|
|
$ |
28,294 |
|
|
$ |
25,725 |
|
|
$ |
29,164 |
|
Costs and expenses
|
|
|
46,568 |
|
|
|
32,935 |
|
|
|
21,250 |
|
|
|
16,542 |
|
|
|
23,692 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
5,201 |
|
|
|
8,041 |
|
|
|
7,044 |
|
|
|
9,183 |
|
|
|
5,472 |
|
Equity earnings (loss) Discovery
|
|
|
8,331 |
|
|
|
4,495 |
|
|
|
3,447 |
|
|
|
2,026 |
|
|
|
(13,401 |
) |
Impairment of investment in Discovery
|
|
|
|
|
|
|
(13,484 |
)(a) |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(8,238 |
) |
|
|
(12,476 |
) |
|
|
(4,176 |
) |
|
|
(3,414 |
) |
|
|
(4,173 |
) |
Interest income
|
|
|
165 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principle
|
|
$ |
5,459 |
|
|
$ |
(13,424 |
) |
|
$ |
6,315 |
|
|
$ |
7,795 |
|
|
$ |
(12,102 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)(b)
|
|
$ |
4,831 |
|
|
$ |
(13,424 |
) |
|
$ |
5,216 |
|
|
$ |
7,795 |
|
|
$ |
(12,102 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principle per limited partner unit:(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unit
|
|
$ |
0.49 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
Subordinated unit
|
|
$ |
0.49 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Net income (loss) per limited partner unit:(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unit
|
|
$ |
0.44 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
Subordinated unit
|
|
$ |
0.44 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
240,941 |
|
|
$ |
219,361 |
|
|
$ |
230,150 |
(c) |
|
$ |
125,069 |
|
|
$ |
122,239 |
|
Property, plant and equipment, net
|
|
|
67,931 |
|
|
|
67,793 |
|
|
|
69,695 |
|
|
|
72,062 |
|
|
|
75,269 |
|
Investment in Discovery
|
|
|
150,260 |
|
|
|
147,281 |
(a) |
|
|
156,269 |
(c) |
|
|
49,323 |
|
|
|
44,499 |
|
Advances from affiliate
|
|
|
|
|
|
|
186,024 |
|
|
|
187,193 |
(c) |
|
|
90,996 |
|
|
|
95,535 |
|
Partners capital
|
|
|
221,655 |
|
|
|
16,668 |
|
|
|
30,092 |
|
|
|
22,914 |
|
|
|
15,236 |
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions declared per unit
|
|
$ |
0.1484 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Cash distributions paid per unit
|
|
$ |
0.1484 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
2002 | |
|
2001 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Dollars in thousands, except per unit amounts) | |
Operating Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conway storage revenues
|
|
$ |
20,290 |
|
|
$ |
15,318 |
|
|
$ |
11,649 |
|
|
$ |
10,854 |
|
|
$ |
11,134 |
|
|
Conway fractionation volumes (bpd) our 50%
|
|
|
39,965 |
|
|
|
39,062 |
|
|
|
34,989 |
|
|
|
38,234 |
|
|
|
40,713 |
|
|
Carbonate Trend gathered volumes (MMBtu/d)
|
|
|
35,605 |
|
|
|
49,981 |
|
|
|
67,638 |
|
|
|
57,060 |
|
|
|
55,746 |
|
Discovery Producer Services 100%:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathered volumes (MMBtu/d)
|
|
|
345,098 |
|
|
|
348,142 |
|
|
|
378,745 |
|
|
|
425,388 |
|
|
|
226,820 |
|
|
Gross processing margin (¢/ MMbtu)
|
|
|
19¢ |
|
|
|
17¢ |
|
|
|
17¢ |
|
|
|
12¢ |
|
|
|
N/A |
|
|
|
|
(a) |
|
The $13.5 million impairment of our equity investment in
Discovery in 2004 reduced the investment balance. See
Note 6 of the Notes to Consolidated Financial Statements. |
|
(b) |
|
Our operations are treated as a partnership with each member
being separately taxed on its ratable share of our taxable
income. Therefore, we have excluded income tax expense from this
financial information. |
|
(c) |
|
In December 2003, we made a $101.6 million capital
contribution to Discovery, which Discovery subsequently used to
repay maturing debt. We funded this contribution with an advance
from Williams. Prior to the closing of our initial public
offering, Williams forgave the entire advances from affiliates
balance. |
|
(d) |
|
The period of August 23, 2005 through December 31,
2005. |
|
|
Item 7. |
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS |
|
|
|
Please read the following discussion of our financial
condition and results of operations in conjunction with the
consolidated financial statements and related notes included in
Item 8 of this annual report. |
General
We are a Delaware limited partnership formed in February 2005 by
Williams to own, operate and acquire a diversified portfolio of
complementary energy assets. On August 23, 2005, we
completed our IPO of 5,000,000 common units at a price of
$21.50 per unit. We used proceeds from the sale of the
units totaling $100.2 million were used to:
|
|
|
|
|
distribute $58.8 million to affiliates of Williams in part
to reimburse Williams for capital expenditures relating to the
assets contributed to us, including a gas purchase contract
contributed to us; |
|
|
|
provide $24.4 million to make a capital contribution to
Discovery to fund an escrow account required in connection with
the Tahiti pipeline lateral expansion project; |
|
|
|
provide $12.7 million of additional working
capital; and |
|
|
|
pay $4.3 million of expenses associated with our IPO and
related formation transactions. |
Additionally, at the closing of our IPO, the underwriters fully
exercised their option to purchase 750,000 common units at
the IPO price of $21.50 per unit from certain affiliates of
Williams.
Prior to the closing of our IPO, our assets were held by wholly
owned subsidiaries of Williams. Upon the closing of our IPO,
these Williams subsidiaries transferred the assets and the
related liabilities to us. The following discussion includes the
historical period prior to the closing of our IPO.
41
Overview
We are principally engaged in the business of gathering,
transporting and processing natural gas and fractionating and
storing NGLs. We manage our business and analyze our results of
operations on a segment basis. Our operations are divided into
two business segments:
|
|
|
|
|
Gathering and Processing. Our Gathering and Processing
segment includes (1) our 40 percent ownership interest
in Discovery and (2) the Carbonate Trend gathering pipeline
off the coast of Alabama. Discovery owns an integrated natural
gas gathering and transportation pipeline system extending from
offshore in the Gulf of Mexico to a natural gas processing
facility and an NGL fractionator in Louisiana. These assets
generate revenues by providing natural gas gathering,
transporting and processing services and integrated NGL
fractionating services to customers under a range of contractual
arrangements. Although Discovery includes fractionation
operations, which would normally fall within the NGL Services
segment, it is primarily engaged in gathering and processing and
is managed as such. |
|
|
|
NGL Services. Our NGL Services segment includes three
integrated NGL storage facilities and a 50 percent
undivided interest in a fractionator near Conway, Kansas. These
assets generate revenues by providing stand-alone NGL
fractionation and storage services using various fee-based
contractual arrangements where we receive a fee or fees based on
actual or contracted volumetric measures. |
Executive Summary
Overall our 2005 results of operations met our expectations for
these assets, although we faced unusual operating conditions the
last few months of 2005. Discovery and Carbonate Trend were
impacted by Hurricanes Dennis, Katrina and Rita, and Conway saw
an impact from a delay in the peak usage of retail propane due
to an unusually moderate winter. The hurricanes created an
unfavorable impact for our traditional natural gas supplies but
also provided an opportunity for Discovery to assist other
producers and processors with stranded gas by offering available
firm transportation capacity to them through two open seasons
discussed below in Recent Events. Discovery replaced some of its
lost revenue while helping to bring the supply of natural gas
back to the nation in advance of winter. We continue to monitor
the longer-term effects these hurricanes had on Discoverys
traditional sources of natural gas, which might cause lower than
expected gathered volumes from these sources in 2006. Conway
experienced an increased demand for propane storage services as
a result of warm early-winter temperatures. Our results were
negatively impacted by unfavorable commodity price movements on
operating supply inventory we held at Conway and by higher
general and administrative costs. Our liquidity continues to
meet our expectations. We have had no borrowings under our
revolving credit facilities and have successfully met our
minimum quarterly distributions. Our capitalization and
relationship with Williams has us well-positioned to grow our
partnership through both internal projects, including
Discoverys Tahiti expansion and acquisition transactions
with Williams and other third parties.
Recent Events
In July 2005, Discovery executed an agreement with three
producers to construct an approximate
35-mile gathering
pipeline lateral to connect Discoverys existing pipeline
system to these producers production facilities for the
Tahiti prospect in the deepwater region of the Gulf of Mexico.
The Tahiti pipeline lateral expansion will have a design
capacity of approximately 200 million cubic feet per day,
and its anticipated completion date is May 1, 2007. We
expect the total construction cost of the Tahiti pipeline
lateral expansion project to be approximately
$69.5 million, of which our 40 percent share will be
approximately $27.8 million. In September 2005, we made a
$24.4 million contribution to Discovery to cover a
substantial portion of the total expenditures attributable to
our share of these costs. We funded this contribution with
proceeds from our IPO. The omnibus agreement, executed in
connection with our IPO, provides that Williams will reimburse
us for our remaining share of $3.4 million once the escrow
funds have been exhausted.
On July 8, 2005, the Discovery and Carbonate Trend assets
were temporarily shut down in anticipation of Hurricane Dennis.
The Discovery and Carbonate Trend assets were off-line for four
and five days,
42
respectively. We estimate the unfavorable impact of this
hurricane on our 2005 net income was approximately $150,000
in lost revenue.
On August 29, 2005, Hurricane Katrina struck the Gulf Coast
area. In anticipation of the hurricane, the Discovery and
Carbonate Trend assets were temporarily shut down on
August 27, 2005. The Discovery assets were off-line for six
days and then continued to experience lower throughput rates
until being temporarily shut down for Hurricane Rita. The
Carbonate Trend assets were off-line for 10 days and then
experienced a gradual return to pre-hurricane throughput rates
by September 19, 2005. On September 24, 2005,
Hurricane Rita struck the Gulf Coast area. In anticipation of
the hurricane, the Discovery assets, which were already at
reduced throughput from Hurricane Katrina, were temporarily shut
down on September 21, 2005. The Discovery assets were
off-line for seven days and then continued to experience lower
throughput rates through the end of the third quarter.
Discoverys net income was unfavorably impacted by an
approximate loss of $2.3 million in revenue and
$1.0 million in uninsured expenses. Discoverys
property insurance policy includes a $1.0 million
deductible per occurrence. We estimate the unfavorable impact of
Hurricanes Katrina and Rita on our 2005 net income was
approximately $1.5 million due primarily to the impact of
these hurricanes on Discoverys results.
In October 2005, Discovery conducted two expedited Federal
Energy Regulatory Commission (FERC) open seasons for
firm transportation to provide outlets for natural gas that was
stranded following damage to third-party facilities during
hurricanes Katrina and Rita. Both of these open seasons were for
up to 250,000 MMBtu/d. The first of these included the
construction of a new receipt point at Texas Eastern
Transmission Companys (TETCO) Larose
compressor station in Lafourche Parish, Louisiana. The second is
via an existing interconnection to Tennessee Gas Pipelines
(TGP) Line 500 in Terrebonne Parish, Louisiana.
We began receiving additional incremental volumes from these
receipt points in November and December 2005 and anticipate
continued throughput through the first quarter of 2006. Shippers
reimbursed Discovery for the majority of the capital necessary
to establish these connections. We estimate the favorable impact
of these open seasons on our 2005 net income was
approximately $4.6 million in increased revenue less
related expenses.
For January 2006, the average gathering volumes for Discovery
were approximately 694,000 million British Thermal Units
per day (MMBtu/d). This volume includes
approximately 412,000 MMBtu/d from multiple customers whose
gas is normally processed at another plant that was severely
damaged by Hurricane Katrina and 282,000 MMBtu/d from
Discoverys traditional sources.
Potential Acquisition Candidate Identified
On November 1, 2005, we announced that we and Williams had
identified an approximate 25 percent interest in
Williams existing gathering and processing assets in the
Four Corners area as our initial candidate to be considered for
acquisition. The terms of this proposed transaction, including
price, will be subject to approval by the boards of directors of
our general partner and of Williams.
How We Evaluate Our Operations
Our management uses a variety of financial and operational
measures to analyze our segment performance, including the
performance of Discovery. These measurements include:
|
|
|
|
|
pipeline throughput volumes; |
|
|
|
gross processing margins; |
|
|
|
fractionation volumes; |
|
|
|
storage revenues; and |
|
|
|
operating and maintenance expenses. |
Pipeline Throughput Volumes. We view throughput volumes
on Discoverys pipeline system and our Carbonate Trend
pipeline as an important component of maximizing our
profitability. We gather and transport
43
natural gas under fee-based contracts. Revenue from these
contracts is derived by applying the rates stipulated to the
volumes transported. Pipeline throughput volumes from existing
wells connected to our pipelines will naturally decline over
time. Accordingly, to maintain or increase throughput levels on
these pipelines and the utilization rate of Discoverys
natural gas processing plant and fractionator, we and Discovery
must continually obtain new supplies of natural gas. Our ability
to maintain existing supplies of natural gas and obtain new
supplies are impacted by (1) the level of workovers or
recompletions of existing connected wells and successful
drilling activity in areas currently dedicated to our pipelines
and (2) our ability to compete for volumes from successful
new wells in other areas. We routinely monitor producer activity
in the areas served by Discovery and Carbonate Trend and pursue
opportunities to connect new wells to these pipelines.
Gross Processing Margins. We view total gross processing
margins as an important measure of Discoverys ability to
maximize the profitability of its processing operations. Gross
processing margins include revenue derived from:
|
|
|
|
|
the rates stipulated under fee-based contracts multiplied by the
actual MMBtu volumes; |
|
|
|
sales of NGL volumes received under
percent-of-liquids
contracts for Discoverys account; and |
|
|
|
sales of natural gas volumes that are in excess of operational
needs. |
The associated costs, primarily shrink replacement gas and fuel
gas, are deducted from these revenues to determine processing
gross margin. Shrink replacement gas refers to natural gas that
is required to replace the Btu content lost when NGLs are
extracted from the natural gas stream. In certain prior years,
such as 2003, we generated significant revenues from the sale of
excess natural gas volumes. However, in response to a final rule
issued by FERC in 2004, we expect that Discovery will generate
only minimal revenues from the sale of excess natural gas in the
future.
Discoverys mix of processing contract types and its
operation and contract optimization activities are determinants
in processing revenues and gross margins. Please read
Our Operations Gathering and
Processing Segment.
Fractionation Volumes. We view the volumes that we
fractionate at the Conway fractionator as an important measure
of our ability to maximize the profitability of this facility.
We provide fractionation services at Conway under fee-based
contracts. Revenue from these contracts is derived by applying
the rates stipulated to the volumes fractionated.
Storage Revenues. Our storage revenues are derived by
applying the average demand charge per barrel to the total
volume of storage capacity under contract. Given the nature of
our operations, our storage facilities have a relatively higher
degree of fixed verses variable costs. Consequently, we view
total storage revenues, rather than contracted capacity or
average pricing per barrel, as the appropriate measure of our
ability to maximize the profitability of our storage assets and
contracts. Total storage revenues include the monthly
recognition of fees received for the storage contract year and
shorter-term storage transactions.
Operating and Maintenance Expenses. Operating and
maintenance expenses are costs associated with the operations of
a specific asset. Direct labor, fuel, utilities, contract
services, materials, supplies, insurance and ad valorem taxes
comprise the most significant portion of operating and
maintenance expenses. Other than fuel, these expenses generally
remain relatively stable across broad ranges of throughput
volumes but can fluctuate depending on the activities performed
during a specific period. For example, plant overhauls and
turnarounds result in increased expenses in the periods during
which they are performed. We include fuel cost in our operating
and maintenance expense, although it is generally recoverable
from our customers in our NGL Services segment. As noted above,
fuel costs in our Gathering and Processing segment are a
component in assessing our gross processing margins.
In addition to the foregoing measures, we also review our
general and administrative expenditures, substantially all of
which are incurred through Williams. In an omnibus agreement,
executed in connection with our IPO, Williams agreed to provide
a five-year partial credit for general and administrative
expenses incurred on our behalf. The amount of this credit in
2005 was $3.9 million, which was pro rated for the period
44
from the closing of our IPO through year end. The pro rated
amount totaled $1.4 million. The amount of the credit will
be $3.2 million in 2006 and will decrease by approximately
$800,000 in each subsequent year.
We record total general and administrative costs, including
those costs that are subject to the credit by Williams, as an
expense, and we record the credit as a capital contribution by
our general partner. Accordingly, our net income does not
reflect the benefit of the credit received from Williams.
However, the cost subject to this credit is allocated entirely
to our general partner. As a result, the net income allocated to
limited partners on a per-unit basis reflects the benefit of
this credit.
Our Operations
|
|
|
Gathering and Processing Segment |
Our Gathering and Processing segment consists of our interest in
Discovery and our Carbonate Trend Pipeline. These assets
generate revenues by providing natural gas gathering,
transporting and processing services and NGL fractionating
services to customers under a range of contractual arrangements.
Although Discovery includes fractionation operations, which
would normally fall within the NGL Services segment, it is
primarily engaged in gathering and processing and is managed as
such. As a result, this equity investment, which can only be
presented in one segment, is considered part of the Gathering
and Processing segment. For additional information on these
activities, and the assets and activities described below,
please read Business and Properties Gathering
and Processing The Discovery Assets.
|
|
|
Gathering and Transportation Contracts |
We generate gathering and transportation revenues by applying
the set tariff or contracted rate to the contractually-defined
volumes of gas gathered or transported. Discoverys
mainline and its FERC-regulated laterals generate revenues
through two types of arrangements firm
transportation service and traditional interruptible
transportation service. Under the firm transportation
arrangement, producers are required to dedicate reserves for the
life of the lease, but pay no reservation fees for firm
capacity. Under the interruptible transportation arrangement, no
reserve dedication is required. Customers with firm
transportation arrangements are entitled to a higher priority of
service, in the case of a full pipeline, than customers who
contract for interruptible transportation service. Firm
transportation services represent the majority of the revenues
from Discoverys FERC-regulated business. Discovery also
offers a third type of arrangement, traditional firm service
with reservation fees, but none of Discoverys customers
currently contract for this type of transportation service.
Discoverys maximum regulated rate for mainline
transportation is scheduled to decrease in 2008. At that time,
Discovery will be required to reduce its mainline transportation
rate on all of its contracts that have rates above the new
reduced rate. This could reduce the revenues generated by
Discovery. Discovery may elect to file a rate case with FERC
seeking to alter this scheduled reduction. However, if filed, we
cannot assure you that a rate case would be successful in even
partially preventing the rate reduction. Please read Risk
Factors Risks Inherent in Our Business
Discoverys interstate tariff rates are subject to review
and possible adjustment by federal regulators, which could have
a material adverse effect on our business and operating results.
Moreover, because Discovery is a non-corporate entity, it may be
disadvantaged in calculating its cost of service for rate-making
purposes and Business and Properties
FERC Regulation.
Carbonate Trends three contracts have terms tied to the
life of the customers lease. The actual terms of these
contracts will vary depending on the productive life of the
natural gas reserves underlying these leases. However, the
per-unit gathering fee associated with two of our three
Carbonate Trend gathering contracts was negotiated on a bundled
basis that includes transportation along a segment of
Transcontinental Gas Pipe Line Company, or Transco, a wholly
owned subsidiary of Williams. The gathering fees we receive are
dependent upon whether our customer elects to utilize this
Transco capacity. If a customer elects to use the Transco
capacity, our gathering fee is determined by subtracting the
Transco tariff from the total negotiated fee and generally
results in a rate lower than would be realized if the customer
elects not to utilize Transcos capacity. The rate
associated with Transco capacity is based on a FERC tariff that
is subject to change. Accordingly, if the Transco rate
increases, our gathering fees will be reduced. The customers
with these bundled contracts
45
must make an annual election to receive this capacity. Both
customers elected to use this capacity during 2004 and only one
elected to use this capacity in 2005 and 2006.
The gathering and transportation revenues that we generate under
fee-based contracts are not directly affected by changing
commodity prices. However, to the extent a sustained decline in
commodity prices realized by our customers results in a decline
in the producers future drilling and development
activities, our revenues from these contracts could be reduced
in the long term.
|
|
|
Processing and Fractionation Contracts |
Fee-based contracts. Discovery generates fee-based
fractionation revenues based on the volumes of mixed NGLs
fractionated and the per-unit fee charged, which is subject to
adjustment for changes in certain fractionation expenses,
including natural gas fuel and labor costs. Some of
Discoverys natural gas processing contracts are also
fee-based contracts under which revenues are generated based on
the volumes of natural gas processed at its natural gas
processing plant. As discussed below, Discovery also processes
natural gas under
percent-of-liquids
contracts.
The processing revenues that Discovery generates under fee-based
contracts are not directly affected by changing commodity
prices. However, to the extent a sustained decline in commodity
prices realized by our customers results in a decline in the
producers future drilling and development activities, our
revenues from these contracts could be reduced due to long-term
development declines.
Percent-of-liquids
contracts. Under
percent-of-liquids
contracts, Discovery (1) processes natural gas for
customers, (2) delivers to customers an agreed-upon
percentage of the NGLs extracted in processing and
(3) retains a portion of the extracted NGLs. Discovery
generates revenue by selling these retained NGLs to other
parties at market prices. Some of Discoverys
percent-of-liquids
contracts have a bypass option. Under this option,
customers may elect not to process, or bypass, their natural gas
on a monthly basis, in which case, Discovery retains a portion
of the customers natural gas in lieu of NGLs as a fee.
Discovery uses its retained natural gas to partially offset the
amount of natural gas Discovery must purchase in the market for
shrink replacement gas and natural gas consumed as fuel.
Discovery may choose to process natural gas that a customer has
elected to bypass, but it then must deliver natural gas with an
equivalent Btu content to the customer. Discovery would not
elect to process bypassed gas if market conditions posed the
risk of negative processing margins. Please read
Operation and Contract Optimization.
Under Discoverys
percent-of-liquids
contracts, revenues either increase or decrease as a result of a
corresponding change in the market prices of NGLs. For contracts
with a bypass option, and depending upon whether the customer
elects the bypass election, Discoverys revenues would
either increase or decrease as a result of a corresponding
change in the relative market prices of NGLs and natural gas.
Discovery is also a party to a small number of
keep-whole gas processing arrangements. Under these
arrangements, a processor retains NGLs removed from a
customers natural gas stream but must deliver gas with an
equivalent Btu content to the customer, either from the
processors inventory or through open market purchases. A
rise in natural gas prices as compared to NGL prices can cause
the processor to suffer negative margins on keep-whole
arrangements. The natural gas associated with Discoverys
keep-whole arrangements has a low NGL content. As a result, this
gas does not require processing to be shipped on downstream
pipelines. Consequently, under unfavorable market conditions,
Discovery may earn little or no margin on these arrangements,
but is not exposed to negative processing margins. Discovery
does not intend to enter into additional keep-whole arrangements
in the future that would represent a material amount of
processing volumes.
Substantially all of Discoverys gas gathering,
transportation, processing and fractionation contracts have
terms that expire at the end of the customers natural
resource lease. The actual terms of these contracts will vary
depending on life of the natural gas reserves underlying these
leases. As a result of Discoverys current contract mix,
Discovery takes title to approximately one-half of the mixed NGL
volumes leaving its natural gas processing plant. A Williams
subsidiary serves as a marketer for these NGLs and, under the
terms of its agreement with Discovery, purchases substantially
all of Discoverys NGLs for resale to end users. As a
result,
46
a significant portion of Discoverys revenues are reported
as affiliate revenues even though Williams is not a producer
that supplies the Discovery pipeline system with any volumes of
natural gas. If the arrangement with the Williams subsidiary
were terminated, we believe that Discovery could contract with a
third party marketer or perform its own marketing services.
|
|
|
Operation and Contract Optimization |
Long-haul natural gas pipelines, generally interstate pipelines
that serve end use markets, publish specifications for the
maximum NGL content of the natural gas that they will transport.
Normally, NGLs must be removed from the natural gas stream at a
gas processing facility in order to meet these pipeline
specifications. It is common industry practice, however, to
blend some unprocessed gas with processed gas to the extent that
the combined gas stream is still able to meet the pipeline
specifications at the point of injection into the long-haul
pipeline.
Although it is typically profitable for producers to separate
NGLs from their natural gas streams, there can be periods of
time in which the relative value of NGL market prices to natural
gas market prices may result in negative processing margins and,
as a result, lack of profit from NGL extraction. Because of this
margin risk, producers are often willing to pay for the right to
bypass the gas processing facility if the circumstances permit.
Owners of gas processing facilities may often allow producers to
bypass their facilities if they are paid a bypass
fee. The bypass fee helps to compensate the gas processing
facility for the loss of processing volumes.
Under Discoverys contracts that include a bypass option,
Discoverys customers may exercise their option to bypass
the gas processing plant. Producers with these contracts notify
Discovery of their decision to bypass prior to the beginning of
each month. For the natural gas volumes that producers have
chosen to bypass, Discovery evaluates current commodity prices
and then decides whether it will process the gas for its own
account and retain the separated NGLs for sale to third parties.
The customer pays a bypass fee regardless of whether or not
Discovery decides to process the gas for its own account.
Discoverys decision is determined by the value of the NGLs
it will separate during the month compared to the cost of the
replacement volume of natural gas it must purchase to keep the
producer whole.
By providing flexibility to both producers and gas processors,
bypass options can enhance both parties profitability.
Discovery manages its operations given its contract portfolio,
which contains a proportion of contracts with this option that
is appropriate given current and expected future commodity
market conditions.
We generate revenues by providing NGL fractionation and storage
services at our facilities near Conway, Kansas, using various
fee based contractual arrangements where we receive a fee or
fees based on actual or contracted volumetric measures.
The fee-based fractionation contracts at our Conway facility
generate revenues based on the volumes of mixed NGLs
fractionated and the per-unit fee charged. The per-unit fee is
generally subject to adjustment for changes in certain operating
expenses, including natural gas, electricity and labor costs,
which are the principal variable costs in NGL fractionation. As
a result, we are generally able to pass through increases in
those operating expenses to our customers. However, under one of
our fractionation contracts, there is a cap on the per-unit fee
and, under current natural gas market conditions, we are not
able to pass through the full amount of increases in variable
expenses to this customer. In order to mitigate the fuel price
risk with respect to our purchases of natural gas needed to
perform under this contract, upon the closing of our IPO
offering in August 2005, Williams transferred to us a
contract for the purchase of a sufficient quantity of natural
gas from a wholly owned subsidiary of Williams at a fixed price
to satisfy our fuel requirements under this fractionation
contract. Williams paid the full costs associated with entering
into this contract prior to assigning the contract to us upon
closing of our IPO. The fair value of this gas purchase contract
was recorded as an equity contribution to us by Williams. This
gas purchase contract will terminate on December 31, 2007
to correspond
47
with the expected termination of the related fractionation
agreement. Pursuant to the terms of this agreement we provided
notice of termination to this customer in July 2005. If we are
unable to negotiate a new agreement with this customer upon such
termination, we believe that we could contract with other
potential customers to replace a significant portion of these
volumes.
Two contracts with remaining terms of approximately three and
five years account for most of our fractionation revenues. The
revenues we generate under fractionation contracts at our Conway
facility generally are not directly affected by changing
commodity prices. However, to the extent a sustained decline in
commodity prices received by our customers results in a decline
in their production volumes, our revenues from these contracts
could be reduced. One of our customers has the contractual
right, on a
month-to-month basis,
to deliver its mixed NGLs elsewhere. Its decision on whether to
ship its products to the Mid-Continent region or another region
depends on supply and demand in the respective regions and the
current price being paid for fractionated products in each
region.
Substantially all our storage contracts are on a firm basis,
pursuant to which our customers pay a demand charge for a
contracted volume of storage capacity, including injection and
withdrawal rights. The majority of our storage revenues are from
three contracts with remaining terms between four and fourteen
years. The terms of our remaining storage contracts are
typically one year or less. In addition, we also enter into
contracts for fungible product storage in increments of six
months, three months and one month.
For storage contracts of one year or less, we require our
customers to remit the full contract price at the time the
contract is signed, which reduces our overall credit risk. Most
of our contracts of one year or less are on a fixed price basis.
We base our longer-term contracts on a percentage of our
published price of storage in our Conway facilities and adjust
these prices annually.
We offer our customers four types of storage contracts: single
product fungible, two product fungible, multi-product fungible
and segregated product storage. In addition to the fees we
charge for contracted storage, we also receive fees for
overstorage. Overstorage is all barrels held in a
customers inventory in excess of that customers
contractual storage rights, calculated on a daily basis.
Because we typically contract for periods of one year or longer,
our business is less susceptible to seasonal variations.
However, spot and future NGL market prices can influence demand
for storage. When the market for propane and other NGLs is in
backwardation, the demand for storage capacity of our Conway
facilities may decrease. While this would not impact our
long-term leases of storage capacity, our customers could become
less likely to enter into short-term storage contracts.
|
|
|
Operating Supply Management |
We also generate revenues by managing product imbalances at our
Conway facilities. In response to market conditions, we actively
manage the fractionation process to optimize the resulting mix
of products. Generally, this process leaves us with a surplus of
propane volumes and a deficit of ethane volumes. We sell the
surplus propane and make up the ethane deficit through
open-market purchases. We refer to these transactions as product
sales and product purchases. In addition, product imbalances may
arise due to measurement variances that occur during the routine
operation of a storage cavern. These imbalances are realized
when storage caverns are emptied. We are able to sell any excess
product volumes for our own account, but must make up product
deficits. The flexibility we enjoy as operator of the storage
facility allows us to manage the economic impact of deficit
volumes by settling deficit volumes either from our storage
inventory or through opportunistic open-market purchases.
Historically, we effected these product sales and purchases with
third parties. However, in December of 2004, we began to effect
these purchases and sales with a subsidiary of Williams. If this
arrangement with the Williams subsidiary were terminated, we
believe we could once again transact with third parties.
48
Critical Accounting Policies and Estimates
Our financial statements reflect the selection and application
of accounting policies that require management to make
significant estimates and assumptions. The selection of these
policies has been discussed with the Audit Committee. We believe
that the following are the more critical judgment areas in the
application of our accounting policies that currently affect our
financial condition and results of operations.
|
|
|
Impairment of Long-Lived Assets and Investments |
We evaluate our long-lived assets and investments for impairment
when we believe events or changes in circumstances indicate that
we may not be able to recover the carrying value of certain
long-lived assets or that the decline in value of an investment
is other-than-temporary.
During 2004, we performed an impairment review of our
40 percent equity investment in Discovery because of
Williams planned purchase of an additional interest in
Discovery at an amount below our current carrying value. We
estimated the fair value of our investment based on a
probability-weighted analysis that considered a range of
expected future cash flows and earnings, EBITDA multiples and
the distribution yields for master limited partnerships
(MLP). Based upon our analysis we concluded that our
investment in Discovery experienced an other-than-temporary
decline in value. As a result, we recorded an 8 percent, or
$13.5 million, impairment of this investment to its
estimated fair value at December 31, 2004 (see Note 6
of Notes to Consolidated Financial Statements). Our computations
utilized judgments and assumptions in the following areas:
|
|
|
|
|
estimated future volumes and rates; |
|
|
|
the net present value of the expected future cash flows; |
|
|
|
potential proceeds from a sale to an existing MLP based on an
acquirers estimated distribution and earnings
impact; and |
|
|
|
expected proceeds from our planned initial public offering. |
Our projections are highly sensitive to changes in the above
assumptions. The estimated cash flows from the various scenarios
ranged from approximately $28.0 million above to
approximately $20.0 million below our estimated fair value
at December 31, 2004.
|
|
|
Accounting for Asset Retirement Obligations |
We record asset retirement obligations for legal obligations
associated with the retirement of long-lived assets that result
from the acquisition, construction, development and/or normal
use of the asset in the period in which it is incurred if a
reasonable estimate of fair value can be made. At
December 31, 2005, we have an accrued asset retirement
obligation liability of $762,000 for estimated retirement costs
associated with the abandonment of our Conway underground
storage caverns and brine ponds in accordance with
KDHE regulations. This estimate is based on the assumption
that the abandonment occurs in 50 years. If this assumption
were changed to 30 years, the recorded asset retirement
obligation would increase by approximately $2.6 million.
Our estimate utilizes judgments and assumptions regarding the
costs to abandon a well bore and the timing of abandonment.
Please read Note 7 of Notes to Consolidated Financial
Statements.
|
|
|
Environmental Remediation Liabilities |
We record liabilities for estimated environmental remediation
liabilities when we assess that a loss is probable and the
amount of the loss can be reasonably estimated. At
December 31, 2005, we have an accrual for estimated
environmental remediation obligations of $5.4 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
49
governmental authorities. As new developments occur or more
information becomes available, it is possible that our
assumptions and estimates in these matters will change. Changes
in our assumptions and estimates or outcomes different from our
current assumptions and estimates could materially affect future
results of operations for any particular quarter or annual
period. During 2004, we purchased an insurance policy covering
some of our environmental liabilities. Please read
Environmental and Note 13 of Notes
to Consolidated Financial Statements for further information.
Results of Operations
The following table and discussion is a summary of our
consolidated results of operations for the three years ended
December 31, 2005. The results of operations by segment are
discussed in further detail following this consolidated overview
discussion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% Change | |
|
|
|
% Change | |
|
|
|
|
|
|
from | |
|
|
|
from | |
|
|
|
|
2005 | |
|
2004(1) | |
|
2004 | |
|
2003(1) | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Dollars in thousands) | |
Revenues
|
|
$ |
51,769 |
|
|
|
+26 |
% |
|
$ |
40,976 |
|
|
|
+45 |
% |
|
$ |
28,294 |
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
25,111 |
|
|
|
-30 |
% |
|
|
19,376 |
|
|
|
-39 |
% |
|
|
13,960 |
|
|
Product cost
|
|
|
11,821 |
|
|
|
-78 |
% |
|
|
6,635 |
|
|
|
NM |
|
|
|
1,263 |
|
|
Depreciation and accretion
|
|
|
3,619 |
|
|
|
+2 |
% |
|
|
3,686 |
|
|
|
+1 |
% |
|
|
3,707 |
|
|
General and administrative expense
|
|
|
5,323 |
|
|
|
-104 |
% |
|
|
2,613 |
|
|
|
-44 |
% |
|
|
1,813 |
|
|
Taxes other than income
|
|
|
700 |
|
|
|
+2 |
% |
|
|
716 |
|
|
|
-12 |
% |
|
|
640 |
|
|
Other, net
|
|
|
(6 |
) |
|
|
-93 |
% |
|
|
(91 |
) |
|
|
-32 |
% |
|
|
(133 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
46,568 |
|
|
|
-41 |
% |
|
|
32,935 |
|
|
|
-55 |
% |
|
|
21,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
5,201 |
|
|
|
-35 |
% |
|
|
8,041 |
|
|
|
+14 |
% |
|
|
7,044 |
|
Equity earnings Discovery
|
|
|
8,331 |
|
|
|
+85 |
% |
|
|
4,495 |
|
|
|
+30 |
% |
|
|
3,447 |
|
Impairment of investment in Discovery
|
|
|
|
|
|
|
+100 |
% |
|
|
(13,484 |
) |
|
|
NM |
|
|
|
|
|
Interest expense
|
|
|
(8,238 |
) |
|
|
+34 |
% |
|
|
(12,476 |
) |
|
|
-199 |
% |
|
|
(4,176 |
) |
Interest income
|
|
|
165 |
|
|
|
+100 |
% |
|
|
|
|
|
|
- |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principle
|
|
|
5,459 |
|
|
|
+141 |
% |
|
|
(13,424 |
) |
|
|
NM |
|
|
|
6,315 |
|
Cumulative effect of change in accounting principle
|
|
|
(628 |
) |
|
|
NM |
|
|
|
|
|
|
|
+100 |
% |
|
|
(1,099 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
4,831 |
|
|
|
+136 |
% |
|
$ |
(13,424 |
) |
|
|
NM |
|
|
$ |
5,216 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
+ = Favorable Change; - = Unfavorable Change; NM = A
percentage calculation is not meaningful due to change in signs,
a zero-value denominator or a percentage change greater than 200. |
Revenues increased $10.8 million, or 26 percent, due
primarily to higher revenues in our NGL Services segment
reflecting increased product sales volumes and higher storage
revenues, slightly offset by lower revenue in our Gathering and
Processing segment due to Hurricanes Katrina and Rita and the
2004 recognition of a $950,000 settlement of a contractual
volume deficiency provision.
Operating and maintenance expense increased $5.7 million,
or 30 percent, due primarily to larger product imbalance
valuation adjustments and higher fuel and power costs recognized
by our NGL Services segment in 2005 as compared to 2004.
50
Product cost increased $5.2 million, or 78 percent,
directly related to the increase in product sales volumes in our
NGL Services segment.
General and administrative expense increased $2.7 million,
or 104 percent, due primarily to the increased costs of
being a publicly-traded partnership. These costs included
$1.1 million for audit fees, tax return preparation,
director fees, and registration and transfer agent fees,
$0.7 million for direct and specific charges allocated, by
Williams, for accounting, legal, and other support,
$0.6 million for business development, and
$0.3 million for other various expenses.
Operating income decreased $2.8 million, or
35 percent, due primarily to higher operating and
maintenance expense in our NGL Services segment, higher general
and administrative expenses and lower revenues in our Gathering
and Processing segment, partially offset by higher storage
revenues in our NGL Services segment.
Equity earnings from Discovery increased $3.8 million. This
increase is discussed in detail in the Results of
Operations Gathering and Processing section.
The impairment of our investment in Discovery is the result of
our analysis pursuant to which we concluded that we had
experienced an other than temporary decline in the value of our
investment in Discovery as described above in
Critical Accounting Policies and
Estimates Impairment of Long-Lived Assets and
Investments.
Interest expense decreased $4.2 million, or
34 percent, due primarily to the forgiveness of the
advances from Williams in conjunction with the closing of the
IPO on August 23, 2005.
The Cumulative effect of change in accounting principle of
$0.6 million in 2005 relates to our December 31, 2005
adoption of Financial Accounting Standards Board Interpretation
(FIN) No. 47. Please read Note 7 of Notes
to Consolidated Financial Statements.
Revenues increased $12.7 million, or 45 percent, due
mainly to higher revenues in our NGL Services segment,
reflecting higher product sales volumes and storage rates.
Operating and maintenance expenses increased $5.4 million,
or 39 percent, due primarily to increased costs to comply
with KDHE requirements at NGL Services Conway facilities.
Product costs increased $5.4 million, from
$1.3 million, due to the increase in product sales.
General and administrative expenses increased $0.8 million,
or 44 percent, due primarily to an increase in allocated
general and administrative expenses from Williams reflecting
increased corporate overhead costs within the Williams
organization. These increased costs related to various corporate
initiatives and Sarbanes-Oxley Act compliance efforts within
Williams.
The impairment of our investment in Discovery is the result of
our analysis pursuant to which we concluded that we had
experienced an other than temporary decline in the value of our
investment in Discovery as described in Results of
Operations Gathering and Processing section.
Interest expense increased $8.3 million, from
$4.2 million, due primarily to the cash advanced by
Williams in December 2003 to fund our $101.6 million share
of a cash call by Discovery to repay its outstanding debt.
The Cumulative effect of change in accounting principle of
$1.1 million in 2003 relates to our January 1, 2003
adoption of Statement of Financial Accounting Standards
(SFAS) No. 143, Accounting for Asset
Retirement Obligations. Please read Note 7 of Notes
to Consolidated Financial Statements.
51
Results of operations Gathering and Processing
The Gathering and Processing segment includes the Carbonate
Trend gathering pipeline and our 40 percent ownership
interest in Discovery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Segment revenues
|
|
$ |
3,515 |
|
|
$ |
4,833 |
|
|
$ |
5,513 |
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
714 |
|
|
|
572 |
|
|
|
379 |
|
|
Depreciation
|
|
|
1,200 |
|
|
|
1,200 |
|
|
|
1,200 |
|
|
General and administrative expense-direct
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
1,916 |
|
|
|
1,772 |
|
|
|
1,579 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
1,599 |
|
|
|
3,061 |
|
|
|
3,934 |
|
Equity earnings Discovery
|
|
|
8,331 |
|
|
|
4,495 |
|
|
|
3,447 |
|
Impairment of investment in Discovery
|
|
|
|
|
|
|
(13,484 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit (loss)
|
|
$ |
9,930 |
|
|
$ |
(5,928 |
) |
|
$ |
7,381 |
|
|
|
|
|
|
|
|
|
|
|
Segment revenues decreased $1.3 million, or
27 percent, due primarily to a 29 percent decline in
average daily gathered volumes between 2005 and 2004 and the
absence of $950,000 of revenue from the settlement of a
contractual volume deficiency payment recognized in 2004,
partially offset by $452,000 of revenue from the settlement of a
contractual volume deficiency payment recognized in 2005.
The decline in average daily gathered volumes was caused by
normal reservoir depletion, reduced capacity experienced at a
third-party onshore treating plant in April 2005 and the
temporary shutdowns for Hurricane Dennis in July 2005 and
Hurricane Katrina in August 2005. The overall impact of this
decline in gathered volumes on gathering revenue was
approximately $1.1 million. This decline in gathered
volumes was partially offset by a 11 percent higher average
gathering rate causing a $300,000 increase in gathering revenue.
The increase in the average gathering rate was due to a
customers annual election in 2005 under a bundled rate
provision within its contract.
Operating and maintenance expense increased $142,000, or
25 percent, due to $72,000 increased costs for inhibitor
chemicals and internal pipeline corrosion inspection, and
$70,000 related to insurance costs. These increases were offset
partially by increased painting expense in 2004.
Segment operating income decreased $1.5 million, or
48 percent, due primarily to the lower revenues discussed
above.
Segment revenues decreased $0.7 million, or
12 percent, due primarily to a 26 percent decline in
gathering volumes in 2004, largely offset by the recognition in
2004 of a $950,000 settlement of a contractual volume deficiency
provision. Gathering volumes declined in 2004 due to lower
production from connected wells that was not offset by new
production coming online.
Operating and maintenance expenses increased $0.2 million
due to additional costs for contractor services.
52
Discovery is accounted for using the equity method of
accounting. As such, our interest in Discoverys net
operating results is reflected as equity earnings in our
Consolidated Statements of Operations. Due to the significance
of Discoverys equity earnings to our results of
operations, the following discussion addresses in greater detail
the results of operations for 100 percent of Discovery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Revenues
|
|
$ |
122,745 |
|
|
$ |
99,876 |
|
|
$ |
103,178 |
|
Costs and expenses, including interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement
|
|
|
64,467 |
|
|
|
45,355 |
|
|
|
42,914 |
|
|
Operating and maintenance expense
|
|
|
10,165 |
|
|
|
17,854 |
|
|
|
15,829 |
|
|
General and administrative expense
|
|
|
2,053 |
|
|
|
1,424 |
|
|
|
1,400 |
|
|
Depreciation and accretion
|
|
|
24,794 |
|
|
|
22,795 |
|
|
|
22,875 |
|
|
Interest expense (income)
|
|
|
(1,685 |
) |
|
|
(550 |
) |
|
|
9,611 |
|
|
Other expenses, net
|
|
|
2,123 |
|
|
|
1,328 |
|
|
|
1,501 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
101,917 |
|
|
|
88,206 |
|
|
|
94,130 |
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative effect of change in accounting
principle
|
|
$ |
20,828 |
|
|
$ |
11,670 |
|
|
$ |
9,048 |
|
|
|
|
|
|
|
|
|
|
|
Williams Partners 40% interest
|
|
$ |
8,331 |
|
|
$ |
4,668 |
|
|
$ |
3,619 |
|
Capitalized interest amortization
|
|
|
|
|
|
|
(173 |
) |
|
|
(172 |
) |
|
|
|
|
|
|
|
|
|
|
Equity earnings per our Consolidated Statement of Operations
|
|
$ |
8,331 |
|
|
$ |
4,495 |
|
|
$ |
3,447 |
|
|
|
|
|
|
|
|
|
|
|
Revenues increased $22.9 million, or 23 percent, due
primarily to higher NGL product sales from marketing of
customers NGLs, fractionation revenue, processing revenue
and average per-unit NGL sales prices, partially offset by lower
NGL sales volumes. The significant components of this increase
include the following.
|
|
|
|
|
Product sales increased $31.6 million for the NGL sales
related to third-party processing customers election to
have Discovery market their NGLs for a fee under an option in
their contracts. These sales were offset by higher associated
product costs of $31.6 million discussed below. |
|
|
|
Processing and fractionation revenues increased
$6.8 million including $3.9 million in additional
volumes related to the TGP and TETCO open seasons discussed
previously, $2.9 million related to an increase in the
fractionation rate for increased natural gas fuel cost pass
through, and other increases related to new volumes from the
Front Runner prospect that came on line in the first quarter of
2005. |
|
|
|
Gathering revenues increased $2.1 million due primarily to
a $1.4 million deficiency payment received in 2005 related
to a volume shortfall under a transportation contract,
$0.4 million related to an increase in volumes and
$0.3 million related to a 25 percent higher average
gathering rate associated with new volumes from the Front Runner
prospect. |
Partially offsetting these increases were the following:
|
|
|
|
|
Product sales decreased $4.9 million as a result of lower
sales of excess fuel and shrink replacement gas in 2005. During
the first half of 2004 increased natural gas prices made it more
economical for Discoverys customers to bypass the
processing plant rather than process the gas, leaving Discovery
with higher levels of excess fuel and replacement gas in 2004
than 2005. |
53
|
|
|
|
|
Product sales also decreased approximately $16.0 million as
a result of 36 percent lower NGL sales volumes following
Hurricanes Katrina and Rita, partially offset by a
$5.0 million increase associated with a 17 percent
higher average sales prices. |
|
|
|
Transportation revenues decreased $0.6 million due
primarily to lower condensate transportation volumes. Higher
average natural gas transportation volumes were partially offset
by a lower average natural gas transmission rate. |
|
|
|
Other revenues declined $1.1 million due largely to lower
platform rental fees. |
Product cost and shrink replacement increased
$19.1 million, or 42 percent, due primarily to:
|
|
|
|
|
$31.6 million increased purchase costs for the two
processing customers who elected to have Discovery market their
NGLs; and |
|
|
|
$3.4 million resulting from higher average per-unit natural
gas prices. |
Partially offsetting these increases were the following:
|
|
|
|
|
$11.0 million lower costs related to reduced processing
activity in 2005; and |
|
|
|
$4.9 million lower cost associated with sales of excess
fuel and shrink natural gas. |
Operating and maintenance expense decreased $7.7 million,
or 43 percent, due primarily to a $10.7 million credit
related to amounts previously deferred for net system gains from
2002 through 2004 that were reversed following the acceptance in
2005 of a filing with the FERC, partially offset by
$1.2 million higher utility costs, $1.0 million of
uninsured damages caused by Hurricane Katrina, and
$0.8 million other miscellaneous operational costs.
General and administrative expense increased $0.6 million,
or 44 percent, due primarily to an increase in the
management fee paid to Williams related to Discoverys
market expansion project and additions of other facilities. For
a discussion of Discoverys recently completed market
expansion project, please read Business The
Discovery Assets Discovery Natural Gas Pipeline
System.
Depreciation and accretion expense increased $2.0 million,
or 9 percent, due primarily to the completion of a pipeline
connection to the Front Runner prospect in late 2004.
Interest income increased $1.1 million, due primarily to
increases in interest-bearing cash balances during early 2005
period when cash flows from operations were being retained by
Discovery.
Other expenses, net increased $0.8 million, or
60 percent, due primarily to a non-cash foreign currency
transaction loss from the revaluation of restricted cash
accounts denominated in Euros. These restricted cash accounts
were established from contributions made by Discoverys
members, including us, for the construction of the Tahiti
pipeline lateral expansion project.
Net income increased $9.2 million, or 78 percent, due
primarily to the $10.7 million reserve reversal,
$8.9 million increased revenue from gathering, processing
and fractionation services and $1.1 million higher interest
income, partially offset by $3.5 million lower product
sales margins, $3.0 million higher other operating and
maintenance expense, $0.6 million higher general and
administrative expense, $2.0 million higher depreciation
and accretion, and $0.8 higher other expense including the
foreign currency transaction loss.
The $3.3 million, or 3 percent, decrease in revenues
resulted primarily from lower fuel and shrink replacement gas
sales in 2004 and lower NGL sales volumes, partially offset by
higher average per-unit NGL sales prices. The significant
components of this decrease consisted of the following:
|
|
|
|
|
Increasing gas prices during some months of 2003 made it more
economical for Discoverys customers to bypass the
processing plant rather than to process the gas, leaving
Discovery with higher levels of |
54
|
|
|
|
|
excess fuel and shrink replacement gas in 2003 than 2004. This
excess natural gas was sold in the market in 2003, which
resulted in $5.1 million of lower revenues in 2004. |
|
|
|
Transportation volumes declined 6 percent due to production
declines and a temporary interruption of service because of an
accidental influx of seawater in a lateral while putting in
place a subsea connection to a wellhead. These lower volumes
resulted in a decrease in fee-based revenues, including
$2.7 million from gathering and transportation,
$2.2 million from fee-based processing and
$0.2 million from fractionation, for a total of
$5.1 million. |
|
|
|
Other revenues decreased $1.5 million due to a
$0.9 million decrease in offshore platform production
handling fees related to lower natural gas production volumes
and $0.8 million received in connection with the resolution
of a condensate measurement and ownership allocation issue in
2003. |
|
|
|
NGL sales increased $8.5 million due to a 26 percent
increase in average sales prices, which were slightly offset by
a 2 percent decrease in sales volumes. |
Product cost and shrink replacement gas costs increased by
$2.4 million, or 6 percent, primarily due to higher
average gas prices. Operating and maintenance expense increased
$2.0 million, or 12 percent, from 2003 due primarily
to $1.2 million of costs for a routine compressor overhaul
and $1.3 million of costs to correct a non-routine
temporary interruption of service due to an accidental influx of
seawater in our offshore pipeline. These increases were
partially offset by lower miscellaneous operating expenses.
Interest expense decreased $9.6 million due to the
repayment of $253.7 million of outstanding debt in December
2003. Other expense, net decreased $0.7 million due
primarily to $0.6 million of income earned on the short
term investing of excess cash.
Net Income increased $2.6 million, or 29 percent, due
primarily to $9.6 million lower interest expense,
$0.7 million lower other expense, partially offset by
$3.3 million lower revenue, $2.4 million higher
product cost and shrink expense and $2.0 million higher
operating and maintenance expense.
We currently estimate that we will incur $3.4 million to
$4.6 million of maintenance expenditures for Carbonate
Trend during 2006 for restoration activities related to the
partial erosion of the pipeline overburden caused by Hurricane
Ivan in September 2004. Under our omnibus agreement, Williams
agreed to reimburse us for the cost of these restoration
activities. In connection with these restoration activities, the
Carbonate Trend pipeline may experience a temporary shut down.
We estimate that this shut down could reduce our cash flows from
operations, excluding the maintenance expenditures, by
approximately $0.2 million to $0.3 million.
Throughput volumes on Discoverys pipeline system and our
Carbonate Trend pipeline are an important component of
maximizing our profitability. Pipeline throughput volumes from
existing wells connected to our pipelines will naturally decline
over time. Accordingly, to maintain or increase throughput
levels on these pipelines and the utilization rate of
Discoverys natural gas plant and fractionator, we and
Discovery must continually obtain new supplies of natural gas.
|
|
|
|
|
In 2006, recompletions and workovers may not offset production
declines from the wells currently connected to the Carbonate
Trend pipeline. |
|
|
|
We anticipate continued throughput from the TGP and TETCO open
season volumes through the first quarter of 2006. Discovery is
discussing retaining some of this gas on a long-term basis and
will compete with several other plants in the area for this
business. |
|
|
|
We anticipate lower gathered volumes from Discoverys
pre-hurricane sources throughout 2006. The 2005 hurricanes
caused a significant disruption in our customers normal
operations including critical recompletion and drilling activity
necessary to sustain and improve their production levels. |
|
|
|
With the current oil and natural gas price environment, drilling
activity across the shelf and the deepwater of the Gulf of
Mexico has been robust. However, the availability of specialized
rigs necessary to drill in the deepwater areas, such as those in
and around Discoverys gathering areas, |
55
|
|
|
|
|
limits producers ability to bring identified reserves to
market quickly. This will prolong the timeframe over which these
reserves will be developed. We expect Discovery to be successful
in competing for a portion of these new volumes. |
|
|
|
Late in the first quarter of 2006, Discovery expects to connect
a new well in ATPs Gomez prospect, with an estimated
initial volume of 35,000 MMBtu/d. Capital to connect this
new well will be provided by others. This initial flow date was
delayed due to the hurricane repair activities. |
Results of operations NGL Services
The NGL Services segment includes our three NGL storage
facilities near Conway, Kansas and our undivided 50 percent
interest in the Conway fractionator.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Segment revenues
|
|
$ |
48,254 |
|
|
$ |
36,143 |
|
|
$ |
22,781 |
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
24,397 |
|
|
|
18,804 |
|
|
|
13,581 |
|
|
Product cost
|
|
|
11,821 |
|
|
|
6,635 |
|
|
|
1,263 |
|
|
Depreciation and accretion
|
|
|
2,419 |
|
|
|
2,486 |
|
|
|
2,507 |
|
|
General and administrative expense direct
|
|
|
1,068 |
|
|
|
535 |
|
|
|
421 |
|
|
Other, net
|
|
|
694 |
|
|
|
625 |
|
|
|
507 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
40,399 |
|
|
|
29,085 |
|
|
|
18,279 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$ |
7,855 |
|
|
$ |
7,058 |
|
|
$ |
4,502 |
|
|
|
|
|
|
|
|
|
|
|
Segment revenues increased $12.1 million, or
34 percent, due primarily to higher product sales, storage
and fractionation revenues. The significant components of the
increase include the following:
|
|
|
|
|
Product sales were $5.0 million higher due primarily to the
sale of surplus propane volumes created through our product
optimization activities. This increase was partially offset by
the related increase in Product cost. |
|
|
|
Storage revenues increased $5.0 million due primarily to
higher average per-unit storage rates for 2005 and higher
storage volumes from additional short-term storage leases caused
by the reduced demand for propane due to unusually warm
temperatures in the early winter months of 2005 and an overall
increase in butane and storage volumes. The published rate for
one-year storage contracts increased 67 percent on
April 1, 2004, primarily reflecting the pass through to
customers of increased costs to comply with KDHE regulations.
The storage volumes in the remaining quarters of 2004 initially
declined due to these higher storage rates. During 2005, the
volumes returned to more normal levels. |
|
|
|
Fractionation revenues increased $1.7 million due primarily
to a 17 percent increase in the average fractionation rate
related to the pass through to customers of increased fuel and
power costs and 4 percent higher volumes in 2005. |
|
|
|
Other revenues increased $0.4 million due to increased
railcar loadings in 2005. |
56
The following table summarizes the major components of operating
and maintenance expense that are discussed in detail below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Operating and maintenance expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Salaries and benefits
|
|
$ |
2,773 |
|
|
$ |
2,740 |
|
|
$ |
2,762 |
|
|
Outside services and other
|
|
|
7,458 |
|
|
|
8,240 |
|
|
|
3,843 |
|
|
Fuel and power
|
|
|
12,538 |
|
|
|
8,565 |
|
|
|
7,608 |
|
|
Product imbalance expense (income)
|
|
|
1,628 |
|
|
|
(741 |
) |
|
|
(632 |
) |
|
|
|
|
|
|
|
|
|
|
Total operating and maintenance expense
|
|
$ |
24,397 |
|
|
$ |
18,804 |
|
|
$ |
13,581 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outside services and other decreased $0.8 million due to
fewer storage cavern workovers in 2005 as compared to 2004. Also
our estimated asset retirement obligation for the storage
caverns was adjusted in 2005, reducing our operating expense by
$0.5 million. |
|
|
|
Fuel and power costs increased $4.0 million due primarily
to a 33 percent increase in the average per-unit price for
natural gas, which we are generally able to pass through to our
customers. Fuel and Power cost also includes $2.0 million
for the amortization of a natural gas purchase contract
contributed to us by Williams at the closing of our IPO. Please
read, Our Operations NGL Services
Segment Fractionation Contracts. |
|
|
|
Product imbalance expense increased $2.4 million due
primarily to $3.0 million larger product imbalance
valuation adjustments and $0.6 million other product
losses, partially offset by a $1.2 million increase in
product optimization gains due to a significantly higher spread
between propane and ethane prices in 2005. |
Product cost increased $5.2 million, or 78 percent,
directly related to increased sales of surplus propane volumes
created through our product optimization activities.
General and administrative expense direct increased
$0.5 million, or 100 percent, due primarily to
increased operational and technical support for these assets.
Segment profit increased $0.8 million, or 11 percent,
due primarily to the $6.7 million higher storage and
fractionation revenues and $0.4 million higher other
revenues for increased railcar loadings in 2005, partially
offset by $5.6 million higher operating and maintenance
expense, $0.5 million higher general and administrative
expense direct charges and $0.2 million
decrease in product margin.
Revenues increased $13.4 million, or 59 percent, due
primarily to increased product sales and storage revenues. The
significant components of the increase consisted of the
following:
|
|
|
|
|
Product sales were $6.9 million higher primarily due to the
sale of surplus propane volumes created through our product
optimization activities. Prior to 2003, the sale and purchase
activities and related inventory associated with product
optimization were conducted by another wholly owned subsidiary
of Williams that was sold in 2002. We made no sales of surplus
propane until 2004 as we transitioned to conducting these
activities and accumulated inventory. |
|
|
|
Storage revenues increased $3.7 million due to higher
average per-unit storage rates, slightly offset by lower
contracted storage volumes. The published rate for one-year
storage contracts increased 67 percent on April 1,
2004 and primarily reflects the pass through of increased costs
to comply with KDHE regulations. |
|
|
|
During 2004 we began offering product upgrading services for
normal butane at our fractionator. This service contributed
$1.7 million of fee revenues in 2004. |
57
Product costs increased $5.4 million, from
$1.3 million, directly related to increased product sales.
Operating and maintenance expenses increased by
$5.2 million, or 38 percent, primarily from higher
maintenance expenses and fuel costs. The significant components
consisted of the following:
|
|
|
|
|
Outside services and other expenses increased $4.4 million
due to new storage cavern workover activity related to KDHE
requirements. |
|
|
|
Fuel expense increased $1.0 million due to an
18 percent increase in the average price of natural gas. |
Segment profit increased $2.6 million, or
56.8 percent, due primarily to higher storage and
fractionation revenue of $4.5 million, favorable product
sales margins of $1.5 million, $1.7 million higher
other fee revenues partially offset by $5.2 million higher
operating and maintenance expense.
We expect volumes fractionated for our customers at the Conway
fractionator to continue averaging 40,000 bpd. Currently,
commodity prices in the Mid-Continent region remain strong
relative to commodity prices at the Mont Belvieu, Texas market
hub, which minimizes the potential for volumes to be redirected
to the Mont Belvieu market. We also expect to continue to
produce income from the blending and segregation of various
products.
During the third and fourth quarters of 2005 we experienced a
significant increase in storage revenues from short-term
contracts. We do not expect this increase to continue because
the seasonal increase in retail propane sales began in the first
quarter of 2006 and we are nearing the end of the storage
contract year. We do not plan to increase storage fees in 2006.
We expect outside service costs to increase in 2006 due to the
large number of cavern workovers planned for the first quarter
of 2006. We expect outside service costs to continue at these
increased levels throughout 2006 and 2007 to ensure that we meet
the regulatory compliance requirement to complete cavern
workovers before the end of 2008.
Financial Condition and Liquidity
Prior to our IPO in August 2005, our sources of liquidity
included cash generated from operations and funding from
Williams. Our cash receipts were deposited in Williams
bank accounts and all cash disbursements were made from these
accounts. Thus, historically our financial statements have
reflected no cash balances. Cash transactions handled by
Williams for us were reflected in intercompany advances between
Williams and us. Following our IPO, we maintain our own bank
accounts but continue to utilize Williams personnel to
manage our cash and investments.
We believe we have, or have access, to the financial resources
and liquidity necessary to meet future requirements for working
capital, capital and investment expenditures, and quarterly cash
distributions. We anticipate our 2006 sources of liquidity will
include:
|
|
|
|
|
Cash generated from operations; |
|
|
|
Cash distributions from Discovery; |
|
|
|
Capital contributions from Williams pursuant to an omnibus
agreement; and |
|
|
|
Credit facilities, as needed. |
We anticipate our more significant 2006 capital requirements to
be:
|
|
|
|
|
Maintenance capital expenditures for our Conway assets; |
|
|
|
Capital contributions to Discovery for its capital expenditure
program; |
58
|
|
|
|
|
Working capital attributable to deferred revenues; and |
|
|
|
Minimum quarterly distributions to our unitholders. |
Prior to our IPO, cash distributions from Discovery to its
members required unanimous consent and no such distributions
were made. Discoverys limited liability company agreement
has been amended to provide for quarterly distributions of
available cash. We expect future cash requirements for Discovery
relating to working capital and maintenance capital expenditures
to be funded from cash retained by Discovery at the closing of
our IPO and from its own internally generated cash flows from
operations. Growth or expansion capital expenditures for
Discovery will be funded by either cash calls to its members,
which requires unanimous consent of the members except in
limited circumstances, or from internally generated funds. Prior
to our IPO, Discovery made a distribution of approximately
$43.8 million on August 22, 2005 to its existing
members, representing about 75 percent of Discoverys
retained cash. This distributed cash was associated with
Discoverys operations prior to our IPO and, accordingly,
we did not receive any portion of this distribution.
Prospectively, Discovery expects to make quarterly distributions
of available cash to its members instead of retaining all cash
from operations. Accordingly, January 31, 2006, pursuant to
the terms of its limited liability company agreement, Discovery
made an $11.0 million distribution of available cash to its
members. Our 40 percent share of this distribution was
$4.4 million.
|
|
|
Capital Contributions from Williams |
Capital contributions from Williams required under the omnibus
agreement consist of the following:
|
|
|
|
|
Indemnification of environmental and related expenditures for a
period of three years (for certain of those expenditures) up to
$14 million, which includes between $3.4 million and
$4.6 million for the restoration activities due to the
partial erosion of the Carbonate Trend pipeline overburden by
Hurricane Ivan, approximately $3.1 million for capital
expenditures related to KDHE-related cavern compliance at our
Conway storage facilities, and approximately $1.0 million
for our 40 percent share of Discoverys costs for
marshland restoration and repair or replacement of Paradis
emission-control flare. |
|
|
|
An annual credit for general and administrative expenses of
$3.9 million in 2005 ($1.4 million pro-rated for the
portion of the year from August 23 to December 31),
$3.2 million in 2006, $2.4 million in 2007,
$1.6 million in 2008 and $0.8 million in 2009. |
|
|
|
Up to $3.4 million to fund our 40 percent share of the
expected total cost of Discoverys Tahiti pipeline lateral
expansion project in excess of the $24.4 million we
contributed during September 2005. |
On May 20, 2005, Williams amended its $1.275 billion
revolving credit facility, which is available for borrowings and
letters of credit, to allow us to borrow up to $75 million
under the Williams facility. Borrowings under this facility
mature on May 3, 2007. Our $75 million borrowing limit
under Williams revolving credit facility is available for
general partnership purposes, including acquisitions, but only
to the extent that sufficient amounts remain unborrowed by
Williams and its other subsidiaries. At December 31, 2005,
letters of credit totaling $378 million had been issued on
behalf of Williams by the participating institutions under this
facility and no revolving credit loans were outstanding. See
Note 11 of the Notes to Consolidated Financial Statements
for additional information.
We also have a $20 million revolving credit facility with
Williams as the lender. The facility is available exclusively to
fund working capital borrowings. Borrowings under the facility
will mature on May 3, 2007. We are required to reduce all
borrowings under this facility to zero for a period of at least
15 consecutive days once
59
each 12-month period
prior to the maturity date of the facility. For 2005, we had no
borrowings under the working capital credit facility. See
Note 11 of Notes to Consolidated Financial Statements for
additional information.
The natural gas gathering, processing and transportation, and
NGL fractionation and storage businesses are capital-intensive,
requiring investment to upgrade or enhance existing operations
and comply with safety and environmental regulations. The
capital requirements of these businesses consist primarily of:
|
|
|
|
|
Maintenance capital expenditures, which are capital expenditures
made to replace partially or fully depreciated assets in order
to maintain the existing operating capacity of our assets and to
extend their useful lives; and |
|
|
|
Expansion capital expenditures such as those to acquire
additional assets to grow our business, to expand and upgrade
plant or pipeline capacity and to construct new plants,
pipelines and storage facilities. |
We estimate that maintenance capital expenditures for the Conway
assets will be approximately $9.0 million for 2006,
including approximately $2.3 million to be spent in
connection with the installation of wellhead control equipment
and well meters and KDHE-related cavern compliance. In the
omnibus agreement, Williams agreed to reimburse us for the cost
of these expenditures subject to a three-year time limitation
from the IPO closing date, August 23, 2005, and an overall
omnibus agreement limitation of $14 million. Additionally,
capital expenditures include $3.2 million related to
workovers that include the installation of cavern liners. The
remaining amount consists of various smaller maintenance
projects.
We estimate that maintenance capital expenditures for
100 percent of Discovery will be approximately
$2.7 million for 2006. We expect Discovery will fund its
maintenance capital expenditures through cash flow from
operations.
We estimate that expansion capital expenditures for
100 percent of Discovery will be approximately
$37.6 million for 2006. This amount includes
$2.0 million for marshland restoration costs related to the
initial construction of the Discovery pipeline,
$27.4 million for the ongoing construction of the Tahiti
pipeline lateral expansion project, $8.0 million related to
a cogeneration project that we expect will have a favorable
impact on Discoverys operating expenses of approximately
$1.5 to $2.0 million annually, and $0.2 million for
other efficiency projects. We expect Discovery will fund the
$2.0 million for marshland restoration through retained
cash flow from operations or capital contributions from its
members. In either case, our 40 percent share of marshland
restoration costs will be reimbursed by Williams pursuant to our
omnibus agreement. We expect Discovery will fund the
$27.4 million for the Tahiti pipeline lateral expansion
project from the amounts escrowed for this project in September
2005 and capital contributions from its members including
approximately $4.0 million of cost that cannot, by
agreement, be funded from the escrowed funds. Our
40 percent share of this $4.0 million cost will be
reimbursed by Williams pursuant to our omnibus agreement. Total
construction costs of this project are expected to be
approximately $69.5 million and we anticipate that the
assets will be placed in service in 2007. We expect Discovery
will fund the $8.0 million for the cogeneration project
with capital contributions from its members, provided it is
approved by the members, including us.
|
|
|
Working Capital Attributable to Deferred Revenues |
We require cash in order to continue providing services to our
storage customers who prepaid their annual storage contracts in
April 2005. The storage year for customer contracts at our
Conway storage facility runs from April 1 of a year to
March 31 of the following year. We typically receive
payment for these one-year contracts in advance in April after
the beginning of the storage year and recognize the associated
revenue over the course of the storage year. As of
December 31, 2005, our deferred storage revenue is
$3.4 million. We retained a portion of the proceeds from
our IPO for working capital purposes associated with this
deferred revenue.
60
|
|
|
Cash Distributions to Unitholders |
We paid a quarterly distribution of $5.0 million
($.35 per unit) to common and subordinated unitholders and
the general partner interest on February 14, 2006. We
intend to make minimum quarterly distributions totaling
$5.0 million to the extent we have sufficient cash from
operations after establishment of cash reserves.
|
|
|
Results of Operations Cash Flows |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Net cash provided by operating activities
|
|
$ |
1,893 |
|
|
$ |
2,703 |
|
|
$ |
6,644 |
|
Net cash used by investing activities
|
|
|
(28,088 |
) |
|
|
(1,534 |
) |
|
|
(102,810 |
) |
Net cash provided (used) by financing activities
|
|
|
33,034 |
|
|
|
(1,169 |
) |
|
|
96,166 |
|
The $0.8 million decrease in net cash provided by operating
activities in 2005 as compared to 2004 is due primarily to:
|
|
|
|
|
$2.8 million related to trade accounts receivable at
August 22, 2005 that were not included in the contribution
of net assets to us; |
|
|
|
$2.3 million related to decreases in the Conway product
imbalance liability largely resulting from settlement activity
in the fourth quarter of 2005; and |
|
|
|
$1.0 million lower operating income, adjusted for non-cash
expenses. |
These decreases were largely offset by:
|
|
|
|
|
$4.2 million in lower interest expense due to the
forgiveness by Williams of advances to us at the closing of our
IPO; and |
|
|
|
a $1.3 million increase in distributed earnings from
Discovery. |
The decrease of $3.9 million in net cash provided by
operating activities in 2004 as compared to 2003 reflects an
increase of $8.3 million in interest expense in 2004
related primarily to the funding of our $101.6 million
share of a Discovery cash call discussed below. This decrease in
net cash provided by operating activities was partially offset
by changes in working capital, including a $2.7 million
increase in accounts payable. The increase in accounts payable
was due to a $1.6 million accrual for spot ethane purchases
in December 2004 and a $1.0 million higher accrual for
power costs at the end of 2004 as compared to 2003.
Net cash used by investing activities includes maintenance
capital expenditures in our NGL Services segment. In addition,
2005 includes our capital contribution of $24.4 million to
Discovery for construction of the Tahiti pipeline lateral
expansion project. Net cash used by investing activities in 2003
also includes our $101.6 million capital contribution to
Discovery for the repayment of Discoverys outstanding debt
in December 2003.
Net cash provided by financing activities in 2005 includes the
cash flows related to our IPO on August 23, 2005. These
consisted of $100.2 million in net proceeds from the sale
of the units, a $58.8 million distribution to Williams and
the payment of $4.3 million in expenses associated with our
IPO. Net cash provided (used) by financing activities for
2005 and 2004 also includes the pass through of
$3.7 million and $1.2 million, respectively, of net
cash flows to Williams prior to August 23, 2005, under its
cash management program. Following the closing of our IPO on
August 23, 2005, we no longer participate in Williams
cash management program, and our net cash flows no longer pass
through to Williams. The 2005 period also includes
$2.1 million of distributions paid to unitholders and
$1.6 million in indemnifications and reimbursements
received from Williams pursuant to the omnibus agreement.
61
Net cash provided by financing activities in 2003 includes
advances from Williams to fund our $101.6 million share of
a Discovery cash call discussed above. The remaining 2003
financing cash flows represent the pass through of our net cash
flows to Williams under its cash management program as described
above.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Net cash provided by operating activities
|
|
$ |
30,814 |
|
|
$ |
35,623 |
|
|
$ |
44,025 |
|
Net cash used by investing activities
|
|
|
(65,997 |
) |
|
|
(39,115 |
) |
|
|
(12,073 |
) |
Net cash provided by financing activities
|
|
|
1,339 |
|
|
|
|
|
|
|
409 |
|
Net cash provided by operating activities decreased
$4.8 million in 2005 as compared to 2004 due primarily to
expenditures incurred for repairs following Hurricane Katrina
that have not yet been reimbursed by Discoverys insurance
carrier. The 2005 use of cash related to accounts receivable
included a $24.6 million outstanding receivable from Power
for the marketing activities associated with the TGP and TETCO
open seasons discussed above; this was offset by a similar
change in accounts payable for a balance due to the shippers of
TGP and the TETCO. The 2005 use of cash related to accounts
receivable also included other increases in customers
outstanding balances of $8.6 million. The 2005 source of
cash related to accounts payable also included a
$7.7 million overpayment by a customer.
Net cash provided by operating activities decreased
$8.4 million in 2004 as compared to 2003 due primarily to
the favorable impact in 2003 of improved accounts receivable
collections. Working capital levels remained more constant in
2004 as compared to 2003. As a result, net cash provided by
operating activities in 2004 did not include significant amounts
from changes in working capital and reflected the return to more
normal levels.
During 2005, net cash used by investing activities included
$44.6 million to fund escrow accounts for the Tahiti
pipeline lateral project and related interest income and
$21.4 million of capital expenditures for (1) the
completion of the Front Runner and market expansion projects,
(2) the initial expenditures for the Tahiti project, and
(3) the purchase of leased compressors at the Larose
processing plant. During 2004, net cash used by investing
activities was primarily used for the construction of a
gathering lateral to connect our pipeline system to the Front
Runner prospect. During 2003, net cash used for investing
activities was primarily for the purchase of a 12
gathering pipeline ($3.5 million) and initial capital
expenditures incurred for the construction of a gathering
lateral to connect to Discoverys pipeline system to the
Front Runner prospect ($4.5 million).
During 2005, net cash provided by financing activities included
capital contributions totaling $48.3 million from our
members for the construction of the Tahiti pipeline lateral
expansion, the distribution of cash associated with our
operations prior to our IPO of $43.8 million and a
quarterly distribution to members in the fourth quarter of 2005
of $3.2 million. During 2003, Discoverys members made
capital contributions of $254.1 million in response to a
cash call by Discovery. Discovery used these contributions to
retire its outstanding debt of $253.7 million.
62
A summary of our contractual obligations as of December 31,
2005, is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 | |
|
2007-2008 | |
|
2009-2010 | |
|
2011+ | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Notes payable/long-term debt
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
30 |
|
|
|
55 |
|
|
|
10 |
|
|
|
|
|
|
|
95 |
|
Purchase obligations
|
|
|
5,135 |
|
|
|
2,928 |
|
|
|
240 |
|
|
|
120 |
(a) |
|
|
8,423 |
|
Other long term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
5,165 |
|
|
$ |
2,983 |
|
|
$ |
250 |
|
|
$ |
120 |
|
|
$ |
8,518 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Year 2011 represents one year of payments associated with an
operating agreement whose term is tied to the life of the
underlying gas reserves. |
Our equity investee, Discovery, also has contractual obligations
for which we are not contractually liable. These contractual
obligations, however, will impact Discoverys ability to
make cash distributions to us. A summary of Discoverys
total contractual obligations as of December 31, 2005, is
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 | |
|
2007-2008 | |
|
2009-2010 | |
|
2011+ | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Notes payable/long-term debt
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
854 |
|
|
|
1,712 |
|
|
|
1,716 |
|
|
|
4,109 |
|
|
|
8,391 |
|
Purchase obligations(a)
|
|
|
30,807 |
|
|
|
23,488 |
|
|
|
|
|
|
|
|
|
|
|
54,295 |
|
Other long-term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
31,661 |
|
|
$ |
25,200 |
|
|
$ |
1,716 |
|
|
$ |
4,109 |
|
|
$ |
62,686 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
With the exception of $3.4 million of 2006 outstanding
purchase orders, all other amounts are Tahiti-related
expenditures that will be funded from the amounts escrowed for
this project in September 2005 and capital contributions from
members including us. Please read Financial Condition and
Liquidity Outlook for 2006. |
Effects of Inflation
Inflation in the United States has been relatively low in recent
years and did not have a material impact on our results of
operations for the three-year period ended December 31,
2005. It may in the future, however, increase the cost to
acquire or replace property, plant and equipment and may
increase the costs of labor and supplies. Our operating revenues
and costs are influenced to a greater extent by specific price
changes in natural gas and NGLs. To the extent permitted by
competition, regulation and our existing agreements, we have and
will continue to pass along increased costs to our customers in
the form of higher fees.
Regulatory Matters
As of December 31, 2005, Discovery had deferred amounts of
$6 million relating to retained system gas gains and the
over-recovery of lost and unaccounted-for gas on the Discovery
system. Please read Note 7 Rate and Regulatory
Matters and Contingent Liabilities Rate and
Regulatory Matters to the Discovery Producer Services LLC
Consolidated Financial Statements included herein. Certain
shippers challenged Discoverys right to retain these
gains. FERC requested and received from Discovery additional
information regarding both lost and unaccounted-for-volumes and
gas gains. Discovery responded to the information
63
request and on October 31, 2005, the FERC accepted the
filing and no requests for rehearing were filed. As a result, we
recognized the portion of this reserve for the period 2002
through 2004 of $10.7 million in 2005.
Discoverys natural gas pipeline transportation is subject
to rate regulation by FERC under the Natural Gas Act. For more
information on federal and state regulations affecting our
business, please read Risk Factors and FERC
Regulation elsewhere in this report.
Environmental
Our Conway storage facilities are subject to strict
environmental regulation by the Underground Storage Unit within
the Geology Section of the Bureau of Water of the KDHE under the
Underground Hydrocarbon and Natural Gas Storage Program, which
became effective on April 1, 2003.
We are in the process of modifying our Conway storage
facilities, including the caverns and brine ponds, and we expect
our storage operations will be in compliance with the
Underground Hydrocarbon and Natural Gas Storage Program
regulations by the applicable required compliance dates. In
2003, we began to complete workovers on approximately 30 to 35
salt caverns per year and install, on average, a double liner on
one brine pond per year. The incremental costs of these
activities is approximately $5.5 million per year to
complete the workovers and approximately $900,000 per year
to install a double liner on a brine bond. In response to these
increased costs, we raised our storage rates in 2004 by an
amount sufficient to preserve our margins in this business.
Accordingly, we do not believe that these increased costs have
had a material effect on our business or results of operations.
We expect on average to complete workovers on each of our
caverns every five to ten years and install double liners on
each of our brine ponds every 18 years. The KDHE has also
advised us that a regulation relating to the metering of NGL
volumes that are injected and withdrawn from our caverns may be
interpreted and enforced to require the installation of meters
at each of our well bores. We have informed the KDHE that we
disagree with this interpretation, and the KDHE has asked us to
provide it with additional information. We estimate that the
cost of installing a meter at each of our well bores at Conway
West and Mitchell would be approximately $3.9 million over
three years.
As of December 31, 2005, we had accrued environmental
liabilities of $5.4 million related to four remediation
projects at the Conway storage facilities. In 2004, we purchased
an insurance policy that covers up to $5.0 million of
remediation costs until an active remediation system is in place
or April 30, 2008, whichever is earlier, excluding
operation and maintenance costs and ongoing monitoring costs,
for these four projects to the extent such costs exceed a
$4.2 million deductible. The policy also covers costs
incurred as a result of third party claims associated with then
existing but unknown contamination related to the storage
facilities. The aggregate limit under the policy for all claims
is $25 million. In the omnibus agreement, Williams agreed
to indemnify us for these remediation expenditures to the extent
not recovered under the insurance policy, excluding costs of
project management and soil and groundwater monitoring, and
certain other environmental and related obligations arising out
of or associated with the operation of the assets before the
closing date of our IPO. There is an aggregate cap of
$14.0 million on the total amount of indemnity coverage
under the omnibus agreement, which will be reduced by actual
recoveries under the environmental insurance policy. There is
also a three-year time limitation from the IPO closing date,
August 23, 2005. We estimate that the approximate cost of
the project management and soil and groundwater monitoring
associated with the four remediation projects at the Conway
storage facilities and for which we will not be indemnified will
be approximately $200,000 to $400,000 per year following
the completion of remediation work. The benefit of the
indemnification will be accounted for as a capital contribution
to us by Williams as the costs are incurred. Please read
Certain Relationships and Related Transactions
Omnibus Agreement.
In connection with our operations at the Conway facilities, we
are required by the KDHE regulations to provide assurance of our
financial capability to plug and abandon the wells and abandon
the brine facilities we operate at Conway. Williams has posted
two letters of credit on our behalf in an aggregate amount of
$17.5 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.
64
In connection with the construction of Discoverys
pipeline, approximately 73 acres of marshland was
traversed. Discovery is required to restore marshland in other
areas to offset the damage caused during the initial
construction. In Phase I of this project, Discovery created
new marshlands to replace about half of the traversed acreage.
Phase II, which will complete the project, began during
2005 and will cost approximately $2.0 million.
|
|
Item 7A. |
Quantitative and Qualitative Disclosures About Market
Risk |
Market risk is the risk of loss arising from adverse changes in
market rates and prices. The principal market risk to which we
are exposed is commodity price risk for natural gas and NGLs. We
were also exposed to the risk of interest rate fluctuations on
our intercompany balances with Williams prior to the forgiveness
of these balances by Williams in conjunction with our IPO.
Commodity Price Risk
Certain of Discoverys processing contracts are exposed to
the impact of price fluctuations in the commodity markets,
including the correlation between natural gas and NGL prices. In
addition, price fluctuations in commodity markets could impact
the demand for Discoverys services in the future.
Carbonate Trend and our fractionation and storage operations are
not directly affected by changing commodity prices except for
product imbalances, which are exposed to the impact of price
fluctuation in NGL markets. Price fluctuations in commodity
markets could also impact the demand for storage and
fractionation services in the future. In connection with the
IPO, Williams transferred to us a gas purchase contract for the
purchase of a portion of our fuel requirements at the Conway
fractionator at a market price not to exceed a specified level.
This physical contract is intended to mitigate the fuel price
risk under one of our fractionation contracts which contains a
cap on the per-unit fee that we can charge, at times limiting
our ability to pass through the full amount of increases in
variable expenses to that customer. We and Discovery do not
currently use financial derivatives to manage the risks
associated with these price fluctuations.
Interest Rate Risk
Historically, our interest rate exposure was related to our
advances from Williams. The table below provides information as
of December 31, 2004 about our interest rate risk. We have
no interest rate risk as of December 31, 2005.
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 | |
|
|
| |
|
|
Carrying | |
|
Fair | |
|
|
Value | |
|
Value | |
|
|
| |
|
| |
|
|
($ in thousands) | |
Advances from Williams
|
|
$ |
186,024 |
|
|
$ |
186,024 |
|
These advances are due on demand. Prior to the closing of our
IPO, Williams forgave these advances. The variable interest rate
was 7.4% at December 31, 2004.
65
|
|
Item 8. |
Financial Statements and Supplementary Data |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Williams Partners GP LLC
General Partner of Williams Partners L.P.
We have audited the accompanying consolidated balance sheets of
Williams Partners L.P. as of December 31, 2005 and 2004,
and the related consolidated statements of operations,
partners capital, and cash flows for each of the three
years in the period ended December 31, 2005. These
financial statements are the responsibility of the
Partnerships management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. We were not engaged to perform an
audit of the Partnerships internal control over financial
reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of
the Partnerships internal control over financial
reporting. Accordingly, we express no such opinion. An audit
also includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant
estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Williams Partners L.P. at
December 31, 2005 and 2004, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2005, in conformity with
U.S. generally accepted accounting principles.
As described in Note 7, effective January 1, 2003,
Williams Partners L.P. adopted Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement
Obligations, and effective December 31, 2005, adopted
Financial Accounting Standards Board Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations.
Tulsa, Oklahoma
February 27, 2005
66
WILLIAMS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
|
(In thousands) | |
ASSETS |
Current assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
6,839 |
|
|
$ |
|
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
|
|
Trade
|
|
|
1,840 |
|
|
|
2,150 |
|
|
|
Other
|
|
|
2,104 |
|
|
|
1,388 |
|
|
Product imbalance
|
|
|
760 |
|
|
|
|
|
|
Gas purchase contract affiliate
|
|
|
5,320 |
|
|
|
|
|
|
Prepaid expenses
|
|
|
1,133 |
|
|
|
749 |
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
17,996 |
|
|
|
4,287 |
|
Investment in Discovery Producer Services
|
|
|
150,260 |
|
|
|
147,281 |
|
Property, plant and equipment, net
|
|
|
67,931 |
|
|
|
67,793 |
|
Gas purchase contract noncurrent
affiliate
|
|
|
4,754 |
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
240,941 |
|
|
$ |
219,361 |
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL |
Current liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
|
|
Trade
|
|
$ |
3,906 |
|
|
$ |
2,480 |
|
|
|
Affiliate
|
|
|
4,729 |
|
|
|
1,980 |
|
|
Product imbalance
|
|
|
|
|
|
|
1,071 |
|
|
Deferred revenue
|
|
|
3,552 |
|
|
|
3,305 |
|
|
Accrued liabilities
|
|
|
2,373 |
|
|
|
3,924 |
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
14,560 |
|
|
|
12,760 |
|
Advances from affiliate
|
|
|
|
|
|
|
186,024 |
|
Environmental remediation liabilities
|
|
|
3,964 |
|
|
|
3,909 |
|
Other noncurrent liabilities
|
|
|
762 |
|
|
|
|
|
Commitments and contingent liabilities (Note 13)
|
|
|
|
|
|
|
|
|
Partners capital:
|
|
|
|
|
|
|
|
|
|
Predecessor partners equity
|
|
|
|
|
|
|
16,668 |
|
|
Common unitholders (7,006,146 outstanding at December 31,
2005)
|
|
|
108,526 |
|
|
|
|
|
|
Subordinated unitholders (7,000,000 outstanding at
December 31, 2005)
|
|
|
108,491 |
|
|
|
|
|
|
General partner
|
|
|
4,638 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
221,655 |
|
|
|
16,668 |
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$ |
240,941 |
|
|
$ |
219,361 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
67
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Storage:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2,426 |
|
|
|
Third-party
|
|
|
20,290 |
|
|
|
15,318 |
|
|
|
9,223 |
|
|
Fractionation
|
|
|
10,770 |
|
|
|
9,070 |
|
|
|
8,221 |
|
|
Gathering
|
|
|
3,063 |
|
|
|
3,883 |
|
|
|
5,513 |
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
13,400 |
|
|
|
506 |
|
|
|
|
|
|
|
Third-party
|
|
|
63 |
|
|
|
7,947 |
|
|
|
1,263 |
|
|
Other
|
|
|
4,183 |
|
|
|
4,252 |
|
|
|
1,648 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
51,769 |
|
|
|
40,976 |
|
|
|
28,294 |
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
13,378 |
|
|
|
9,986 |
|
|
|
8,789 |
|
|
|
Third-party
|
|
|
11,733 |
|
|
|
9,390 |
|
|
|
5,171 |
|
|
Product cost
|
|
|
11,821 |
|
|
|
6,635 |
|
|
|
1,263 |
|
|
Depreciation and accretion
|
|
|
3,619 |
|
|
|
3,686 |
|
|
|
3,707 |
|
|
General and administrative expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
4,186 |
|
|
|
2,534 |
|
|
|
1,738 |
|
|
|
Third-party
|
|
|
1,137 |
|
|
|
79 |
|
|
|
75 |
|
|
Taxes other than income
|
|
|
700 |
|
|
|
716 |
|
|
|
640 |
|
|
Other net
|
|
|
(6 |
) |
|
|
(91 |
) |
|
|
(133 |
) |
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
46,568 |
|
|
|
32,935 |
|
|
|
21,250 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
5,201 |
|
|
|
8,041 |
|
|
|
7,044 |
|
Equity earnings Discovery Producer Services
|
|
|
8,331 |
|
|
|
4,495 |
|
|
|
3,447 |
|
Impairment of investment in Discovery Producer Services
|
|
|
|
|
|
|
(13,484 |
) |
|
|
|
|
Interest expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
(7,461 |
) |
|
|
(11,980 |
) |
|
|
(4,176 |
) |
|
Third-party
|
|
|
(777 |
) |
|
|
(496 |
) |
|
|
|
|
Interest income
|
|
|
165 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principle
|
|
|
5,459 |
|
|
|
(13,424 |
) |
|
|
6,315 |
|
Cumulative effect of change in accounting principle
|
|
|
(628 |
) |
|
|
|
|
|
|
(1,099 |
) |
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
4,831 |
|
|
$ |
(13,424 |
) |
|
$ |
5,216 |
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
4,831 |
|
|
|
|
|
|
|
|
|
|
Net loss applicable to the period through August 22, 2005
|
|
|
(103 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income applicable to the period August 23 through
December 31, 2005
|
|
|
4,934 |
|
|
|
|
|
|
|
|
|
|
Allocation of net loss to general partner
|
|
|
(1,273 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income to limited partners
|
|
$ |
6,207 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting
principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$ |
0.49 |
|
|
|
|
|
|
|
|
|
|
|
Subordinated units
|
|
$ |
0.49 |
|
|
|
|
|
|
|
|
|
|
Cumulative effect of change in accounting principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$ |
(0.05 |
) |
|
|
|
|
|
|
|
|
|
|
Subordinated units
|
|
$ |
(0.05 |
) |
|
|
|
|
|
|
|
|
|
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
$ |
0.44 |
|
|
|
|
|
|
|
|
|
|
|
Subordinated units
|
|
$ |
0.44 |
|
|
|
|
|
|
|
|
|
Weighted average number of units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
7,001,366 |
|
|
|
|
|
|
|
|
|
|
Subordinated units
|
|
|
7,000,000 |
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
68
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated | |
|
|
|
|
|
|
|
|
|
|
Other | |
|
|
|
|
Pre-IPO | |
|
Limited Partners | |
|
|
|
Comprehensive | |
|
Total | |
|
|
Owners | |
|
| |
|
General | |
|
Income | |
|
Partners | |
|
|
Equity | |
|
Common | |
|
Subordinated | |
|
Partner | |
|
(Loss) | |
|
Capital | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Dollars in thousands) | |
Balance January 1, 2003
|
|
$ |
24,876 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,962 |
) |
|
$ |
22,914 |
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income 2003
|
|
|
5,216 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,216 |
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(116 |
) |
|
|
(116 |
) |
|
|
Net reclassification into earnings of derivative instrument
losses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,078 |
|
|
|
2,078 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,962 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,178 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2003
|
|
|
30,092 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,092 |
|
|
Net loss 2004
|
|
|
(13,424 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,424 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2004
|
|
|
16,668 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,668 |
|
Accounts receivable not contributed
|
|
|
(2,640 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,640 |
) |
Net loss attributable to the period through August 22, 2005
|
|
|
(103 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(103 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,925 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,925 |
|
Contribution of net assets of predecessor companies (2,000,000
common units; 7,000,000 subordinated units)
|
|
|
(13,925 |
) |
|
|
10,471 |
|
|
|
106,427 |
|
|
|
4,343 |
|
|
|
|
|
|
|
107,316 |
|
Issuance of units to public (5,000,000 common units)
|
|
|
|
|
|
|
100,247 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100,247 |
|
Offering costs
|
|
|
|
|
|
|
(4,291 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,291 |
) |
Net income (loss) attributable to the period August 23,
2005 through December 31, 2005
|
|
|
|
|
|
|
3,104 |
|
|
|
3,103 |
|
|
|
(1,273 |
) |
|
|
|
|
|
|
4,934 |
|
Cash distributions ($.1484 per unit)
|
|
|
|
|
|
|
(1,039 |
) |
|
|
(1,039 |
) |
|
|
(42 |
) |
|
|
|
|
|
|
(2,120 |
) |
Issuance of common units (6,146 common units)
|
|
|
|
|
|
|
34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34 |
|
Contributions pursuant to the Omnibus Agreement
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,610 |
|
|
|
|
|
|
|
1,610 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2005
|
|
$ |
|
|
|
$ |
108,526 |
|
|
$ |
108,491 |
|
|
$ |
4,638 |
|
|
$ |
|
|
|
$ |
221,655 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
69
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) before cumulative effect of change in
accounting principle
|
|
$ |
5,459 |
|
|
$ |
(13,424 |
) |
|
$ |
6,315 |
|
|
Adjustments to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and accretion
|
|
|
3,619 |
|
|
|
3,686 |
|
|
|
3,707 |
|
|
|
Impairment of investment in Discovery Producer Services
|
|
|
|
|
|
|
13,484 |
|
|
|
|
|
|
|
Amortization of gas purchase contract affiliate
|
|
|
2,033 |
|
|
|
|
|
|
|
|
|
|
|
Undistributed earnings of Discovery Producer Services
|
|
|
(7,051 |
) |
|
|
(4,495 |
) |
|
|
(3,447 |
) |
|
|
Cash provided (used) by changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(3,045 |
) |
|
|
261 |
|
|
|
(850 |
) |
|
|
|
Other current assets
|
|
|
(384 |
) |
|
|
(362 |
) |
|
|
(187 |
) |
|
|
|
Accounts payable
|
|
|
4,215 |
|
|
|
2,711 |
|
|
|
(274 |
) |
|
|
|
Accrued liabilities
|
|
|
(737 |
) |
|
|
(417 |
) |
|
|
(320 |
) |
|
|
|
Deferred revenue
|
|
|
247 |
|
|
|
775 |
|
|
|
1,108 |
|
|
|
Other, including changes in noncurrent assets and liabilities
|
|
|
(2,463 |
) |
|
|
484 |
|
|
|
592 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
1,893 |
|
|
|
2,703 |
|
|
|
6,644 |
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(3,688 |
) |
|
|
(1,534 |
) |
|
|
(1,167 |
) |
|
|
Contribution to Discovery Producer Services
|
|
|
(24,400 |
) |
|
|
|
|
|
|
(101,643 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(28,088 |
) |
|
|
(1,534 |
) |
|
|
(102,810 |
) |
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sale of common units
|
|
|
100,247 |
|
|
|
|
|
|
|
|
|
|
|
Payment of offering costs
|
|
|
(4,291 |
) |
|
|
|
|
|
|
|
|
|
|
Distribution to The Williams Companies, Inc.
|
|
|
(58,756 |
) |
|
|
|
|
|
|
|
|
|
|
Changes in advances from affiliates net
|
|
|
(3,656 |
) |
|
|
(1,169 |
) |
|
|
96,166 |
|
|
|
Distributions to unitholders
|
|
|
(2,120 |
) |
|
|
|
|
|
|
|
|
|
|
Contributions per omnibus agreement
|
|
|
1,610 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities
|
|
|
33,034 |
|
|
|
(1,169 |
) |
|
|
96,166 |
|
|
|
|
|
|
|
|
|
|
|
Increase in cash and cash equivalents
|
|
|
6,839 |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$ |
6,839 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
70
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unless the context clearly indicates otherwise, references in
this report to we, our, us
or like terms refer to Williams Partners L.P. and its
subsidiaries. Unless the context clearly indicates otherwise,
references to we, our, and
us include the operations of Discovery Producer
Services LLC (Discovery), in which we own a
40 percent interest. When we refer to Discovery by name, we
are referring exclusively to its businesses and operations.
We are a Delaware limited partnership that was formed in
February 2005, to acquire and own (1) a 40 percent
interest in Discovery; (2) the Carbonate Trend gathering
pipeline off the coast of Alabama; (3) three integrated
natural gas liquids (NGL) product storage facilities
near Conway, Kansas; and (4) a 50 percent undivided
ownership interest in a fractionator near Conway, Kansas. Prior
to the closing of our initial public offering (the
IPO) in August 2005, the 40 percent interest in
Discovery was held by Williams Energy, L.L.C.
(Energy) and Williams Discovery Pipeline LLC; the
Carbonate Trend gathering pipeline was held in Carbonate Trend
Pipeline LLC (CTP), which was owned by Williams
Mobile Bay Producers Services, L.L.C.; and the NGL product
storage facilities and the interest in the fractionator were
owned by Mid-Continent Fractionation and Storage, LLC
(MCFS). All of these are wholly owned indirect
subsidiaries of The Williams Companies, Inc. (collectively
Williams). Williams Partners GP LLC, a Delaware
limited liability company, was also formed in February 2005, to
serve as our general partner. We also formed Williams Partners
Operating LLC, an operating limited liability company (wholly
owned by us) through which all our activities are conducted,.
|
|
|
Initial Public Offering and Related Transactions |
On August 23, 2005, we completed our IPO of 5,000,000
common units representing limited partner interests in us at a
price of $21.50 per unit. The proceeds of
$100.2 million, net of the underwriters discount and
a structuring fee totaling $7.3 million, were used to:
|
|
|
|
|
distribute $58.8 million to Williams, in part to reimburse
Williams for capital expenditures relating to the assets
contributed to us and for a gas purchase contract contributed to
us; |
|
|
|
provide $24.4 million to make a capital contribution to
Discovery to fund an escrow account required in connection with
the Tahiti pipeline lateral expansion project; |
|
|
|
provide $12.7 million of additional working
capital; and |
|
|
|
pay $4.3 million of expenses associated with the IPO and
related formation transactions. |
Concurrent with the closing of the IPO, the 40 percent
interest in Discovery and all of the interests in CTP and MCFS
were contributed to us by Williams subsidiaries in
exchange for an aggregate of 2,000,000 common units and
7,000,000 subordinated units. The public, through the
underwriters of the offering, contributed $107.5 million
($100.2 million net of the underwriters discount and
a structuring fee) to us in exchange for 5,000,000 common units,
representing a 35 percent limited partner interest in us.
Additionally, at the closing of the IPO, the underwriters fully
exercised their option to purchase 750,000 common units from
Williams subsidiaries at the IPO price of $21.50 per
unit, less the underwriters discount and a structuring fee.
|
|
Note 2. |
Description of Business |
We are principally engaged in the business of gathering,
transporting and processing natural gas and fractionating and
storing NGLs. Operations of our businesses are located in the
United States and are organized into two reporting segments:
(1) Gathering and Processing and (2) NGL Services. Our
Gathering and Processing segment includes our equity investment
in Discovery and the Carbonate Trend gathering pipeline. Our NGL
Services segment includes the Conway fractionation and storage
operations.
71
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Gathering and Processing. We own a 40 percent
interest in Discovery, which includes a wholly owned subsidiary,
Discovery Gas Transmission LLC. Discovery owns (1) a
273-mile natural gas
gathering and transportation pipeline system, located primarily
off the coast of Louisiana in the Gulf of Mexico, (2) a
600 million cubic feet per day cryogenic natural gas
processing plant in Larose, Louisiana, (3) a
32,000 barrels per day (bpd) natural gas
liquids fractionator in Paradis, Louisiana and (4) two
onshore liquids pipelines, including a
22-mile mixed NGL
pipeline connecting the gas processing plant to the fractionator
and a 10-mile
condensate pipeline connecting the gas processing plant to a
third party oil gathering facility. Although Discovery includes
fractionation operations, which would normally fall within the
NGL Services segment, it is primarily engaged in gathering and
processing and is managed as such. Hence, this equity investment
is considered part of the Gathering and Processing segment.
Our Carbonate Trend gathering pipeline is an unregulated sour
gas gathering pipeline consisting of approximately 34 miles
of pipeline off the coast of Alabama.
NGL Services. Our Conway storage facilities include three
underground NGL storage facilities in the Conway, Kansas, area
with a storage capacity of approximately 20 million
barrels. The facilities are connected via a series of pipelines.
The storage facilities receive daily shipments of a variety of
products, including mixed NGLs and fractionated products. In
addition to pipeline connections, one facility offers truck and
rail service.
Our Conway fractionation facility is located near McPherson,
Kansas, and has a capacity of approximately 107,000 bpd. We
own a 50 percent undivided interest in these facilities
representing capacity of approximately 53,500 bpd.
ConocoPhillips and ONEOK, Inc. are the other owners. Williams
operates the facility pursuant to an operating agreement that
extends until May 2011. The fractionator separates mixed NGLs
into five products: ethane, propane, normal butane, isobutane
and natural gasoline. Portions of these products are then
transported and stored at our Conway storage facilities.
|
|
Note 3. |
Summary of Significant Accounting Policies |
Basis of Presentation. The consolidated financial
statements have been prepared based upon accounting principles
generally accepted in the United States and include the accounts
of the parent and our wholly owned subsidiaries. Intercompany
accounts and transactions have been eliminated.
Use of Estimates. The preparation of financial statements
in conformity with accounting principles generally accepted in
the United States requires management to make estimates and
assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results
could differ from those estimates.
Estimates and assumptions which, in the opinion of management,
are significant to the underlying amounts included in the
financial statements and for which it would be reasonably
possible that future events or information could change those
estimates include:
|
|
|
|
|
impairment assessments of investments and long-lived assets; |
|
|
|
loss contingencies; |
|
|
|
environmental remediation obligations; and |
|
|
|
asset retirement obligations. |
These estimates are discussed further throughout the
accompanying notes.
Proportional Accounting for the Conway Fractionator. No
separate legal entity exists for the fractionator. We hold a
50 percent undivided interest in the fractionator property,
plant and equipment, and we are responsible for our proportional
share of the costs and expenses of the fractionator. As operator
of the facility, we incur the liabilities of the fractionator
(except for certain fuel costs purchased directly by one of the
co-
72
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
owners) and are reimbursed by the co-owners for their
proportional share of the total costs and expenses. Each
co-owner is responsible for the marketing of their proportional
share of the fractionators capacity. Accordingly, we
reflect our proportionate share of the revenues and costs and
expenses of the fractionator in the Consolidated Statements of
Operations; and we reflect our proportionate share of the
fractionator property, plant and equipment in the Consolidated
Balance Sheets. Liabilities in the Consolidated Balance Sheets
include those incurred on behalf of the co-owners with
corresponding receivables from the co-owners. Accounts
receivable also includes receivables from our customers for
fractionation services.
Cash and Cash Equivalents. Cash and cash equivalents
include demand and time deposits, certificates of deposit and
other marketable securities with maturities of three months or
less when acquired.
Accounts Receivable. Accounts receivable are carried on a
gross basis, with no discounting, less an allowance for doubtful
accounts. No allowance for doubtful accounts is recognized at
the time the revenue which generates the accounts receivable is
recognized. We estimate the allowance for doubtful accounts
based on existing economic conditions, the financial condition
of our customers, and the amount and age of past due accounts.
Receivables are considered past due if full payment is not
received by the contractual due date. Past due accounts are
generally written off against the allowance for doubtful
accounts only after all collection attempts have been
unsuccessful.
Investments. The voting rights under Discoverys
limited liability company agreement are such that our
40 percent interest combined with the additional interest
held by Williams do not control Discovery. Hence, we account for
our investment in Discovery under the equity method. Prior to
2004, the excess of the carrying value of our investment over
the amount of underlying equity in net assets of Discovery
represented interest capitalized during construction on the
funds advanced to Discovery for construction prior to
Discoverys receipt of external financing. This excess was
being amortized on a straight-line basis over the life of the
related assets. In 2004, we recognized an other-than-temporary
impairment of our investment. As a result, Discoverys
underlying equity exceeds the carrying value of our investment
at December 31, 2005.
Property, Plant and Equipment. Property, plant and
equipment is recorded at cost. We base the carrying value of
these assets on capitalized costs, useful lives and salvage
values. Depreciation of property, plant and equipment is
provided on the straight-line basis over estimated useful lives.
Expenditures for maintenance and repairs are expensed as
incurred. Expenditures that enhance the functionality or extend
the useful lives of the assets are capitalized. The cost of
property, plant and equipment sold or retired and the related
accumulated depreciation is removed from the accounts in the
period of sale or disposition. Gains and losses on the disposal
of property, plant and equipment are recorded in the
Consolidated Statements of Operations.
We record an asset and a liability equal to the present value of
each expected future asset retirement obligation
(ARO). The ARO asset is depreciated in a manner
consistent with the depreciation of the underlying physical
asset. We measure changes in the liability due to passage of
time by applying an interest method of allocation. This amount
is recognized as an increase in the carrying amount of the
liability and as a corresponding accretion expense included in
operating income.
Revenue Recognition. The nature of our businesses result
in various forms of revenue recognition. Our Gathering and
Processing segment recognizes revenue from gathering services
when the services have been performed. Our NGL Services segment
recognizes (1) fractionation revenues when services have
been performed and product has been delivered, (2) storage
revenues under prepaid contracted storage capacity evenly over
the life of the contract as services are provided and
(3) product sales revenue when the product has been
delivered.
Gas purchase contract. In connection with the IPO,
Williams transferred to us a gas purchase contract for the
purchase of a portion of our fuel requirements at the Conway
fractionator at a market price not to exceed a specified level.
The gas purchase contract is for the purchase of
80,000 MMBtu per month and
73
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
terminates on December 31, 2007. The initial value of this
contract is being amortized to expense over the contract life.
Product Imbalances. In the course of providing
fractionation and storage services to our customers, we realize
product gains and losses that are reflected as product imbalance
receivables or payables on the Consolidated Balance Sheets.
These imbalances are valued based on the market price of the
products when the imbalance is identified and are evaluated for
the impact of a change in market prices at the balance sheet
date. Certain of these product gains and losses arise due to the
product blending process at the fractionator. Others are
realized when storage caverns are emptied. Storage caverns are
emptied periodically to determine whether any product gains or
losses have occurred, and as these caverns are emptied, it is
possible that the resulting product gains or losses could have a
material impact to the results of operations for the period
during which the cavern drain is performed.
Impairment of Long-Lived Assets and Investments. We
evaluate our long-lived assets of identifiable business
activities for impairment when events or changes in
circumstances indicate the carrying value of such assets may not
be recoverable. The impairment evaluation of tangible long-lived
assets is measured pursuant to the guidelines of Statement of
Financial Accounting Standards (SFAS) No. 144,
Accounting for the Impairment or Disposal of Long-Lived
Assets. When an indicator of impairment has occurred, we
compare our managements estimate of undiscounted future
cash flows attributable to the assets to the carrying value of
the assets to determine whether the carrying value of the assets
is recoverable. We apply a probability weighted approach to
consider the likelihood of different cash flow assumptions and
possible outcomes. If the carrying value is not recoverable, we
determine the amount of the impairment recognized in the
financial statements by estimating the fair value of the assets
and recording a loss for the amount that the carrying value
exceeds the estimated fair value.
We evaluate our investments for impairment when events or
changes in circumstances indicate, in our managements
judgment, that the carrying value of such investments may have
experienced an other-than-temporary decline in value. When
evidence of loss in value has occurred, we compare our estimate
of fair value of the investment to the carrying value of the
investment to determine whether an impairment has occurred. If
the estimated fair value is less than the carrying value and we
consider the decline in value to be other than temporary, the
excess of the carrying value over the estimated fair value is
recognized in the financial statements as an impairment.
Judgments and assumptions are inherent in our managements
estimate of undiscounted future cash flows used to determine
recoverability of an asset and the estimate of an assets
fair value used to calculate the amount of impairment to
recognize. The use of alternate judgments and/or assumptions
could result in the recognition of different levels of
impairment charges in the financial statements.
Income Taxes. We are not a taxable entity for federal and
state income tax purposes. The tax on our net income is borne by
the individual partners through the allocation of taxable
income. Net income for financial statement purposes may differ
significantly from taxable income of unitholders as a result of
differences between the tax basis and financial reporting basis
of assets and liabilities and the taxable income allocation
requirements under our partnership agreement. The aggregate
difference in the basis of our net assets for financial and tax
reporting purposes cannot be readily determined because
information regarding each partners tax attributes in us
is not available to us.
Environmental. Environmental expenditures that relate to
current or future revenues are expensed or capitalized based
upon the nature of the expenditures. Expenditures that relate to
an existing contamination caused by past operations that do not
contribute to current or future revenue generation are expensed.
Accruals related to environmental matters are generally
determined based on site-specific plans for remediation, taking
into account our prior remediation experience. Environmental
contingencies are recorded independently of any potential claim
for recovery.
74
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Capitalized Interest. We capitalize interest on major
projects during construction to the extent we incur interest
expense. Historically, Williams provided the financing for
capital expenditures; hence, the rates used to calculate the
interest were based on Williams average interest rate on
debt during the applicable period in time.
Earnings Per Unit. In accordance with the Emerging Issues
Task Force (EITF)
Issue 03-6, we use
the two-class method to calculate basic and diluted earnings per
unit whereby net income, adjusted for items specifically
allocated to our general partner, is allocated on a pro-rata
basis between unitholders and our general partner. Basic and
diluted earnings per unit are based on the average number of
common and subordinated units outstanding. Basic and diluted
earnings per unit are equivalent as there are no dilutive
securities outstanding.
Recent Accounting Standards. In December 2004, the
Financial Accounting Standards Board (FASB) issued
revised SFAS No. 123, Share-Based Payment.
The Statement requires that compensation costs for all
share-based awards to employees be recognized in the financial
statements at fair value. The Statement, as issued by the FASB,
was to be effective as of the beginning of the first interim or
annual reporting period that begins after June 15, 2005.
However, in April 2005, the Securities and Exchange Commission
(SEC) adopted a new rule that delayed the effective
date for revised SFAS No. 123 to the beginning of the
next fiscal year that begins after June 15, 2005. We intend
to adopt the revised Statement as of January 1, 2006.
Payroll costs directly charged to us by Williams and general and
administrative costs allocated to us by Williams (see
Note 5) will include such compensation costs beginning
January 1, 2006. Our and Williams adoption of this
Statement will not have a material impact on our Consolidated
Financial Statements.
In November 2004, the FASB issued SFAS No. 151,
Inventory Costs, an amendment of ARB No. 43,
Chapter 4, which will be applied prospectively for
inventory costs incurred in fiscal years beginning after
June 15, 2005. The Statement amends Accounting Research
Bulletin (ARB) No. 43, Chapter 4, Inventory
Pricing, to clarify that abnormal amounts of certain costs
should be recognized as current period charges and that the
allocation of overhead costs should be based on the normal
capacity of the production facility. The impact of this
Statement on our Consolidated Financial Statements will not be
material.
In December 2004, the FASB issued SFAS No. 153,
Exchanges of Nonmonetary Assets, an amendment of APB
Opinion No. 29, which is effective for nonmonetary
asset exchanges occurring in fiscal periods beginning after
June 15, 2005, and will be applied prospectively. The
Statement amends APB Opinion No. 29, Accounting for
Nonmonetary Transactions. The guidance in APB Opinion
No. 29 is based on the principle that exchanges of
nonmonetary assets should be measured based on the fair value of
the assets exchanged but includes certain exceptions to that
principle. SFAS No. 153 amends APB Opinion No. 29
to eliminate the exception for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for
exchanges of nonmonetary assets that do not have commercial
substance. A nonmonetary exchange has commercial substance if
the future cash flows of the entity are expected to change
significantly as a result of the exchange.
In May 2005, the FASB issued SFAS No. 154,
Accounting Changes and Error Corrections a
replacement of APB Opinion No. 20 and FASB Statement
No. 3, which is effective prospectively for reporting
a change in accounting principle for fiscal years beginning
after December 15, 2005. The Statement changes the
reporting of a change in accounting principle to require
retrospective application to prior periods financial
statements, except for explicit transition provisions provided
for in any existing accounting pronouncements, including those
in the transition phase when SFAS No. 154 becomes
effective.
75
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 4. |
Allocation of Net Income and Distributions |
The allocation of net income between our general partner and
limited partners for the period August 23, 2005 through
December 31, 2005 is as follows (in thousands):
|
|
|
|
|
|
|
Allocation of net income to general partner:
|
|
|
|
|
|
Net income for the period August 23, 2005 through
December 31, 2005
|
|
$ |
4,934 |
|
|
Direct charges to general partner:
|
|
|
|
|
|
|
Reimbursable general and administrative costs
|
|
|
1,400 |
|
|
|
|
|
|
Income before direct charges to general partner
|
|
|
6,334 |
|
|
General partners share of net income
|
|
|
2.0 |
% |
|
|
|
|
|
General partners allocated share of net income before
direct charges
|
|
|
127 |
|
|
Direct charges to general partner
|
|
|
(1,400 |
) |
|
|
|
|
Net loss allocated to general partner
|
|
$ |
(1,273 |
) |
|
|
|
|
Net income for the period August 23, 2005 through
December 31, 2005
|
|
$ |
4,934 |
|
Net loss allocated to general partner
|
|
|
(1,273 |
) |
|
|
|
|
Net income allocated to limited partners
|
|
$ |
6,207 |
|
|
|
|
|
The reimbursable general and administrative costs represent the
general and administrative costs charged against our income that
are required to be reimbursed to us by our general partner under
the terms of the Omnibus Agreement.
On November 14, 2005, we paid a cash distribution of
$0.1484 per unit on our outstanding common and subordinated
units to unitholders of record at the close of business on
November 7, 2005. The distribution represents the
$0.35 per unit minimum quarterly distribution pro-rated for
the 39-day period
following the IPO closing date (August 23, 2005 through
September 30, 2005). The total distribution, including
distributions paid to our general partner on its equivalent
units, was $2.1 million.
On February 14, 2006, we paid a cash distribution of
$0.35 per unit on our outstanding common and subordinated
units to unitholders of record on February 7, 2006. The
total distribution, including distributions paid to our general
partner on its equivalent units, was $5.0 million.
|
|
Note 5. |
Related Party Transactions |
The employees of our operated assets and all of our general and
administrative employees are employees of Williams. Williams
directly charges us for the payroll costs associated with the
operations employees and certain general and administrative
employees. Williams carries the obligations for most
employee-related benefits in its financial statements, including
the liabilities related to the employee retirement and medical
plans and paid time off. Certain of these costs are charged back
to the other Conway fractionator co-owners. Our share of those
costs are charged to us through affiliate billings and reflected
in Operating and maintenance expense Affiliate in
the accompanying Consolidated Statements of Operations.
Williams charges its affiliates, including us and its Midstream
segment, of which we are a part, for certain corporate
administrative expenses that are directly identifiable or
allocable to the affiliates. Direct costs charged from Williams
represent the direct costs of services provided by Williams on
our behalf. Prior to the IPO, a portion of the charges allocated
to the Midstream segment were then reallocated to us. These
allocated corporate administrative expenses are based on a
three-factor formula, which considered revenues; property, plant
and equipment; and payroll. Certain of these costs are charged
back to the other Conway fractionator co-owners. Our share of
these costs is reflected in General and administrative
expense Affiliate in the
76
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
accompanying Consolidated Statements of Operations. In
managements estimation, the allocation methodologies used
are reasonable and result in a reasonable allocation to us of
our costs of doing business incurred by Williams. Under the
Omnibus Agreement, Williams gives us a quarterly credit for
general and administrative expenses. These amounts are reflected
as a capital contribution from our general partner. The annual
amounts of the credits are as follows: $3.9 million in 2005
($1.4 million pro-rated for the portion of the year from
August 23 to December 31), $3.2 million in 2006,
$2.4 million in 2007, $1.6 million in 2008 and
$0.8 million in 2009.
At December 31, 2005, we have a contribution receivable
from our general partner of $.3 million, which is netted
against Partners capital on the Consolidated Balance
Sheets, for amounts reimbursable to us under the Omnibus
Agreement.
We purchase fuel for the Conway fractionator, including fuel on
behalf of the co-owners, from Williams Power Company
(Power), a wholly owned subsidiary of Williams.
These purchases are made at market rates at the time of
purchase. In connection with the IPO, Williams transferred to us
a gas purchase contract for the purchase of a portion of our
fuel requirements at the Conway fractionator at a market price
not to exceed a specified level. The amortization of this
contract is reflected in Operating and maintenance
expense Affiliate in the accompanying Consolidated
Statements of Operations. The carrying value of this contract is
reflected as Gas purchase contract affiliate and Gas
purchase contract noncurrent affiliate
on the Consolidated Balance Sheets.
During a portion of 2003, we provided propane storage,
fractionation, transportation and terminalling services to
subsidiaries of Williams that have subsequently been sold. In
December 2004, we began selling surplus propane and other NGLs
to Power, which takes title to the product and resells it, for
its own account, to end users. Revenues associated with these
activities are reflected as Affiliate revenues on the
Consolidated Statements of Operations. Correspondingly, we
purchase ethane and other NGLs from Power to replenish deficit
product positions. The transactions conducted between us and
Power are transacted at current market prices for the products.
A summary of the general and administrative expenses directly
charged and allocated to us, fuel purchases from Power and NGL
purchases from Power for the periods stated is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
General and administrative expenses, including amounts
subsequently charged to co-owners:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated
|
|
$ |
3,494 |
|
|
$ |
2,078 |
|
|
$ |
1,392 |
|
|
Directly charged
|
|
|
992 |
|
|
|
456 |
|
|
|
346 |
|
Operating and maintenance expenses, including amounts
subsequently charged to co-owners:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel purchases, including amortization of gas contract
|
|
|
24,478 |
|
|
|
17,053 |
|
|
|
12,843 |
|
|
Salaries and benefits
|
|
|
3,514 |
|
|
|
3,473 |
|
|
|
2,105 |
|
NGL purchases
|
|
|
15,657 |
|
|
|
1,271 |
|
|
|
|
|
The per-unit gathering fee associated with two of our Carbonate
Trend gathering contracts was negotiated on a bundled basis that
includes transportation along a segment of a pipeline system
owned by Transcontinental Gas Pipe Line Company
(Transco), a wholly owned subsidiary of Williams.
The fees we realize are dependent upon whether our customer
elects to utilize this Transco capacity. When they make this
election, our gathering fee is determined by subtracting the
Transco tariff from the total negotiated fee. The rate
associated with the capacity agreement is based on a Federal
Energy Regulatory Commission tariff that is subject to change.
Accordingly, if the Transco rate increases, our net gathering
fees for these two contracts
77
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
may be reduced. The customers with these bundled contracts must
make an annual election to receive this capacity. For 2005 and
2006, only one of our customers has elected to utilize this
capacity.
We historically participated in Williams cash management
program; thus, we carried no cash balance on our Consolidated
Balance Sheet at December 31, 2004. Effective with the IPO,
we began maintaining our own bank accounts but continue to
utilize Williams personnel to manage our cash and
investments. As of December 31, 2004, our net Advances from
affiliate consisted of an unsecured promissory note agreement
with Williams for both advances to and from Williams. The
advances were due on demand; however, Williams did not
historically require repayment. Therefore, Advances from
affiliate at December 31, 2004 were classified as
noncurrent. Prior to the closing of the IPO, Williams forgave
the advances due to them at the date the net assets were
transferred to us. Accordingly, the advances balance was
transferred to Partners capital at that date.
Affiliate interest expense includes interest on the advances
with Williams calculated using Williams weighted average
cost of debt applied to the outstanding balance of the advances
with Williams and commitment fees on the working capital credit
facility (see Note 11). The interest rate on the advances
with Williams was 7.373 percent at December 31, 2004.
|
|
Note 6. |
Investment in Discovery Producer Services |
Our 40 percent investment in Discovery is accounted for
using the equity method of accounting. At December 31,
2005, Williams owned an additional 20 percent ownership
interest in Discovery through Energy. Although we and Williams
hold a 60 percent interest in Discovery on a combined
basis, the voting provisions of Discoverys limited
liability company agreement give the other member of Discovery
significant participatory rights such that we and Williams do
not control Discovery.
Of the total ownership interest owned by Williams prior to the
transfer of 40 percent to us, a portion was acquired by
Williams in April 2005 resulting in a revised basis used for the
calculation of the 40 percent interest transferred to us in
connection with the IPO. As a result, the carrying value of our
40 percent interest in Discovery and Partners capital
decreased $11.0 million during the second quarter of 2005.
On August 22, 2005, Discovery made a distribution of
approximately $43.8 million to Williams and the other
member of Discovery at that date. This distribution was
associated with Discoverys operations prior to the IPO;
hence, we did not receive any portion of this distribution. The
distribution resulted in a revised basis used for the
calculation of the 40 percent interest transferred to us in
connection with the IPO. As a result, the carrying value of our
40 percent interest in Discovery and Partners capital
decreased $17.5 million during the third quarter of 2005.
In September 2005, we made a $24.4 million capital
contribution to Discovery for a substantial portion of our share
of the estimated future capital expenditures for the Tahiti
pipeline lateral expansion project.
Williams is the operator of Discovery. Discovery reimburses
Williams for actual payroll and employee benefit costs incurred
on its behalf. In addition, Discovery pays Williams a monthly
operations and management fee to cover the cost of accounting
services, computer systems and management services provided to
it. Discovery also has an agreement with Williams pursuant to
which Williams markets the NGLs and excess natural gas to which
Discovery takes title.
During 2004, we performed an impairment review of this
investment because of Williams planned purchase of an
additional interest in Discovery at an amount below its carrying
value. As a result, we recorded a $13.5 million impairment
of our investment in Discovery based on a probability-weighted
estimation of fair value of our investment. In December 2003,
each of the owners made an additional investment in Discovery,
which was subsequently used by Discovery to repay maturing debt.
Our proportionate share of this additional investment was
approximately $101.6 million.
78
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Due to the significance of Discoverys equity earnings to
our results of operations, the summarized financial position and
results of operations for 100 percent of Discovery are
presented below (in thousands).
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
Current assets
|
|
$ |
70,525 |
|
|
$ |
67,534 |
|
Non-current restricted cash
|
|
|
44,559 |
|
|
|
|
|
Property, plant and equipment
|
|
|
344,743 |
|
|
|
356,385 |
|
Current liabilities
|
|
|
(45,070 |
) |
|
|
(31,572 |
) |
Non-current liabilities
|
|
|
(1,121 |
) |
|
|
(702 |
) |
|
|
|
|
|
|
|
Members capital
|
|
$ |
413,636 |
|
|
$ |
391,645 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Revenues
|
|
$ |
122,745 |
|
|
$ |
99,876 |
|
|
$ |
103,178 |
|
Costs and expenses
|
|
|
102,597 |
|
|
|
88,756 |
|
|
|
84,519 |
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
9,611 |
|
Interest income
|
|
|
(1,685 |
) |
|
|
(550 |
) |
|
|
|
|
Foreign exchange loss
|
|
|
1,005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
$ |
20,828 |
|
|
$ |
11,670 |
|
|
$ |
9,048 |
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
20,652 |
|
|
$ |
11,670 |
|
|
$ |
8,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 7. |
Property, Plant and Equipment |
Property, plant and equipment, at cost, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
Estimated |
|
|
| |
|
Depreciable |
|
|
2005 | |
|
2004 | |
|
Lives |
|
|
| |
|
| |
|
|
|
|
(In thousands) | |
|
|
Land and right of way
|
|
$ |
2,373 |
|
|
$ |
2,373 |
|
|
|
Fractionation plant and equipment
|
|
|
16,646 |
|
|
|
16,555 |
|
|
30 years |
Storage plant and equipment
|
|
|
65,892 |
|
|
|
63,632 |
|
|
30 years |
Pipeline plant and equipment
|
|
|
23,684 |
|
|
|
23,684 |
|
|
20-30 years |
Construction work in progress
|
|
|
1,886 |
|
|
|
566 |
|
|
|
Other
|
|
|
1,492 |
|
|
|
1,490 |
|
|
5-45 years |
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
111,973 |
|
|
|
108,300 |
|
|
|
Accumulated depreciation
|
|
|
44,042 |
|
|
|
40,507 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$ |
67,931 |
|
|
$ |
67,793 |
|
|
|
|
|
|
|
|
|
|
|
|
We adopted SFAS No. 143, Accounting for Asset
Retirement Obligations on January 1, 2003. As a
result, we recorded a liability of $993,000 representing the
present value of expected future asset retirement obligations at
January 1, 2003, and a decrease to earnings of $992,000
reflected as a cumulative effect of a change in accounting
principle. An additional $107,000 reduction of earnings is
reflected as a cumulative
79
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
effect of a change in accounting principle for our
40 percent interest in Discoverys cumulative effect
of a change in accounting principle related to the adoption of
SFAS No. 143.
Effective December 31, 2005, we adopted FASB Interpretation
(FIN) No. 47, Accounting for Conditional
Asset Retirement Obligations. This Interpretation
clarifies that an entity is required to recognize a liability
for the fair value of a conditional ARO when incurred if the
liabilitys fair value can be reasonably estimated. The
Interpretation clarifies when an entity would have sufficient
information to reasonably estimate the fair value of an ARO. As
required by the new standard, we reassessed the estimated
remaining life of all our assets with a conditional ARO. We
recorded additional liabilities totaling $573,000 equal to the
present value of expected future asset retirement obligations at
December 31, 2005. The liabilities are slightly offset by a
$16,000 increase in property, plant and equipment, net of
accumulated depreciation, recorded as if the provisions of the
Interpretation had been in effect at the date the obligation was
incurred. The net $557,000 reduction to earnings is reflected as
a cumulative effect of a change in accounting principle for the
year ended 2005. An additional $70,000 reduction of earnings is
reflected as a cumulative effect of a change in accounting
principle for our 40 percent interest in Discoverys
cumulative effect of a change in accounting principle related to
the adoption of FIN No. 47. If the Interpretation had
been in effect at the beginning of 2003, the impact to our
income from continuing operations and net income would have been
immaterial.
The obligations relate to underground storage caverns and the
associated brine ponds. At the end of the useful life of each
respective asset, we are legally obligated to properly abandon
the storage caverns, empty the brine ponds and restore the
surface, and remove any related surface equipment.
A rollforward of our asset retirement obligation for 2005 and
2004 is presented below.
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Balance, January 1
|
|
$ |
760 |
|
|
$ |
801 |
|
Liabilities incurred during the period
|
|
|
91 |
|
|
|
79 |
|
Liabilities settled during the period
|
|
|
(204 |
) |
|
|
(166 |
) |
Accretion expense
|
|
|
1 |
|
|
|
83 |
|
Estimate revisions
|
|
|
(460 |
) |
|
|
|
|
FIN No. 47 revisions
|
|
|
574 |
|
|
|
|
|
Gain on settlements
|
|
|
|
|
|
|
(37 |
) |
|
|
|
|
|
|
|
Balance, December 31
|
|
$ |
762 |
|
|
$ |
760 |
|
|
|
|
|
|
|
|
|
|
Note 8. |
Accrued Liabilities |
Accrued liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Environmental remediation current portion
|
|
$ |
1,424 |
|
|
$ |
1,633 |
|
Customer volume deficiency payment
|
|
|
|
|
|
|
749 |
|
Asset retirement obligation current portion
|
|
|
|
|
|
|
760 |
|
Employee costs affiliate
|
|
|
387 |
|
|
|
317 |
|
Taxes other than income
|
|
|
375 |
|
|
|
359 |
|
Other
|
|
|
187 |
|
|
|
106 |
|
|
|
|
|
|
|
|
|
|
$ |
2,373 |
|
|
$ |
3,924 |
|
|
|
|
|
|
|
|
80
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 9. |
Long-Term Incentive Plan |
In November 2005, our general partner adopted the Williams
Partners GP LLC Long-Term Incentive Plan (the Plan)
for employees, consultants and directors of our general partner
and its affiliates who perform services for us. The Plan permits
the grant of awards covering an aggregate of 700,000 common
units. These awards may be in the form of options, restricted
units, phantom units or unit appreciation rights. The
compensation committee of our general partners board of
directors administers the Plan.
During November and December 2005, our general partner granted
6,146 restricted units pursuant to the Plan to members of our
general partners board of directors who are not officers
or employees of our general partner or its affiliates. These
restricted units vest six months from grant date. We recognized
compensation expense of $34 thousand associated with these
awards in 2005.
|
|
Note 10. |
Major Customers, Concentrations of Credit Risk and Financial
Instruments |
In 2005, four customers, Williams Power Company (an affiliate
company), SemStream, L.P., Enterprise and BP Products North
America, Inc. (BP) accounted for approximately
25.9 percent, 17.1 percent, 14.1 percent and
13.5 percent, respectively, of our total revenues. In 2004,
three customers, SemStream, L.P., BP and Enterprise accounted
for approximately 20.6 percent, 16.1 percent and
16.0 percent, respectively, of our total revenues. In 2003,
four customers, BP, Enterprise, Chevron and Williams Power
Company, accounted for approximately 24.6 percent,
15.9 percent, 14.7 percent and 11.6 percent,
respectively, of our total revenues. SemStream, L.P., BP,
Enterprise and Williams Power Company are customers of the NGL
Services segment. Chevron is a customer of the Gathering and
Processing segment.
Our Carbonate Trend gathering pipeline has only two customers.
The loss of either of these customers, unless replaced, would
have a significant impact on the Gathering and Processing
segment.
|
|
|
Concentrations of credit risk |
Our cash equivalents consist of high-quality securities placed
with various major financial institutions with credit ratings at
or above AA by Standard & Poors or Aa by
Moodys Investors Service.
The following table summarizes the concentration of accounts
receivable by service and segment.
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Gathering and Processing:
|
|
|
|
|
|
|
|
|
|
Natural gas gathering
|
|
$ |
525 |
|
|
$ |
441 |
|
NGL Services:
|
|
|
|
|
|
|
|
|
|
Fractionation services
|
|
|
532 |
|
|
|
468 |
|
|
Amounts due from fractionator partners
|
|
|
1,834 |
|
|
|
1,381 |
|
|
Storage
|
|
|
793 |
|
|
|
1,241 |
|
|
Other
|
|
|
260 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
$ |
3,944 |
|
|
$ |
3,538 |
|
|
|
|
|
|
|
|
Our fractionation and storage customers include crude refiners;
propane wholesalers and retailers; gas producers; natural gas
plant, fractionator and storage operators; and NGL traders and
pipeline operators. Our two Carbonate Trend natural gas
gathering customers are oil and gas producers. While sales to
our customers are unsecured, we routinely evaluate their
financial condition and creditworthiness.
81
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We used the following methods and assumptions to estimate the
fair value of financial instruments.
Cash and cash equivalents. The carrying amounts reported
in the balance sheets approximate fair value due to the
short-term maturity of these instruments.
Advances from affiliates. At December 31, 2004, our
net Advances from affiliate consisted of an unsecured promissory
note agreement with Williams for both advances to and from
Williams. The carrying amounts reported in the Consolidated
Balance Sheet approximate fair value as this instrument had an
interest rate approximating market.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
|
Carrying | |
|
Fair | |
|
Carrying | |
|
Fair | |
|
|
Amount | |
|
Value | |
|
Amount | |
|
Value | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Cash and cash equivalents
|
|
$ |
6,839 |
|
|
$ |
6,839 |
|
|
|
|
|
|
|
|
|
Advances from affiliates
|
|
|
|
|
|
|
|
|
|
$ |
186,024 |
|
|
$ |
186,024 |
|
|
|
Note 11. |
Credit Facilities and Leasing Activities |
On May 20, 2005, Williams amended its $1.275 billion
revolving credit facility (Williams facility), which
is available for borrowings and letters of credit, to allow us
to borrow up to $75 million under the Williams facility.
Borrowings under the Williams facility mature on May 3,
2007. Our $75 million borrowing limit under the Williams
facility is available for general partnership purposes,
including acquisitions, but only to the extent that sufficient
amounts remain unborrowed by Williams and its other
subsidiaries. At December 31, 2005, letters of credit
totaling $378 million had been issued on behalf of Williams
by the participating institutions under the Williams facility
and no revolving credit loans were outstanding.
Interest on any borrowings under the Williams facility is
calculated based on our choice of two methods: (i) a
fluctuating rate equal to the facilitating banks base rate
plus an applicable margin or (ii) a periodic fixed rate
equal to LIBOR plus an applicable margin. We are also required
to pay or reimburse Williams for a commitment fee based on the
unused portion of its $75 million borrowing limit under the
Williams facility, currently 0.325 percent annually. The
applicable margin, currently 1.75 percent, and the
commitment fee are based on Williams senior unsecured
long-term debt rating. Under the Williams facility, Williams and
certain of its subsidiaries, other than us, are required to
comply with certain financial and other covenants. Significant
financial covenants under the Williams facility to which
Williams is subject include the following:
|
|
|
|
|
ratio of debt to net worth no greater than
(i) 70 percent through December 31, 2005, and
(ii) 65 percent for the remaining term of the
agreement; |
|
|
|
ratio of debt to net worth no greater than 55 percent for
Northwest Pipeline Corporation, a wholly-owned subsidiary of
Williams, and Transco; and |
|
|
|
ratio of EBITDA to interest, on a rolling four quarter basis, no
less than (i) 2.0 for any period after March 31, 2005
through December 31, 2005, and (ii) 2.5 for the
remaining term of the agreement. |
In August 2005, we entered into a $20 million revolving
credit facility (the credit facility) with Williams
as the lender. The credit facility is available exclusively to
fund working capital requirements. Borrowings under the credit
facility mature on May 3, 2007 and bear interest at the
same rate as for borrowings under the Williams facility
described above. We pay a commitment fee to Williams on the
unused portion of the credit facility of 0.30 percent
annually. We are required to reduce all borrowings under the
82
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
credit facility to zero for a period of at least 15 consecutive
days once each 12-month
period prior to the maturity date of the credit facility. No
amounts have been drawn on this facility.
We lease automobiles for use in our NGL Services segment. We
account for these leases as operating leases. Future minimum
annual rentals under non-cancelable operating leases as of
December 31, 2005 are as follows (in thousands):
|
|
|
|
|
2006
|
|
$ |
30 |
|
2007
|
|
|
29 |
|
2008
|
|
|
27 |
|
2009
|
|
|
10 |
|
2010
|
|
|
|
|
|
|
|
|
|
|
$ |
96 |
|
|
|
|
|
Total rent expense was $119,000, $110,000 and $116,000 for 2005,
2004 and 2003, respectively.
|
|
Note 12. |
Partners Capital |
Of the 7,006,146 common units outstanding at December 31,
2005, 5,756,146 are held by the public, with the remaining
1,250,000 held by our affiliates. All of the 7,000,000
subordinated units are held by our affiliates.
Upon expiration of the subordination period, each outstanding
subordinated unit will convert into one common unit and will
then participate pro rata with the other common units in
distributions of available cash. The subordination period will
end on the first day of any quarter beginning after
June 30, 2008 or when we meet certain financial tests
provided for in our partnership agreement.
Significant information regarding rights of the limited partners
include the following:
|
|
|
|
|
Right to receive distributions of available cash within
45 days after the end of each quarter. |
|
|
|
No limited partner shall have any management power over our
business and affairs; the general partner shall conduct, direct
and manage our activities. |
|
|
|
The general partner may be removed if such removal is approved
by the unitholders holding at least
662/3 percent
of the outstanding units voting as a single class, including
units held by our general partner and its affiliates. |
|
|
|
Right to receive information reasonably required for tax
reporting purposes within 90 days after the close of the
calendar year. |
Our general partner is entitled to incentive distributions if
the amount we distribute to unitholders with respect to any
quarter exceeds specified target levels shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
General | |
Quarterly Distribution Target Amount (per unit) |
|
Unitholders | |
|
Partner | |
|
|
| |
|
| |
Minimum quarterly distribution of $0.35
|
|
|
98 |
% |
|
|
2 |
% |
Up to $0.4025
|
|
|
98 |
|
|
|
2 |
|
Above $0.4025 up to $0.4375
|
|
|
85 |
|
|
|
15 |
|
Above $0.4375 up to $0.5250
|
|
|
75 |
|
|
|
25 |
|
Above $0.5250
|
|
|
50 |
|
|
|
50 |
|
83
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In the event of a liquidation, all property and cash in excess
of that required to discharge all liabilities will be
distributed to the unitholders and our general partner, in
proportion to their capital account balances, as adjusted to
reflect any gain or loss upon the sale or other disposition of
our assets in liquidation.
|
|
|
Other Comprehensive Income |
The main component of our accumulated other comprehensive loss
is our share of Discoverys accumulated other comprehensive
loss which is related to a cash flow hedge of interest rate risk
held by Discovery in 2003.
|
|
Note 13. |
Commitments and Contingencies |
Environmental Matters. We are a participant in certain
environmental remediation activities associated with soil and
groundwater contamination at our Conway storage facilities.
These activities relate to four projects that are in various
remediation stages including assessment studies, cleanups and/or
remedial operations and monitoring. We continue to coordinate
with the Kansas Department of Health and Environment
(KDHE) to develop screening, sampling, cleanup and
monitoring programs. The costs of such activities will depend
upon the program scope ultimately agreed to by the KDHE and are
expected to be paid over the next two to nine years.
In 2004, we purchased an insurance policy that covers up to
$5 million of remediation costs until an active remediation
system is in place or April 30, 2008, whichever is earlier,
excluding operation and maintenance costs and ongoing monitoring
costs, for these projects to the extent such costs exceed a
$4.2 million deductible. The policy also covers costs
incurred as a result of third party claims associated with then
existing but unknown contamination related to the storage
facilities. The aggregate limit under the policy for all claims
is $25 million. In addition, under an omnibus agreement
with Williams entered into at the closing of the IPO, Williams
has agreed to indemnify us for the $4.2 million deductible
(less amounts expended prior to the closing of the IPO) of
remediation expenditures not covered by the insurance policy,
excluding costs of project management and soil and groundwater
monitoring. There is a $14 million cap on the total amount
of indemnity coverage under the omnibus agreement, which will be
reduced by actual recoveries under the environmental insurance
policy. There is also a three-year time limitation from the IPO
closing date, August 23, 2005. The benefit of this
indemnification will be accounted for as a capital contribution
to us by Williams as the costs are reimbursed. We estimate that
the approximate cost of this project management and soil and
groundwater monitoring associated with the four remediation
projects at the Conway storage facilities and for which we will
not be indemnified will be approximately $200,000 to
$400,000 per year following the completion of the
remediation work.
At December 31, 2005, we had accrued liabilities totaling
$5.4 million for these costs. It is reasonably possible
that we will incur losses in excess of our accrual for these
matters. However, a reasonable estimate of such amounts cannot
be determined at this time because actual costs incurred will
depend on the actual number of contaminated sites identified,
the amount and extent of contamination discovered, the final
cleanup standards mandated by KDHE and other governmental
authorities and other factors.
Other. We are not currently a party to any legal
proceedings but are a party to various administrative and
regulatory proceedings that have arisen in the ordinary course
of our business. Management, including internal counsel,
currently believes that the ultimate resolution of the foregoing
matters, taken as a whole, and after consideration of amounts
accrued, insurance coverage or other indemnification
arrangements, will not have a material adverse effect upon our
future financial position.
84
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 14. |
Segment Disclosures |
Our reportable segments are strategic business units that offer
different products and services. The segments are managed
separately because each segment requires different industry
knowledge, technology and marketing strategies. The accounting
policies of the segments are the same as those described in
Note 3, Summary of Significant Accounting Policies.
Long-lived assets are comprised of property, plant and equipment.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & | |
|
NGL | |
|
|
|
|
Processing | |
|
Services | |
|
Total | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues
|
|
$ |
3,515 |
|
|
$ |
48,254 |
|
|
$ |
51,769 |
|
Operating and maintenance expense
|
|
|
714 |
|
|
|
24,397 |
|
|
|
25,111 |
|
Product cost
|
|
|
|
|
|
|
11,821 |
|
|
|
11,821 |
|
Depreciation and accretion
|
|
|
1,200 |
|
|
|
2,419 |
|
|
|
3,619 |
|
Direct general and administrative expenses
|
|
|
2 |
|
|
|
1,068 |
|
|
|
1,070 |
|
Other, net
|
|
|
|
|
|
|
694 |
|
|
|
694 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
1,599 |
|
|
|
7,855 |
|
|
|
9,454 |
|
Equity earnings
|
|
|
8,331 |
|
|
|
|
|
|
|
8,331 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$ |
9,930 |
|
|
$ |
7,855 |
|
|
$ |
17,785 |
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
$ |
9,454 |
|
|
General and administrative expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate
|
|
|
|
|
|
|
|
|
|
|
(3,194 |
) |
|
|
Third-party direct
|
|
|
|
|
|
|
|
|
|
|
(1,059 |
) |
|
|
|
|
|
|
|
|
|
|
|
Combined operating income
|
|
|
|
|
|
|
|
|
|
$ |
5,201 |
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets
|
|
$ |
171,009 |
|
|
$ |
64,579 |
|
|
$ |
235,588 |
|
Other assets and eliminations
|
|
|
|
|
|
|
|
|
|
|
5,353 |
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
|
|
|
|
|
|
|
$ |
240,941 |
|
|
|
|
|
|
|
|
|
|
|
Equity method investments
|
|
$ |
150,260 |
|
|
$ |
|
|
|
$ |
150,260 |
|
Additions to long-lived assets
|
|
|
|
|
|
|
3,688 |
|
|
|
3,688 |
|
85
WILLIAMS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & | |
|
NGL | |
|
|
|
|
Processing | |
|
Services | |
|
Total | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues
|
|
$ |
4,833 |
|
|
$ |
36,143 |
|
|
$ |
40,976 |
|
Operating and maintenance expense
|
|
|
572 |
|
|
|
18,804 |
|
|
|
19,376 |
|
Product cost
|
|
|
|
|
|
|
6,635 |
|
|
|
6,635 |
|
Depreciation and accretion
|
|
|
1,200 |
|
|
|
2,486 |
|
|
|
3,686 |
|
Direct general and administrative expenses
|
|
|
|
|
|
|
535 |
|
|
|
535 |
|
Other, net
|
|
|
|
|
|
|
625 |
|
|
|
625 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
3,061 |
|
|
|
7,058 |
|
|
|
10,119 |
|
Equity earnings
|
|
|
4,495 |
|
|
|
|
|
|
|
4,495 |
|
Impairment of investment
|
|
|
(13,484 |
) |
|
|
|
|
|
|
(13,484 |
) |
|
|
|
|
|
|
|
|
|
|
Segment profit (loss)
|
|
$ |
(5,928 |
) |
|
$ |
7,058 |
|
|
$ |
1,130 |
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
$ |
10,119 |
|
|
Allocated general and administrative expenses
|
|
|
|
|
|
|
|
|
|
|
(2,078 |
) |
|
|
|
|
|
|
|
|
|
|
|
Combined operating income
|
|
|
|
|
|
|
|
|
|
$ |
8,041 |
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
166,985 |
|
|
$ |
52,376 |
|
|
$ |
219,361 |
|
Equity method investments
|
|
|
147,281 |
|
|
|
|
|
|
|
147,281 |
|
Additions to long-lived assets
|
|
|
|
|
|
|
1,622 |
|
|
|
1,622 |
|
2003
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues
|
|
$ |
5,513 |
|
|
$ |
22,781 |
|
|
$ |
28,294 |
|
Operating and maintenance expense
|
|
|
379 |
|
|
|
13,581 |
|
|
|
13,960 |
|
Product cost
|
|
|
|
|
|
|
1,263 |
|
|
|
1,263 |
|
Depreciation and accretion
|
|
|
1,200 |
|
|
|
2,507 |
|
|
|
3,707 |
|
Direct general and administrative expenses
|
|
|
|
|
|
|
421 |
|
|
|
421 |
|
Other, net
|
|
|
|
|
|
|
507 |
|
|
|
507 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
3,934 |
|
|
|
4,502 |
|
|
|
8,436 |
|
Equity earnings
|
|
|
3,447 |
|
|
|
|
|
|
|
3,447 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit
|
|
$ |
7,381 |
|
|
$ |
4,502 |
|
|
$ |
11,883 |
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Statement of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income
|
|
|
|
|
|
|
|
|
|
$ |
8,436 |
|
|
Allocated general and administrative expenses
|
|
|
|
|
|
|
|
|
|
|
(1,392 |
) |
|
|
|
|
|
|
|
|
|
|
|
Combined operating income
|
|
|
|
|
|
|
|
|
|
$ |
7,044 |
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
177,769 |
|
|
$ |
52,381 |
|
|
$ |
230,150 |
|
Equity method investments
|
|
|
156,269 |
|
|
|
|
|
|
|
156,269 |
|
Additions to long-lived assets
|
|
|
|
|
|
|
1,176 |
|
|
|
1,176 |
|
86
WILLIAMS PARTNERS L.P.
QUARTERLY FINANCIAL DATA
(Unaudited)
Summarized quarterly financial data are as follows (thousands,
except per-unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First | |
|
Second | |
|
Third | |
|
Fourth | |
|
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
|
| |
|
| |
|
| |
|
| |
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
11,369 |
|
|
$ |
12,176 |
|
|
$ |
12,176 |
|
|
$ |
16,048 |
|
Costs and operating expenses
|
|
|
10,266 |
|
|
|
8,036 |
|
|
|
13,175 |
|
|
|
15,091 |
|
Income (loss) before cumulative effect of change in accounting
principle
|
|
|
311 |
|
|
|
1,849 |
|
|
|
(2,871 |
) |
|
|
6,170 |
|
Net income (loss)
|
|
|
311 |
|
|
|
1,849 |
|
|
|
(2,871 |
) |
|
|
5,542 |
|
Basic and diluted net income (loss) per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
NA |
|
|
|
NA |
|
|
$ |
(0.02 |
) |
|
$ |
0.51 |
|
|
|
Subordinated units
|
|
|
NA |
|
|
|
NA |
|
|
$ |
(0.02 |
) |
|
$ |
0.51 |
|
|
Cumulative effect of change in accounting principle:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
NA |
|
|
|
NA |
|
|
$ |
|
|
|
$ |
(0.05 |
) |
|
|
Subordinated units
|
|
|
NA |
|
|
|
NA |
|
|
$ |
|
|
|
$ |
(0.05 |
) |
|
Net income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units
|
|
|
NA |
|
|
|
NA |
|
|
$ |
(0.02 |
) |
|
$ |
0.46 |
|
|
|
Subordinated units
|
|
|
NA |
|
|
|
NA |
|
|
$ |
(0.02 |
) |
|
$ |
0.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First | |
|
Second | |
|
Third | |
|
Fourth | |
|
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
|
| |
|
| |
|
| |
|
| |
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
7,953 |
|
|
$ |
9,043 |
|
|
$ |
10,457 |
|
|
$ |
13,523 |
|
Costs and operating expenses
|
|
|
5,256 |
|
|
|
8,289 |
|
|
|
8,956 |
|
|
|
10,434 |
|
Income (loss) before cumulative effect of change in accounting
principle
|
|
|
1,569 |
|
|
|
(1,125 |
) |
|
|
(1,684 |
) |
|
|
(12,184 |
) |
Net income (loss)
|
|
|
1,569 |
|
|
|
(1,125 |
) |
|
|
(1,684 |
) |
|
|
(12,184 |
) |
|
|
|
|
|
Net income for fourth-quarter 2005 includes our 40 percent
share of Discoverys favorable adjustment of
$10.7 million related to amounts previously deferred for
net system gains from 2002 through 2004 that were reversed
following the acceptance in 2005 of a filing with the FERC. |
|
|
|
Net loss for third-quarter 2005 includes a $3.4 million
unfavorable product imbalance adjustments included in NGL
services. |
|
|
|
Net loss for fourth-quarter 2004 includes a $13.5 million
impairment of our investment in Discovery Producer Services (see
Note 6). |
87
|
|
Item 9. |
Changes In and Disagreements With Accountants on
Accounting and Financial Disclosure |
None.
|
|
Item 9A. |
Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation
of our disclosure controls and procedures (as defined in
Rules 13a-15(e)
and 15(d) (e) of the Securities Exchange Act)
(Disclosure Controls) was performed as of the end of
the period covered by this report. This evaluation was performed
under the supervision and with the participation of our general
partners management, including our general partners
chief executive officer and chief financial officer. Based upon
that evaluation, our general partners chief executive
officer and chief financial officer concluded that these
Disclosure Controls are effective at a reasonable assurance
level.
Our management, including our general partners chief
executive officer and chief financial officer, does not expect
that our Disclosure Controls or our internal controls over
financial reporting (Internal Controls) will prevent
all errors and all fraud. A control system, no matter how well
conceived and operated, can provide only reasonable, not
absolute, assurance that the objectives of the control system
are met. Further, the design of a control system must reflect
the fact that there are resource constraints, and the benefits
of controls must be considered relative to their costs. Because
of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all
control issues and instances of fraud, if any, within the
company have been detected. These inherent limitations include
the realities that judgments in decision-making can be faulty,
and that breakdowns can occur because of simple error or
mistake. Additionally, controls can be circumvented by the
individual acts of some persons, by collusion of two or more
people, or by management override of the control. The design of
any system of controls also is based in part upon certain
assumptions about the likelihood of future events, and there can
be no assurance that any design will succeed in achieving its
stated goals under all potential future conditions. Because of
the inherent limitations in a cost-effective control system,
misstatements due to error or fraud may occur and not be
detected. We monitor our Disclosure Controls and Internal
Controls and make modifications as necessary; our intent in this
regard is that the Disclosure Controls and the Internal Controls
will be modified as systems change and conditions warrant.
Management concludes that its current controls are effective at
a reasonable assurance level. In addition, there has been no
material change in our Internal Controls that occurred during
the registrants fourth fiscal quarter.
Item 9B. Other
Information
There have been no events that occurred in the fourth quarter of
2005 that would need to be reported on
Form 8-K that have
not been previously reported.
PART III
|
|
Item 10. |
Directors and Executive Officers of the Registrant |
Our general partner manages our operations and activities. Our
general partner is not elected by our unitholders and is not
subject to re-election on a regular basis in the future.
Unitholders are not entitled to elect the directors of our
general partner or directly or indirectly participate in our
management or operation.
We are managed and operated by the directors and officers of our
general partner. All of our operational personnel are employees
of an affiliate of our general partner.
All of the senior officers of our general partner are also
senior officers of Williams and spend a sufficient amount of
time overseeing the management, operations, corporate
development and future acquisition initiatives of our business.
Alan Armstrong, the chief operating officer of our general
partner, is the principal
88
executive responsible for the oversight of our affairs. Our
non-executive directors will devote as much time as is necessary
to prepare for and attend board of directors and committee
meetings.
The following table shows information for the directors and
executive officers of our general partner as of
February 28, 2006.
|
|
|
|
|
|
|
Name |
|
Age | |
|
Position with Williams Partners GP LLC |
|
|
| |
|
|
Steven J. Malcolm
|
|
|
57 |
|
|
Chairman of the Board and Chief Executive Officer |
Donald R. Chappel
|
|
|
54 |
|
|
Chief Financial Officer and Director |
Alan S. Armstrong
|
|
|
43 |
|
|
Chief Operating Officer and Director |
James J. Bender
|
|
|
48 |
|
|
General Counsel |
Thomas C. Knudson
|
|
|
59 |
|
|
Director and Member of Audit, Conflicts and Compensation
Committees |
Bill Z. Parker
|
|
|
58 |
|
|
Director and Member of Audit, Conflicts and Compensation
Committees |
Alice M. Peterson
|
|
|
53 |
|
|
Director and Member of Audit, Conflicts and Compensation
Committees |
Phillip D. Wright
|
|
|
50 |
|
|
Director |
The directors of our general partner are elected for one-year
terms and hold office until the earlier of their death,
resignation, removal or disqualification or until their
successors have been elected and qualified. Officers serve at
the discretion of the board of directors of our general partner.
There are no family relationships among any of the directors or
executive officers of our general partner. All of our
operational personnel are employees of an affiliate of our
general partner.
Steven J. Malcolm has served as the chairman of the board
of directors and chief executive officer of our general partner
since February 2005. Mr. Malcolm has served as president of
Williams since September 2001, chief executive of Williams since
January 2002 and chairman of the board of directors of Williams
since May 2002. Mr. Malcolm has served as a member of the
board of directors of the BOK Financial Corporation since 2002.
From May 2001 to September 2001, he served as executive vice
president of Williams. From December 1998 to May 2001, he served
as president and chief executive officer of Williams Energy
Services, LLC. From November 1994 to December 1998,
Mr. Malcolm served as the senior vice president and general
manager of Williams Field Services Company. Mr. Malcolm
served as chief executive officer and chairman of the board of
directors of the general partner of Williams Energy Partners
L.P. from the initial public offering in February 2001 of
Williams Energy Partners L.P. (now known as Magellan Midstream
Partners, L.P.) to the sale of Williams interests therein
in June 2003. Mr. Malcolm has been named as a defendant in
numerous shareholder class action suits that have been filed
against Williams. These class actions include issues related to
the spin-off of WilTel Communications, a previously-owned
subsidiary of Williams, Williams Power Company, and public
offerings in January 2001, August 2001 and January 2002, known
as the FELINE PACS offering. Additionally, four class action
complaints were filed under the Employee Retirement Income
Security Act of 1974 (ERISA) against Williams,
certain committee members and certain members of Williams
board of directors, including Mr. Malcolm, by participants
in Williams Investment Plus Plan. Final court approval of
the ERISA litigation and dismissal with prejudice occurred in
November 2005.
Donald R. Chappel has served as the chief financial
officer and a director of our general partner since February
2005. Mr. Chappel has served as senior vice president and
chief financial officer of Williams since April 2003. Prior to
joining Williams, Mr. Chappel, from 2000 to April 2003,
founded and served as chief executive officer of a development
business in Chicago, Illinois. From 1987 though February 2000,
Mr. Chappel served in various financial, administrative and
operational leadership positions for Waste Management, Inc.,
including twice serving as chief financial officer, during 1997
and 1998 and most recently during 1999 through February 2000.
Alan S. Armstrong has served as the chief operating
officer and a director of our general partner since February
2005. Mr. Armstrong has served as a senior vice president
of Williams since February 2002
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responsible for heading Williams midstream business unit.
From 1999 to February 2002, Mr. Armstrong was vice
president, gathering and processing in Williams midstream
business unit and from 1998 to 1999 was vice president,
commercial development in Williams midstream business
unit. From 1997 to 1998, Mr. Armstrong was vice president
of retail energy in Williams energy services business
unit. Prior to this, Mr. Armstrong served in various
operations, engineering and commercial leadership roles within
Williams.
James J. Bender has served as the general counsel of our
general partner since February 2005. Mr. Bender has served
as senior vice president and general counsel of Williams since
December 2002. From June 2000 until joining Williams,
Mr. Bender was senior vice president and general counsel
with NRG Energy, Inc. Mr. Bender was vice president,
general counsel and secretary of NRG Energy from June 1997 to
June 2000. NRG Energy filed a voluntary bankruptcy petition
during 2003 and its plan of reorganization was approved in
December 2003.
Thomas C. Knudson has served as a director of our general
partner since November 2005. Mr. Knudson has served as a
member of the board of directors of Bristow Group Inc. (formerly
Offshore Logistics, Inc.), a leading provider of helicopter
transportation services to the oil and gas industry, since
January 2004. Mr. Knudson has also served as a director of
NATCO Group Inc., a leading provider of wellhead process
equipment, systems and services used in the production of oil
and gas, since April 2005. From 2000 to 2003, he was a senior
vice president of ConocoPhillips.
Bill Z. Parker has served as a director of our general
partner since August 2005. Mr. Parker has served as a
director for Latigo Petroleum, Inc., a privately-held
independent oil and gas production company, since January 2003.
From April 2000 to November 2002, he served as executive vice
president of Phillips Petroleum Companys worldwide
upstream operations. Mr. Parker was executive vice
president of Phillips Petroleum Companys worldwide
downstream operations from September 1999 to April 2000.
Alice M. Peterson has served as a director of our general
partner since September 2005. Ms. Peterson is the president
of Syrus Global, a provider of ethics, compliance and reputation
management solutions. Ms. Peterson has served as a director
for RIM Finance, LLC, a wholly owned subsidiary of Research In
Motion, Ltd., the maker of the
BlackBerrytm
handheld device, since 2000. Ms. Peterson served as a
director of TBC Corporation, a marketer of private branded
replacement tires, from July 2005 to November 2005, when it was
acquired by Sumitomo Corporation of America. From 1998 to August
2004, she served as a director of Fleming Companies. From
December 2000 to December 2001, she served as president and
general manager of RIM Finance, LLC. From April 2000 to
September 2000, Ms. Peterson served as the chief executive
officer of Guidance Resources.com, a
start-up business
focused on providing online behavioral health and concierge
services to employer groups and other associations. From 1998 to
2000, she served as vice president of Sears Online and from 1993
to 1998, as vice president and treasurer of Sears, Roebuck and
Co. Following the bankruptcy of Fleming Companies in 2003,
Ms. Peterson was named as a defendant, along with each
other member of the companys board of directors, in a
securities class action. The case was settled and all claims
against Ms. Peterson were released and dismissed after the
courts approval of the settlement which became a final
judgment in December 2005. Ms. Peterson has also been named
as a defendant, along each other member of the board of
directors of Fleming Companies, in connection with a claim by
trade creditors of Dunigan Fuels (a subsidiary of the former
Fleming Companies) for conspiracy to breach fiduciary
duties.
Phillip D. Wright has served as a director of our general
partner since February 2005. Mr. Wright has served as
senior vice president of Williams gas pipeline operations
since January 2005. From October 2002 to January 2005,
Mr. Wright served as chief restructuring officer of
Williams. From September 2001 to October 2002, Mr. Wright
served as president and chief executive officer of Williams
Energy Services. From 1996 to September 2001, he was senior vice
president, enterprise development and planning for
Williams energy services group. From 1989 to 1996,
Mr. Wright served in various capacities for Williams.
Mr. Wright served as president, chief operating officer and
director of the general partner of Williams Energy Partners L.P.
from the initial public offering in February 2001 of Williams
Energy Partners L.P. (now known as Magellan Midstream Partners,
L.P.) to the sale of Williams interests therein in June
2003. Mr. Wright has been named as a defendant in four
class action complaints filed under ERISA against Williams,
certain members of the benefits and investment committees and
certain members of the Williams board of directors, by
participants
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in Williams Investment Plus Plan. Final court approval of
the ERISA litigation and dismissal with prejudice occurred in
November 2005.
Governance Matters
In August 2005 our general partner adopted governance
guidelines. The governance guidelines address, among other
areas, director independence standards, policies on meeting
attendance and preparation, executive sessions of non-management
directors and communications with non-management directors.
Because we are a limited partnership, our general partners
board of directors is not required to be composed of a majority
of directors who meet the criteria for independence required by
the New York Stock Exchange and is not required to maintain
nominating/corporate governance and compensation committees
composed entirely of independent directors.
Our general partners board of directors annually reviews
the independence of directors and affirmatively makes a
determination that each director expected to be independent has
no material relationship with our general partner (either
directly or indirectly or as a partner, shareholder or officer
of an organization that has a relationship with our general
partner). In order to make this determination, our general
partners board of directors broadly considers all relevant
facts and circumstances and applies categorical standards from
our governance guidelines. Under those categorical standards, a
director will not be considered to be independent if:
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the director, or an immediate family member of the director, has
received during any twelve-month period within the last three
years more than $100,000 per year in direct compensation
from our general partner, us, and any parent or subsidiary in a
consolidated group with such entities (collectively, the
Partnership Group), other than board and committee
fees and pension or other forms of deferred compensation for
prior service (provided such compensation is not contingent in
any way on continued service). Neither compensation received by
a director for former service as an interim chairman or chief
executive officer or other executive officer nor compensation
received by an immediate family member for service as an
employee of the Partnership Group will be considered in
determining independence under this standard. |
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the director is a current employee, or has an immediate family
member who is a current executive officer, of another company
that has made payments to, or received payments from, the
Partnership Group for property or services in an amount which,
in any of the last three fiscal years, exceeds the greater of
$1 million, or two percent of the other companys
consolidated gross annual revenues. Contributions to tax exempt
organizations are not considered payments for
purposes of this standard. |
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the director is, or has been within the last three years, an
employee of the Partnership Group, or an immediate family member
is, or has been within the last three years, an executive
officer, of the Partnership Group. Employment as an interim
chairman or chief executive officer or other executive officer
will not disqualify a director from being considered independent
following that employment. |
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(i) the director or an immediate family member is a current
partner of a present or former internal or external auditor for
the Partnership Group, (ii) the director is a current
employee of such a firm, (iii) the director has an
immediate family member who is a current employee of such a firm
and participates in such firms audit, assurance or tax
compliance (but not tax planning) practice or (iv) the
director or an immediately family member was within the last
three years (but is no longer) a partner or employee of such a
firm and personally worked on an audit for the Partnership Group
within that time. |
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if the director or an immediate family member is, or has been
within the last three years, employed as an executive officer of
another company where any of the Partnership Groups
present executive officers at the same time serves or served on
that companys compensation committee. |
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if the board of directors determines that a discretionary
contribution made by any member of the Partnership Group to a
non-profit organization with which a director, or a
directors spouse, has a relationship, impacts the
directors independence. |
Our general partners board of directors has affirmatively
determined that each of Ms. Peterson and
Messrs. Knudson and Parker is an independent
director under the current listing standards of the New
York Stock Exchange and our categorical director independence
standards. In doing so, the board of directors determined that
each of these individuals met the bright line
independence standards of the New York Stock Exchange. In
addition, the board of directors considered relationships with
our general partner, either directly or indirectly. The purpose
of this review was to determine whether any such relationships
or transactions were inconsistent with a determination that the
director is independent. The board of directors considered the
fact that Mr. Knudson serves as a director for NATCO Group
Inc., which provides goods or services for affiliates of
Williams. The board of directors also considered the fact that
Ms. Peterson is a director of an affiliate of Research in
Motion Corp. and was a director of TBC Corporation, which
provides goods or services to affiliates of Williams. The board
of directors noted that, since Ms. Peterson and
Mr. Knudson do not serve as an executive officer and are
not a significant stockholder of these companies, these
relationships are not material and affirmatively determined that
all of the directors mentioned above are independent.
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Meeting Attendance and Preparation |
Members of the board of directors are expected to attend at
least 75 percent of regular board meetings and meetings of
the committees on which they serve, either in person or
telephonically. In addition, directors are expected to be
prepared for each meeting of the board by reviewing written
materials distributed in advance.
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Executive Sessions of Non-Management Directors |
The general partners non-management board members periodically
meet outside the presence of our general partners
executive officers. The chairman of the audit committee serves
as the presiding director for executive sessions of
non-management board members. The current chairman of the audit
committee and the presiding director is Mr. Bill Z. Parker.
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Communications with Directors |
Interested parties wishing to communicate with the our
non-management directors may contact our general partners
corporate secretary or the presiding director. The contact
information is published on the investor relations page of our
website at http://www.williamslp.com.
The current contact information is as follows:
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Williams Partners L.P. |
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One Williams Center, Suite 4700 |
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Tulsa, Oklahoma 74172 |
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Attn: Corporate Secretary |
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Williams Partners L.P. |
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One Williams Center, Suite 4700 |
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Tulsa, Oklahoma 74172 |
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Attn: Presiding Director |
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Email: brian.shore@williams.com |
Board Committees
The board of directors of our general partner has a
separately-designated standing audit committee established in
accordance with section 3(a)(58)(A) of the Securities
Exchange Act of 1934, a conflicts
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committee and a compensation committee. The following is a
description of each of the committees and committee membership
as of February 28, 2006.
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Board Committee Membership |
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Audit | |
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Compensation | |
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Committee | |
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Committee | |
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Thomas C. Knudson
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Bill Z. Parker
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Alice M. Peterson
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ü = committee member
Our general partners board of directors has determined
that all members of the audit committee meet the heightened
independence requirements of the New York Stock Exchange for
audit committee members and that all members are financially
literate as defined by the rules of the New York Stock Exchange.
The board of directors has further determined that
Ms. Alice M. Peterson is an audit committee financial
expert as defined by the rules of the SEC.
Ms. Petersons biographical information is set forth
above under the caption Directors and Executive Officers
of the Registrant. The audit committee is governed by a
written charter adopted by the board of directors. For further
information about the audit committee, please read the
Report of the Audit Committee below and Principal
Accountant Fees and Services.
Our general partners board of directors has established a
compensation committee to administer the Williams Partners GP
LLC Long-Term Incentive Plan for employees, consultants and
directors of our general partner and employees and consultants
of its affiliates who perform services for our general partner
and its affiliates. The long-term incentive plan consists of
four components: restricted units, phantom units, unit options
and unit appreciation rights. The plan permits the grant of
awards covering an aggregate of 700,000 units. To date, the
only grants made pursuant to the plan are restricted units
related to director compensation. For more information about the
long-term incentive plan, please read Compensation of
Directors and Long-Term Incentive Plan under
Executive Compensation and Securities Authorized Under
Equity Compensation Plans under Security Ownership of
Certain Beneficial Owners and Management and Related Stockholder
Matters. The compensation committee is governed by a written
charter adopted by the board of directors.
The conflicts committee of our general partners board of
directors reviews specific matters that the board believes may
involve conflicts of interest. The conflicts committee
determines if resolution of the conflict is fair and reasonable
to us. The members of the conflicts committee may not be
officers or employees of our general partner or directors,
officers or employees of its affiliates, and must meet the
independence and experience requirements established by the New
York Stock Exchange and the Sarbanes-Oxley Act of 2002 and other
federal securities laws. Any matters approved by the conflicts
committee will be conclusively deemed fair and reasonable to us,
approved by all of our partners and not a breach by our general
partner of any duties it may owe to us or our unitholders.
Internet Access to Governance Documents
Our general partners code of business conduct and ethics,
governance guidelines and the charters for the audit and
compensation committees are available on our Internet website at
http://www.williamslp.com under the Investor
Relations caption. We will provide, free of charge, a copy
of our code of business conduct and
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ethics or any of our other governance documents listed above
upon written request to our general partners secretary at
Williams Partners L.P., One Williams Center, Suite 4700,
Tulsa, Oklahoma 74172.
Section 16(a) Beneficial Ownership Reporting
Compliance
Section 16(a) of the Securities Exchange Act of 1934
requires our general partners officers and directors, and
persons who own more than 10 percent of a registered class
of our equity securities to file with the SEC and the New York
Stock Exchange reports of ownership of Company securities and
changes in reported ownership. Officers and directors of our
general partner and greater than 10 percent common
unitholders are required to by SEC rules to furnish to us copies
of all Section 16(a) reports that they file. Based solely
on a review of reports furnished to our general partner, or
written representations from reporting persons that all
reportable transactions were reported, we believe that during
the fiscal year ended December 31, 2005 our general
partners officers, directors and greater than
10 percent common unitholders filed all reports they were
required to file under Section 16(a).
Code of Business Conduct and Ethics
Our general partner has adopted a code of business conduct and
ethics for directors, officers and employees. We intend to
disclose any amendments to or waivers of the code of business
conduct and ethics on behalf of our general partners chief
executive officer, chief financial officer, controller and
persons performing similar functions on our Internet website at
http://www.williamslp.com under the Investor
Relations caption, promptly following the date of any such
amendment or waiver.
REPORT OF THE AUDIT COMMITTEE
The audit committee oversees our financial reporting process on
behalf of the board of directors. Management has the primary
responsibility for the financial statements and the reporting
process including the systems of internal controls. The audit
committee operates under a written charter approved by the
board. The charter, among other things, provides that the audit
committee has full authority to appoint, retain and oversee the
independent auditor. In this context, the audit committee:
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reviewed and discussed the audited financial statements in this
annual report on
Form 10-K with
management, including a discussion of the quality, not just the
acceptability, of the accounting principles, the reasonableness
of significant judgments and the clarity of disclosures in the
financial statements; |
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reviewed with Ernst & Young LLP, the independent
auditors, who are responsible for expressing an opinion on the
conformity of those audited financial statements with generally
accepted accounting principles, their judgments as to the
quality and acceptability of Williams Partners L.P.s
accounting principles and such other matters as are required to
be discussed with the audit committee under generally accepted
auditing standards; |
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received the written disclosures and the letter required by
standard No. 1 of the independence standards board
(independence discussions with audit committees) provided to the
audit committee by Ernst & Young LLP; |
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discussed with Ernst & Young LLP its independence from
management and Williams Partners L.P. and considered the
compatibility of the provision of nonaudit services by the
independent auditors with the auditors independence; |
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discussed with Ernst & Young LLP the matters required
to be discussed by statement on auditing standards No. 61
(communications with audit committees); |
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discussed with Williams Partners L.P.s internal auditors
and Ernst & Young LLP the overall scope and plans for
their respective audits. The audit committee meets with the
internal auditors and Ernst & Young LLP, with and
without management present, to discuss the results of their
examinations, their |
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evaluations of Williams Partners L.P.s internal controls
and the overall quality of Williams Partners L.P.s
financial reporting; |
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based on the foregoing reviews and discussions, recommended to
the board of directors that the audited financial statements be
included in the annual report on
Form 10-K for the
year ended December 31, 2005, for filing with the
SEC; and |
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approved the selection and appointment of Ernst & Young
LLP to serve as Williams Partners L.P.s independent
auditors for 2006. |
This report has been furnished by the members of the audit
committee of the board of directors:
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Bill Z. Parker chairman |
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Alice M. Peterson |
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Thomas C. Knudson |
February 24, 2006
The report of the audit committee in this report shall not be
deemed incorporated by reference into any other filing by
Williams Partners L.P. under the Securities Act of 1933, as
amended, or the Securities Exchange Act of 1934, except to the
extent that we specifically incorporate this information by
reference, and shall not otherwise be deemed filed under such
acts.
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Item 11. |
Executive Compensation |
We and our general partner were formed in February 2005. We have
no employees. We are managed by the officers of our general
partner. We reimburse Williams for direct and indirect general
and administrative expenses incurred on our behalf. For the
fiscal year ended December 31, 2005, Williams allocated
approximately $22,341 of salary and bonus expense to us (and our
predecessor for the portion of the year prior to our formation)
for Steven J. Malcolm, the chairman of the board and chief
executive officer of our general partner, and approximately
$27,659 for all other expenses related to his compensation. For
the fiscal year ended December 31, 2004, Williams allocated
approximately $19,846 of salary and bonus expense to our
predecessor for Mr. Malcolm and approximately $14,873 for
all other expenses related to his compensation. Allocated
expenses related to Mr. Malcolms compensation other
than salary and bonus included Williams deferred stock awards,
matching contributions made under a Williams 401(k) plan, and
premiums for life insurance. We also allocated a portion of
Williams expenses related to perquisites which did not
exceed $50,000 or 10 percent of Mr. Malcolms
salary and bonus from Williams. The foregoing amounts exclude
expenses allocated by Williams to Discovery. Total compensation
received by Mr. Malcolm, who is also the chairman,
president and chief executive officer of Williams, will be set
forth in the proxy statement for Williams 2006 annual
meeting of shareholders which will be available upon its filing
on the SECs website at http://www.sec.gov and on
Williams website at http://www.williams.com under
the heading Investors SEC Filings. No
other executive officer of our general partner received salary
and bonus compensation allocable to us or our predecessor in
excess of $100,000 and no awards were granted to our general
partners executive officers under the Williams Partners GP
LLC Long-Term Incentive Plan in 2004 or 2005.
Employment Agreements
The executive officers of our general partner are also executive
officers of Williams. These executive officers do not have
employment agreements in their capacity as officers of our
general partner.
Compensation of Directors
Members of the board of directors of our general partner who are
also officers or employees of our affiliates do not receive
additional compensation for serving on the board of directors.
Subject to the proration provisions of the policy, members of
the board of directors who are not officers or employees of our
affiliates (each a Non-Employee Director) each
receive an annual compensation package consisting of the
following: (a) $50,000 cash; (b) restricted units
representing limited partnership interests in us valued at
$25,000; and
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(c) $5,000 cash each for service on the conflicts and audit
committees of the board. In addition, each Non-Employee Director
receives a one-time grant of restricted units valued at $25,000.
Restricted units are granted under the Williams Partners GP LLC
Long-Term Incentive Plan and vest 180 days after the date
of grant. Cash distributions will be paid on the restricted
units granted to the Non-Employee Directors. Each Non-Employee
Director is reimbursed for
out-of-pocket expenses
in connection with attending meetings of the board of directors
or its committees. Each director will be fully indemnified by us
for actions associated with being a director to the extent
permitted under Delaware law. We also reimburse Non-Employee
directors for the costs of education programs relevant to their
duties as board members.
Long-Term Incentive Plan
In connection with our IPO, our general partner adopted the
Williams Partners GP LLC Long-Term Incentive Plan for employees,
consultants and directors of our general partner and employees
and consultants of its affiliates who perform services for our
general partner or its affiliates. To date, the only grants
under the plan have been grants of restricted units to
Non-Employee Directors. The long-term incentive plan consists of
four components: restricted units, phantom units, unit options
and unit appreciation rights. The long-term incentive plan
currently permits the grant of awards covering an aggregate of
700,000 units. The plan is administered by the compensation
committee of the board of directors of our general partner.
Our general partners board of directors, or its
compensation committee, in its discretion may terminate, suspend
or discontinue the long-term incentive plan at any time with
respect to any award that has not yet been granted. Our general
partners board of directors, or its compensation
committee, also has the right to alter or amend the long-term
incentive plan or any part of the plan from time to time,
including increasing the number of units that may be granted
subject to unitholder approval as required by the exchange upon
which the common units are listed at that time. However, no
change in any outstanding grant may be made that would
materially impair the rights of the participant without the
consent of the participant.
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Restricted Units and Phantom Units |
A restricted unit is a common unit subject to forfeiture prior
to the vesting of the award. A phantom unit will be a notional
unit that entitles the grantee to receive a common unit upon the
vesting of the phantom unit or, in the discretion of the
compensation committee, cash equivalent to the value of a common
unit. The compensation committee may determine to make grants
under the plan of restricted units and phantom units to
employees, consultants and directors containing such terms as
the compensation committee shall determine. The compensation
committee determines the period over which restricted units and
phantom units granted to employees, consultants and directors
will vest. The committee may base its determination upon the
achievement of specified financial objectives. In addition, the
restricted units and phantom units will vest upon a change of
control of Williams Partners L.P., our general partner or
Williams, unless provided otherwise by the compensation
committee.
If a grantees employment, service relationship or
membership on the board of directors terminates for any reason,
the grantees restricted units and phantom units will be
automatically forfeited unless, and to the extent, the
compensation committee provides otherwise. Common units to be
delivered in connection with the grant of restricted units or
upon the vesting of phantom units may be common units acquired
by our general partner on the open market, common units already
owned by our general partner, common units acquired by our
general partner directly from us or any other person or any
combination of the foregoing. Our general partner is entitled to
reimbursement by us for the cost incurred in acquiring common
units. Thus, the cost of the restricted units and delivery of
common units upon the vesting of phantom units will be borne by
us. If we issue new common units in connection with the grant of
restricted units or upon vesting of the phantom units, the total
number of common units outstanding will increase. The
compensation committee, in its discretion, may grant tandem
distribution rights with respect to restricted units and tandem
distribution equivalent rights with respect to phantom units.
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Unit Options and Unit Appreciation Rights |
The long-term incentive plan permits the grant of options
covering common units and the grant of unit appreciation rights.
A unit appreciation right is an award that, upon exercise,
entitles the participant to receive the excess of the fair
market value of a unit on the exercise date over the exercise
price established for the unit appreciation right. Such excess
may be paid in common units, cash or a combination thereof, as
determined by the compensation committee in its discretion. The
compensation committee may make grants of unit options and unit
appreciation rights under the plan to employees, consultants and
directors containing such terms as the committee shall
determine. Unit options and unit appreciation rights may not
have an exercise price that is less than the fair market value
of the common units on the date of grant. In general, unit
options and unit appreciation rights granted will become
exercisable over a period determined by the compensation
committee. In addition, the unit options and unit appreciation
rights will become exercisable upon a change in control of
Williams Partners L.P., our general partner or Williams, unless
provided otherwise by the committee. The compensation committee,
in its discretion may grant tandem distribution equivalent
rights with respect to unit options and unit appreciation rights.
Upon exercise of a unit option (or a unit appreciation right
settled in common units), our general partner will acquire
common units on the open market or directly from us or any other
person or use common units already owned by our general partner,
or any combination of the foregoing. Our general partner will be
entitled to reimbursement by us for the difference between the
cost incurred by our general partner in acquiring these common
units and the proceeds received from a participant at the time
of exercise. Thus, the cost of the unit options (or a unit
appreciation right settled in common units) will be borne by us.
If we issue new common units upon exercise of the unit options
(or a unit appreciation right settled in common units), the
total number of common units outstanding will increase, and our
general partner will pay us the proceeds it receives from an
optionee upon exercise of a unit option. The availability of
unit options and unit appreciation rights is intended to furnish
additional compensation to employees, consultants and directors
and to align their economic interests with those of common
unitholders.
Reimbursement of Expenses of Our General Partner
Our general partner will not receive any management fee or other
compensation for its management of Williams Partners L.P. Our
general partner and its affiliates are reimbursed for expenses
incurred on our behalf, including the compensation of employees
of an affiliate of our general partner that perform services on
our behalf. These expenses include all expenses necessary or
appropriate to the conduct of the business of, and allocable to,
Williams Partners L.P. Our partnership agreement provides that
our general partner will determine in good faith the expenses
that are allocable to Williams Partners L.P. There is no cap on
the amount that may be paid or reimbursed to our general partner
for compensation or expenses incurred on our behalf, except that
pursuant to the omnibus agreement, Williams will provide a
partial credit for general and administrative expenses that we
incur for a period of five years following our IPO of common
units in August 2005. Please read Certain Relationships
and Related Transactions Omnibus Agreement.
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Item 12. |
Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters |
The following table sets forth the beneficial ownership of units
of Williams Partners L.P. that, as of February 28, 2006,
are owned by:
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each person known by us to be a beneficial owner of more than
five percent of the units; |
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each of the directors of our general partner; |
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each of the named executive officers of our general
partner; and |
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all directors and executive officers of our general partner as a
group. |
The amounts and percentage of units beneficially owned are
reported on the basis of regulations of the SEC governing the
determination of beneficial ownership of securities. Under the
rules of the SEC, a person is
97
deemed to be a beneficial owner of a security if
that person has or shares voting power, which
includes the power to vote or to direct the voting of such
security, or investment power, which includes the
power to dispose of or to direct the disposition of such
security. A person is also deemed to be a beneficial owner of
any securities of which that person has a right to acquire
beneficial ownership within 60 days. Under these rules,
more than one person may be deemed a beneficial owner of the
same securities and a person may be deemed a beneficial owner of
securities as to which he has no economic interest.
Except as indicated by footnote, the persons named in the table
below have sole voting and investment power with respect to all
units shown as beneficially owned by them, subject to community
property laws where applicable.
Percentage of total units beneficially ownership is based on
14,006,146 units outstanding. Unless otherwise noted below,
the address for the beneficial owners listed below is One
Williams Center, Tulsa, Oklahoma 74172-0172.
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Percentage of | |
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Common | |
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Common | |
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Subordinated | |
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Percentage of | |
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Percentage of | |
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Units | |
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Units | |
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Units | |
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Subordinated | |
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Total Units | |
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Beneficially | |
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Beneficially | |
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Beneficially | |
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Beneficially | |
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Beneficially | |
Name of Beneficial Owner |
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Owned | |
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Owned | |
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Owned | |
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Owned | |
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Owned | |
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The Williams Companies, Inc.(a)
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1,250,000 |
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17.9 |
% |
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7,000,000 |
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100.0 |
% |
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58.9 |
% |
Williams Energy Services, LLC
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821,761 |
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11.7 |
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4,601,861 |
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65.7 |
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38.7 |
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Williams Energy, L.L.C.
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447,308 |
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6.4 |
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2,504,925 |
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35.8 |
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23.0 |
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Williams Discovery Pipeline LLC
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215,980 |
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3.1 |
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1,209,486 |
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17.3 |
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10.2 |
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Williams Partners Holdings LLC
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428,239 |
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6.1 |
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2,398,139 |
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34.2 |
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20.2 |
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MAPCO Inc.(a)
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447,308 |
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6.4 |
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2,504,925 |
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35.8 |
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23.0 |
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Fiduciary Asset Management, L.L.C.(b)
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632,465 |
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9.0 |
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4.5 |
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Alan S. Armstrong
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10,000 |
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* |
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* |
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James J. Bender
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2,000 |
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* |
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* |
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Donald R. Chappel
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10,000 |
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* |
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* |
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Steven J. Malcolm(c)
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25,100 |
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* |
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* |
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Bill Z. Parker(d)
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7,326 |
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* |
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* |
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Alice M. Peterson(d)
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2,326 |
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* |
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* |
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Thomas C. Knudson(d)
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1,494 |
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* |
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* |
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Phillip D. Wright
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2,000 |
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* |
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* |
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All directors and executive officers as a group (eight persons)
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60,246 |
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* |
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* |
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(a) |
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As noted in the Schedule 13D filed with the SEC on
September 2, 2005, The Williams Companies, Inc. is the
ultimate parent company of Williams Energy Services, LLC,
Williams Energy, L.L.C., Williams Discovery Pipeline LLC and
Williams Partners Holdings LLC and may, therefore, be deemed to
beneficially own the units held by Williams Energy Services,
LLC, Williams Energy, L.L.C., Williams Discovery Pipeline LLC
and Williams Partners Holdings LLC. The Williams Companies,
Inc.s common stock is listed on the New York Stock
Exchange under the symbol WMB. The Williams
Companies, Inc. files information with or furnishes information
to, the Securities and Exchange Commission pursuant to the
information requirements of the Securities Exchange Act of 1934
(the Act). Williams Energy Services, LLC is the
record owner of 158,473 common units and 887,450 subordinated
units and, as the sole stockholder of MAPCO Inc. and the sole
member of Williams Discovery Pipeline LLC, may, pursuant to
Rule 13d-3, be
deemed to beneficially own the units beneficially owned by MAPCO
Inc. and Williams Discovery Pipeline LLC. MAPCO Inc., as the
sole member of Williams Energy, L.L.C., may, pursuant to
Rule 13d-3, be
deemed to beneficially own the units held by Williams Energy,
L.L.C. |
98
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(b) |
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Based solely on the Schedule 13G filed with the SEC on
February 16, 2006, Fiduciary Asset Management, L.L.C.
(FAMCO), an investment sub-adviser to certain
closed-end investment companies registered under the Investment
Company Act of 1940 as well as to private individuals, may be
deemed the beneficial owner of 632,465 common units. FAMCO by
virtue of investment advisory agreements with these clients has
all investment and voting power over securities owned of record
by these clients. However, despite their delegation of
investment and voting power to FAMCO, these clients may be
deemed to be the beneficial owners under
Rule 13d-3 of the
Act of the securities they own of record because they have the
right to acquire investment and voting power through termination
of their investment advisory agreement with FAMCO. Thus, FAMCO
reported that it shares voting power and dispositive power over
the securities owned of record by these clients. FAMCO may be
deemed the beneficial owner of the securities covered by this
statement under Rule 13-3 of the Act. None of the
securities listed below are owned of record by FAMCO and FAMCO
disclaims any beneficial interest in the securities. The filing
further indicates that except for Fiduciary/ Claymore MLP
Opportunity Fund, a Delaware statutory Trust, which may be
deemed to beneficially own 426,400 common units, the interest of
any one person does not exceed five percent of our outstanding
common units. The Schedule 13G notes that each of FAMCO and
Fiduciary/ Claymore have shared voting and investment power with
respect to their common units. The address of FAMCO is 8112
Maryland Avenue, Suite 400, St. Louis, Missouri, 63105. |
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(c) |
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Represents units beneficially owned by Mr. Malcolm that are
held by the Steven J. Malcolm Revocable Trust. |
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(d) |
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Includes unvested restricted units granted pursuant to the
Williams Partners GP LLC Long-Term Incentive Plan which may be
voted by the grantees as follows: Mr. Knudson, 1,494;
Mr. Parker, 2,326; and Ms. Peterson, 2,326. |
The following table sets forth, as of February 28, 2006,
the number of shares of common stock of Williams owned by each
of the executive officers and directors of our general partner
and all directors and executive officers of our general partner
as a group.
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Shares of Common | |
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Stock Owned | |
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Shares Underlying | |
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Directly or | |
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Options Exercisable | |
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Name of Beneficial Owner |
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Indirectly(a) | |
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Within 60 Days(b) | |
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Total | |
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Percent of Class | |
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Alan S. Armstrong
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88,975 |
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13,333 |
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102,308 |
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* |
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James J. Bender
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126,334 |
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13,333 |
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139,667 |
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* |
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Donald R. Chappel
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223,731 |
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118,333 |
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342,064 |
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* |
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Steven J. Malcolm
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670,210 |
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75,000 |
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745,210 |
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* |
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Bill Z. Parker
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Alice M. Peterson
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Thomas C. Knudson
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Phillip D. Wright
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172,631 |
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13,333 |
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185,964 |
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* |
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All directors and executive officers as a group
(eight persons)
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1,281,881 |
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233,332 |
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1,515,213 |
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* |
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(a) |
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Includes shares held under the terms of incentive and investment
plans as follows: Mr. Armstrong, 14 shares in The
Williams Companies Investment Plus Plan, 68,660 deferred shares
and 20,301 beneficially owned shares; Mr. Bender,
3,000 shares owned by children, 68,600 deferred shares and
54,674 beneficially owned shares; Mr. Chappel, 141,608
deferred shares of which 50,000 vest on April 16, 2006 and
82,123 beneficially owned shares; Mr. Malcolm,
44,623 shares in The Williams Companies Investment Plus
Plan, 374,758 deferred shares and 250,829 beneficially owned
shares; and Mr. Wright, 14,742 shares in The Williams
Investment Plus Plan, 68,660 deferred shares and 89,229
beneficially owned shares. |
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(b) |
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The shares indicated represent stock options granted under
Williams current or previous stock option plans, which are
currently exercisable or which will become exercisable within
60 days of February 28, 2006. Shares subject to
options cannot be voted. |
Securities Authorized for Issuance Under Equity Compensation
Plans(1)
The following table provides information concerning common units
that may be issued under the Williams Partners GP LLC Long-Term
Incentive Plan. For more information about this plan, which did
not require approval by our limited partners, please read
Note 9 of our Notes to Consolidated Financial Statements
and Executive Compensation Long-Term Incentive
Plan.
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Number of Securities | |
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Number of Securities | |
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Remaining Available for | |
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to be Issued Upon | |
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Weighted-Average | |
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Future Issuance Under | |
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Exercise of Outstanding | |
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Exercise Price of | |
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Equity Compensation Plan | |
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Options, Warrants | |
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Outstanding Options, | |
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(Excluding Securities | |
Plan Category |
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and Rights | |
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Warrants and Rights | |
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Reflected in Column (a)) | |
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(a) | |
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(b) | |
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(c) | |
Equity compensation plans approved by security holders
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Equity compensation plans not approved by security holders
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6,146 |
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693,854 |
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Total
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6,146 |
(1) |
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693,854 |
(2) |
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(1) |
Represents unvested restricted units granted pursuant to the
Williams Partners GP LLC Long-Term Incentive Plan. No value is
shown in column (b) of the table because the restricted
units do not have an exercise price. To date, the only grants
under the plan have been grants of restricted units. |
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(2) |
Please read Executive Compensation Long-Term
Incentive Plan for a description of the material features
of the plan, including the awards that may be granted under the
plan. |
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Item 13. |
Certain Relationships and Related Transactions |
Our general partner and its affiliates own 1,250,000 common
units and 7,000,000 subordinated units representing a
59 percent limited partner interest in us. In addition, our
general partner owns a two percent general partner interest in
us.
In addition to the related transactions and relationships
discussed below, information about such transactions and
relationships is included in Note 5 of our Notes to
Consolidated Financial Statements and is incorporated herein by
reference in its entirety.
Distributions and Payments to Our General Partner and Its
Affiliates
The following table summarizes the distributions and payments
made or to be made by us to our general partner and its
affiliates in connection with the ongoing operation and
liquidation of Williams Partners L.P. These distributions and
payments were determined by and among affiliated entities and,
consequently, are not the result of arms-length
negotiations.
Operational Stage
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Distributions of available cash to our general partner and its
affiliates |
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We will generally make cash distributions 98 percent to
unitholders, including our general partner and its affiliates,
as holders of an aggregate of 1,250,000 common units, all of the
subordinated units and the remaining two percent to our general
partner. |
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In addition, if distributions exceed the minimum quarterly
distribution and other higher target levels, our general partner
will be entitled to increasing percentages of the distributions,
up to 50 percent of the distributions above the highest
target level. We refer to the rights to increasing distribution
as incentive distribution rights. For further
information about distributions, please read Market for
Registrants Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities. |
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Payments to our general partner and its affiliates |
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Our general partner does not receive a management fee or other
compensation for the management of our partnership. Our general
partner and its affiliates are reimbursed, however, for all
direct and indirect expenses incurred on our behalf. Our general
partner determines the amount of these expenses. |
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Withdrawal or removal of our general partner |
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If our general partner withdraws or is removed, its general
partner interest and its incentive distribution rights will
either be sold to the new general partner for cash or converted
into common units, in each case for an amount equal to the fair
market value of those interests. |
Liquidation Stage
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Liquidation |
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Upon our liquidation, the partners, including our general
partner, will be entitled to receive liquidating distributions
according to their particular capital account balances. |
Agreements Governing the IPO Transactions
We, our general partner, our operating company and other parties
entered into agreements to effect the transactions related to
our IPO of common units in August 2005, including the vesting of
assets in, and the assumption of liabilities by, us and our
subsidiaries, and the application of the proceeds of this
offering. These agreements were not be the result of
arms-length negotiations, and they, or any of the
transactions that they provided may not have been effected on
terms at least as favorable to the parties to these agreements
as they could have been obtained from unaffiliated third
parties. From the proceeds of the IPO, we paid approximately
$4.3 million of expenses associated with the IPO and the
related formation transactions.
Omnibus Agreement
Upon the closing of the IPO, we entered into an omnibus
agreement with Williams and its affiliates that governs our
relationship with them regarding the following matters:
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reimbursement of certain general and administrative expenses; |
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indemnification for certain environmental liabilities, tax
liabilities and
right-of-way defects; |
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reimbursement for certain expenditures; and |
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a license for the use of certain software and intellectual
property. |
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General and Administrative Expenses |
Williams will provide us with a five-year partial credit for
general and administrative, or G&A, expenses incurred on our
behalf. For 2005, the amount of this credit was
$3.9 million on an annualized basis but was pro rated from
the closing of our initial public offering in August 2005
through the end of the year. In 2006, the
101
amount of the G&A credit will be $3.2 million, and the
amount of the credit will decrease by $800,000 for each
subsequent year. As a result, after 2009, we will no longer
receive any credit and will be required to reimburse Williams
for all of the general and administrative expenses incurred on
our behalf.
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Indemnification for Environmental and Related
Liabilities |
Williams agreed to indemnify us after the closing of our IPO
against certain environmental and related liabilities arising
out of or associated with the operation of the assets before the
closing date of the IPO. These liabilities include both known
and unknown environmental and related liabilities, including:
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remediation costs associated with the KDHE Consent Orders and
certain fugitive NGLs associated with our Conway storage
facilities; |
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the costs associated with the installation of wellhead control
equipment and well meters at our Conway storage facility; |
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KDHE-related cavern compliance at our Conway storage
facility; and |
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the costs relating to the restoration of the overburden along
our Carbonate Trend pipeline in connection with erosion caused
by Hurricane Ivan in September 2004. |
Williams will not be required to indemnify us for any project
management or monitoring costs. This indemnification obligation
will terminate three years after the closing of the IPO, except
in the case of the remediation costs associated with the KDHE
Consent Orders which will survive for an unlimited period of
time. There is an aggregate cap of $14.0 million on the
amount of indemnity coverage, including any amounts recoverable
under our insurance policy covering those remediation costs and
unknown claims at Conway. For further information about the
indemnity obligation, please read Environmental
under Managements Discussion and Analysis of
Financial Condition and Results of Operations. In
addition, we are not entitled to indemnification until the
aggregate amounts of claims exceed $250,000. Liabilities
resulting from a change of law after the closing of our IPO are
excluded from the environmental indemnity by Williams for the
unknown environmental liabilities.
Williams will also indemnify us for liabilities related to:
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certain defects in the easement rights or fee ownership
interests in and to the lands on which any assets contributed to
us in connection with the IPO are located and failure to obtain
certain consents and permits necessary to conduct our business
that arise within three years after the closing of the
IPO; and |
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certain income tax liabilities attributable to the operation of
the assets contributed to us in connection with the IPO prior to
the time they were contributed. |
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Reimbursement for Certain Expenditures Attributable to
Discovery |
We expect the cost of the Tahiti pipeline lateral expansion
project will be approximately $69.5 million, of which our
40 percent share will be approximately $27.8 million.
Williams will reimburse us for the excess (up to
$3.4 million) of our 40 percent share of the total
cost of the Tahiti pipeline lateral expansion project above the
amount of the required escrow deposit ($24.4 million)
attributable to our 40 percent interest in Discovery.
Williams will reimburse us for these capital expenditures upon
the earlier to occur of a capital call from Discovery or
Discovery actually incurring the expenditure.
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Intellectual Property License |
Williams and its affiliates granted a license to us for the use
of certain marks, including our logo, for as long as Williams
controls our general partner, at no charge.
102
The omnibus agreement may not be amended without the prior
approval of the conflicts committee if the proposed amendment
will, in the reasonable discretion of our general partner,
adversely affect holders of our common units.
Williams is not restricted under the omnibus agreement from
competing with us. Williams may acquire, construct or dispose of
additional midstream or other assets in the future without any
obligation to offer us the opportunity to purchase or construct
those assets.
Credit Facilities
At the closing of the IPO, we entered into a $20 million
revolving credit facility with Williams as the lender. The
facility is available exclusively to fund working capital
borrowings. Borrowings under the facility will mature on
May 3, 2007 and bear interest at the same rate as would be
available for borrowings under the Williams revolving credit
facility described in please read Managements
Discussion and Analysis of Financial Condition
Financial Condition and Liquidity Sources of
Liquidity Credit Facility.
We are required to reduce all borrowings under our working
capital credit facility to zero for a period of at least 15
consecutive days once each
12-month period prior
to the maturity date of the facility.
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Williams Revolving Credit Facility |
In addition we also have the ability to borrow up to
$75 million under the Williams revolving credit facility.
For further information, please read Managements
Discussion and Analysis of Financial Condition and Results of
Operations Financial Condition and
Liquidity Sources of Liquidity Credit
Facilities and Risk Factors Risks
Inherent in Our Business Williams revolving
credit facility and Williams public indentures contain
financial and operating restrictions that may limit our access
to credit. In addition, our ability to obtain credit in the
future will be affected by Williams credit ratings.
Discovery Limited Liability Company Agreement
We, an affiliate of Williams and Duke Energy Field Services have
entered into an amended and restated limited liability company
agreement for Discovery Producer Services LLC. This agreement
governs the ownership and management of Discovery and provides
for quarterly distributions of available cash to the members.
The amount of any such distributions are determined by majority
approval of Discoverys management committee, which
consists of representatives from each of the three owners. In
addition, to the extent Discovery requires working capital in
excess of applicable reserves, the Williams affiliate that is a
Discovery member (Williams Energy, L.L.C.) must make capital
advances to Discovery up to the amount of Discoverys two
most recent prior quarterly distributions of available cash, but
Discovery must repay these advances before it makes any future
distributions. In addition, the owners are required to offer to
Discovery all opportunities to construct pipeline laterals
within an area of interest.
Discovery Operating and Maintenance Agreements
Discovery is party to three operating and maintenance agreements
with Williams: one relating to Discovery Producer Services LLC,
one relating to Discovery Gas Transmission LLC and another
relating to the Paradis Fractionation Facility and the Larose
Gas Processing Plant. Under these agreements, Discovery is
required to reimburse Williams for direct payroll and employee
benefit costs incurred on Discoverys behalf. Most costs
for materials, services and other charges are third-party
charges and are invoiced directly to Discovery. Discovery is
required to pay Williams a monthly operation and management fee
to cover the cost of accounting services, computer systems and
management services provided to Discovery under each of these
103
agreements. Discovery also pays Williams a project management
fee to cover the cost of managing capital projects. This fee is
determined on a project by project basis.
Gas Purchase Contract
Upon the closing of our IPO, an affiliate of Williams
transferred to us a contract for the purchase of a sufficient
quantity of natural gas from a wholly owned subsidiary of
Williams at a price not to exceed a specified price to satisfy
our fuel requirements under this fractionation contract. The
fair value of this gas purchase contract was an equity
contribution to us by Williams. This gas purchase contract will
terminate on December 31, 2007.
Natural Gas and NGL Marketing Contracts
A subsidiary of Williams markets substantially all of the NGLs
and excess natural gas to which Discovery and our Conway
fractionation and storage facility take title. Discovery and our
Conway fractionation and storage facility conduct the sales of
the NGLs and excess natural gas to which they take title
pursuant to a base contract for sale and purchase of natural gas
and a natural gas liquids master purchase, sale and exchange
agreement. These agreements contain the general terms and
conditions governing the transactions such as apportionment of
taxes, timing and manner of payment, choice of law and
confidentiality. Historically, the sales of natural gas and NGLs
to which Discovery and our Conway fractionation and storage
facility take title have been conducted at market prices with a
subsidiary of Williams as the counter party. Additionally,
Discovery and our Conway fractionation and storage facility may
purchase natural gas to meet their fuel and other requirements
and our Conway storage facility may purchase NGLs as needed to
maintain inventory balances.
Summary of Transactions with Williams
In connection with the closing of our IPO:
|
|
|
|
|
we contributed 2,000,000 common units, 7,000,000 subordinated
units, a two percent general partner interest and incentive
distribution rights to affiliates of Williams in exchange for
the interests in our operating subsidiaries and Discovery; |
|
|
|
we distributed $58.8 million to affiliates of Williams to
reimburse Williams for certain capital expenditures incurred
prior to our formation and for the contribution by an affiliate
of Williams to one of our operating subsidiaries of a gas
purchase contract that provides for the purchase of a sufficient
quantity of natural gas from a wholly owned subsidiary of
Williams at a price not to exceed a specified price to satisfy
our fuel requirements under a fractionation contract; |
|
|
|
we provided $24.4 million to make a capital contribution to
Discovery to fund an escrow account in connection with the
Tahiti pipeline lateral expansion project; and |
|
|
|
Williams forgave $186.0 million in intercompany advances to
us. |
For the year ended December 31, 2005:
|
|
|
|
|
we incurred $17.6 million from Williams for direct and
indirect expenses incurred on our behalf pursuant to the
partnership agreement; |
|
|
|
we distributed $1.3 million to affiliates of Williams as
quarterly distributions on their common units, subordinated
units and 2 percent general partner interest; |
|
|
|
we received from Williams $1.4 million of general and
administrative credits pursuant to the omnibus agreement; |
|
|
|
Williams indemnified us $0.5 million, primarily for
KDHE-required compliance costs, pursuant to the omnibus
agreement; |
104
|
|
|
|
|
Discovery reimbursed Williams $3.4 million for direct
payroll and employee benefit costs pursuant to the operating and
maintenance agreements; |
|
|
|
Discovery paid Williams $2.2 million for operation and
management fees pursuant to the operating and maintenance
agreements; |
|
|
|
we purchased a gross amount of $22.4 million of natural gas
for the Conway fractionator from an affiliate of Williams; |
|
|
|
we purchased $15.7 million of NGLs from a subsidiary of
Williams based on market pricing; |
|
|
|
we sold $13.4 million to a subsidiary of Williams that
markets substantially all of the NGLs and excess natural gas to
which our Conway fractionation and storage facility takes
title; and |
|
|
|
Discovery sold $70.8 million to a subsidiary of Williams
that markets substantially all of the NGLs and excess natural
gas to which Discovery takes title. |
|
|
Item 14. |
Principal Accountant Fees and Services |
We and our general partner we formed in February 2005 and our
IPO occurred in August 2005. Fees for professional services
provided by our independent auditors, Ernst & Young
LLP, for the last fiscal year in each of the following
categories are:
|
|
|
|
|
|
|
2005 | |
|
|
| |
|
|
(Thousands) | |
Audit Fees
|
|
$ |
1,624 |
|
Audit-Related Fees
|
|
|
|
|
Tax Fees
|
|
|
|
|
All Other Fees
|
|
|
|
|
|
|
|
|
|
|
$ |
1,624 |
|
|
|
|
|
We did not rely on the de minimus exception provided for
by the SECs rules for any fee approvals.
Fees for audit services in 2005 include fees associated with the
annual audit, the reviews of our quarterly reports on
Form 10-Q, and
services provided in connection with other filings with the SEC.
The audit fees included in the table above include
$1.2 million for services rendered in connection with our
IPO.
On an ongoing basis, our management presents specific projects
and categories of service to our general partners audit
committee for which advance approval is requested. The audit
committee reviews those requests and advises management if the
audit committee approves the engagement of Ernst &
Young LLP. On a periodic basis, the management of the general
partner reports to the audit committee regarding the actual
spending for such projects and services compared to the approved
amounts. The audit committee may also delegate the ability to
pre-approve audit and permitted non-audit services, excluding
services related to our internal control over financial
reporting, to any two committee members, provided that any such
pre-approvals are reported at a subsequent audit committee
meeting. The audit committees pre-approval policy with
respect to audit and non-audit services is provided as an
exhibit to this report.
PART IV
|
|
Item 15. |
Exhibits and Financial Statement Schedules |
(a) 1 and 2. Williams Partners L.P. financials
105
|
|
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|
|
|
|
|
Page | |
|
|
| |
Covered by reports of independent auditors:
|
|
|
|
|
|
Consolidated balance sheets at December 31, 2005 and 2004
|
|
|
67 |
|
|
Consolidated statements of operations for each of the three
years ended December 31, 2005
|
|
|
68 |
|
|
Consolidated statement of partners capital for each of the
three years ended
December 31, 2005
|
|
|
69 |
|
|
Consolidated statements of cash flows for each of the three
years ended December 31, 2005
|
|
|
70 |
|
|
Notes to consolidated financial statements
|
|
|
71-86 |
|
Not covered by reports of independent auditors:
|
|
|
|
|
|
Quarterly financial data (unaudited)
|
|
|
87 |
|
All other schedules have been omitted since the required
information is not present or is not present in amounts
sufficient to require submission of the schedule, or because the
information required is included in the financial statements and
notes thereto.
(a) 3 and (b). The exhibits listed below are filed as
part of this annual report:
|
|
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
*Exhibit 3 |
.1 |
|
|
|
Certificate of Limited Partnership of Williams Partners L.P.
(attached as Exhibit 3.1 to Williams Partners L.P.s
registration statement on Form S-1 (File
No. 333-124517) filed with the SEC on May 2, 2005). |
|
*Exhibit 3 |
.2 |
|
|
|
Certificate of Formation of Williams Partners GP LLC (attached
as Exhibit 3.3 to Williams Partners L.P.s
registration statement on Form S-1 (File
No. 333-124517) filed with the SEC on May 2, 2005). |
|
|
*Exhibit 3 |
.3 |
|
|
|
Amended and Restated Agreement of Limited Partnership of
Williams Partners L.P. (attached as Exhibit 3.1 to Williams
Partners L.P.s current report on Form 8-K (File No.
001-32599) filed with the SEC on August 26, 2005). |
|
|
*Exhibit 3 |
.4 |
|
|
|
Amended and Restated Limited Liability Company Agreement of
Williams Partners GP LLC (attached as Exhibit 3.2 to
Williams Partners L.P.s current report on Form 8-K
(File No. 001-32599) filed with the SEC on August 26, 2005). |
|
|
*Exhibit 10 |
.1 |
|
|
|
Fractionation Agreement dated July 18, 1997, by and between
MAPCO Natural Gas Liquids Inc. and Amoco Oil Company (attached
as Exhibit 10.6 to Amendment No. 1 to Williams
Partners L.P.s registration statement on Form S-1
(File No. 333-124517) filed with the SEC on June 24,
2005). |
|
|
*Exhibit 10 |
.2 |
|
|
|
Omnibus Agreement among Williams Partners L.P., Williams Energy
Services, LLC, Williams Energy, L.L.C., Williams Partners
Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners
GP LLC, Williams Partners Operating LLC and (for purposes of
Articles V and VI thereof only) The Williams Companies,
Inc. (attached as Exhibit 10.1 to Williams Partners
L.P.s current report on Form 8-K
(File No. 001-32599) filed with the SEC on
August 26, 2005). |
|
|
*#Exhibit 10 |
.3 |
|
|
|
Williams Partners GP LLC Long-Term Incentive Plan (attached as
Exhibit 10.2 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599) filed with the SEC
on August 26, 2005). |
|
|
*Exhibit 10 |
.4 |
|
|
|
Contribution, Conveyance and Assumption Agreement, dated
August 23, 2005, by and among Williams Partners L.P.,
Williams Energy, L.L.C., Williams Partners GP LLC, Williams
Partners Operating LLC, Williams Energy Services, LLC, Williams
Discovery Pipeline LLC, Williams Partners Holdings LLC and
Williams Natural Gas Liquids, Inc. (attached as
Exhibit 10.3 to Williams Partners L.P.s current
report on Form 8-K filed with the SEC on August 26,
2005). |
|
|
*Exhibit 10 |
.5 |
|
|
|
Working Capital Loan Agreement, dated August 23, 2005,
between The Williams Companies, Inc. and Williams Partners L.P.
(attached as Exhibit 10.4 to Williams Partners L.P.s
current report on Form 8-K (File No. 001-32599) filed with
the SEC on August 26, 2005). |
106
|
|
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
|
*Exhibit 10 |
.6 |
|
|
|
Amended and Restated Credit Agreement dated as of May 20,
2005 among The Williams Companies, Inc., Williams Partners L.P.,
Northwest Pipeline Corporation, Transcontinental Gas Pipe Line
Corporation, and the Banks, Citibank, N.A. and Bank of America,
N.A., and Citicorp USA, INC. as administrative agent (attached
as Exhibit 1.1 to The Williams Companies, Inc.s
current report on Form 8-K (File No. 001-04174) filed with
the SEC on May 26, 2005). |
|
|
*Exhibit 10 |
.7 |
|
|
|
Third Amended and Restated Limited Liability Company Agreement
for Discovery Producer Services LLC (attached as
Exhibit 10.7 to Amendment No. 1 to Williams Partners
L.P.s registration statement on Form S-1 (File
No. 333-124517) filed with the SEC on June 24, 2005). |
|
|
*Exhibit 10 |
.8 |
|
|
|
Base Contract for Sale and Purchase of Natural Gas between
Williams Natural Gas Liquids, Inc. and Williams Power Company,
Inc., dated August 15, 2005 (attached as Exhibit 10.7
to Williams Partners L.P.s quarterly report on
Form 10-Q filed with the SEC on September 22, 2005). |
|
|
*#Exhibit 10 |
.9 |
|
|
|
Director Compensation Policy dated November 29, 2005
(attached as Exhibit 10.1 to Williams Partners L.P.s
current report on Form 8-K (File No. 001-32599) filed with
the SEC on December 1, 2005). |
|
|
*#Exhibit 10 |
.10 |
|
|
|
Form of Grant Agreement for Restricted Units (attached as
Exhibit 10.2 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599) filed with the SEC
on December 1, 2005). |
|
|
*Exhibit 21 |
|
|
|
|
List of subsidiaries of Williams Partners L.P. (attached as
Exhibit 21.1 to Amendment No. 1 to Williams Partners
L.P.s registration statement on Form S-1 (File
No. 333-124517) filed with the SEC on June 24, 2005) |
|
|
+Exhibit 23 |
|
|
|
|
Consent of Independent Registered Public Accounting Firm,
Ernst & Young LLP. |
|
|
+Exhibit 24 |
|
|
|
|
Power of attorney together with certified resolution. |
|
|
+Exhibit 31 |
.1 |
|
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive
Officer. |
|
|
+Exhibit 31 |
.2 |
|
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial
Officer. |
|
|
+Exhibit 32 |
|
|
|
|
Section 1350 Certifications of Chief Executive Officer and
Chief Financial Officer. |
|
|
+Exhibit 99 |
.1 |
|
|
|
Pre-approval policy with respect to audit and non-audit services
of the audit committee of the board of directors of Williams
Partners GP LLC. |
|
+Exhibit 99 |
.2 |
|
|
|
Williams Partners GP LLC Financial Statements. |
|
|
|
|
* |
Each such exhibit has heretofore been filed with the SEC as part
of the filing indicated and is incorporated herein by reference. |
+ Filed herewith.
|
|
|
|
|
Confidential treatment requested for omitted portions. |
|
|
# |
Management contract or compensatory plan or arrangement. |
(c) Discovery Producer Services LLC financial statements
and notes thereto
107
REPORT OF INDEPENDENT AUDITORS
To the Management Committee of
Discovery Producer Services LLC
We have audited the accompanying consolidated balance sheets of
Discovery Producer Services LLC as of December 31, 2005 and
2004, and the related consolidated statements of income and
comprehensive income, members capital, and cash flows for
each of the three years in the period ended December 31,
2005. These financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the auditing
standards generally accepted in the United States. Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. We were not engaged to perform an
audit of the Companys internal control over financial
reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of
the Companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Discovery Producer Services LLC at
December 31, 2005 and 2004, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2005, in conformity with
accounting principles generally accepted in the
United States.
As described in Note 4, effective January 1, 2003,
Discovery Producer Services LLC adopted Statement of Financial
Accounting Standards No. 143, Accounting for Asset
Retirement Obligations.
Tulsa, Oklahoma
February 27, 2005
108
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
|
(In thousands) | |
ASSETS |
Current assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
21,378 |
|
|
$ |
55,222 |
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
31,448 |
|
|
|
4,399 |
|
|
|
Other
|
|
|
14,451 |
|
|
|
5,761 |
|
|
Inventory
|
|
|
924 |
|
|
|
840 |
|
|
Other current assets
|
|
|
2,324 |
|
|
|
1,312 |
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
70,525 |
|
|
|
67,534 |
|
Restricted cash
|
|
|
44,559 |
|
|
|
|
|
Property, plant and equipment, net
|
|
|
344,743 |
|
|
|
356,385 |
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
459,827 |
|
|
$ |
423,919 |
|
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS CAPITAL |
Current liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts payable:
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$ |
9,334 |
|
|
$ |
682 |
|
|
|
Other
|
|
|
26,796 |
|
|
|
14,622 |
|
|
Accrued liabilities
|
|
|
6,205 |
|
|
|
14,197 |
|
|
Other current liabilities
|
|
|
2,735 |
|
|
|
2,071 |
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
45,070 |
|
|
|
31,572 |
|
Noncurrent accrued liabilities
|
|
|
1,121 |
|
|
|
702 |
|
Commitments and contingent liabilities (Note 7)
|
|
|
|
|
|
|
|
|
Members capital
|
|
|
413,636 |
|
|
|
391,645 |
|
|
|
|
|
|
|
|
Total liabilities and members capital
|
|
$ |
459,827 |
|
|
$ |
423,919 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
109
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
$ |
70,848 |
|
|
$ |
57,838 |
|
|
$ |
54,145 |
|
|
|
Third-party
|
|
|
4,271 |
|
|
|
1,611 |
|
|
|
1,943 |
|
|
Gas and condensate transportation services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
1,908 |
|
|
|
3,966 |
|
|
|
4,611 |
|
|
|
Third-party
|
|
|
13,498 |
|
|
|
12,052 |
|
|
|
13,225 |
|
|
Gathering and processing services:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
3,585 |
|
|
|
6,962 |
|
|
|
7,549 |
|
|
|
Third-party
|
|
|
26,133 |
|
|
|
14,168 |
|
|
|
16,974 |
|
|
Other revenues
|
|
|
2,502 |
|
|
|
3,279 |
|
|
|
4,731 |
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
122,745 |
|
|
|
99,876 |
|
|
|
103,178 |
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
7,911 |
|
|
|
423 |
|
|
|
7,832 |
|
|
|
Third-party
|
|
|
56,556 |
|
|
|
44,932 |
|
|
|
35,082 |
|
|
Operating and maintenance expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate
|
|
|
3,355 |
|
|
|
3,098 |
|
|
|
3,035 |
|
|
|
Third-party
|
|
|
6,810 |
|
|
|
14,756 |
|
|
|
12,794 |
|
|
Depreciation and accretion
|
|
|
24,794 |
|
|
|
22,795 |
|
|
|
22,875 |
|
|
General and administrative expenses affiliate
|
|
|
2,053 |
|
|
|
1,424 |
|
|
|
1,400 |
|
|
Taxes other than income
|
|
|
1,151 |
|
|
|
1,382 |
|
|
|
1,602 |
|
|
Other net
|
|
|
(33 |
) |
|
|
(54 |
) |
|
|
(101 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
102,597 |
|
|
|
88,756 |
|
|
|
84,519 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
20,148 |
|
|
|
11,120 |
|
|
|
18,659 |
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
9,611 |
|
Interest income
|
|
|
(1,685 |
) |
|
|
(550 |
) |
|
|
|
|
Foreign exchange loss
|
|
|
1,005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
20,828 |
|
|
|
11,670 |
|
|
|
9,048 |
|
Cumulative effect of change in accounting principle
|
|
|
(176 |
) |
|
|
|
|
|
|
(267 |
) |
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$ |
20,652 |
|
|
$ |
11,670 |
|
|
$ |
8,781 |
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow hedging activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Losses reclassified to earnings during year
|
|
$ |
|
|
|
$ |
|
|
|
$ |
5,196 |
|
|
|
Unrealized losses during year
|
|
|
|
|
|
|
|
|
|
|
(291 |
) |
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
4,905 |
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
$ |
20,652 |
|
|
$ |
11,670 |
|
|
$ |
13,686 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
110
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENT OF MEMBERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated | |
|
|
|
|
|
|
Williams | |
|
Duke Energy | |
|
|
|
Other | |
|
|
|
|
Williams | |
|
Operating | |
|
Field | |
|
Eni BB | |
|
Comprehensive | |
|
|
|
|
Energy LLC | |
|
Partners LLC | |
|
Services, LLC | |
|
Pipelines LLC | |
|
Income (Loss) | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Balance, December 31, 2002
|
|
$ |
58,541 |
|
|
$ |
|
|
|
$ |
39,028 |
|
|
$ |
19,515 |
|
|
$ |
(4,905 |
) |
|
$ |
112,179 |
|
|
Contributions
|
|
|
127,055 |
|
|
|
|
|
|
|
84,695 |
|
|
|
42,360 |
|
|
|
|
|
|
|
254,110 |
|
|
Net income 2003
|
|
|
4,391 |
|
|
|
|
|
|
|
2,927 |
|
|
|
1,463 |
|
|
|
|
|
|
|
8,781 |
|
|
Other comprehensive (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,905 |
|
|
|
4,905 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2003
|
|
|
189,987 |
|
|
|
|
|
|
|
126,650 |
|
|
|
63,338 |
|
|
|
|
|
|
|
379,975 |
|
|
Net income 2004
|
|
|
5,835 |
|
|
|
|
|
|
|
3,890 |
|
|
|
1,945 |
|
|
|
|
|
|
|
11,670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2004
|
|
|
195,822 |
|
|
|
|
|
|
|
130,540 |
|
|
|
65,283 |
|
|
|
|
|
|
|
391,645 |
|
|
Contributions
|
|
|
16,269 |
|
|
|
24,400 |
|
|
|
7,634 |
|
|
|
|
|
|
|
|
|
|
|
48,303 |
|
|
Distributions
|
|
|
(30,030 |
) |
|
|
(1,280 |
) |
|
|
(15,654 |
) |
|
|
|
|
|
|
|
|
|
|
(46,964 |
) |
|
Net income 2005
|
|
|
8,063 |
|
|
|
4,651 |
|
|
|
6,909 |
|
|
|
1,029 |
|
|
|
|
|
|
|
20,652 |
|
|
Sale of Eni 16.67% interest to subsidiaries of Williams Energy
LLC
|
|
|
66,312 |
|
|
|
|
|
|
|
|
|
|
|
(66,312 |
) |
|
|
|
|
|
|
|
|
|
Sale of Williams Energy LLC and subsidiaries 40% interest to
Williams Operating Partners LLC
|
|
|
(142,761 |
) |
|
|
142,761 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sale of Williams Energy LLC 6.67% interest to Duke Energy Field
Services LLC
|
|
|
(25,869 |
) |
|
|
|
|
|
|
25,869 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2005
|
|
$ |
87,806 |
|
|
$ |
170,532 |
|
|
$ |
155,298 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
413,636 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
111
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
$ |
20,828 |
|
|
$ |
11,670 |
|
|
$ |
9,048 |
|
Adjustments to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and accretion
|
|
|
24,794 |
|
|
|
22,795 |
|
|
|
22,875 |
|
|
Cash provided (used) by changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(35,739 |
) |
|
|
(1,658 |
) |
|
|
7,860 |
|
|
|
Inventory
|
|
|
(84 |
) |
|
|
(240 |
) |
|
|
(229 |
) |
|
|
Other current assets
|
|
|
(1,012 |
) |
|
|
(1 |
) |
|
|
(761 |
) |
|
|
Accounts payable
|
|
|
29,355 |
|
|
|
1,256 |
|
|
|
(1,415 |
) |
|
|
Other current liabilities
|
|
|
664 |
|
|
|
(668 |
) |
|
|
2,223 |
|
|
|
Accrued liabilities
|
|
|
(7,992 |
) |
|
|
2,469 |
|
|
|
4,424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
30,814 |
|
|
|
35,623 |
|
|
|
44,025 |
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(12,906 |
) |
|
|
(46,701 |
) |
|
|
(14,746 |
) |
|
Change in accounts payable capital expenditures
|
|
|
(8,532 |
) |
|
|
7,586 |
|
|
|
2,673 |
|
Increase in restricted cash
|
|
|
(44,559 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(65,997 |
) |
|
|
(39,115 |
) |
|
|
(12,073 |
) |
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments of long-term debt
|
|
|
|
|
|
|
|
|
|
|
(253,701 |
) |
|
Distributions to members
|
|
|
(46,964 |
) |
|
|
|
|
|
|
|
|
|
Capital contributions
|
|
|
48,303 |
|
|
|
|
|
|
|
254,110 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
1,339 |
|
|
|
|
|
|
|
409 |
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents
|
|
|
(33,844 |
) |
|
|
(3,492 |
) |
|
|
32,361 |
|
Cash and cash equivalents at beginning of period
|
|
|
55,222 |
|
|
|
58,714 |
|
|
|
26,353 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$ |
21,378 |
|
|
$ |
55,222 |
|
|
$ |
58,714 |
|
|
|
|
|
|
|
|
|
|
|
Supplemental Disclosure of Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the year for interest
|
|
$ |
|
|
|
$ |
|
|
|
$ |
9,855 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
112
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
Note 1. |
Organization and Description of Business |
Our company consists of Discovery Producer Services LLC
(DPS), a Delaware limited liability company formed
on June 24, 1996, and its wholly owned subsidiary,
Discovery Gas Transmission LLC (DGT), a Delaware
limited liability company formed on June 24, 1996. DPS was
formed for the purpose of constructing and operating a
600 million cubic feet per day (MMcf/d)
cryogenic natural gas processing plant near Larose, Louisiana
and a 32,000 barrel per day (bpd) natural
gas liquids fractionator plant near Paradis, Louisiana. DGT was
formed for the purpose of constructing and operating a natural
gas pipeline from offshore deep water in the Gulf of Mexico to
DPSs gas processing plant in Larose, Louisiana. The
pipeline has a design capacity of 600 million cubic feet
per day and consists of approximately 173 miles of pipe.
DPS has since connected several laterals to the DGT pipeline to
expand its presence in the Gulf. Herein, DPS and DGT are
collectively referred to in the first person as we,
us or our and sometimes as the
Company.
Until April 14, 2005, we were owned 50 percent by
Williams Energy, L.L.C. (a wholly owned subsidiary of The
Williams Companies, Inc.), 33.33 percent by Duke Energy
Field Services, LP (Duke) and 16.67 percent by
Eni BB Pipeline, LLC (Eni) (formerly British-Borneo
Pipeline LLC). Williams Energy is our operator. Herein, The
Williams Companies, Inc. and its subsidiaries are collectively
referred to as Williams.
On April 14, 2005, Williams acquired the 16.67 percent
ownership interest in us previously held by Eni. As a result we
became 66.67 percent owned by Williams and
33.33 percent owned by Duke.
On August 22, 2005, we distributed cash of $44 million
to the members based on 66.67 percent ownership by Williams
and 33.33 percent ownership by Duke.
On August 23, 2005, Williams Partners Operating LLC (a
wholly owned subsidiary of Williams Partners L.P.)
(WPZ) acquired a 40 percent interest in us
previously held by Williams Energy. As a result we became
40 percent owned by WPZ, 26.67 percent owned by
Williams and 33.33 percent owned by Duke. In connection
with this Williams, Duke and WPZ amended our limited liability
company agreement including provisions for (1) quarterly
distributions of available cash, as defined in the amended
agreement and (2) pursuit of capital projects for the
benefit of one or more of our members when there is not
unanimous consent.
On December 22, 2005, Duke acquired 6.67 percent
interest in us previously held by Williams Energy. As a result
we became 40 percent owned by WPZ, 20 percent owned by
Williams and 40 percent owned by Duke.
|
|
Note 2. |
Summary of Significant Accounting Policies |
Basis of Presentation. The consolidated financial
statements have been prepared based upon accounting principles
generally accepted in the United States and include the accounts
of DPS and its wholly owned subsidiary, DGT. Intercompany
accounts and transactions have been eliminated.
Reclassifications. Certain prior years amounts have been
reclassified to conform with the current year presentation.
These include the reclassification of certain costs charged by
Williams under operation and maintenance agreements. We have
reclassified these costs, which relate to accounting services,
computer systems and management services, to General and
administrative expenses affiliate on the
Consolidated Statements of Income.
Use of Estimates. The preparation of consolidated
financial statements in conformity with accounting principles
generally accepted in the United States requires management to
make estimates and assumptions that affect the amounts reported
in the consolidated financial statements and accompanying notes.
Actual results could differ from those estimates.
113
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cash and Cash Equivalents. Cash and cash equivalents
include demand and time deposits, certificates of deposit and
other marketable securities with maturities of three months or
less when acquired.
Accounts Receivable. Accounts receivable are carried on a
gross basis, with no discounting, less an allowance for doubtful
accounts. No allowance for doubtful accounts is recognized at
the time the revenue that generates the accounts receivable is
recognized. We estimate the allowance for doubtful accounts
based on existing economic conditions, the financial condition
of the customers and the amount and age of past due accounts.
Receivables are considered past due if full payment is not
received by the contractual due date. Past due accounts are
generally written off against the allowance for doubtful
accounts only after all collection attempts have been exhausted.
There was no allowance for doubtful accounts at
December 31, 2005, and 2004.
Gas Imbalances. In the course of providing transportation
services to customers, DGT may receive different quantities of
gas from shippers than the quantities delivered on behalf of
those shippers. This results in gas transportation imbalance
receivables and payables which are recovered or repaid in cash,
based on market-based prices, or through the receipt or delivery
of gas in the future and are recorded in the balance sheet.
Settlement of imbalances requires agreement between the
pipelines and shippers as to allocations of volumes to specific
transportation contracts and the timing of delivery of gas based
on operational conditions. In accordance with its tariff, DGT is
required to account for this imbalance (cash-out)
liability/receivable and refund or invoice the excess or
deficiency when the cumulative amount exceeds $400,000. To the
extent that this difference, at any year end, is less than
$400,000 such amount would carry forward and be included in the
cumulative computation of the difference evaluated at the
following year end.
Inventory. Inventory includes fractionated products at
our Paradis facility and is carried at the lower cost of market.
Restricted cash. Restricted cash within non-current
assets relates to escrow funds contributed by our members for
the construction of the Tahiti pipeline lateral expansion. The
restricted cash is classified as non-current because the funds
will be used to construct a long-term asset. The restricted cash
is primarily invested in short-term money market accounts with
financials institutions.
Property, Plant and Equipment. Property, plant and
equipment are carried at cost. We base the carrying value of
these assets on estimates, assumptions and judgments relative to
capitalized costs, useful lives and salvage values. The natural
gas and natural gas liquids maintained in the pipeline
facilities necessary for their operation (line fill) are
included in property, plant and equipment.
Depreciation for DPSs facilities and equipment is computed
primarily using the straight-line method with
25-year lives.
Depreciation for DGTs facilities and equipment is computed
using the straight-line method with
15-year lives.
We record an asset and a liability equal to the present value of
each expected future asset retirement obligation
(ARO). The ARO asset is depreciated in a manner
consistent with the depreciation of the underlying physical
asset. We measure changes in the liability due to passage of
time by applying an interest method of allocation. This amount
is recognized as an increase in the carrying amount of the
liability and as a corresponding accretion expense included in
operating income.
Revenue Recognition. Revenue for sales of products are
recognized in the period of delivery and revenues from the
gathering, transportation and processing of gas are recognized
in the period the service is provided based on contractual terms
and the related natural gas and liquid volumes. DGT is subject
to Federal Energy Regulatory Commission
(FERC) regulations, and accordingly, certain
revenues collected may be subject to possible refunds upon final
orders in pending cases. DGT records rate refund liabilities
considering regulatory proceedings by DGT and other third
parties, advice of counsel, and estimated total exposure as
114
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
discounted and risk weighted, as well as collection and other
risks. There were no rate refund liabilities accrued at
December 31, 2005 or 2004.
Derivative Instruments and Hedging Activities. The
accounting for changes in the fair value of a derivative depends
upon whether we have designated it in a hedging relationship
and, further, on the type of hedging relationship. To qualify
for designation in a hedging relationship, specific criteria
must be met and the appropriate documentation maintained in
accordance with Statement of Financial Accounting Standards
(SFAS) No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended.
We establish hedging relationships pursuant to our risk
management policies. We initially and regularly evaluate the
hedging relationships to determine whether they are expected to
be, and have been, highly effective hedges. If a derivative
ceases to be a highly effective hedge, hedge accounting is
discontinued prospectively, and future changes in the fair value
of the derivative are recognized in earnings each period.
We entered into interest rate swap agreements to reduce the
impact of changes in interest rates on our floating rate debt.
These instruments were designated as cash flow hedges under
SFAS No. 133. The effective portion of the change in
fair value of the derivatives is reported in other comprehensive
income and reclassified into earnings and included in interest
expense in the period in which the hedged item affects earnings.
There are no amounts excluded from the effectiveness
calculation, and there was no ineffective portion of the change
in fair value in 2003. The interest rate swap expired on
December 31, 2003, and we have no other derivative
instruments.
Impairment of Long-Lived Assets. We evaluate long-lived
assets for impairment on an individual asset or asset group
basis when events or changes in circumstances indicate, in our
managements judgment, that the carrying value of such
assets may not be recoverable. When such a determination has
been made, we compare our managements estimate of
undiscounted future cash flows attributable to the assets to the
carrying value of the assets to determine whether impairment has
occurred. If an impairment of the carrying value has occurred,
we determine the amount of the impairment recognized in the
financial statements by estimating the fair value of the assets
and recording a loss for the amount that the carrying value
exceeds the estimated fair value.
Judgments and assumptions are inherent in our managements
estimate of undiscounted future cash flows used to determine
recoverability of an asset and the estimate of an assets
fair value used to calculate the amount of impairment to
recognize. These judgments and assumptions include such matters
as the estimation of additional tie-ins of customers, strategic
value, rate adjustments, and capital expenditures. The use of
alternate judgments and/or assumptions could result in the
recognition of different levels of impairment charges in the
financial statements.
Accounting for Repair and Maintenance Costs. We expense
the cost of maintenance and repairs as incurred; significant
improvements are capitalized and depreciated over the remaining
useful life of the asset.
Capitalization of Interest. We capitalize interest on
major projects during construction. Interest is capitalized on
borrowed funds. Rates are based on the average interest rate on
debt.
Income Taxes. For federal tax purposes, we have elected
to be treated as a partnership with each member being separately
taxed on its ratable share of our taxable income. This election,
to be treated as a pass-through entity, also applies to our
wholly owned subsidiary, DGT. Therefore, no income taxes or
deferred income taxes are reflected in the consolidated
financial statements.
Foreign Currency Transactions. Transactions denominated
in currencies other than the functional currency are recorded
based on exchange rates at the time such transactions arise.
Subsequent changes in exchange rates result in transaction gains
or losses which are reflected in the Consolidated Statements of
Income.
115
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Recent Accounting Standards. In December 2004, the
Financial Accounting Standards Board (FASB) issued
revised SFAS No. 123, Share-Based Payment.
The Statement requires that compensation costs for all
share-based awards to employees be recognized in the financial
statements at fair value. The Statement, as issued by the FASB,
was to be effective as of the beginning of the first interim or
annual reporting period that begins after June 15, 2005.
However, in April 2005, the Securities and Exchange Commission
(SEC) adopted a new rule that delayed the
effective date for revised SFAS No. 123 to the
beginning of the next fiscal year that begins after
June 15, 2005. We intend to adopt the revised Statement as
of January 1, 2006. Payroll costs directly charged to us by
Williams and general and administrative costs allocated to us by
Williams (see Note 3) will include such compensation costs
beginning January 1, 2006. Our adoption of this Statement
will not have a material impact on our Consolidated Financial
Statements.
In November 2004, the FASB issued SFAS No. 151,
Inventory Costs, an amendment of ARB No. 43,
Chapter 4, which will be applied prospectively for
inventory costs incurred in fiscal years beginning after
June 15, 2005. The Statement amends Accounting Research
Bulletin (ARB) No. 43, Chapter 4,
Inventory Pricing, to clarify that abnormal amounts
of certain costs should be recognized as current period charges
and that the allocation of overhead costs should be based on the
normal capacity of the production facility. The impact of this
Statement on our Consolidated Financial Statements will not be
material.
In December 2004, the FASB issued SFAS No. 153,
Exchanges of Nonmonetary Assets, an amendment of APB
Opinion No. 29, which is effective for nonmonetary
asset exchanges occurring in fiscal periods beginning after
June 15, 2005, and will be applied prospectively. The
Statement amends APB Opinion No. 29, Accounting for
Nonmonetary Transactions. The guidance in APB Opinion
No. 29 is based on the principle that exchanges of
nonmonetary assets should be measured based on the fair value of
the assets exchanged but includes certain exceptions to that
principle. SFAS No. 153 amends APB Opinion No. 29
to eliminate the exception for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for
exchanges of nonmonetary assets that do not have commercial
substance. A nonmonetary exchange has commercial substance if
the future cash flows of the entity are expected to change
significantly as a result of the exchange.
In May 2005, the FASB issued SFAS No. 154,
Accounting Changes and Error Corrections a
replacement of APB Opinion No. 20 and FASB Statement
No. 3, which is effective prospectively for reporting
a change in accounting principle for fiscal years beginning
after December 15, 2005. The Statement changes the
reporting of a change in accounting principle to require
retrospective application to prior periods financial
statements, except for explicit transition provisions provided
for in any existing accounting pronouncements, including those
in the transition phase when SFAS No. 154 becomes
effective.
|
|
Note 3. |
Related Party Transactions |
We have no employees. Pipeline and plant operations were
performed under operation and maintenance agreements with
Williams. Under this agreement, we reimburse Williams for direct
payroll and employee benefit costs incurred on our behalf. Most
costs for materials, services and other charges are third-party
charges and are invoiced directly to us. Additionally, we
purchase a portion of the natural gas from Williams to meet our
fuel and shrink requirements at our processing plant. These
costs are presented as Operating and maintenance
expenses affiliate and Product costs and shrink
replacement affiliate on the Consolidated Statements
of Income.
We pay Williams a monthly operation and management fee to cover
the cost of accounting services, computer systems and management
services provided to us. This fee is presented as General and
administrative expenses affiliate on the
Consolidated Statements of Income.
We also pay Williams a project management fee to cover the cost
of managing capital projects. This fee is determined on a
project by project basis and is capitalized as part of the
construction costs.
116
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A summary of the payroll costs and project fees charged to us by
Williams and capitalized are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
Capitalized labor
|
|
$ |
351 |
|
|
$ |
288 |
|
|
$ |
204 |
|
Capitalized project fee
|
|
|
115 |
|
|
|
854 |
|
|
|
147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
466 |
|
|
$ |
1,142 |
|
|
$ |
351 |
|
|
|
|
|
|
|
|
|
|
|
We have various business transactions with our members and other
subsidiaries and affiliates of our members, including an
agreement with Williams pursuant to which Williams markets the
NGLs and natural gas to which we take title. Under the terms of
this agreement, Williams purchases the NGLs and excess natural
gas and resells it, for its own account, to end users. During
2005, we had transactions with Texas Eastern Corporation, a
subsidiary of Duke. These transactions primarily included
processing and sales of natural gas liquids and transportation
of gas and condensate. We have business transactions with Eni
that primarily include processing and transportation of gas and
condensate. The following table summarizes these related-party
revenues during 2005, 2004 and 2003.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2005 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Eni*
|
|
$ |
2,830 |
|
|
$ |
10,928 |
|
|
$ |
12,160 |
|
Texas Eastern Corporation
|
|
|
2,663 |
|
|
|
|
|
|
|
|
|
Williams
|
|
|
70,848 |
|
|
|
57,838 |
|
|
|
54,145 |
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
76,341 |
|
|
$ |
68,766 |
|
|
$ |
66,305 |
|
|
|
|
|
|
|
|
|
|
|
Note 4. Property, Plant and
Equipment
Property, plant and equipment consisted of the following at
December 31, 2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
|
Construction work in progress
|
|
$ |
5,444 |
|
|
$ |
11,739 |
|
|
Buildings
|
|
|
4,406 |
|
|
|
4,393 |
|
|
Land and land rights
|
|
|
1,530 |
|
|
|
1,165 |
|
|
Transportation lines
|
|
|
302,252 |
|
|
|
286,661 |
|
|
Plant and other equipment
|
|
|
198,837 |
|
|
|
195,429 |
|
|
|
|
|
|
|
|
|
|
|
512,469 |
|
|
|
499,387 |
|
Less accumulated depreciation and amortization
|
|
|
167,726 |
|
|
|
143,002 |
|
|
|
|
|
|
|
|
|
|
$ |
344,743 |
|
|
$ |
356,385 |
|
|
|
|
|
|
|
|
Commitments for construction and acquisition of property, plant
and equipment for Tahiti are approximately $64 million at
December 31, 2005.
We adopted SFAS No. 143, Accounting for Asset
Retirement Obligations on January 1, 2003. As a
result, we recorded a liability of $549,000 representing the
present value of expected future asset retirement obligations at
January 1, 2003, and a decrease to earnings of $267,000
reflected as a cumulative effect of a change in accounting
principle.
117
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Effective December 31, 2005, we adopted Financial
Accounting Standards Board Interpretation (FIN)
No. 47, Accounting for Conditional Asset Retirement
Obligations. This Interpretation clarifies that an entity
is required to recognize a liability for the fair value of a
conditional ARO when incurred if the liabilitys fair value
can be reasonably estimated. The Interpretation clarifies when
an entity would have sufficient information to reasonably
estimate the fair value of an ARO. As required by the new
standard, we reassessed the estimated remaining life of all our
assets with a conditional ARO. We recorded additional
liabilities totaling $327,000 equal to the present value of
expected future asset retirement obligations at
December 31, 2005. The liabilities are slightly offset by a
$151,000 increase in property, plant and equipment, net of
accumulated depreciation, recorded as if the provisions of the
Interpretation had been in effect at the date the obligation was
incurred. The net $176,000 reduction to earnings is reflected as
a cumulative effect of a change in accounting principle for the
year ended 2005. If the Interpretation had been in effect at the
beginning of 2003, the impact to our income from continuing
operations and net income would have been immaterial.
The obligations relate to an offshore platform and our onshore
processing and fractionation facilities. At the end of the
useful life of each respective asset, we are legally or
contractually obligated to dismantle the offshore platform,
remove the onshore facilities and related surface equipment and
restore the surface of the property.
A rollforward of our asset retirement obligation for 2005 and
2004 is presented below.
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
|
(In thousands) | |
Balance, January 1
|
|
$ |
702 |
|
|
$ |
621 |
|
Accretion expense
|
|
|
92 |
|
|
|
81 |
|
FIN No. 47 revisions
|
|
|
327 |
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31
|
|
$ |
1,121 |
|
|
$ |
702 |
|
|
|
|
|
|
|
|
|
|
Note 5. |
Leasing Activities |
We lease the land on which the Paradis fractionator plant and
the Larose processing plant are located. The initial terms of
the leases are 20 years with renewal options for an
additional 30 years. We entered into a 10 year leasing
agreement for pipeline capacity from Texas Eastern Transmission,
LP, as part of our Market Expansion project which began in June
2005 (see Note 7). The lease includes renewal options and
options to increase capacity which would also increase rentals.
The future minimum annual rentals under these non-cancelable
leases as of December 31, 2005 are payable as follows:
|
|
|
|
|
|
|
(In thousands) | |
2006
|
|
$ |
854 |
|
2007
|
|
|
854 |
|
2008
|
|
|
858 |
|
2009
|
|
|
858 |
|
2010
|
|
|
858 |
|
Thereafter
|
|
|
4,109 |
|
|
|
|
|
|
|
$ |
8,391 |
|
|
|
|
|
Total rent expense for 2005, 2004 and 2003, including a
cancelable platform space lease and
month-to-month leases,
was $994,610, $866,000 and $1,050,000, respectively.
118
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 6. |
Financial Instruments and Concentrations of Credit Risk |
|
|
|
Financial Instruments Fair Value |
We used the following methods and assumptions to estimate the
fair value of financial instruments:
Cash and cash equivalents. The carrying amounts reported
in the balance sheets approximate fair value due to the
short-term maturity of these instruments.
Restricted cash. The carrying amounts reported in the
balance sheets approximate fair value as these instruments have
interest rates approximating market.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
|
|
| |
|
| |
|
|
Carrying | |
|
Fair | |
|
Carrying | |
|
Fair | |
Asset |
|
Amount | |
|
Value | |
|
Amount | |
|
Value | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(In thousands) | |
Cash and cash equivalents
|
|
$ |
21,378 |
|
|
$ |
21,378 |
|
|
$ |
55,222 |
|
|
$ |
55,222 |
|
Restricted cash
|
|
|
44,559 |
|
|
|
44,559 |
|
|
|
|
|
|
|
|
|
|
|
|
Concentrations of Credit Risk |
Our cash equivalents and restricted cash consist of high-quality
securities placed with various major financial institutions with
credit ratings at or above AA by Standard & Poors
or Aa by Moodys Investors Service.
Substantially all of our accounts receivable result from gas
transmission services for and natural gas liquids sales to our
two largest customers at December 31, 2005 and 2004. This
concentration of customers may impact our overall credit risk
either positively or negatively, in that these entities may be
similarly affected by industry-wide changes in economic or other
conditions. As a general policy, collateral is not required for
receivables, but customers financial condition and credit
worthiness are evaluated regularly. Our credit policy and the
relatively short duration of receivables mitigate the risk of
uncollected receivables. We did not incur any credit losses on
receivables during 2005 and 2004.
Major Customers. Williams and Eni accounted for
approximately $70.8 million (58 percent) and
$8.5 million (7 percent), respectively, of our total
revenues in 2005, and $57.8 million (58 percent) and
$10.9 million (11 percent), respectively, of our total
revenues in 2004. Three customers, Williams, Eni and Pogo
Producing Company accounted for approximately $54 million
(52 percent), $12.2 million (12 percent) and
$12 million (12 percent), respectively, of our total
revenues in 2003.
|
|
Note 7. |
Rate and Regulatory Matters and Contingent Liabilities |
Rate and Regulatory Matters. In 2002, DGT filed a request
with the FERC to change the lost and unaccounted-for gas
percentage to be allocated to shippers from 0.5 percent to
0.1 percent to be effective for the period from
July 1, 2002 to June 30, 2003. On June 26, 2002,
the FERC approved DGTs request. Additionally, DGT filed to
reduce the lost and unaccounted-for gas percentage to zero to be
effective for the period from July 1, 2003 to June 30,
2004. On June 19, 2003, the FERC approved this request. On
June 1, 2004, DGT filed to maintain a lost and
unaccounted-for percentage of zero for the period from
July 1, 2004 to June 30, 2005 due to the continued
absence of system gas losses. On June 22, 2004, the FERC
approved this request. In this filing, DGT explained that
management determined the reasons for the gas gains and
established new procedures in July 2003 that significantly
reduced the amount of gains occurring thereafter. On
April 28, 2005, DGT filed to maintain a lost and
unaccounted-for gas percentage of zero for the period from
July 1, 2005 to June 30, 2006. DGT also filed to
retain net system gains that are unrelated to the lost and
unaccounted-for gas over-recovered from its shippers. These
system gas gains totaled approximately $2.5 million,
$2.5 million and $5.5 million respectively in 2005,
2004, and 2003. Certain shippers protested the net system gains
filing and the FERC requested additional information in a
May 27, 2005 Letter Order. DGT
119
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
responded to the information request and on October 31,
2005, the FERC accepted the filing and no requests for rehearing
were filed. As a result, we recognized system gains for
2002 2004 of $10.7 million in 2005. As of
December 31, 2005 and 2004, DGT has deferred amounts of
$6 million and $14.2 million, respectively, included
in current accrued liabilities in the accompanying Consolidated
Balance Sheets representing amounts collected from customers
pursuant to prior years lost and unaccounted for gas
percentage and unrecognized net system gains for 2005.
On July 23, 2003, DGT applied to the FERC for a Certificate
of Public Convenience and Necessity authorizing DGTs
market expansion to acquire, lease or construct and/or to own
and operate certain new delivery points, pipeline, compression
services and metering and appurtenant facilities to enable DGT
to deliver natural gas to four additional delivery points to new
markets in southern Louisiana. This application was amended on
December 30, 2003. On the same dates, DPS applied to the
FERC and amended its application for a Limited Jurisdiction
Certificate authorizing DPS to provide the compression services
to DGT to enable DGT to provide service through the Market
Expansion facilities. The capital cost of the expansion
facilities was approximately $11 million. On May 6,
2004, the FERC granted DGTs and DPSs applications.
On July 13, 2004, the FERC granted an additional approval
on a rate design issue requested by DGT. On January 6,
2005, the FERC granted DGT permission to commence construction
of the Market Expansion facilities. The Market Expansion
facilities became operational in June 2005.
On November 25, 2003, the FERC issued Order No. 2004
promulgating new standards of conduct applicable to natural gas
pipelines. On August 10, 2004, the FERC granted DGT a
partial exemption allowing the continuation of DGTs
current ownership structure and management subject to compliance
with many of the other standards of conduct. DGT continues to
evaluate the effect of the partial exemption and the compliance
with the remaining requirements. The effect of complying with
the new standards is not expected to have a material effect on
the consolidated financial statements.
On October 11, 2005, DGT applied to the FERC for permission
to construct and operate facilities to allow temporary
re-routing of gas to DGT from other facilities that were
impacted by Hurricane Katrina. The FERC granted emergency
exemptions and waivers permitting such actions the same day,
allowing emergency service for up to one year or until certain
third-party processing facilities were restored to service. DGT
conducted two open seasons for shippers wishing to take
advantage of the new service.
On January 16, 2006, DPS and DGT received notice of a claim
by POGO Producing Company (POGO) relating to the
results of a POGO audit performed in April 2004. POGO claims
that DPS and DGT overcharged POGO and its working interest
owners of approximately $600,000 relating to condensate
transportation and handling during 2000 2004. The
underlying agreements limit audit claims to a two-year period
from the date of the audit, and DPS and DGT dispute the validity
of the claim.
Environmental Matters. We are subject to extensive
federal, state and local environmental laws and regulations
which affect our operations related to the construction and
operation of our facilities. Appropriate governmental
authorities may enforce these laws and regulations with a
variety of civil and criminal enforcement measures, including
monetary penalties, assessment and remediation requirements and
injunctions as to future compliance. We have not been notified
and are not currently aware of any noncompliance under the
various environmental laws and regulations.
Other. We are party to various other claims, legal
actions and complaints arising in the ordinary course of
business. Litigation, arbitration and environmental matters are
subject to inherent uncertainties. Were an unfavorable ruling to
occur, there exists the possibility of a material adverse impact
on the results of operations in the period in which the ruling
occurs. Management, including internal counsel, currently
believes that the ultimate resolution of the foregoing matters,
taken as a whole, and after consideration of amounts accrued,
insurance coverage or other indemnification arrangements, will
not have a material adverse effect upon our future financial
position.
120
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
|
|
|
Williams Partners L.P. |
|
(Registrant) |
|
|
By: Williams Partners GP LLC, |
|
its general partner |
|
|
|
|
|
William H. Gault |
|
Attorney-in-fact |
Date: March 3, 2006
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signature |
|
Title |
|
Date |
|
|
|
|
|
|
*
Steven J. Malcolm |
|
President, Chief Executive Officer and Chairman of the Board
(Principal Executive Officer) |
|
March 3, 2006 |
|
*
Donald R. Chappel |
|
Chief Financial Officer and Director (Principal Financial
Officer) |
|
March 3, 2006 |
|
*
Ted T. Timmermans |
|
Chief Accounting Officer and Controller (Principal Accounting
Officer) |
|
March 3, 2006 |
|
*
Alan S. Armstrong |
|
Chief Operating Officer and Director |
|
March 3, 2006 |
|
*
Bill Z. Parker |
|
Director |
|
March 3, 2006 |
|
*
Alice M. Peterson |
|
Director |
|
March 3, 2006 |
|
*
Thomas C. Knudson |
|
Director |
|
March 3, 2006 |
|
*
Phillip D. Wright |
|
Director |
|
March 3, 2006 |
|
By: |
|
/s/ William H. Gault
William H. Gault
Attorney-in-fact |
|
|
|
March 3, 2006 |
121
INDEX TO EXHIBITS
The exhibits listed below are filed as part of this annual
report:
|
|
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
*Exhibit 3 |
.1 |
|
|
|
Certificate of Limited Partnership of Williams Partners L.P.
(attached as Exhibit 3.1 to Williams Partners L.P.s
registration statement on Form S-1 (File
No. 333-124517) filed with the SEC on May 2, 2005). |
|
|
*Exhibit 3 |
.2 |
|
|
|
Certificate of Formation of Williams Partners GP LLC (attached
as Exhibit 3.3 to Williams Partners L.P.s
registration statement on Form S-1 (File
No. 333-124517) filed with the SEC on May 2, 2005). |
|
|
*Exhibit 3 |
.3 |
|
|
|
Amended and Restated Agreement of Limited Partnership of
Williams Partners L.P. (attached as Exhibit 3.1 to Williams
Partners L.P.s current report on Form 8-K (File
No. 001-32599) filed with the SEC on August 26, 2005). |
|
|
*Exhibit 3 |
.4 |
|
|
|
Amended and Restated Limited Liability Company Agreement of
Williams Partners GP LLC (attached as Exhibit 3.2 to
Williams Partners L.P.s current report on Form 8-K
(File No. 001-32599) filed with the SEC on August 26,
2005). |
|
|
*Exhibit 10 |
.1 |
|
|
|
Fractionation Agreement dated July 18, 1997, by and between
MAPCO Natural Gas Liquids Inc. and Amoco Oil Company (attached
as Exhibit 10.6 to Amendment No. 1 to Williams
Partners L.P.s registration statement on Form S-1
(File No. 333-124517) filed with the SEC on June 24,
2005). |
|
|
*Exhibit 10 |
.2 |
|
|
|
Omnibus Agreement among Williams Partners L.P., Williams Energy
Services, LLC, Williams Energy, L.L.C., Williams Partners
Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners
GP LLC, Williams Partners Operating LLC and (for purposes of
Articles V and VI thereof only) The Williams Companies,
Inc. (attached as Exhibit 10.1 to Williams Partners
L.P.s current report on Form 8-K
(File No. 001-32599) filed with the SEC on
August 26, 2005). |
|
|
*#Exhibit 10 |
.3 |
|
|
|
Williams Partners GP LLC Long-Term Incentive Plan (attached as
Exhibit 10.2 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599) filed with the
SEC on August 26, 2005). |
|
|
*Exhibit 10 |
.4 |
|
|
|
Contribution, Conveyance and Assumption Agreement, dated
August 23, 2005, by and among Williams Partners L.P.,
Williams Energy, L.L.C., Williams Partners GP LLC, Williams
Partners Operating LLC, Williams Energy Services, LLC, Williams
Discovery Pipeline LLC, Williams Partners Holdings LLC and
Williams Natural Gas Liquids, Inc. (attached as
Exhibit 10.3 to Williams Partners L.P.s current
report on Form 8-K filed with the SEC on August 26,
2005). |
|
|
*Exhibit 10 |
.5 |
|
|
|
Working Capital Loan Agreement, dated August 23, 2005,
between The Williams Companies, Inc. and Williams Partners L.P.
(attached as Exhibit 10.4 to Williams Partners L.P.s
current report on Form 8-K (File No. 001-32599) filed
with the SEC on August 26, 2005). |
|
|
*Exhibit 10 |
.6 |
|
|
|
Amended and Restated Credit Agreement dated as of May 20,
2005 among The Williams Companies, Inc., Williams Partners L.P.,
Northwest Pipeline Corporation, Transcontinental Gas Pipe Line
Corporation, and the Banks, Citibank, N.A. and Bank of America,
N.A., and Citicorp USA, INC. as administrative agent (attached
as Exhibit 1.1 to The Williams Companies, Inc.s
current report on Form 8-K (File No. 001-04174) filed with
the SEC on May 26, 2005). |
|
|
*Exhibit 10 |
.7 |
|
|
|
Third Amended and Restated Limited Liability Company Agreement
for Discovery Producer Services LLC (attached as
Exhibit 10.7 to Amendment No. 1 to Williams Partners
L.P.s registration statement on Form S-1 (File
No. 333-124517) filed with the SEC on June 24, 2005). |
|
|
*Exhibit 10 |
.8 |
|
|
|
Base Contract for Sale and Purchase of Natural Gas between
Williams Natural Gas Liquids, Inc. and Williams Power Company,
Inc., dated August 15, 2005 (attached as Exhibit 10.7
to Williams Partners L.P.s quarterly report on
Form 10-Q filed with the SEC on September 22, 2005). |
122
|
|
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
*#Exhibit 10 |
.9 |
|
|
|
Director Compensation Policy dated November 29, 2005
(attached as Exhibit 10.1 to Williams Partners L.P.s
current report on Form 8-K (File No. 001-32599) filed
with the SEC on December 1, 2005). |
|
|
*#Exhibit 10 |
.10 |
|
|
|
Form of Grant Agreement for Restricted Units (attached as
Exhibit 10.2 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599) filed with the
SEC on December 1, 2005). |
|
|
*Exhibit 21 |
|
|
|
|
List of subsidiaries of Williams Partners L.P. (attached as
Exhibit 21.1 to Amendment No. 1 to Williams Partners
L.P.s registration statement on Form S-1 (File
No. 333-124517) filed with the SEC on June 24, 2005). |
|
|
+Exhibit 23 |
|
|
|
|
Consent of Independent Registered Public Accounting Firm,
Ernst & Young LLP. |
|
|
+Exhibit 24 |
|
|
|
|
Power of attorney together with certified resolution. |
|
|
+Exhibit 31 |
.1 |
|
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive
Officer. |
|
|
+Exhibit 31 |
.2 |
|
|
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial
Officer. |
|
|
+Exhibit 32 |
|
|
|
|
Section 1350 Certifications of Chief Executive Officer and
Chief Financial Officer. |
|
|
+Exhibit 99 |
.1 |
|
|
|
Pre-approval policy with respect to audit and non-audit services
of the audit committee of the board of directors of Williams
Partners GP LLC. |
|
|
+Exhibit 99 |
.2 |
|
|
|
Williams Partners GP LLC Financial Statements. |
|
|
* |
Each such exhibit has heretofore been filed with the SEC as part
of the filing indicated and is incorporated herein by reference. |
+ Filed herewith.
|
|
|
Confidential treatment requested for omitted portions. |
|
# |
Management contract or compensatory plan or arrangement. |
123