e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
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For the fiscal year ended December 31, 2009 |
or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the transition period from to |
Commission file number 1-32599
Williams Partners L.P.
(Exact name of Registrant as Specified in Its Charter)
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Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
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20-2485124
(IRS Employer
Identification No.) |
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One Williams Center, Tulsa, Oklahoma
(Address of Principal Executive Offices)
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74172-0172
(Zip Code) |
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 þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K (§229.405) is not contained herein, and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements incorporated by reference in Part III of
this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
(Do not check if a smaller reporting company)
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Smaller Reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2
of the Exchange Act). Yes o No þ
The aggregate market value of the registrants common units held by non-affiliates based on
the closing sale price of such units as reported on the New York Stock Exchange, as of the last
business day of the registrants most recently completed second quarter was approximately
$740,953,508. This figure excludes common units beneficially owned by the directors and executive
officers of Williams Partners GP LLC, our general partner.
The registrant had 52,777,452 common units and 203,000,000 Class C units outstanding as of
February 24, 2010.
DOCUMENTS INCORPORATED BY REFERENCE
None
WILLIAMS PARTNERS L.P.
FORM 10-K
TABLE OF CONTENTS
2
DEFINITIONS
We use the following oil and gas measurements and industry terms in this report:
Barrel: One barrel of petroleum products equals 42 U.S. gallons.
Bcf/d: One billion cubic feet of natural gas per day.
bpd: Barrels per day.
British Thermal Units (Btu): When used in terms of volumes, Btu is used to refer to the
amount of natural gas required to raise the temperature of one pound of water by one degree
Fahrenheit at one atmospheric pressure.
BBtu/d: One billion Btus per day.
Dth: One dekatherm.
Mbbls/d: One thousand barrels per day.
MDth: One thousand dekatherms.
Mdt/d: One thousand dekatherms per day.
¢/MMBtu: Cents per one million Btus.
MMBtu: One million Btus.
MMBtu/d: One million Btus per day.
MMcf: One million cubic feet.
MMcf/d: One million cubic feet per day.
MMdt: One million dekatherms or approximately one trillion BTUs.
MMdt/d: One million dekatherms per day.
TBtu: One trillion BTUs.
Other definitions:
FERC: Federal Energy Regulatory Commission.
Fractionation: The process by which a mixed stream of natural gas liquids is separated into
its constituent products, such as ethane, propane and butane.
LNG: Liquified natural gas. Natural gas which has been liquefied at cryogenic
temperatures.
NGLs: Natural gas liquids. Natural gas liquids result from natural gas processing and crude
oil refining and are used as petrochemical feedstocks, heating fuels and gasoline additives,
among other applications.
NGL margins: NGL revenues less Btu replacement cost, plant fuel, transportation and
fractionation.
Partially Owned Entities: Entities in which we do not, following the consummation of the
Dropdown, own a 100% ownership interest, including principally Discovery, Gulfstream, Northwest
Pipeline, and Laurel Mountain.
3
Pipeline Entities: Our regulated pipeline entities, including principally Northwest
Pipeline, Transco, Gulfstream, Discovery and Black Marlin Pipeline LLC.
Recompletions: After the initial completion of a well, the action and techniques of
reentering the well and redoing or repairing the original completion to restore the wells
productivity.
Throughput: The volume of product transported or passing through a pipeline, plant,
terminal or other facility.
Workover: Operations on a completed production well to clean, repair and maintain the well
for the purposes of increasing or restoring production.
4
WILLIAMS PARTNERS L.P.
FORM 10-K
PART I
Items 1 and 2. Business and Properties
Unless the context clearly indicates otherwise, references in this report to we, our, us
or like terms refer to Williams Partners L.P. and its subsidiaries. Unless the context clearly
indicates otherwise, references to we, our, and us include the operations of Wamsutter LLC
(Wamsutter) and our Partially Owned Entities in which we own interests accounted for as equity
investments that are not consolidated in our financial statements. When we refer to Wamsutter or
our Partially Owned Entities by name, we are referring exclusively to their businesses and
operations.
WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION
We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K and other documents electronically with the U.S. Securities and Exchange Commission (SEC)
under the Securities Exchange Act of 1934, as amended (the Exchange Act). You may read and copy any
materials that we file with the SEC at the SECs Public Reference Room at 100 F Street, N.E.,
Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by
calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SECs Internet website
at http://www.sec.gov.
Our Internet website is http://www.williamslp.com. We make available free of charge
through the Investor Relations tab of our Internet website our annual report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed
or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably
practicable after we electronically file such material with, or furnish it to, the SEC. Our
Corporate Governance Guidelines, Code of Business Conduct and Ethics and the charter of the audit
committee of our general partners board of directors are also available on our Internet website
under the Investor Relations caption. We will also provide, free of charge, a copy of any of our
governance documents listed above upon written request to our general partners secretary at
Williams Partners L.P., One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
GENERAL
We are a publicly-traded Delaware limited partnership formed by The Williams Companies, Inc.
(Williams) in February 2005. We were formed to own, operate and acquire a diversified portfolio of
complementary energy assets. Prior to the completion of the Dropdown discussed below, our focus was
on the gathering, transporting, processing and treating of natural gas and the fractionation and
storage of NGLs. Fractionation is the process by which a mixed stream of NGLs is separated into its
constituent products, such as ethane, propane and butane. These NGLs result from natural gas
processing and crude oil refining and are used as petrochemical feedstocks, heating fuels and
gasoline additives, among other applications.
Our assets were owned by Williams prior to the initial public offering (IPO) of our common
units in August 2005, our acquisition of Williams Four Corners LLC (Four Corners) in 2006, our
acquisition of an additional 20% ownership percentage of Discovery Producer Services LLC
(Discovery) in 2007 and our acquisition of ownership interests in Wamsutter in 2007. The assets
acquired in February 2010 through the Dropdown discussed below were also owned by Williams. After
the Dropdown, Williams indirectly owns an approximate 82% limited partnership interest in us and
all of our 2% general partner interest.
Williams is an integrated energy company with 2009 revenues in excess of $8.2 billion that
trades on the New York Stock Exchange under the symbol WMB. Williams operates in a number of
segments of the energy industry, including natural gas exploration and production, interstate
natural gas transportation and midstream services. Williams has been in the midstream natural gas
and NGL industry for more than 20 years.
Our principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172. Our
telephone number is 918-573-2000.
5
RECENT EVENTS
The Dropdown
On February 17, 2010, we
closed a transaction with our general partner, our operating company,
Williams and certain subsidiaries of Williams, pursuant to which Williams contributed to us the
ownership interests in the entities that make up Williams Gas Pipeline and Midstream Gas & Liquids
business segments, to the extent not already owned by us, including Williams limited and general
partner interests in Williams Pipeline Partners L.P. (WMZ), but excluding Williams Canadian,
Venezuelan and olefin operations and 25.5% of Gulfstream Natural Gas System, L.L.C. (Gulfstream).
Such entities are hereafter referred to as the Contributed Entities. This contribution was made in
exchange for aggregate consideration of:
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$3.5 billion in cash, less certain expenses incurred by us relating to our acquisition
of the Contributed Entities. This cash consideration was financed through the private
issuance of $3.5 billion of senior unsecured notes with net proceeds of $3.466 billion. |
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203 million of our Class C limited partnership units, which are identical to our common
limited partnership units except that for the distribution with respect to the first
quarter of 2010 they will receive a prorated quarterly distribution since they were not
outstanding during the full quarterly period. The Class C units will automatically convert
into our common limited partnership units following the record date for the distribution
with respect to the first quarter of 2010. |
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an increase in the capital account of our general partner to allow it to maintain its 2%
general partner interest. |
The transactions described in the preceding paragraph are referred to as the Dropdown.
Beginning with reporting of first-quarter 2010 results, our operations will be divided into
two business segments: Gas Pipeline and Midstream Gas & Liquids. All of the operations we
conducted prior to the Dropdown will be reported within the Midstream Gas & Liquids segment. The
Contributed Entities business activities will be included in our two business segments as follows:
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Gas Pipeline will include Transcontinental Gas Pipe Line Company, LLC (Transco) and
Northwest Pipeline GP (Northwest Pipeline), which own and operate a combined total of
approximately 13,900 miles of pipelines with a total annual throughput of approximately
2,700 TBtu of natural gas and peak-day delivery capacity of approximately 12 MMdt of
natural gas. Gas Pipeline will also hold interests in joint venture interstate and
intrastate natural gas pipeline systems including a 24.5% interest in Gulfstream, which
owns an approximate 745-mile pipeline with the capacity to transport approximately 1.26
million Dth per day of natural gas. |
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Midstream Gas & Liquids will include the Contributed Entities natural gas gathering,
processing and treating facilities located primarily in the Rocky Mountain and Gulf Coast
regions of the United States and natural gas and crude oil gathering and transportation
facilities in the Gulf Coast region of the United States. |
WMZ Exchange Offer
We have also announced our intention to launch an exchange offer for the publicly traded
common units of WMZ at a future date (the WMZ Exchange Offer). We will offer a fixed exchange
ratio of 0.7584 of our common units for each WMZ common unit. The ratio is based on closing prices
on the New York Stock Exchange on Friday, January 15, 2010, the business day before our intention
to make the exchange offer was announced, of $23.35 for WMZ and $30.79 for us. The exact timing of
the launch will be based upon the filing of necessary offering documents with the SEC and upon
market conditions. If we acquire ownership of more than 75% of WMZs outstanding
common units pursuant to the
WMZ Exchange Offer, we will consider causing the general partner of WMZ to (i)
deregister WMZ under the Exchange Act or cause
its common units to no longer be traded on the New York Stock Exchange, if these
options are available, (ii) exercise its right under WMZs limited partnership
agreement to purchase all of the remaining common units or (iii) exercise any other available options.
New Credit Facility
In connection with the
Dropdown, we entered into a new $1.75 billion senior unsecured revolving
three-year credit facility with Transco and Northwest Pipeline, as
co-borrowers with borrowing sublimits of $400 million each, and
Citibank, N.A. as administrative agent, and other lenders named
therein (New Credit Facility). The New Credit Facility
replaced our existing $450 million senior unsecured credit agreement. At the closing of the Dropdown, we borrowed $250 million
under the New Credit Facility to repay the term loan outstanding
under our existing credit facility.
6
FINANCIAL INFORMATION ABOUT SEGMENTS
See Part II, Item 8 Financial Statements and Supplementary Data.
NARRATIVE DESCRIPTION OF BUSINESS PRIOR TO THE DROPDOWN
At December 31, 2009, the operations of our businesses, which are located in the United
States, were organized into three reporting segments: (1) Gathering and Processing West, (2)
Gathering and Processing Gulf and (3) NGL Services.
The discussion below reflects the operations of our businesses as they were at December 31,
2009 and does not reflect any impact thereon of the Dropdown, which was consummated in February
2010 and is discussed under the headings The Dropdown and
Narrative Description of our Business
after Completion of the Dropdown.
Gathering and Processing West
Our Gathering and Processing West segment includes a 100% interest in Four Corners and
ownership interests in Wamsutter, consisting of (i) 100% of the Class A limited liability company
membership interests and (ii) 69% of the Class C limited liability company membership interests in
Wamsutter (together, the Wamsutter Ownership Interests).
Four Corners
The Four Corners assets include an approximate
3,800-mile natural gas gathering system in the
San Juan Basin in New Mexico and Colorado, three natural gas processing plants and two natural gas
treating plants. We provide our customers, primarily natural gas producers in the San Juan Basin,
with a full range of gathering, processing and treating services. Four Corners revenues are
comprised of product sales and fee-based gathering, processing, and treating revenues. Fee-based
gathering, processing and treating services accounted for approximately 75% of Four Corners total
revenue less product cost and shrink replacement for the year ended December 31, 2009. The
remaining 25% was derived from the sale of NGLs received as consideration for processing services.
For more detail of Four Corners revenues, please read Note 17, Segment Disclosures, in our Notes
to Consolidated Financial Statements in this report.
During 2009, our Four Corners gathering system gathered approximately 36% of the natural gas
produced in the San Juan Basin. It connects with the five pipeline systems that transport natural
gas to end markets from the basin. Approximately 40% of the supply connected to our Four Corners
pipeline system in the San Juan Basin is produced from conventional formations with approximately
60% coming from coal bed formations.
Wamsutter
In 2009, we owned the Wamsutter Ownership Interests and accounted for this investment under
the equity method of accounting due to the voting provisions of Wamsutters limited liability
company agreement which provided the other member of Wamsutter, Williams, significant participatory
rights such that we did not control the investment. Following the Dropdown, Wamsutter LLC became
our wholly owned, consolidated subsidiary.
Wamsutter owns an approximate
1,880-mile natural gas gathering system in the Washakie Basin
and a natural gas processing plant in Sweetwater County, Wyoming. Wamsutter provides its customers,
primarily natural gas producers in the Washakie Basin, with a broad range of gathering and
processing services. Fee-based gathering, processing and other services accounted for approximately
43% of Wamsutters total revenues less product costs for the year ended December 31, 2009. The
remaining 57% was derived primarily from the sale of NGLs received by Wamsutter as consideration
for processing services.
The Wamsutter system gathers and processes approximately 69% of the natural gas produced in
the Washakie Basin and connects with four natural gas pipeline systems that transport natural gas
to end markets from the basin.
Gathering and Processing Gulf
Our Gathering and Processing Gulf segment is comprised of our 60% interest in Discovery and
the Carbonate Trend gathering pipeline.
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Discovery
We own a 60% interest in Discovery and account for this investment under the equity method of
accounting due to the voting provisions of Discoverys limited liability company agreement which
provide the other member of Discovery significant participatory rights such that we do not control
the investment. Discovery owns an approximate 300-mile natural gas gathering and transportation
pipeline system, located primarily off the coast of Louisiana in the Gulf of Mexico, a cryogenic
natural gas processing plant in Larose, Louisiana and a fractionator in Paradis, Louisiana.
Carbonate Trend Pipeline
Our Carbonate Trend gathering pipeline is a sour gas gathering pipeline consisting of
approximately 34 miles of pipeline that is used to gather sour gas production from the Carbonate
Trend area off the coast of Alabama. For the year ended December 31, 2009, our average
transportation volume was approximately 18 MMcf/d. Our Carbonate Trend pipeline is not regulated
under the Natural Gas Act but is regulated under the Outer Continental Shelf Lands Act, which
requires us to transport gas supplies on the Outer Continental Shelf on an open and
non-discriminatory access basis.
NGL Services
Our NGL Services segment includes our three integrated NGL storage facilities and a 50%
interest in an NGL fractionator near Conway, Kansas. These assets are strategically located at one
of the two major NGL trading hubs in the continental United States.
Conway Storage Assets
We own and operate three integrated underground NGL storage facilities in the Conway, Kansas
area with an aggregate storage capacity of approximately 20 million barrels, which we refer to as
the Conway West, Conway East and Mitchell storage facilities. Each facility is comprised of a
network of caverns located several hundred feet below ground, and all three facilities are
connected by pipeline. The caverns hold large volumes of NGLs and other hydrocarbons, such as
propylene and naphtha. We operate these assets as one coordinated facility. Three lines connect the
Mitchell facility to the Conway West facility and two lines connect the Conway East facility to the
Conway West Facility. These facilities have a total brine pond capacity of approximately 13 million
barrels. A brine pond is an above-ground location that stores brine, or salt water, until it is
pumped into the storage cavern to displace and move NGLs. These facilities generate revenues under
fee-based contractual arrangements.
Our Conway storage facilities interconnect directly with three end-use interstate NGL
pipelines: MAPL, NuStar and the ONEOK North System (formerly Kinder Morgan) pipeline. We also,
through connections of less than a mile, indirectly interconnect to an additional end-use
interstate NGL pipeline: the ONEOK pipeline. Through these pipelines and other storage facilities
we can provide our customers interconnectivity to additional interstate NGL pipelines. We believe
that the attributes of our storage facilities, such as the number and size of our caverns and well
bores and our extensive brine system, coupled with our direct connectivity to MAPL through multiple
meters allows our customers to inject, withdraw and deliver all of their products stored in our
facilities more rapidly than products stored with our competitors.
Conway Fractionation Facility
The Conway fractionation facility is strategically located at the junction of the south, east
and west legs of MAPL and has interconnections with the Buckeye pipeline and the ConocoPhillips
Chisholm pipeline, each of which transports mixed NGLs to our facility. The Conway fractionation
facility has a total design capacity of approximately 107,000 bpd and generates revenues under
fee-based contractual arrangements.
We own a 50% undivided interest in the Conway fractionation facility resulting in
proportionate capacity of approximately 53,500 bpd. ConocoPhillips and ONEOK own 40% and 10%
undivided interests, respectively. Each joint owner markets its own capacity independently. Each
owner can also contract with the other owners for additional capacity at the Conway fractionation
facility, if necessary. We are the operator of the facility pursuant to an operating agreement that
extends until May 2011.
8
NARRATIVE DESCRIPTION OF OUR BUSINESS AFTER COMPLETION OF THE
DROPDOWN
Operations of our businesses after the Dropdown continue to be located exclusively within the
United States. We manage our business and analyze our results of operations on a segment basis.
After the Dropdown, our operations are divided into two business segments:
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Gas Pipeline this segment includes our interstate natural gas pipelines and pipeline
joint venture investments. Gas Pipeline also includes our interests in WMZ, a
publicly traded master limited partnership that was formed by Williams in 2007. |
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Midstream Gas & Liquids this segment includes our natural gas gathering, treating and
processing business and is comprised of several wholly owned and partially owned
subsidiaries. |
Detailed discussion of each of our new business segments after the Dropdown follows.
Gas Pipeline
After the Dropdown, we own and operate a combined total of approximately 13,900 miles of
pipelines with a total annual throughput of approximately 2,700 TBtu of natural gas and peak-day
delivery capacity of approximately 12 MMdt of natural gas. Gas Pipeline consists of Transco and
Northwest Pipeline. Gas Pipeline also holds interests in joint venture interstate and intrastate
natural gas pipeline systems including a 24.5% interest in Gulfstream. Gas Pipeline also includes
WMZ.
Transco
Transco is an interstate natural gas transportation company that owns and operates a
10,000-mile natural gas pipeline system extending from Texas, Louisiana, Mississippi and the
offshore Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia,
Maryland, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves
customers in Texas and 11 southeast and Atlantic seaboard states, including major metropolitan
areas in Georgia, North Carolina, Washington, D.C., New York, New Jersey and Pennsylvania.
Pipeline system and customers
At December 31, 2009, Transcos system had a mainline delivery capacity of approximately 4.7
MMdt of natural gas per day from its production areas to its primary markets. Using its Leidy Line
along with market-area storage and transportation capacity, Transco can deliver an additional 3.9
MMdt of natural gas per day for a system-wide delivery capacity total of approximately 8.6 MMdt of
natural gas per day. Transcos system includes 45 compressor stations, four underground storage
fields, and an LNG storage facility. Compression facilities at sea level-rated capacity total
approximately 1.5 million horsepower.
Transcos major natural gas transportation customers are public utilities and municipalities
that provide service to residential, commercial, industrial and electric generation end users.
Shippers on Transcos system include public utilities, municipalities, intrastate pipelines, direct
industrial users, electrical generators, gas marketers and producers. Two of our customers
accounted for approximately 10% each of Transcos total revenues in 2009. Transcos firm
transportation agreements are generally long-term agreements with various expiration dates and
account for the major portion of Transcos business. Additionally, Transco offers storage services
and interruptible transportation services under short-term agreements.
Transco has natural gas storage capacity in four underground storage fields located on or near
its pipeline system or market areas and operates two of these storage fields. Transco also has
storage capacity in an LNG storage facility that we own and operate. The total usable gas storage
capacity available to Transco and its customers in such underground storage fields and LNG storage
facility and through storage service contracts is approximately 204 billion cubic feet of gas. In
addition, wholly owned subsidiaries of Transco operate and hold a 35 percent ownership interest in
Pine Needle LNG Company, LLC, an LNG storage facility with 4 billion cubic feet of storage
capacity. Storage capacity permits Transcos customers to inject gas into storage during the summer
and off-peak periods for delivery during peak winter demand periods.
Transco expansion projects
The pipeline projects listed below were completed during 2009 or are future significant
pipeline projects for which Transco has customer commitments.
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Sentinel Expansion Project
The Sentinel Expansion Project is a recently completed expansion of Transcos existing natural
gas transmission system from the Leidy Hub in Clinton County, Pennsylvania and from the Pleasant
Valley interconnection with Cove Point LNG in Fairfax County, Virginia to various delivery points
requested by the shippers under the project. The capital cost of the project is estimated to be up
to approximately $229 million. Phase I was placed into service in December 2008. Phase II was
placed into service in November 2009.
Mobile Bay South Expansion Project
The Mobile Bay South Expansion Project involves the addition of compression at Transcos
Station 85 in Choctaw County, Alabama, to allow Transco to provide firm transportation service
southbound on the Mobile Bay line from Station 85 to various delivery points. In May 2009, Transco
received approval from the FERC. The capital cost of the project is estimated to be approximately
$37 million. Transco plans to place the project into service by May 2010.
Mobile Bay South II Expansion Project
The Mobile Bay South II Expansion Project involves the addition of compression at Transcos
Station 85 in Choctaw County, Alabama, and modifications to existing facilities at Transcos
Station 83 in Mobile County, Alabama, to allow Transco to provide additional firm transportation
service southbound on the Mobile Bay line from Station 85 to various delivery points. In November
2009, Transco filed an application with the FERC. The capital cost of the project is estimated to
be approximately $36 million. Transco plans to place the project into service by May 2011.
85 North Expansion Project
The 85 North Expansion Project involves an expansion of Transcos existing natural gas
transmission system from Station 85 in Choctaw County, Alabama, to various delivery points as far
north as North Carolina. In September 2009, Transco received approval from the FERC. The capital
cost of the project is estimated to be $241 million. Transco plans to place the project into
service in phases, in July 2010 and May 2011.
Mid-South Expansion Project
The Mid-South Expansion Project involves an expansion of Transcos mainline from Station 85 in
Choctaw County, Alabama, to markets as far downstream as North Carolina. Transco anticipates filing
an application with the FERC in the fourth quarter of 2010. The capital cost of the project is
estimated to be approximately $200 million. Transco plans to place the project into service in
September 2012.
Mid-Atlantic Connector Project
The Mid-Atlantic Connector Project involves an expansion of Transcos mainline from an
existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far
downstream as Maryland. Transco anticipates filing an application with the FERC in the first
quarter of 2011. The capital cost of the project is estimated to be approximately $55 million.
Transco plans to place the project into service in November 2012.
Rockaway Delivery Lateral Project
The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore
lateral to National Grids distribution system in New York. Transco anticipates filing an
application with the FERC in the third quarter of 2010. The capital cost of the project is
estimated to be approximately $120 million. Transco plans to place the project into service in
November 2013.
10
Operating statistics
The following table summarizes transportation data for the Transco system for the periods
indicated:
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2009 |
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2008 |
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2007 |
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(In TBtu) |
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Market-area deliveries: |
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Long-haul transportation |
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624 |
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753 |
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839 |
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Market-area transportation |
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1,093 |
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969 |
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875 |
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Total market-area deliveries |
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1,717 |
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1,722 |
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1,714 |
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Production-area transportation |
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184 |
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188 |
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190 |
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Total system deliveries |
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1,901 |
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1,910 |
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1,904 |
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Average Daily Transportation Volumes |
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5.2 |
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5.2 |
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5.2 |
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Average Daily Firm Reserved Capacity |
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6.8 |
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6.8 |
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6.6 |
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Transcos facilities are divided into eight rate zones. Five are located in the production
area, and three are located in the market area. Long-haul transportation involves gas that Transco
receives in one of the production-area zones and delivers to a market-area zone. Market-area
transportation involves gas that Transco both receives and delivers within the market-area zones.
Production-area transportation involves gas that Transco both receives and delivers within the
production-area zones.
Northwest Pipeline
Northwest Pipeline is an interstate natural gas transportation company that owns and operates
a natural gas pipeline system extending from the San Juan basin in northwestern New Mexico and
southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on
the Canadian border near Sumas, Washington. Northwest Pipeline provides services for markets in
California, Arizona, New Mexico, Colorado, Utah, Nevada, Wyoming, Idaho, Oregon and Washington
directly or indirectly through interconnections with other pipelines.
Northwest Pipeline is currently owned 65% by us and 35% by WMZ. Assuming the successful
completion of the WMZ Exchange Offer and any follow-on cash call in which we acquire any
unexchanged WMZ units, Northwest Pipeline will be our wholly owned subsidiary.
Pipeline system and customers
At December 31, 2009, Northwest Pipelines system, having long-term firm transportation
agreements including peaking service of approximately 3.7 Bcf of natural gas per day, was composed
of approximately 3,900 miles of mainline and lateral transmission pipelines and 41 transmission
compressor stations having a combined sea level-rated capacity of approximately 473,000 horsepower.
In 2009, Northwest Pipeline served a total of 129 transportation and storage customers.
Northwest Pipeline transports and stores natural gas for a broad mix of customers, including local
natural gas distribution companies, municipal utilities, direct industrial users, electric power
generators and natural gas marketers and producers. The two largest customers of Northwest Pipeline
in 2009 accounted for approximately 22% and 11%, respectively, of its total operating revenues. No
other customer accounted for more than 10% of Northwest Pipelines total operating revenues in
2009. Northwest Pipelines firm transportation and storage contracts are generally long-term
contracts with various expiration dates and account for the major portion of Northwest Pipelines
business. Additionally, Northwest Pipeline offers interruptible and short-term firm transportation
service.
Northwest Pipeline owns a one-third interest in the Jackson Prairie underground storage
facility in Washington and contracts with a third party for storage service in the Clay Basin
underground field in Utah. Northwest Pipeline also owns and operates an LNG storage facility in
Washington. These storage facilities, which have an aggregate working gas storage capacity of 13
Bcf of gas and firm delivery capability of approximately 700 MMcf of gas per day, enable Northwest
Pipeline to provide storage services to its customers and to balance daily receipts and deliveries.
Northwest Pipeline expansion projects
The pipeline projects listed below were completed during 2009 or are future pipeline projects
for which Northwest Pipeline has customer commitments.
11
Colorado Hub Connection Project
In November 2009, Northwest Pipeline placed into service the new 27-mile, 24-inch diameter
lateral referred to as the Colorado Hub Project (CHC Project). The new lateral connects the
Meeker/White River Hub near Meeker, Colorado to its mainline south of Rangely, Colorado, and is
estimated to cost up to $60 million. The CHC Project combined the new lateral capacity with
existing mainline capacity to provide approximately 363 MDth per day of firm transportation from
various receipt points to delivery points on the mainline as far south as Ignacio, Colorado.
In April 2009, the FERC issued a certificate approving the CHC Project, including the
presumption of rolling in the costs of the project in any future rate case filed with the FERC.
Sundance Trail Expansion
In November 2009, Northwest Pipeline received approval from the FERC to construct
approximately 16 miles of 30-inch loop between Northwest Pipelines existing Green River and Muddy
Creek compressor stations in Wyoming as well as an upgrade to Northwest Pipelines existing Vernal
compressor station, with service targeted to commence in November 2010. The total project is
estimated to cost up to $65 million, including the cost of replacing existing compression at
Vernal, which will enhance the efficiency of Northwest Pipelines system. Northwest Pipeline
executed a precedent agreement for 150 MDth per day of firm transportation service from the
Greasewood and Meeker Hubs in Colorado for delivery to the Opal Hub in Wyoming. Northwest Pipeline
has proposed to collect its maximum system rates and in the certificate order approving the
project, the FERC granted the presumption of rolling in the costs of the project in any future rate
cases.
Operating statistics
The following table summarizes volume and capacity data for the Northwest Pipeline system for
the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(In TBtu) |
|
|
|
|
|
Total Transportation Volume |
|
|
769 |
|
|
|
781 |
|
|
|
757 |
|
Average Daily Transportation Volumes |
|
|
2.1 |
|
|
|
2.1 |
|
|
|
2.1 |
|
Average Daily Reserved Capacity Under Base Firm Contracts, excluding peak capacity |
|
|
2.7 |
|
|
|
2.5 |
|
|
|
2.5 |
|
Average Daily Reserved Capacity Under Short-Term Firm Contracts (1) |
|
|
0.5 |
|
|
|
0.7 |
|
|
|
0.8 |
|
|
|
|
(1) |
|
Consists primarily of additional capacity created from time to
time through the installation of new receipt or delivery points
or the segmentation of existing mainline capacity. Such capacity
is generally marketed on a short-term firm basis. |
Gulfstream
Gulfstream is a natural gas pipeline system extending from the Mobile Bay area in Alabama to
markets in Florida. Gulfstream is owned by the following entities:
|
|
|
|
|
Owners of Gulfstream |
|
Ownership Interest |
|
Williams Partners Operating LLC, a subsidiary of Williams Partners L.P. |
|
|
24.5 |
% |
WGP Gulfstream Pipeline Company, L.L.C., an indirect, wholly owned subsidiary of Williams |
|
|
25.5 |
% |
Spectra
Energy Partners OLP, LP, a Delaware master limited partnership |
|
|
24.5 |
% |
Spectra Energy Southeast Pipeline Corporation, an indirect, wholly owned subsidiary of
Spectra Energy Corporation |
|
|
25.5 |
% |
Gulfstream expansion projects
Gulfstream placed the Phase III expansion project in service on September 1, 2008. The project
extended the pipeline system into South Florida and fully subscribed the remaining 345 Mdt/d of
firm capacity on the existing pipeline system on a long-term basis. The capital cost of this
project was $118 million. Service under the Gulfstream Phase IV expansion project began during the
fourth quarter of 2008. The project is fully subscribed on a long-term basis and is the first
incremental expansion of Gulfstreams mainline capacity.
12
The capital cost of this expansion was $190 million. The Phase V expansion involves the
addition of compression to provide 35 Mdt/d of firm capacity by July 2011. The estimated capital
cost of this expansion is approximately $54 million with our share being 24.5% of such cost
incurred after completion of the Dropdown.
WMZ
WMZ was formed to own and operate natural gas transportation and storage assets. After the
Dropdown, we own an approximate 45.7% limited partnership interest and a 2% general partner
interest in WMZ. A subsidiary of ours, Williams Pipeline GP LLC, serves as the general partner of
WMZ. WMZ owns a 35% interest in Northwest Pipeline.
In connection with the announcement of the Dropdown, we announced our intention to launch an
exchange offer for the publicly held units of WMZ at a future date, subject to certain conditions.
Please read Recent Events
WMZ Exchange Offer above for more information.
Midstream Gas & Liquids
Our Midstream segment, one of the nations largest natural gas gatherers and processors, has
primary service areas concentrated in major producing basins in Colorado, New Mexico, Wyoming, the
Gulf of Mexico and Pennsylvania. Midstreams primary businesses natural gas gathering, treating,
and processing; NGL fractionation, storage and transportation; and oil transportation fall
within the middle of the process of taking raw natural gas and crude oil from the producing fields
to the consumer.
Key variables for our business will continue to be:
|
|
|
Retaining and attracting customers by continuing to provide reliable services; |
|
|
|
|
Revenue growth associated with additional infrastructure either completed or currently
under construction; |
|
|
|
|
Disciplined growth in our core service areas and new step-out areas; |
|
|
|
|
Prices impacting our commodity-based processing activities. |
Gathering, processing and treating
Our gathering systems receive natural gas from producers oil and natural gas wells and gather
these volumes to gas processing, treating or redelivery facilities. Typically, natural gas, in its
raw form, is not acceptable for transportation in major interstate natural gas pipelines or for
commercial use as a fuel. In addition, natural gas contains various amounts of NGLs, which
generally have a higher value when separated from the natural gas stream. Our processing and
treating plants remove water vapor, carbon dioxide and other contaminants and our processing plants
extract the NGLs. NGL products include:
|
|
|
Ethane, primarily used in the petrochemical industry as a feedstock for ethylene
production, one of the basic building blocks for plastics; |
|
|
|
|
Propane, used for heating, fuel and as a petrochemical feedstock in the production of
ethylene and propylene, another building block for petrochemical-based products such as
carpets, packing materials and molded plastic parts; |
|
|
|
|
Normal butane, iso-butane and natural gasoline, primarily used by the refining industry
as blending stocks for motor gasoline or as a petrochemical feedstock. |
Although a significant portion of our gas processing services are performed for a
volumetric-based fee, a portion of our gas processing agreements are commodity-based and include
two distinct types of commodity exposure. The first type includes keep-whole processing
agreements whereby we own the rights to the value from NGLs recovered at our plants and have the
obligation to replace the lost heating value with natural gas. Under these agreements, we are
exposed to the spread between NGL prices and natural gas prices. The second type consists of
percent-of-liquids agreements whereby we receive a portion of the extracted liquids with no
direct exposure to the price of natural gas. Under these agreements, we are only exposed to NGL
price movements. NGLs we retain in connection with both of these types of processing agreements are
referred to as our equity NGL production. Our gathering and processing agreements have terms
ranging from month-to-month to the life of the producing lease. Generally, our gathering and
processing agreements are long-term agreements.
13
Our gas gathering and processing customers are generally natural gas producers who have proved
and/or producing natural gas fields in the areas surrounding our infrastructure. During 2009, these
operations gathered and processed gas for approximately 230 gas gathering and processing customers.
Our top 7 gathering and processing customers accounted for approximately 50% of our gathering and
processing revenue.
In addition to our natural gas assets, we own and operate three deepwater crude oil pipelines
and own two production platforms serving the deepwater in the Gulf of Mexico. Our crude oil
transportation revenues are typically volumetric-based fee arrangements. However, a portion of our
marketing revenues are recognized from purchase and sale arrangements whereby we purchase oil from
producers at the receipt points of our crude oil pipelines for an index-based price and resell the
oil at delivery points at the same index-based price. Our offshore floating production platform
provides centralized services to deepwater producers such as compression, separation, production
handling, water removal and pipeline landings. Revenue sources have historically included a
combination of fixed-fee, volumetric-based fee and cost reimbursement arrangements. Fixed fees
associated with the resident production at our Devils Tower facility are recognized on a
units-of-production basis.
Geographically, our Midstream natural gas assets are positioned to maximize commercial and
operational synergies with Williams and our other assets. For example, most of our offshore
gathering and processing assets attach and process or condition natural gas supplies delivered to
the Transco pipeline. Also, our gathering and processing facilities in the San Juan basin handle
approximately 87% of Williams Exploration & Production segments equity production in this basin.
Our Willow Creek plant, completed in 2009, is currently processing Williams Exploration &
Production segments wellhead production in the Piceance basin. Our San Juan basin, southwest
Wyoming and Willow Creek systems deliver residue gas volumes into Northwest Pipelines interstate
system in addition to third-party interstate systems.
West region gathering, processing and treating
We own and/or operate gas gathering, processing and treating assets within the western states
of Wyoming, Colorado and New Mexico.
In the Rocky Mountain area, our assets include:
|
|
|
Approximately 3,500 miles of gathering pipelines with a capacity of nearly one Bcf/d and
over 4,000 receipt points serving the Wamsutter and southwest Wyoming areas in Wyoming; |
|
|
|
|
Opal and Echo Springs processing plants with a combined daily inlet capacity of over
1,800 MMcf/d and NGL processing capacity of nearly 100 Mbbls/d. |
In
the Four Corners area, our assets include:
|
|
|
Approximately 3,800 miles of gathering pipelines with a capacity of nearly two Bcf/d and
approximately 6,500 receipt points serving the San Juan basin in New Mexico and Colorado; |
|
|
|
|
Ignacio, Kutz and Lybrook processing plants with a combined daily inlet capacity of 765
MMcf/d and NGL processing capacity of approximately 40 Mbbls/d. The Ignacio plant also has
the capacity to produce slightly more than one Mbbls/d of LNG; |
|
|
|
|
Milagro and Esperanza natural gas treating plants, which remove carbon dioxide but do not
extract NGLs, with a combined daily inlet capacity of 750 MMcf/d. At our Milagro facility,
we also use gas-driven turbines to produce approximately 60 mega-watts per day of
electricity which we primarily sell into the local electrical grid. |
In the Piceance basin in Colorado, our infrastructure includes:
|
|
|
The Willow Creek processing plant, a 450 MMcf/d cryogenic natural gas processing plant in
western Colorados Piceance basin, is designed to recover 30 Mbbls/d of NGLs. In the third
quarter of 2009, construction was finished and the plant began operations. The plant is
currently operating at its designed inlet capacity. In the current processing arrangement
with Williams Exploration & Production segment, Midstream receives a volumetric-based
processing fee and a percent of the NGLs extracted. |
14
|
|
|
Parachute Lateral, a 38-mile, 30-inch diameter line transporting gas from the Parachute
area to the Greasewood hub and White River hub in northwest Colorado. Our Willow Creek plant
processes gas flowing through the Parachute Lateral. |
|
|
|
|
PGX pipeline delivering NGLs previously transported by truck from Williams Exploration &
Production segments existing Parachute area processing plants to a major NGL transportation
pipeline system. |
West region expansion projects
Our major capital and expansion projects include additional capacity at our Echo Springs
facility and related gathering system expansions in the Wamsutter basin.
|
|
|
We expect to significantly increase the processing and NGL production capacities at our
Echo Springs cryogenic natural gas processing plant in Wyoming. The addition of a fourth
cryogenic processing train will add approximately 350 MMcf/d of processing capacity and 30
Mbbls/d of NGL production capacity, nearly doubling Echo Springs capacities in both cases.
We began construction on the fourth train at Echo Springs during the second half of 2009 and
expect to bring the additional capacity online during late 2010. |
Gulf region gathering, processing and treating
We own and/or operate gas gathering and processing assets and crude oil pipelines primarily
within the onshore and offshore shelf and deepwater areas in and around the Gulf Coast states of
Texas, Louisiana, Mississippi and Alabama. We own:
|
|
|
Over 700 miles of onshore and offshore natural gas gathering pipelines with a combined
capacity of approximately 3.5 Bcf/d, including: |
|
|
|
The 115-mile deepwater Seahawk gas pipeline in the western Gulf of Mexico, flowing
into our Markham processing plant and serving the Boomvang and Nansen field areas; |
|
|
|
|
The 139-mile Canyon Chief gas pipeline, now including the 37-mile Blind Faith
extension added in the fourth quarter of 2008, in the eastern Gulf of Mexico, flowing
into our Mobile Bay processing plant and serving the Devils Tower, Triton, Goldfinger,
Bass Lite and Blind Faith fields; |
|
|
|
Mobile Bay and Markham processing plants with a combined daily inlet capacity of nearly
1,000 MMcf/d and NGL handling capacity of 50 Mbbls/d; |
|
|
|
|
Canyon Station production platform, which brings natural gas to specifications allowable
by major interstate pipelines but does not extract NGLs, with a daily inlet capacity of 500
MMcf/d; |
|
|
|
|
Three deepwater crude oil pipelines with a combined length of 300 miles and capacity of
325 Mbbls/d including: |
|
|
|
BANJO pipeline running parallel to the Seahawk gas pipeline delivering
production from two producer-owned spar-type floating production systems; and delivering
production to our shallow-water platform at Galveston Area Block A244 (GA-A244) and then
onshore through ExxonMobils Hoover Offshore Oil Pipeline System (HOOPS); |
|
|
|
|
Alpine pipeline in the central Gulf of Mexico, serving the Gunnison field,
and delivering production to GA-A244 and then onshore through HOOPS under a joint tariff
agreement; |
|
|
|
|
Mountaineer oil pipeline which connects to similar production sources as our
Canyon Chief pipeline and, now including the new Blind Faith extension, ultimately
delivering production to ChevronTexacos Empire Terminal in Plaquemines Parish,
Louisiana; |
|
|
|
Devils Tower production platform located in Mississippi Canyon Block 773, approximately
150 miles south-southwest of Mobile, Alabama and serving production from the Devils Tower,
Triton, Goldfinger and Bass Lite fields. Located in 5,610 feet of water, it is one of the
worlds deepest dry tree spars. The platform, which is operated by ENI Petroleum on our
behalf, is capable of handling 210 MMcf/d of natural gas and 60 Mbbls/d of oil. |
15
Gulf region expansion projects
Our current major expansion project in the Gulf region is our Perdido Norte project located in
the western deepwater of the Gulf of Mexico. The investment expands our existing infrastructure and
includes a total of 184 miles of oil and gas pipeline and a 200 MMcf/d expansion of our onshore
Markham gas processing facility. We expect the project to begin start-up operations in the first
quarter of 2010.
NGL marketing services
In addition to our gathering and processing operations, we market NGLs products to a wide
range of users in the energy and petrochemical industries. The NGL marketing business transports
and markets equity NGLs from the production at our processing plants, and also markets NGLs on
behalf of third-party NGL producers, including some of our fee-based processing customers, and the
NGL volumes owned by Discovery. The NGL marketing business bears the risk of price changes in these
NGL volumes while they are being transported to final sales delivery points. In order to meet sales
contract obligations, we may purchase products in the spot market for resale. The majority of sales
are based on supply contracts of one year or less in duration.
Other
We own interests in and/or operate NGL fractionation and storage assets. These assets include
two partially owned NGL fractionation facilities: one near Conway, Kansas and the other in Baton
Rouge, Louisiana that have a combined capacity in excess of 167 Mbbls/d. We also own approximately
20 million barrels of NGL storage capacity in central Kansas near Conway.
We own a 60% equity interest in and operate the facilities of Discovery. Discoverys assets
include a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32 Mbbls/d
NGL fractionator plant near Paradis, Louisiana and an offshore natural gas gathering and
transportation system in the Gulf of Mexico.
We also own a 14.6% equity interest in Aux Sable Liquid Products and its Channahon, Illinois
gas processing and NGL fractionation facility near Chicago. The facility is capable of processing
up to 2.1 Bcf/d of natural gas from the Alliance Pipeline system and fractionating approximately 87
Mbbls/d of extracted liquids into NGL products.
In June 2009, we completed the formation of a new joint venture, Laurel Mountain Midstream LLC
(Laurel Mountain), in the Marcellus Shale located in southwest Pennsylvania. Our partner in the
venture contributed its existing Appalachian basin gathering system, which has an average
throughput of approximately 100 MMcf/d. In exchange for a 51% interest, we contributed $100 million
and issued a $26 million note payable. In 2010, we expect to significantly increase our investment
in our Laurel Mountain joint venture through new gathering system infrastructure construction.
In conjunction with a long-term agreement with a major producer, we will construct a 28-mile
natural gas gathering pipeline in the Marcellus Shale region that will deliver to the Transco
pipeline. Construction is expected to begin on the 20-inch pipeline in the latter part of 2010,
and it is expected to be placed into service during 2011. We will operate the pipeline, which
represents our second significant midstream expansion in the Marcellus Shale.
16
Operating statistics
The following table summarizes our significant operating statistics for Midstream:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Volumes: (1) |
|
|
|
|
|
|
|
|
|
|
|
|
Gathering (TBtu) |
|
|
1,068 |
|
|
|
1,013 |
|
|
|
1,045 |
|
Plant inlet natural gas (TBtu) |
|
|
1,342 |
|
|
|
1,311 |
|
|
|
1,275 |
|
NGL production (Mbbls/d) (2) |
|
|
164 |
|
|
|
154 |
|
|
|
163 |
|
NGL equity sales (Mbbls/d) (2) |
|
|
80 |
|
|
|
80 |
|
|
|
92 |
|
Crude oil gathering (Mbbls/d) (2) |
|
|
109 |
|
|
|
70 |
|
|
|
80 |
|
|
|
|
(1) |
|
Excludes volumes associated with partially owned assets, such as
our Discovery and Laurel Mountain investments, that are not
consolidated for financial reporting purposes. |
|
(2) |
|
Annual average Mbbls/d. |
REGULATORY MATTERS
Gas Pipeline
Gas Pipelines interstate transmission and storage activities are subject to FERC regulation
under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, and, as such,
its rates and charges for the transportation of natural gas in interstate commerce, its accounting,
and the extension, enlargement or abandonment of its jurisdictional facilities, among other things,
are subject to regulation. Each gas pipeline company holds certificates of public convenience and
necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and
properties for which certificates are required under the NGA. FERC Standards of Conduct govern how
our interstate pipelines communicate and do business with gas marketing employees. Among other
things, the Standards of Conduct require that interstate pipelines not operate their systems to
preferentially benefit gas marketing functions.
Each of our interstate natural gas pipeline companies establishes its rates primarily through
the FERCs ratemaking process. Key determinants in the ratemaking process are:
|
|
|
Costs of providing service, including depreciation expense; |
|
|
|
|
Allowed rate of return, including the equity component of the capital structure and
related income taxes; |
|
|
|
|
Volume throughput assumptions. |
The allowed rate of return is determined in each rate case. Rate design and the allocation of
costs between the demand and commodity rates also impact profitability. As a result of these
proceedings, certain revenues previously collected may be subject to refund.
Midstream Gas & Liquids
For our Midstream segment, onshore gathering is subject to regulation by states in which we
operate and offshore gathering is subject to the Outer Continental Shelf Lands Act (OCSLA). Of the
states where Midstream gathers gas, currently only Texas actively regulates gathering activities.
Texas regulates gathering primarily through complaint mechanisms under which the state commission
may resolve disputes involving an individual gathering arrangement. Although offshore gathering
facilities are not subject to the NGA, offshore transmission pipelines are subject to the NGA, and
in recent years the FERC has taken a broad view of offshore transmission, finding many
shallow-water pipelines to be jurisdictional transmission. Most gathering facilities offshore are
subject to the OCSLA, which provides in part that outer continental shelf pipelines must provide
open and nondiscriminatory access to both owner and nonowner shippers.
Midstream also owns interests in and operates two offshore transmission pipelines that are
regulated by the FERC because they are deemed to transport gas in interstate commerce. Black Marlin
Pipeline Company provides transportation service for offshore Texas production in the High Island
area and redelivers that gas to intrastate pipeline interconnects near Texas City. Discovery
provides
17
transportation service for offshore Louisiana production from the South Timbalier, Grand
Isle, Ewing Bank and Green Canyon (deepwater) areas to an onshore processing facility and
downstream interconnect points with major interstate pipelines. FERC regulation requires all terms
and conditions of service, including the rates charged, to be filed with and approved by the FERC
before any changes can go into effect. In 2007, Black Marlin filed and settled a major rate change
application before the FERC, resulting in increased rates for service. In November 2007, Discovery
filed a settlement in lieu of a rate change filing, which the FERC approved effective January 1,
2008, for all parties, except one protestor, Exxon Mobil Gas and Power Marketing Company. Among
other things, the settlement increases Discoverys rates for service, although most volumes flowing
before the settlement became effective are not affected by the rate change due to life of lease
rates and commitments.
Safety and Maintenance
Each gas pipeline company is subject to the Natural Gas Pipeline Safety Act of 1968, as
amended, and the Pipeline Safety Improvement Act of 2002 (PSIA), which regulates safety
requirements in the design, construction, operation and maintenance of interstate natural gas
transmission facilities. The Natural Gas Pipeline Safety Act regulates safety requirements in the
design, construction, operation and maintenance of gas pipeline facilities while the Pipeline
Safety Improvement Act establishes mandatory inspections for all United States oil and natural gas
transportation pipelines and some gathering lines in certain high-consequence areas.
Certain of our natural gas pipelines are subject to regulation by, among others, the United
States Department of Transportation (DOT) under the Accountable Pipeline and Safety Partnership Act
of 1996 (often referred to as the Hazardous Liquid Pipeline Safety Act) and comparable state
statutes with respect to design, installation, testing, construction, operation, replacement and
management. These statutes require access to and copying of records and the filing of certain
reports and carry potential fines and penalties for violations.
Gas Pipeline Integrity Regulations
The DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) rules implementing the
PSIA require pipeline operators to implement integrity management programs, including more frequent
inspections and other safeguards in areas where the potential consequences of pipeline accidents
pose the greatest risk to people and property. In accordance with the final rule, Transco and
Northwest Pipeline developed Integrity Management Plans, identified high-consequence areas,
completed baseline assessment plans, and are on schedule to complete the required assessments
within specified timeframes. Currently, Transco and Northwest Pipeline estimate that the cost to
perform required assessments and remediation will be primarily capital and range between $150
million and $220 million and between $65 million and $85 million, respectively, over the remaining
assessment period of 2010 through 2012.
Management
considers the costs incurred by Transco and Northwest to comply with
the PHMSA rule to be prudent costs incurred in the ordinary course of business and, therefore,
recoverable through their respective rates.
Midstream
Discoverys gas pipeline system is subject to the Natural Gas Pipeline Safety Act of 1968 and
the Pipeline Safety Improvement Act of 2002. Discovery currently anticipates incurring costs of
approximately $0.3 million in 2010 to implement integrity management program testing along certain
segments of Discoverys 16, 20 and 30-inch diameter natural gas pipelines and its 10, 14 and
18-inch diameter NGL pipelines. This does not include the costs, if any, of repair, remediation, or
any preventative or mitigating actions that may be deemed necessary as a result of the testing
program.
States are largely preempted by federal law from regulating pipeline safety but may, in
certain cases, assume responsibility for enforcing federal intrastate pipeline regulations and
inspection of intrastate pipelines. In practice, states vary considerably in their authority and
capacity to address pipeline safety. We do not anticipate any significant problems in complying
with applicable state laws and regulations in those states in which we or the entities in which we
own an interest operate.
We are also subject to a number of federal and state laws and regulations such as the federal
Occupational Safety and Health Act, referred to as OSHA, and comparable state statutes, whose
purpose is to protect the health and safety of workers and the general public, both generally and
within the pipeline industry. In addition, the OSHA hazard communication standard, the United
States Environmental Protection Agency (EPA) community right-to-know regulations under Title III of
the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that
information be maintained about hazardous materials used or
18
produced in our operations and that
this information be provided to employees, state and local government authorities and citizens. We
and some of the entities in which we own an interest are also subject to OSHA Process Safety
Management regulations, which are designed to prevent or minimize the consequences of catastrophic
releases of toxic, reactive, flammable or explosive chemicals. These regulations, with a few
exemptions, apply to any process which involves a chemical at or above the specified thresholds or
any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess
of 10,000 pounds at various locations. We have an internal program of inspection designed to
monitor and enforce compliance with worker safety requirements. We believe that we remain in
material compliance with the OSHA and similar state and local regulations.
ENVIRONMENTAL REGULATION
We are subject to extensive and complex federal, state and local laws and regulations relating
to the protection of the environment. As with the industry generally, compliance with current and
anticipated environmental laws and regulations increases our overall cost of business, including
our capital costs to construct, maintain, operate, and upgrade equipment and facilities. While
these laws and regulations carry significant costs, they do not affect competitiveness because our
competitors are similarly affected. These laws and regulations can restrict or impact our business
activities in many ways, such as:
|
|
|
requiring the acquisition of permits to conduct regulated activities; |
|
|
|
|
restricting the manner in which materials can be released into the environment; |
|
|
|
|
imposing investigatory and remedial obligations to monitor or mitigate emissions or
releases from former or current operations; |
|
|
|
|
imposing significant reporting requirements; |
|
|
|
|
assessing administrative, civil and criminal penalties for failure to comply with
applicable legal requirements; |
|
|
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in certain instances, enjoining some or all of the operations of facilities deemed in
non-compliance with permits issued pursuant to applicable laws and regulations; and |
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limiting or prohibiting construction activities in sensitive areas such as wetlands,
coastal regions, or areas inhabited by endangered species. |
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Environmental laws and regulations affecting us include, but are not limited to: |
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Resource Conservation and Recovery Act (RCRA) and analogous state laws, which impose
stringent requirements for the management of solid wastes, including hazardous wastes,
pursuant to a comprehensive regulatory regime; |
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Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) and
analogous state laws, which 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; |
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Clean Air Act (CAA) and analogous state laws, which impose obligations related to air
emissions; |
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Clean Water Act (CWA) and analogous state laws, which regulate discharge of wastewaters
from our facilities to state and federal waters; |
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the National Environmental Policy Act (NEPA), which requires federal agencies to assess
and consider the environmental impacts of major federal projects (which may include
situations where federal money, lands, or permitting are involved) when making decisions; |
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the Endangered Species Act (ESA), which requires the evaluation of potential impact on
endangered or threatened species and may restrict activities that adversely affect such
species; |
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the Rivers and Harbors Act which, among other things, requires permits for the
installation of structures and other work in navigable waters of the United States; and |
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the Toxic Substances Control Act (TSCA), which provides the EPA with authority to
require reporting, record-keeping and testing requirements, and restrictions relating to
chemical substances and/or mixtures. |
Failure to comply with these laws and regulations may trigger a variety of administrative,
civil and criminal enforcement measures, including the assessment of monetary penalties, the
imposition of remedial requirements, and the issuance of orders enjoining future operations.
Certain environmental statutes impose strict, joint and several liability for costs required to
clean up and restore sites where hazardous substances have been disposed or otherwise released.
Moreover, it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and property damage
allegedly caused by the release of substances or other waste products into the environment.
The trend in environmental regulation is to place more restrictions and limitations on
activities that may affect the environment, and thus there can be no assurance as to the amount or
timing of future expenditures for environmental compliance or remediation, and actual future
expenditures may be different from the amounts currently anticipated.
We have ongoing programs designed to keep our operations in compliance with existing
environmental laws and regulations and to monitor changes in applicable regulations. The following
is a discussion of some of the environmental laws and regulations that are applicable to natural
gas gathering, processing, transportation and storage activities and that may have a material
impact on our businesses.
Waste Management
Our operations generate hazardous and non-hazardous solid wastes that may be subject to laws
designed to track and control waste disposal, including RCRA, TSCA and comparable state laws, which
impose detailed requirements for the handling, storage, treatment and disposal of hazardous and
non-hazardous solid wastes. Hazardous waste laws may also require corrective action, including the
investigation and remediation of certain units, at a facility where such waste may have been
released or disposed. For instance, CERCLA and comparable state laws impose liability, often
without regard to fault or the legality of the original conduct, on certain classes of persons that
may or may not have contributed to the release of a hazardous substance into the environment.
These persons include the owner or operator of the site where the release occurred and companies
that disposed or arranged for the disposal of the hazardous substances found at the site, as well
as successors in interest. Despite the petroleum exclusion of CERCLA Section 101(14) that
currently includes natural gas, our businesses may nonetheless handle other hazardous substances
within the meaning of CERCLA or similar state statutes, in the course of ordinary operations and,
as a result, we 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.
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 operations, will in the future be designated as
hazardous wastes and, therefore, become 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 maintenance capital expenditures and operating expenses.
Site Remediation
CERCLA and comparable state laws may impose liability, without regard to fault or the legality
of the original conduct, on certain classes of persons responsible for the release of hazardous
substances into the environment. Such classes of persons include the current and past owner or
operator of a site where a hazardous substance was released into the environment, and companies
that disposed or arranged for the disposal of hazardous substances found at the site. Under CERCLA,
such persons may be subject to joint and several strict liability for the costs of cleaning up the
hazardous substances that were 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 cases third
parties, to take actions in response to threats to the public health or the environment and to seek
to recover from the responsible classes of persons the costs that they incur. Moreover, it is not
uncommon for neighboring landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the release of substances or wastes into the environment.
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We currently own or lease properties that for many years have been used for the
transportation, compression, and storage of natural gas. Although they typically used operating and
disposal practices that were standard in the industry at the time, petroleum hydrocarbons and
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
such substances have been taken for recycling or disposal. In addition, some of these properties
may have been operated by third parties or by previous owners whose treatment and disposal or
release of petroleum hydrocarbons or wastes was not under their control. These properties and the
substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, our businesses could be required to (i) remove previously disposed wastes,
including waste disposed of by prior owners or operators; (ii) remediate contaminated property,
including groundwater contamination, whether from prior owners or operators or other historic
activities or spills; or (iii) perform remedial closure operations to prevent future contamination.
Air Emissions
We are subject to increasingly stringent air regulations, and threshold limits and applicable
control technologies written into the regulations regularly change over time, keeping standards
dynamic. The CAA, as amended, and comparable state laws regulate emissions of air pollutants from
various industrial sources, including compressor stations, and also impose various monitoring and
reporting requirements. Such laws and regulations may require (i) pre-approval for the construction
or modification of certain projects or facilities expected to produce air emissions or result in an
increase of existing air emissions; (ii) application for and strict compliance with air permits
containing various emissions and operational limitations; or (iii) the utilization of specific
emission control technologies to limit emissions. Failure to comply with these requirements could
result in the assessment of monetary penalties and the pursuit of potentially criminal enforcement
actions, the issuance of injunctions, and the further imposition of conditions or restrictions on
permitted operations.
We may incur expenditures in the future for air pollution control equipment in connection with
obtaining or maintaining operating permits and approvals for air emissions. For instance, our
businesses may be required to supplement or modify air emission control equipment and strategies
due to changes in state implementation plans for controlling air emissions in regional
non-attainment areas, or stricter regulatory requirements for sources of hazardous air pollutants.
We believe that any such future requirements imposed on our businesses will not have a material
adverse effect on their operations.
Water Discharges
Laws and regulations that protect surface and groundwater, including the CWA and analogous
state laws, impose restrictions and often strict controls with respect to discharges, including
stormwater runoff and spills and leaks of oil and other substances associated with our operations,
into certain surface and groundwater. The discharge of most substances into regulated waters is
prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state
agency. These controls, including permits associated thereunder, often require monitoring and
reporting and may impose substantial potential civil and criminal penalties for noncompliance. We
believe that compliance with existing permits and foreseeable new permit requirements will not have
a material adverse effect on our financial condition or results of operations.
Activities on Federal Lands
Our activities conducted on federal lands may be subject to review and assessment under
current permits, federal land management directives and/or provisions of NEPA. NEPA requires
federal agencies, including the Department of Interior, to evaluate major federal agency actions
having the potential to significantly impact the environment. In the course of such evaluations,
agencies prepare environmental assessments, or more detailed environmental impact statements which
assess the potential direct, indirect and cumulative impacts of a proposed project and may be made
available for public review and comment. Our businesses current activities, as well as any
proposed plans for future activities, on federal lands are subject to the requirements of NEPA.
Endangered Species
The ESA restricts activities that may affect threatened and endangered species or their
habitats. Some facilities operated by Transco and Northwest are located in areas inhabited by
threatened or endangered species. If the activities of any of our businesses are deemed to
adversely affect endangered species or their habitats, we could incur additional costs or become
subject to operating restrictions or bans in the affected area. Civil and criminal penalties can be
imposed against any person violating the ESA.
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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. Please read Safety and Maintenance.
Kansas Department of Health and Environment Obligations
We currently own and operate underground storage caverns near Conway, Kansas. These storage
caverns are used to store NGLs and other liquid hydrocarbons and are subject to strict
environmental regulation by the KDHE. The current revision of the Underground Hydrocarbon and
Natural Gas Storage regulations became effective in 2003 and regulates the storage of liquefied
petroleum gas and other hydrocarbons in bedded salt for the purpose of protecting public health and
safety, property and the environment. The revision also regulates the construction, operation and
closure of brine ponds associated with our storage caverns. These regulations specify several
compliance deadlines including the due date for final permit submittals, which was met by April 1,
2006, and the April 1, 2010 deadline for completion of mechanical integrity and casing testing
requirements, which we believe our facilities will meet. Failure to comply with the Underground
Hydrocarbon and Natural Gas Storage program may lead to the assessment of administrative, civil or
criminal penalties.
We are in the process of modifying our Conway storage facilities, including the caverns and
brine ponds, and we believe that our storage operations will be in compliance with the Underground
Hydrocarbon Storage (UHS) program regulations by the applicable compliance dates. In 2003, we began
to complete workovers on approximately 30 to 35 salt caverns per year and install, on average, a
double liner on one to two brine ponds per year. We expect, on average, to complete workovers on
each of our caverns every five to ten years and install double liners on each of our brine ponds
every 18 years.
Additionally, we are currently undergoing remedial activities pursuant to KDHE Consent Orders
issued in the early 1990s. The Consent Orders were issued after elevated concentrations of
chlorides were discovered in various on-site and off-site shallow groundwater resources at each of
our Conway storage facilities. With KDHE approval, we have installed and are operating containment
and monitoring systems to contain the migration of the chloride plume at all three UHS facilities.
However, investigation and delineation of chloride impacts is ongoing at Conway Underground East
and Conway West 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 Conway West facility, remediation of residual hydrocarbon derivatives from a historic
pipeline release is included in the consent order required activities.
Although not mandated by any consent order, we are currently cooperating with the KDHE and
other area operators in an investigation of NGLs observed in the subsurface at the Conway
Underground East facility. In addition, we have also recently detected NGLs in groundwater
monitoring wells adjacent to two abandoned storage caverns at the Conway West facility. Although
the complete extent of the contamination appears to be limited and appears to have been arrested,
we are continuing to work to delineate further the scope of the contamination. To date, the KDHE
has not undertaken any enforcement action related to the NGL releases around the abandoned storage
caverns.
We are continuing to monitor and evaluate our assets to prevent future releases. While we
maintain an extensive inspection and audit program designed, as appropriate, to prevent and to
detect and address such releases promptly, there can be no assurance that future environmental
releases from our assets will not have a material effect on us.
For more information about environmental compliance and other environmental issues, please
read Environmental under Managements Discussion and Analysis of Financial Condition and Results
of Operations and Note 16, Commitments and Contingencies, in our Notes to Consolidated Financial
Statements in this report.
COMPETITION AFTER COMPLETION OF THE DROPDOWN
Gas Pipeline. The natural gas industry has undergone significant change over the past two
decades. A highly-liquid competitive commodity market in natural gas and increasingly competitive
markets for natural gas services, including competitive secondary markets in pipeline capacity,
have developed. As a result, pipeline capacity is being used more efficiently, and peaking and
storage services are increasingly effective substitutes for annual pipeline capacity.
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Local distribution company (LDC) and electric industry restructuring by states have affected
pipeline markets. Pipeline operators are increasingly challenged to accommodate the flexibility
demanded by customers and allowed under tariffs, but the changes implemented at the state level
have not required renegotiation of LDC contracts. The state plans have in some cases discouraged
LDCs from signing long-term contracts for new capacity.
States are in the process of developing new energy plans that may require utilities to
encourage energy saving measures and diversify their energy supplies to include renewable sources.
This could lower the growth of gas demand.
These factors have increased the risk that customers will reduce their contractual commitments
for pipeline capacity. Future utilization of pipeline capacity will also depend on competition from
LNG imported into markets and new pipelines from the Rockies and other new producing areas, many of
which are utilizing master limited partnership structures with a lower cost of capital, and on
growth of natural gas demand.
Midstream Gas & Liquids. In our Midstream segment, we face regional competition with varying
competitive factors in each basin. Our gathering and processing business competes with other
midstream companies, interstate and intrastate pipelines, producers and independent gatherers and
processors. We primarily compete with five to ten companies across all basins in which we provide
services. Numerous factors impact any given customers choice of a gathering or processing services
provider, including rate, location, term, timeliness of services to be provided, pressure
obligations and contract structure.
Employees
We do not have any employees. We are managed and operated by the directors and officers of our
general partner. After the Dropdown, our general partner or its affiliates employed approximately
2,798 full-time employees, including 1,775 and 1,023 related to the operations of Gas Pipelines and Midstreams businesses, respectively. Additionally,
our general partner and its affiliates provide general and administrative services to us. For
further information, please read Directors, Executive Officers and Corporate Governance and
Certain Relationships and Related Transactions, and Director Independence Reimbursement of
Expenses of our General Partner.
FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
We have no revenue or segment profit/loss attributable to international activities both prior
to and after the Dropdown.
Item 1A. Risk Factors
FORWARD-LOOKING STATEMENTS, RISK FACTORS AND CAUTIONARY STATEMENT FOR
PURPOSES OF THE SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
Certain matters discussed in this report include forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements
relate to anticipated financial performance, managements plans and objectives for future
operations, business prospects, outcome of regulatory proceedings, market conditions, and other
matters.
All statements, other than statements of historical facts, included in this report that
address activities, events or developments that we expect, believe or anticipate will exist or may
occur in the future are forward-looking statements. Forward-looking statements can be identified
by various forms of words such as anticipates, believes, seeks, could, may, should,
continues, estimates, expects, forecasts, intends, might, goals, objectives,
targets, planned, potential, projects, scheduled, will, or other similar expressions.
These statements are based on managements beliefs and assumptions and on information currently
available to management and include, among others, statements regarding:
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amounts and nature of future capital expenditures; |
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expansion and growth of our business and operations; |
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financial condition and liquidity; |
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business strategy; |
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cash flow from operations or results of operations; |
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the levels of cash distributions to unitholders; |
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seasonality of certain business segments; and |
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natural gas and NGL prices and demand. |
Forward-looking statements are based on numerous assumptions, uncertainties, and risks that
could cause future events or results to be materially different from those stated or implied in
this report. Limited partner units 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. You should carefully consider the
risk factors discussed below in addition to the other information in this annual report. If any of
the following risks were actually to occur, our business, results of operations and financial
condition could be materially adversely affected. Many of the factors that could adversely affect
our business, results of operations and financial condition are beyond our ability to control or
predict. Specific factors that could cause actual results to differ from results contemplated by
the forward-looking statements include, among others, the following:
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whether we have sufficient cash from operations to enable us to maintain current levels
of cash distributions or to pay the minimum quarterly distribution following establishment
of cash reserves and payment of fees and expenses, including payments to our general
partner; |
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availability of supplies (including the uncertainties inherent in assessing and
estimating future natural gas reserves), market demand, volatility of prices, and the
availability and cost of capital; |
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inflation, interest rates and general economic conditions (including future disruptions
and volatility in the global credit markets and the impact of these events on our customers
and suppliers); |
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the strength and financial resources of our competitors; |
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development of alternative energy sources; |
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the impact of operational and development hazards; |
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costs of, changes in, or the results of laws, government regulations (including proposed
climate change legislation), environmental liabilities, litigation and rate proceedings; |
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our costs and funding obligations for defined benefit pension plans and other
postretirement benefit plans; |
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changes in maintenance and construction costs; |
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changes in the current geopolitical situation; |
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our exposure to the credit risks of our customers; |
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risks related to strategy and financing, including restrictions stemming from our debt
agreements, future changes in our credit ratings and the availability and cost of credit; |
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risks associated with future weather conditions; |
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acts of terrorism; and |
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additional risks described in our filings with the SEC. |
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Given the uncertainties and risk factors that could cause our actual results to differ
materially from those contained in any forward-looking statement, we caution investors not to
unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to
update the above list to announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to
below may cause our intentions to change from those statements of intention set forth in this
report. Such changes in our intentions may also cause our results to differ. We may change our
intentions, at any time and without notice, based upon changes in such factors, our assumptions, or
otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are
important factors, in addition to those listed above, that may cause actual results to differ
materially from those contained in the forward-looking statements. These factors are described in
the following section.
RISK FACTORS
You should carefully consider the following risk factors in addition to the other information
in this report. Each of these factors could adversely affect our business, operating results and
financial condition as well as adversely affect the value of an investment in our securities.
Risks Inherent in Our Business
We may not have sufficient cash from operations to enable us to maintain current levels of cash
distributions or to pay the minimum quarterly distribution following establishment of cash
reserves and payment of fees and expenses, including payments to our general partner.
We may not have sufficient available cash from operating surplus each quarter to maintain
current levels of cash distributions or to pay the minimum quarterly distribution. The amount of
cash we can distribute on our common units principally depends upon the amount of cash we generate
from our operations, which will fluctuate from quarter to quarter based on, among other things:
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the prices we obtain for our services; |
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the prices of, level of production of, and demand for natural gas and NGLs and our NGL
margins; |
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the volumes of natural gas we gather, transport, process and treat and the volumes of
NGLs we fractionate and store; |
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the level of our operating costs, including payments to our general partner; and |
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prevailing economic conditions. |
In addition, the actual amount of cash we will have available for distribution will depend on
other factors, some of which are beyond our control, such as:
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the level of capital expenditures we make; |
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the restrictions contained in Williams indentures, our indentures and credit facility
and our debt service requirements; |
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the cost of acquisitions, if any; |
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fluctuations in our working capital needs; |
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our ability to borrow for working capital or other purposes; |
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the amount, if any, of cash reserves established by our general partner; and |
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the amount of cash that the Partially Owned Entities and our subsidiaries distribute to
us. |
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Unitholders should be aware that the amount of cash we have available for distribution depends
primarily on our cash flow, including cash reserves and working capital or other borrowings, and
not solely on profitability, which will be affected by non-cash items. As a result, we may make
cash distributions during periods when we record losses, and we may not make cash distributions
during periods when we record net income.
We may not be able to grow or effectively manage our growth.
A principal focus of our strategy is to continue to grow by expanding our business. Our future
growth will depend upon our ability to successfully identify, finance, acquire, integrate and
operate projects and
businesses. Failure to achieve any of these factors would adversely affect our ability to
achieve anticipated growth in the level of cash flows or realize anticipated benefits.
We may acquire new facilities or expand our existing facilities to capture anticipated future
growth in natural gas production that does not ultimately materialize. As a result, our new or
expanded facilities may not achieve profitability. In addition, the process of integrating newly
acquired or constructed assets into our operations may result in unforeseen operating difficulties,
may absorb significant management attention and may require financial resources that would
otherwise be available for the ongoing development and expansion of our existing operations. Future
acquisitions or construction projects may require substantial new capital and could result in the
incurrence of indebtedness, additional liabilities and excessive costs that could have a material
adverse effect on our business, results of operations, financial condition and our ability to make
cash distributions to unitholders. If we issue additional common units in connection with future
acquisitions, unitholders interest in us will be diluted and distributions to unitholders may be
reduced. Further, any limitations on our access to capital, including limitations caused by
illiquidity in the capital markets, may impair our ability to complete future acquisitions and
construction projects on favorable terms, if at all.
Prices for natural gas liquids, natural gas and other commodities are volatile and this
volatility could adversely affect our financial results, cash flows, access to capital and
ability to maintain existing businesses.
Our revenues, operating results, future rate of growth and the value of certain segments of
our businesses depend primarily upon the prices of NGLs, natural gas, or other commodities, and the
differences between prices of these commodities. Price volatility can impact both the amount we
receive for our products and services and the volume of products and services we sell. Prices
affect the amount of cash flow available for capital expenditures and our ability to borrow money
or raise additional capital. Any of the foregoing can also have an adverse effect on our business,
results of operations and financial condition and our ability to make cash distributions to
unitholders.
The markets for NGLs, natural gas and other commodities are likely to continue to be volatile.
Wide fluctuations in prices might result from relatively minor changes in the supply of and demand
for these commodities, market uncertainty and other factors that are beyond our control, including:
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worldwide and domestic supplies of and demand for natural gas, NGLs, petroleum, and
related commodities; |
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turmoil in the Middle East and other producing regions; |
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the activities of the Organization of Petroleum Exporting Countries; |
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terrorist attacks on production or transportation assets; |
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weather conditions; |
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the level of consumer demand; |
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the price and availability of other types of fuels; |
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the availability of pipeline capacity; |
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supply disruptions, including plant outages and transportation disruptions; |
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the price and level of foreign imports; |
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domestic and foreign governmental regulations and taxes; |
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volatility in the natural gas markets; |
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the overall economic environment; |
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the credit of participants in the markets where products are bought and sold; and |
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the adoption of regulations or legislation relating to climate change. |
We might not be able to successfully manage the risks associated with selling and marketing
products in the wholesale energy markets.
Our portfolio of derivative and other energy contracts may consist of wholesale contracts to
buy and sell commodities, including contracts for natural gas, NGLs and other commodities that are
settled by the delivery of the commodity or cash throughout the United States. If the values of
these contracts change in a direction or manner that we do not anticipate or cannot manage, it
could negatively affect our results of operations. In the past, certain marketing and trading
companies have experienced severe financial problems due to price volatility in the energy
commodity markets. In certain instances this volatility has caused companies to be unable to
deliver energy commodities that they had guaranteed under contract. If such a delivery failure were
to occur in one of our contracts, we might incur additional losses to the extent of amounts, if
any, already paid to, or received from, counterparties. In addition, in our businesses, we often
extend credit to our counterparties. Despite performing credit analysis prior to extending credit,
we are exposed to the risk that we might not be able to collect amounts owed to us. If the
counterparty to such a transaction fails to perform and any collateral that secures our
counterpartys obligation is inadequate, we will suffer a loss. Downturns in the economy or
disruptions in the global credit markets could cause more of our counterparties to fail to perform
than we expect.
Any decrease in NGL prices or a change in NGL prices relative to the price of natural gas could
affect our processing, fractionation and storage businesses.
The relationship between natural gas prices and NGL prices affects our profitability. When
natural gas prices are low relative to NGL prices, it is more profitable for us and our customers
to process natural gas. When natural gas prices are high relative to NGL prices, it is less
profitable to process natural gas both because of the higher value of natural gas and because of
the increased cost of separating the mixed NGLs from the natural gas. Higher natural gas prices
relative to NGL prices may also make it uneconomical to recover ethane, which may further
negatively impact sales volumes and margins. Finally, higher natural gas prices relative to NGL
prices could also reduce volumes of gas processed generally, reducing the volumes of mixed NGLs
available for fractionation.
The long-term financial condition of our natural gas transportation and midstream businesses is
dependent on the continued availability of natural gas supplies in the supply basins that we
access, demand for those supplies in our traditional markets, and the prices of and market
demand for natural gas.
The development of the additional natural gas reserves that are essential for our gas
transportation and midstream businesses to thrive requires significant capital expenditures by
others for exploration and development drilling and the installation of production, gathering,
storage, transportation and other facilities that permit natural gas to be produced and delivered
to our pipeline systems. Low prices for natural gas, regulatory limitations, including
environmental regulations, or the lack of available capital for these projects could adversely
affect the development and production of additional reserves, as well as gathering, storage,
pipeline transportation and import and export of natural gas supplies, adversely impacting our
ability to fill the capacities of our gathering, transportation and processing facilities.
Production from existing wells and natural gas supply basins with access to our pipeline will
also naturally decline over time. The amount of natural gas reserves underlying these wells may
also be less than anticipated, and the rate at which production from these reserves declines may be
greater than anticipated. Additionally, the competition for natural gas supplies to serve other
markets could reduce the amount of natural gas supply for our customers. Accordingly, to maintain
or increase the contracted capacity or the volume of natural gas transported on our pipeline and
cash flows associated with the transportation of natural gas, our customers must compete with
others to obtain adequate supplies of natural gas. In addition, if natural gas prices in the supply
basins connected to our pipeline systems are higher than prices in other natural gas producing
regions, our ability to compete with other transporters may be negatively impacted on a short-term
basis, as well as with respect to our long-term recontracting activities. If new supplies of
natural
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gas are not obtained to replace the natural decline in volumes from existing supply areas,
if natural gas supplies are diverted to serve other markets, or if environmental regulators
restrict new natural gas drilling, the overall volume of natural gas transported and stored on our
system would decline, which could have a material adverse effect on our business, financial
condition and results of operations, and our ability to make cash distributions to unitholders. In
addition, new LNG import facilities built near our markets could result in less demand for our
gathering and transportation facilities.
Our risk measurement and hedging activities might not be effective and could increase the
volatility of our results.
Although we have systems in place that use various methodologies to quantify commodity price
risk associated with our businesses, these systems might not always be followed or might not always
be effective. Further, such systems do not in themselves manage risk, particularly risks outside of
our control, and adverse changes in energy commodity market prices, volatility, adverse correlation
of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed
in this report might still adversely affect our earnings, cash flows and balance sheet under
applicable accounting rules, even if risks have been identified.
In an effort to manage our financial exposure related to commodity price and market
fluctuations, we have entered into contracts to hedge certain risks associated with our assets and
operations. In these hedging activities, we have used fixed-price, forward, physical purchase and
sales contracts, futures, financial swaps and option contracts traded in the over-the-counter
markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all
risks present in a given contract. For example, a forward contract that would be effective in
hedging commodity price volatility risks would not hedge the contracts counterparty credit or
performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to
manage counterparty credit risk within guidelines established by our credit policy, we may not be
able to successfully manage all credit risk and as such, future cash flows and results of
operations could be impacted by counterparty default.
Our use of hedging arrangements through which we attempt to reduce the economic risk of our
participation in commodity markets could result in increased volatility of our reported results.
Changes in the fair values (gains and losses) of derivatives that qualify as hedges under generally
accepted accounting principles (GAAP), to the extent that such hedges are not fully effective in
offsetting changes to the value of the hedged commodity, as well as changes in the fair value of
derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded
in our income. This creates the risk of volatility in earnings even if no economic impact to us has
occurred during the applicable period.
The impact of changes in market prices for NGLs and natural gas on the average prices paid or
received by us may be reduced based on the level of our hedging activities. These hedging
arrangements may limit or enhance our margins if the market prices for NGLs or natural gas were to
change substantially from the price established by the hedges. In addition, our hedging
arrangements expose us to the risk of financial loss in certain circumstances, including instances
in which:
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volumes are less than expected; |
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the hedging instrument is not perfectly effective in mitigating the risk being hedged;
and |
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the counterparties to our hedging arrangements fail to honor their financial
commitments. |
Our industry is highly competitive, and increased competitive pressure could adversely affect
our business and operating results.
We have numerous competitors in all aspects of our businesses, and additional competitors may
enter our markets. Some of our competitors are large oil, natural gas and petrochemical companies
that have greater access to supplies of natural gas and NGLs than we do. In addition, current or
potential competitors may make strategic acquisitions or have greater financial resources than we
do, which could affect our ability to make investments or acquisitions. Other companies with which
we compete may be able to respond more quickly to new laws or regulations or emerging technologies
or to devote greater resources to the construction, expansion or refurbishment of their facilities
than we can. In addition, current or potential competitors may make strategic acquisitions or have
greater financial resources than we do, which could affect our ability to make investments or
acquisitions. There can be no assurance that we will be able to compete successfully against
current and future competitors and any failure to do so could have a material adverse effect on our
business, results of operations, and financial condition and our ability to make cash distributions
to unitholders.
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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 in the ordinary course of our business. Generally, our customers are rated investment
grade, are otherwise considered creditworthy or are required to make prepayments or provide
security to satisfy credit concerns. However, our credit procedures and policies may not be
adequate to fully eliminate customer credit risk. We cannot predict to what extent our business
would be impacted by deteriorating conditions in the economy, including declines in our customers
creditworthiness. 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 cause us to write down or write off doubtful
accounts. Such write-downs or write-offs could negatively affect our operating results in the
periods in which they occur, and, if significant, could have a material adverse effect on our
business, results of operations, cash flows, and financial condition and our ability to make cash
distributions to unitholders.
The failure of counterparties to perform their contractual obligations could adversely affect our
operating results, financial condition and cash available to make distributions.
Despite performing credit analysis prior to extending credit, we are exposed to the credit
risk of our contractual counterparties in the ordinary course of business even though we monitor
these situations and attempt to take appropriate measures to protect ourselves. In addition to
credit risk, counterparties to our commercial agreements, such as product sales, gathering,
treating, storage, transportation, processing and fractionation agreements, may fail to perform
their other contractual obligations. A failure of counterparties to perform their contractual
obligations, including Williams, could cause us to write down or write off doubtful accounts, which
could materially adversely affect our operating results, and financial condition and our ability to
make cash distributions to unitholders.
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. Because we do not own these
third-party pipelines or facilities, their continuing operation is not within our control. If
these pipelines or facilities were to
become temporarily or permanently unavailable for any reason, or if throughput were reduced
because of testing, line repair, damage to pipelines or facilities, reduced operating pressures,
lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or
other causes, we and our customers would have reduced capacity to transport, store or deliver
natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby
reducing our revenues. Further, although there are laws and regulations designed to encourage
competition in wholesale market transactions, some companies may fail to provide fair and equal
access to their transportation systems or may not provide sufficient transportation capacity for
other market participants.
Any temporary or permanent interruption at any key pipeline interconnect or in operations on
third-party pipelines or facilities that would cause a material reduction in volumes transported on
our pipelines or our gathering systems or processed, fractionated, treated or stored at our
facilities could have a material adverse effect on our business, results of operations, and
financial condition and our ability to make cash distributions to unitholders.
Future disruptions in the global credit markets may make equity and debt markets less accessible,
create a shortage in the availability of credit and lead to credit market volatility, which could
disrupt our financing plans and limit our ability to grow.
In 2008, public equity markets experienced significant declines, and global credit markets
experienced a shortage in overall liquidity and a resulting disruption in the availability of
credit. Future disruptions in the global financial marketplace, including the bankruptcy or
restructuring of financial institutions, could make equity and debt markets inaccessible and
adversely affect the availability of credit already arranged and the availability and cost of
credit in the future. We have availability under our New Credit Facility, but our ability to borrow
under that facility could be impaired if one or more of our lenders fails to honor its contractual
obligation to lend to us.
As a publicly traded partnership, these developments could significantly impair our ability to
make acquisitions or finance growth projects. We distribute all of our available cash to our
unitholders on a quarterly basis. We typically rely upon external financing sources, including the
issuance of debt and equity securities and bank borrowings, to fund acquisitions or expansion
capital
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expenditures. Any limitations on our access to external capital, including limitations
caused by illiquidity or volatility in the capital markets, may impair our ability to complete
future acquisitions and construction projects on favorable terms, if at all. As a result, we may be
at a competitive disadvantage as compared to businesses that reinvest all of their available cash
to expand ongoing operations, particularly under adverse economic conditions.
Adverse economic conditions could negatively affect our results of operations.
A slowdown in the economy has the potential to negatively impact our businesses in many ways.
Included among these potential negative impacts are reduced demand and lower prices for our
products and services, increased difficulty in collecting amounts owed to us by our customers and a
reduction in our credit ratings (either due to tighter rating standards or the negative impacts
described above), which could result in reducing our access to credit markets, raising the cost of
such access or requiring us to provide additional collateral to our counterparties.
Restrictions in our debt agreements and our leverage may affect our future financial and
operating flexibility.
Our total outstanding long-term debt as of December 31, 2009, was $1.0 billion, and as of
February 18, 2010, after consummation of the dropdown was $6.5 billion.
Our debt service obligations and restrictive covenants in our New Credit Facility and the
indentures governing our senior unsecured notes could have important consequences. For example,
they could:
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make it more difficult for us to satisfy our obligations with respect our senior
unsecured notes and our other indebtedness, which could in turn result in an event of
default on such other indebtedness or our outstanding notes; |
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impair our ability to obtain additional financing in the future for working capital,
capital expenditures, acquisitions, general partnership purposes or other purposes; |
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adversely affect our ability to pay cash distributions to unitholders; |
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diminish our ability to withstand a continued or future downturn in our business or the
economy generally; |
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require us to dedicate a substantial portion of our cash flow from operations to debt
service payments, thereby reducing the availability of cash for working capital, capital
expenditures, acquisitions, general corporate purposes or other purposes; |
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limit our flexibility in planning for, or reacting to, changes in our business and the
industry in which we operate; and |
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place us at a competitive disadvantage compared to our competitors that have
proportionately less debt. |
Our ability to repay, extend or refinance our existing debt obligations and to obtain future
credit will depend primarily on our operating performance, which will be affected by general
economic, financial, competitive, legislative, regulatory, business and other factors, many of
which are beyond our control. Our ability to refinance existing debt obligations or obtain future
credit will also depend upon the current conditions in the credit markets and the availability of
credit generally. If we are unable to meet our debt service obligations, we could be forced to
restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be
unable to obtain financing or sell assets on satisfactory terms, or at all.
We are not prohibited under our indentures from incurring additional indebtedness. Our
incurrence of significant additional indebtedness would exacerbate the negative consequences
mentioned above, and could adversely affect our ability to repay our senior notes.
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Our debt agreements and Williams public indentures contain financial and operating restrictions
that may limit our access to credit and affect our ability to operate our business. In addition,
our ability to obtain credit in the future will be affected by Williams credit ratings.
Our public indentures contain various covenants that, among other things, limit our ability to
grant certain liens to support indebtedness, merge, or sell substantially all of our assets. In
addition, our New Credit Facility contains certain financial covenants and restrictions on our
ability and our subsidiaries ability to incur indebtedness, to consolidate or allow any material
change in the nature of our business, enter into certain affiliate transactions and make certain
distributions during an event of default. These covenants could adversely affect our ability to
finance our future operations or capital needs or engage in, expand or pursue our business
activities and prevent us from engaging in certain transactions that might otherwise be considered
beneficial to us. Our ability to comply with these covenants may be affected by events beyond our
control, including prevailing economic, financial and industry conditions. If market or other
economic conditions deteriorate, our current assumptions about future economic conditions turn out
to be incorrect or unexpected events occur, our ability to comply with these covenants may be
significantly impaired.
Williams public indentures contain covenants that restrict Williams and our ability to incur
liens to support indebtedness. These covenants could adversely affect our ability to finance our
future operations or capital needs or engage in, expand or pursue our business activities and
prevent us from engaging in certain transactions that might otherwise be considered beneficial to
us. Williams ability to comply with the
covenants contained in its debt instruments may be affected by events beyond our and Williams
control, including prevailing economic, financial and industry conditions. If market or other
economic conditions deteriorate, Williams ability to comply with these covenants may be negatively
impacted.
Our failure to comply with the covenants in our debt agreements could result in events of
default. Upon the occurrence of such an event of default, the lenders could elect to declare all
amounts outstanding under a particular facility to be immediately due and payable and terminate all
commitments, if any, to extend further credit. Certain payment defaults or an acceleration under
our public indentures or other material indebtedness could cause a cross-default or
cross-acceleration of our New Credit Facility. Such a cross-default or cross-acceleration could
have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a
single debt instrument. If an event of default occurs, or if our New Credit Facility
cross-defaults, and the lenders under the affected debt agreements accelerate the maturity of any
loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts
outstanding under such debt agreements. For more information regarding our debt agreements, please
read Managements Discussion and Analysis of Financial Condition and Results of
OperationsFinancial Condition and Liquidity.
Substantially all of Williams operations are conducted through its subsidiaries. Williams
cash flows are substantially derived from loans, dividends and distributions paid to it by its
subsidiaries. Williams cash flows are typically utilized to service debt and pay dividends on the
common stock of Williams, with the balance, if any, reinvested in its subsidiaries as loans or
contributions to capital. Due to our relationship with Williams, our ability to obtain credit will
be affected by Williams credit ratings. If Williams were to experience a deterioration in its
credit standing or financial condition, our access to credit and our ratings could be adversely
affected. Any future downgrading of a Williams credit rating would likely also result in a
downgrading of our credit rating. A downgrading of a Williams credit rating could limit our
ability to obtain financing in the future upon favorable terms, if at all.
Our subsidiaries are not prohibited from incurring indebtedness by their organizational
documents, which may affect our ability to make distributions to unitholders.
Our subsidiaries are not prohibited by the terms of their respective organizational documents
from incurring indebtedness. If they were to incur significant amounts of indebtedness, such
occurrence may inhibit their ability to make distributions to us. An inability by our subsidiaries
to make distributions to us would materially and adversely affect our ability to make distributions
to unitholders because we expect distributions we receive from our subsidiaries to represent a
significant portion of the cash available to make cash distributions to unitholders.
A downgrade of our credit rating could impact our liquidity, access to capital and our costs of
doing business, and maintaining credit ratings is under the control of independent third
parties.
A downgrade of our credit rating might increase our cost of borrowing and could require us to
post collateral with third parties, negatively impacting our available liquidity. Our ability to
access capital markets could also be limited by a downgrade of our credit rating and other
disruptions. Such disruptions could include:
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economic downturns; |
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deteriorating capital market conditions; |
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declining market prices for natural gas, NGLs and other commodities; |
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terrorist attacks or threatened attacks on our facilities or those of other energy
companies; and |
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the overall health of the energy industry, including the bankruptcy or insolvency of
other companies. |
Credit rating agencies perform independent analysis when assigning credit ratings. The
analysis includes a number of criteria including, but not limited to, business composition, market
and operational risks, as well as various financial tests. Credit rating agencies continue to
review the criteria for industry sectors and various debt ratings and may make changes to those
criteria from time to time. Our current credit ratings after the Dropdown from Moodys is Baa3,
from S&P is BBB-, and from Fitch is BBB-. Credit ratings are not recommendations to buy, sell or
hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by
the ratings agencies and no assurance can be given that we will maintain our current credit
ratings.
We are subject to risks associated with climate change.
There is a growing belief that emissions of greenhouse gases may be linked to climate change.
Climate change and the costs that may be associated with its impacts and the regulation of
greenhouse gases have the potential to affect our business in many ways, including negatively
impacting the costs we incur in providing our products and services, the demand for and consumption
of our products and services (due to change in both costs and weather patterns), and the economic
health of the regions in which we operate, all of which can create financial risks.
Our assets and operations can be affected by weather and other natural phenomena.
Our assets and operations can be adversely affected by hurricanes, floods, earthquakes,
tornadoes and other natural phenomena and weather conditions, including extreme temperatures,
making it more difficult for us to realize the historic rates of return associated with these
assets and operations. Insurance may be inadequate, and in some instances, we have been unable to
obtain insurance on commercially reasonable terms or insurance has not been available 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.
Our customers energy needs vary with weather conditions. To the extent weather conditions are
affected by climate change or demand is impacted by regulations associated with climate change,
customers energy use could increase or decrease depending on the duration and magnitude of the
changes, leading either to increased investment or decreased revenues.
We depend on certain key customers and producers for a significant portion of our revenues and
supply of natural gas and NGLs. If we lost any of these key customers or producers or contracted
volumes, our revenues and cash available to pay distributions could decline.
We rely on a limited number of customers for a significant portion of our revenues. Although
some of these customers are subject to long-term contracts, we may be unable to negotiate
extensions or replacements of these contracts on favorable terms, if at all. The loss of all, or
even a portion of, the revenues from natural gas, NGLs or contracted volumes, as applicable,
supplied by these customers, as a result of competition, creditworthiness, inability to negotiate
extensions or replacements of contracts or otherwise, could have a material adverse effect on our
business, results of operations, financial condition and our ability to make cash distributions to
unitholders, unless we are able to acquire comparable volumes from other sources.
We do not own all of the interests in Partially Owned Entities, which could adversely affect our
ability to operate and control these assets in a manner beneficial to us.
Because we do not control the Partially Owned Entities except Northwest Pipeline, we may have
limited flexibility to control the operation of or cash distributions received from these assets.
Any future disagreements with the other co-owners of these assets could
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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.
The Partially Owned Entities may reduce their cash distributions to us in some situations.
The Partially Owned Entities organizational documents require distribution of their available
cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by
reserves appropriate for operating their respective businesses.
Significant prolonged changes in natural gas prices could affect supply and demand, cause a
reduction in or termination of the long-term transportation and storage contracts or throughput on
the Pipeline Entities systems, and adversely affect our cash available to make distributions.
Higher natural gas prices over the long term could result in a decline in the demand for
natural gas and, therefore, in the Pipeline Entities long-term transportation and storage
contracts or throughput on their respective systems. Also, lower natural gas prices over the long
term could result in a decline in the production of natural gas resulting in reduced contracts or
throughput on their systems. As a result, significant prolonged changes in natural gas prices could
have a material adverse effect on our Pipeline Entities business, financial condition, results of
operations and cash flows, and on our ability to make cash distributions to unitholders.
The Pipeline Entities natural gas sales, transportation and storage operations are subject to
regulation by FERC, which could have an adverse impact on their ability to establish transportation
and storage rates that would allow them to recover the full cost of operating their respective
pipelines, including a reasonable rate of return.
The Pipeline Entities natural gas sales, transmission and storage operations are subject to
federal, state and local regulatory authorities. Specifically, their interstate pipeline
transportation and storage service is subject to regulation by FERC. The federal regulation extends
to such matters as:
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transportation and sale for resale of natural gas in interstate commerce; |
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rates, operating terms and conditions of service, including initiation and
discontinuation of service; |
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the types of services the Pipeline Entities may offer to their customers; |
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certification and construction of new facilities; |
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acquisition, extension, disposition or abandonment of facilities; |
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accounts and records; |
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depreciation and amortization policies; |
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relationships with affiliated companies who are involved in marketing functions of the
natural gas business; and |
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market manipulation in connection with interstate sales, purchases or transportation of
natural gas. |
Under the Natural Gas Act (NGA), FERC has authority to regulate providers of natural gas
pipeline transportation and storage services in interstate commerce, and such providers may only
charge rates that have been determined to be just and reasonable by FERC. In addition, FERC
prohibits providers from unduly preferring or unreasonably discriminating against any person with
respect to pipeline rates or terms and conditions of service.
Regulatory actions in these areas can affect our business in many ways, including decreasing
tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise
altering the profitability of our pipeline business.
The FERC Standards of Conduct govern the relationship between natural gas transmission
providers and their marketing function employees as defined by the rule. The standards of conduct
are intended to prevent natural gas transmission providers from preferentially benefiting gas
marketing functions by requiring the employees of a transmission provider that perform transmission
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functions to function independently from marketing function employees and by restricting the
information that transmission providers may provide to gas marketing employees. The inefficiencies
created by the restrictions on the sharing of employees and information may increase our costs, and
the restriction on the sharing of information may have an adverse impact on our senior managements
ability to effectively obtain important information about our business.
Unlike other pipelines that own facilities in the offshore Gulf of Mexico, Transco charges its
transportation customers a separate fee to access its offshore facilities. The separate charge
that it assesses, referred to as an IT feeder charge, is charged only when the facilities are
used and typically is paid by producers or marketers. This means that Transco recovers the costs
included in the IT feeder charge only if its facilities are used, and because it is typically paid
by producers and marketers, it generally results in netback prices to producers that are slightly
lower than the netbacks realized by producers transporting on other interstate pipelines. Longer
term, this rate design disparity could result in producers bypassing Transcos offshore facilities
in favor of alternative transportation facilities. Transco has asked FERC to allow it to eliminate
the IT feeder charge and charge for transportation on its offshore facilities in the same manner as
other pipelines. Transcos requests have been denied.
The rates, terms and conditions for the Pipeline Entities interstate pipeline services are
set forth in their respective FERC-approved tariffs. Any successful complaint or protest against
the Pipeline Entities rates could have an adverse impact on their revenues associated with
providing transportation services. In addition, there is a risk that rates set by the FERC in
future rate cases filed by the Pipeline Entities will be inadequate to recover increases in
operating costs or to sustain an adequate return on capital investments. There is also the risk
that higher rates would cause their customers to look for alternative ways to transport natural
gas.
The Pipeline Entities could be subject to penalties and fines if they fail to comply with FERC
regulations.
The Pipeline Entities transportation and storage operations are regulated by FERC. Should the
Pipeline Entities fail to comply with all applicable FERC administered statutes, rules, regulations
and orders, they could be subject to substantial penalties and fines. Under the Energy Policy Act
of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations
of up to $1,000,000 per day for each violation. Any material penalties or fines imposed by FERC
could have a material adverse impact on the Pipeline Entities business, financial condition,
results of operations and cash flows, and on our ability to make cash distributions to unitholders.
The outcome of certain FERC proceedings involving FERC policy statements is uncertain and could
affect the level of return on equity that the Pipeline Entities may be able to achieve in any
future rate proceeding.
In an effort to provide some guidance and to obtain further public comment on FERCs policies
concerning return on equity determinations, on July 19, 2007, FERC issued its Proposed Proxy Policy
Statement, Composition of Proxy Groups for Determining Gas and Oil Pipeline Return on Equity. In
the Proposed Proxy Policy Statement, FERC proposes to permit inclusion of publicly traded
partnerships in the proxy group analysis relating to return on equity determinations in rate
proceedings, provided that the analysis be limited to actual publicly traded partnership
distributions capped at the level of the pipelines earnings.
After receiving public comment on the proposed policy statement, on April 17, 2008, FERC
issued a final policy statement rejecting the concept of capping distributions in favor of an
adjustment to the long-term growth rate used to calculate the equity cost of capital for publicly
traded partnerships which are included in the proxy group.
On January 19, 2009, the FERC applied the policy statement to a pipeline rate case and
determined that the pipelines return on equity should be 11.55 percent. It is difficult to know
how instructive this case is for purposes of anticipating rates of return in future rate cases,
because the FERC determined the composition of the proxy group using data from 2004 when the case
was filed.
The effect of the application of FERCs policy to the Pipeline Entities future rate
proceedings is not certain, and we cannot ensure that such application would not adversely affect
our ability to achieve a reasonable level of return on equity.
The outcome of future rate cases to set the rates the Pipeline Entities can charge customers on
their respective pipelines might result in rates that lower their return on the capital invested
in those pipelines.
There is a risk that rates set by the FERC in the Pipeline Entities future rate cases will be
inadequate to recover increases in operating costs or to sustain an adequate return on capital
investments. There is also the risk that higher rates will cause their customers to look for
alternative ways to transport their natural gas.
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The outcome of future rate cases will determine the amount of income taxes the Pipeline
Entities will be allowed to recover.
In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in
its cost-of-service computations an income tax allowance provided that an entity or individual has
an actual or potential income tax liability on income from the pipelines public utility assets.
The extent to which owners of pipelines have such actual or potential income tax liability will be
reviewed by FERC on a case-by-case basis in rate cases where the amounts of the allowances will be
established.
Legal and regulatory proceedings and investigations relating to the energy industry and capital
markets have adversely affected the Pipeline Entities businesses and may continue to do so.
Public and regulatory scrutiny of the energy industry and of the capital markets has resulted
in increased regulation being either proposed or implemented. Such scrutiny has also resulted in
various inquiries, investigations and court proceedings in which the Pipeline Entities or their
affiliates are named as defendants. Both the shippers on the Pipeline Entities pipelines and
regulators have rights to challenge the rates they charge under certain circumstances. Any
successful challenge could materially affect the Pipeline Entities results of operations.
Certain inquiries, investigations and court proceedings are ongoing. Adverse effects may
continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional
inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In
addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will
lead to additional legal proceedings against the Pipeline Entities, civil or criminal fines or
penalties, or other regulatory action, including legislation, which might be materially adverse to
the operation of the Pipeline Entities businesses and our revenues and net income or increase
their operating costs in other ways. Current legal proceedings or other matters against us
including environmental matters, suits,
regulatory appeals and similar matters might result in adverse decisions against the Pipeline
Entities. The result of such adverse decisions, either individually or in the aggregate, could be
material and may not be covered fully or at all by insurance.
Increased competition from alternative natural gas transportation and storage options and
alternative fuel sources could have a significant financial impact on us.
We compete primarily with other interstate pipelines and storage facilities in the
transportation and storage of natural gas. Some of our competitors may have greater financial
resources and access to greater supplies of natural gas than we do. Some of these competitors may
expand or construct transportation and storage systems that would create additional competition for
natural gas supplies or the services we provide to our customers. Moreover, Williams and its other
affiliates may not be limited in their ability to compete with us. Further, natural gas also
competes with other forms of energy available to our customers, including electricity, coal, fuel
oils and other alternative energy sources.
The principal elements of competition among natural gas transportation and storage assets are
rates, terms of service, access to natural gas supplies, flexibility and reliability. FERCs
policies promoting competition in natural gas markets are having the effect of increasing the
natural gas transportation and storage options for our traditional customer base. As a result, we
could experience some turnback of firm capacity as the primary terms of existing agreements
expire. If we are unable to remarket this capacity or can remarket it only at substantially
discounted rates compared to previous contracts, we or our remaining customers may have to bear the
costs associated with the turned back capacity. Increased competition could reduce the amount of
transportation or storage capacity contracted on our system or, in cases where we do not have
long-term fixed rate contracts, could force us to lower our transportation or storage rates.
Competition could intensify the negative impact of factors that significantly decrease demand for
natural gas or increase the price of natural gas in the markets served by our pipeline system, such
as competing or alternative forms of energy, a regional or national recession or other adverse
economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory
actions that directly or indirectly increase the price of natural gas or limit the use of natural
gas. Our ability to renew or replace existing contracts 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, financial
condition, results of operations and cash flows and our ability to make cash distributions to
unitholders.
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We may not be able to maintain or replace expiring natural gas transportation and storage
contracts at favorable rates or on a long-term basis.
The Pipeline Entities primary exposure to market risk occurs at the time the terms of
existing transportation and storage contracts expire and are subject to termination. Although none
of our material contracts are terminable in 2010, upon expiration of the terms we may not be able
to extend contracts with existing customers to obtain replacement contracts at favorable rates or
on a long-term basis.
The extension or replacement of existing contracts depends on a number of factors beyond our
control, including:
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the level of existing and new competition to deliver natural gas to our markets; |
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the growth in demand for natural gas in our markets; |
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whether the market will continue to support long-term firm contracts; |
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whether our business strategy continues to be successful; |
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the level of competition for natural gas supplies in the production basins serving us;
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the effects of state regulation on customer contracting practices. |
Any failure to extend or replace a significant portion of our existing contracts may have a
material adverse effect on our business, financial condition, results of operations and cash flows
and our ability to make cash distributions to unitholders.
Competitive pressures could lead to decreases in the volume of natural gas contracted or
transported through the Pipeline Entities pipeline systems.
Although most of the Pipeline Entities pipeline systems current capacity is fully
contracted, the FERC has taken certain actions to strengthen market forces in the natural gas
pipeline industry that have led to increased competition throughout the industry. In a number of
key markets, interstate pipelines are now facing competitive pressure from other major pipeline
systems, enabling local distribution companies and end users to choose a transmission provider
based on considerations other than location. Other entities could construct new pipelines or expand
existing pipelines that could potentially serve the same markets as our pipeline system. Any such
new pipelines could offer transportation services that are more desirable to shippers because of
locations, facilities, or other factors. These new pipelines could charge rates or provide service
to locations that would result in greater net profit for shippers and producers and thereby force
us to lower the rates charged for service on our pipeline in order to extend our existing
transportation service agreements or to attract new customers. We are aware of proposals by
competitors to expand pipeline capacity in certain markets we also serve which, if the proposed
projects proceed, could increase the competitive pressure upon us. There can be no assurance that
we will be able to compete successfully against current and future competitors and any failure to
do so could have a material adverse effect on our business, results of operations, and our ability
to make cash distributions to unitholders.
Decreases in demand for natural gas could adversely affect our business.
Demand for our transportation services depends on the ability and willingness of shippers with
access to our facilities to satisfy their demand by deliveries through our system. Any decrease in
this demand could adversely affect our business. Demand for natural gas is also affected by
weather, future industrial and economic conditions, fuel conservation measures, alternative fuel
requirements, governmental regulation, or technological advances in fuel economy and energy
generation devices, all of which are matters beyond our control. Additionally, in some cases, new
LNG import facilities built near our markets could result in less demand for our gathering and
transmission facilities.
The failure of new sources of natural gas production or LNG import terminals to be successfully
developed in North America could increase natural gas prices and reduce the demand for our
services.
New sources of natural gas production in the United States and Canada, particularly in areas
of shale development are expected to become an increasingly significant component of future U.S.
natural gas supply in North America. Additionally, increases in LNG supplies are expected to be
imported through new LNG import terminals, particularly in the Gulf Coast region. If these
additional
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sources of supply are not developed, natural gas prices could increase and cause
consumers of natural gas to turn to alternative energy sources, which could have a material adverse
effect on our business, financial condition, results of operations and cash flows and our ability
to make cash distributions to unitholders.
Certain of the Pipeline Entities services are subject to long-term, fixed-price contracts that
are not subject to adjustment, even if our cost to perform such services exceeds the revenues
received from such contracts.
The Pipeline Entities provide some services pursuant to long-term, fixed price contracts. It
is possible that costs to perform services under such contracts will exceed the revenues they
collect for their services. Although most of the services are priced at cost-based rates that are
subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer
may mutually agree to sign a contract for service at a negotiated rate that may be above or below
the FERC regulated cost-based rate for that service. These negotiated rate contracts are not
generally subject to adjustment for increased costs that
could be produced by inflation or other factors relating to the specific facilities being used
to perform the services.
Our operations are subject to operational hazards and unforeseen interruptions for which they
may not be adequately insured.
There are operational risks associated with the gathering, transporting, storage, processing
and treating of natural gas and the fractionation and storage of NGLs, including:
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hurricanes, tornadoes, floods, fires, extreme weather conditions and other natural
disasters; |
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aging infrastructure and mechanical problems; |
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damages to pipelines and pipeline blockages; |
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uncontrolled releases of natural gas (including sour gas), NGLs, brine or industrial
chemicals; |
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collapse of NGL storage caverns; |
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operator error; |
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damage inadvertently caused by third party activity, such as operation of construction
equipment; |
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pollution and other environmental risks; |
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fires, explosions, craterings and blowouts; |
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risks related to truck and rail loading and unloading; |
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risks related to operating in a marine environment; and |
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terrorist attacks or threatened attacks on our facilities or those of other energy
companies. |
Any of these risks could result in loss of human life, personal injuries, significant damage
to property, environmental pollution, impairment of our operations and substantial losses to us. In
accordance with customary industry practice, we maintain insurance against some, but not all, of
these risks and losses, and only at levels we believe to be appropriate. The location of certain
segments of our facilities in or near populated areas, including residential areas, commercial
business centers and industrial sites, could increase the level of damages resulting from these
risks. In spite of our precautions, an event such as those described above could cause considerable
harm to people or property, and could have a material adverse effect on our financial condition and
results of operations, particularly if the event is not fully covered by insurance. Accidents or
other operating risks could further result in loss of service available to our customers.
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Some portions of our current pipeline infrastructure and other assets have been in use for many
decades, which may adversely affect our business.
Some portions of our assets, including our pipeline infrastructure, have been in use for many
decades. The current age and condition of our assets could result in a material adverse impact on
our business, financial condition and results of operations if the costs of maintaining our
facilities exceed current expectations.
Our operations are subject to governmental laws and regulations relating to the protection of
the environment, which may expose us to significant costs and liabilities and could exceed
current expectations.
The risk of substantial environmental costs and liabilities is inherent in natural gas
gathering, transportation, storage, processing and treating, and in the fractionation and storage
of NGLs, and we may incur substantial environmental costs and liabilities in the performance of
these types of operations. Our operations are subject to extensive federal, state and local
environmental laws and regulations governing environmental protection, the discharge of materials
into the environment and the security of chemical and industrial facilities. These laws include:
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CAA and analogous state laws, which impose obligations related to air emissions; |
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CWA, and analogous state laws, which regulate discharge of wastewaters from our
facilities to state and federal waters; |
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CERCLA, and analogous state laws, which 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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RCRA, and analogous state laws, which impose requirements for the handling and discharge
of solid and hazardous waste from our facilities. |
Various governmental authorities, including the U.S. Environmental Protection Agency (EPA) and
analogous state agencies and the United States Department of Homeland Security, have the power to
enforce compliance with these laws and regulations and the permits issued under them, oftentimes
requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits
may result in the assessment of administrative, civil, and criminal penalties, the imposition of
remedial obligations, the imposition of stricter conditions on or revocation of permits, and the
issuance of injunctions limiting or preventing some or all of our operations.
There is inherent risk of the incurrence of environmental costs and liabilities in our
business, some of which may be material, due to our handling of the products we gather, transport,
process, fractionate and store, air emissions related to our operations, historical industry
operations, waste disposal practices, and the prior use of flow meters containing mercury. Joint
and several, strict liability may be incurred without regard to fault under certain environmental
laws and regulations, including CERCLA, RCRA, and analogous state laws, for the remediation of
contaminated areas and in connection with spills or releases of natural gas and wastes on, under,
or from our properties and facilities. Private parties, including the owners of properties through
which our pipeline and gathering systems pass and facilities where our wastes are taken for
reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well
as to seek damages for non-compliance with environmental laws and regulations or for personal
injury or property damage arising from our operations. Some sites we operate are located near
current or former third-party hydrocarbon storage and processing operations, and there is a risk
that contamination has migrated from those sites to ours. In addition, increasingly strict laws,
regulations and enforcement policies could materially increase our compliance costs and the cost of
any remediation that may become necessary. Our insurance may not cover all environmental risks and
costs or may not provide sufficient coverage if an environmental claim is made against us.
Our business may be adversely affected by increased costs due to stricter pollution control
requirements or liabilities resulting from non-compliance with required operating or other
regulatory permits. Also, we might not be able to obtain or maintain from time to time all
required environmental regulatory approvals for our operations. If there is a delay in obtaining
any required environmental regulatory approvals, or if we fail to obtain and comply with them, the
operation of our facilities could be prevented or become subject to
additional costs, resulting in potentially material adverse consequences to our business,
financial condition, results of operations and cash flows.
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We make assumptions and develop expectations about possible expenditures related to
environmental conditions based on current laws and regulations and current interpretations of those
laws and regulations. If the interpretation of laws or regulations, or the laws and regulations
themselves, change, our assumptions may change, and any new capital costs incurred to comply with
such changes may not be recoverable under our regulatory rate structure or our customer contracts.
In addition, new environmental laws and regulations might adversely affect our products and
activities, including processing, fractionation, storage and transportation, as well as waste
management and air emissions. For instance, federal and state agencies could impose additional
safety requirements, any of which could affect our profitability. In addition, recent scientific
studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases
(GHGs), may be contributing to warming of the earths atmosphere, and various governmental bodies
have considered legislative and regulatory responses in this area.
Legislative and regulatory responses related to GHGs and climate change creates the potential
for financial risk. The United States Congress and certain states have for some time been
considering various forms of legislation related to GHG emissions. There have also been
international efforts seeking legally binding reductions in emissions of GHGs. In addition,
increased public awareness and concern may result in more state, regional and/or federal
requirements to reduce or mitigate GHG emissions.
Several bills have been introduced in the United States Congress that would compel GHG
emission reductions. On June 26, 2009, the U.S. House of Representatives passed the American Clean
Energy and Security Act which is intended to decrease annual GHG emissions through a variety of
measures, including a cap and trade system which limits the amount of GHGs that may be emitted
and incentives to reduce the nations dependence on traditional energy sources. The U.S. Senate is
currently considering similar legislation, and numerous states have also announced or adopted
programs to stabilize and reduce GHGs. In addition, on December 7, 2009, the EPA issued a final
determination that six GHGs are a threat to public safety and welfare. This determination could
ultimately lead to the direct regulation of GHG emissions in our industry under the CAA. While it
is not clear whether or when any federal or state climate change laws or regulations will be
passed, any of these actions could result in increased costs to (i) operate and maintain our
facilities, (ii) install new emission controls on our facilities, and (iii) administer and manage
any GHG emissions program. If we are unable to recover or pass through a significant level of our
costs related to complying with climate change regulatory requirements imposed on us, it could have
a material adverse effect on our results of operations and our ability to make cash distributions
to unitholders. To the extent financial markets view climate change and GHG emissions as a
financial risk, this could negatively impact our cost of and access to capital.
We do not insure against all potential losses and could be seriously harmed by unexpected
liabilities or by the ability of the insurers we do use to satisfy our claims.
We are not fully insured against all risks inherent to our business, including environmental
accidents that might occur. In addition, we do not maintain business interruption insurance in the
type and amount to cover all possible risks of loss. We currently maintain excess liability
insurance with limits of $610 million per occurrence and in the aggregate annually and a deductible
of $2 million per occurrence. This insurance covers us, our subsidiaries, and certain of our
affiliates for legal and contractual liabilities arising out of bodily injury, personal injury or
property damage, including resulting loss of use to third parties. This excess liability insurance
includes coverage for sudden and accidental pollution liability for full limits, with the first
$135 million of insurance also providing gradual pollution liability coverage for natural gas and
NGL operations. Pollution liability coverage excludes: release of pollutants subsequent to their
disposal; release of substances arising from the combustion of fuels that result in acidic
deposition, and testing, monitoring, clean-up, containment, treatment or removal of pollutants from
property owned, occupied by, rented to, used by or in the care, custody or control of us, our
subsidiaries, or certain of our affiliates.
We do not insure onshore underground pipelines for physical damage, except at river crossings
and at certain locations such as compressor stations. We maintain coverage of $300 million per
occurrence for
physical damage to onshore assets and resulting business interruption caused by terrorist
acts. We also maintain coverage of $100 million per occurrence for physical damage to offshore
assets caused by terrorist acts, except for our Devils Tower spar where we maintain limits of $300
million per occurrence for property damage caused by terrorist acts and $105 million per occurrence
for resulting business interruption. Also, all of our insurance is subject to deductibles. If a
significant accident or event occurs for which we are not fully insured, it could adversely affect
our operations and financial condition. We may not be able to maintain or obtain insurance of the
type and amount we desire at reasonable rates. Changes in the insurance markets subsequent to
hurricanes losses in recent years have impacted named windstorm insurance coverage, rates and
availability for Gulf of Mexico area exposures, and we may elect to self insure a portion of our
asset portfolio. We cannot assure you that we will in the future be able to obtain the levels or
types of insurance we would otherwise have obtained prior to these market changes or that the
insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards
or cover all potential losses. The occurrence of any operating risks not fully covered by insurance
could have a material adverse effect on our business, financial condition, results of operations
and cash flows, and our ability to make cash distributions to unitholders.
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In addition, certain insurance companies that provide coverage to us, including American
International Group, Inc., have experienced negative developments that could impair their ability
to pay any of our potential claims. As a result, we could be exposed to greater losses than
anticipated and may have to obtain replacement insurance, if available, at a greater cost.
Execution of our capital projects subjects us to construction risks, increases in labor costs
and materials, and other risks that may adversely affect financial results.
Our growth may be dependent upon the construction of new natural gas gathering,
transportation, processing or treating pipelines and facilities or natural gas liquids
fractionation or storage facilities, as well as the expansion of existing facilities. Construction
or expansion of these facilities is subject to various regulatory, development and operational
risks, including:
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the ability to obtain necessary approvals and permits by regulatory agencies on a timely
basis and on acceptable terms; |
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the availability of skilled labor, equipment, and materials to complete expansion
projects; |
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potential changes in federal, state and local statutes and regulations, including
environmental requirements, that prevent a project from proceeding or increase the
anticipated cost of the project; |
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impediments on our ability to acquire rights-of-way or land rights on a timely basis and
on acceptable terms; |
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the ability to construct projects within estimated costs, including the risk of cost
overruns resulting from inflation or increased costs of equipment, materials, labor or
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the ability to access capital markets to fund construction projects. |
Any of these risks could prevent a project from proceeding, delay its completion or increase
its anticipated costs. As a result, new facilities may not achieve expected investment return,
which could adversely affect our results of operations, financial position, or cash flows and our
ability to make cash distributions to unitholders.
Our operating results for certain segments of our business might fluctuate on a seasonal and
quarterly basis.
Revenues from certain segments of our business can have seasonal characteristics. In many
parts of the country, demand for natural gas and other fuels peaks during the winter. As a result,
our overall operating results in the future might fluctuate substantially on a seasonal basis.
Demand for natural gas and other fuels could vary significantly from our expectations depending on
the nature and location of our facilities and pipeline systems and the terms of our natural gas
transportation arrangements relative to demand created by unusual weather patterns.
We do not operate all of our assets. This reliance on others to operate our assets and to
provide other services could adversely affect our business and operating results.
Williams and other third parties operate certain of our assets. We have a limited ability to
control these operations and the associated costs. The success of these operations is therefore
dependent upon a number of factors that are outside our control, including the competence and
financial resources of the operators.
We rely on Williams for certain services necessary for us to be able to conduct our business.
Williams may outsource some or all of these services to third parties, and a failure of all or part
of Williams relationships with its outsourcing providers could lead to delays in or interruptions
of these services. Our reliance on Williams and others as operators and on Williams outsourcing
relationships, and our limited ability to control certain costs could have a material adverse
effect on our business, results of operations, and financial condition and our ability to make cash
distributions to unitholders.
We do not own all of the land on which our pipelines and facilities are located, which could
disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed. As
such, we are subject to the possibility of increased costs to retain necessary land use. We obtain
the rights to construct and operate our pipelines and gathering systems on land owned by third
parties and governmental agencies for a specific period of time. Our loss of these rights, through
our
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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.
Potential changes in accounting standards might cause us to revise our financial results and
disclosures in the future, which might change the way analysts measure our business or financial
performance.
Regulators and legislators continue to take a renewed look at accounting practices, financial
disclosures, companies relationships with their independent public accounting firms and retirement
plan practices. It remains unclear what new laws or regulations will be adopted, and we cannot
predict the ultimate impact that any such new laws or regulations could have. In addition, the
Financial Accounting Standards Board, the SEC or the FERC could enact new accounting standards or
FERC orders that might impact how we are required to record revenues, expenses, assets and
liabilities. Any significant change in accounting standards or disclosure requirements could have a
material adverse effect on our business, results of operations, and financial condition and our
ability to make cash distributions to unitholders.
Institutional knowledge residing with current employees nearing retirement eligibility might
not be adequately preserved.
In our business, institutional knowledge resides with employees who have many years of
service. As these employees reach retirement age, we may not be able to replace them with employees
of comparable knowledge and experience. In addition, we may not be able to retain or recruit other
qualified individuals, and our efforts at knowledge transfer could be inadequate. If knowledge
transfer, recruiting and retention
efforts are inadequate, access to significant amounts of internal historical knowledge and
expertise could become unavailable to us.
Failure of or disruptions to our outsourcing relationships might negatively impact our ability
to conduct our business.
Some studies indicate a high failure rate of outsourcing relationships. Although Williams has
taken steps to build a cooperative and mutually beneficial relationship with its outsourcing
providers and to closely monitor their performance, a deterioration in the timeliness or quality of
the services performed by the outsourcing providers or a failure of all or part of these
relationships could lead to loss of institutional knowledge and interruption of services necessary
for us to be able to conduct our business. The expiration of such agreements or the transition of
services between providers could lead to similar losses of institutional knowledge or disruptions.
Certain of our accounting, information technology, application development, and help desk
services are currently provided by Williams outsourcing provider from service centers outside of
the United States. The economic and political conditions in certain countries from which Williams
outsourcing providers may provide services to us present similar risks of business operations
located outside of the United States, including risks of interruption of business, war,
expropriation, nationalization, renegotiation, trade sanctions or nullification of existing
contracts and changes in law or tax policy, that are greater than in the United States.
Acts of terrorism could have a material adverse effect on our financial condition, results of
operations and cash flows.
Our assets and the assets of our customers and others may be targets of terrorist activities
that could disrupt our business or cause significant harm to our operations, such as full or
partial disruption to our ability to produce, process, transport or distribute natural gas, natural
gas liquids or other commodities. Acts of terrorism as well as events occurring in response to or
in connection with acts of terrorism could cause environmental repercussions that could result in a
significant decrease in revenues or significant reconstruction or remediation costs, which could
have a material adverse effect on our financial condition, results of operations, and cash flows
and on our ability to make cash distributions to unitholders.
Risks Inherent in an Investment in Us
We may not realize the anticipated benefits from the Dropdown.
We may not realize the benefits that we anticipate from the Dropdown for a number of reasons,
including, but not limited to, if any of the matters identified as risks in this Risk Factors
section were to occur. If we do not realize the anticipated benefits from the Dropdown for any
reason, our business may be materially adversely affected.
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Williams did not seek a vote of its shareholders in
connection with the Dropdown. If there
is a determination that such a vote was required, the resulting consequences could impact us.
Section 271 of the Delaware General Corporation
Law (the DGCL) generally requires a corporation to
obtain authorization from the holders of a majority of its outstanding shares if the corporation
intends to sell all or substantially all of its assets. Williams does not believe the Dropdown
constituted a sale of all or substantially all of its
assets because of, among other things, the portion of Williams assets
involved, the significance of its assets and businesses that were not
transferred and the facts that Williams retains control of all of the
assets involved and over an 80% interest in the cash flows therefrom.
As such, Williams did not seek a vote of its shareholders in connection with the Dropdown. There is a limited body of Delaware
case law interpreting the phrase all or substantially all, and there is no precise established
definition. We cannot assure you that the Dropdown does not constitute a sale of all or
substantially all of Williams assets and, therefore, that a shareholder vote was not required. If
such a shareholder vote were determined to be required, the resulting consequences
could impact us and could include (among other consequences) shareholders of Williams
asserting claims against us, some or all of which could ultimately be successful.
We will have certain indemnification obligations in favor of Williams subsequent to the
completion of the Dropdown.
In connection with the Dropdown, we have agreed to indemnify Williams, its affiliates
(other than us and our securityholders, officers, directors and employees) and its
respective securityholders, officers, directors and employees against certain losses
resulting from any breach of our representations, warranties, covenants or agreements contained in
the Contribution Agreement. These indemnification obligations could be significant. We cannot
determine whether we will have to indemnify Williams or its affiliates for any substantial
obligations after the Dropdown has become effective. We also cannot provide any assurance
that if Williams has to indemnify us for any substantial obligations after the Dropdown has
become effective, Williams will be able to satisfy such obligations.
Williams controls our general partner, which has sole responsibility for conducting our business
and managing our operations. Our general partner and its affiliates have conflicts of interest
with us and limited fiduciary duties, and they may favor their own interests to the detriment of
our unitholders.
Williams owns and controls our general partner and appoints all of the directors of our
general partner. All of the executive officers and certain directors of our general partner are
officers and/or directors of Williams and its affiliates, including WMZs general partner. Although
our general partner has a fiduciary duty to manage us in a manner beneficial to us and our
unitholders, the directors and officers of our general partner have a fiduciary duty to manage our
general partner in a manner beneficial to Williams. Therefore, conflicts of interest may arise
between Williams and its affiliates, including our general partner and WMZ, on the one hand, and us
and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor
its own interests and the interests of its affiliates over the interests of our unitholders. These
conflicts include, among others, the following factors:
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neither our partnership agreement nor any other agreement requires Williams or its
affiliates to pursue a business strategy that favors us. Williams directors and officers
have a fiduciary duty to make decisions in the best interests of the owners of Williams,
which may be contrary to ours; |
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all of the executive officers and certain of the directors of our general partner are
also officers and/or directors of Williams and WMZs general partner, and these persons will
also owe fiduciary duties to those entities; |
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our general partner is allowed to take into account the interests of parties other than
us, such as Williams and its affiliates, in resolving conflicts of interest; |
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Williams owns common units representing an 82% limited partner interest in us, and if a
vote of limited partners is required, Williams will be entitled to vote its units in
accordance with its own interests, which may be contrary to our interests or your interests; |
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all of the executive officers and certain of the directors of our general partner will
devote significant time to the business of Williams and/or Williams Partners, and will be
compensated by Williams for the services rendered to them; |
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our general partner determines the amount and timing of our cash reserves, asset
purchases and sales, capital expenditures, borrowings and issuances of additional
partnership securities, each of which can affect the amount of cash that is distributed to
our unitholders; |
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our general partner determines the amount and timing of any capital expenditures and,
based on the applicable facts and circumstances, whether a capital expenditure is classified
as a maintenance
capital expenditure, which reduces operating surplus, or an expansion capital expenditure or
investment capital expenditure, neither of which reduces operating surplus. This determination
can affect the amount of cash that is distributed to our unitholders and to our general
partner with respect to its incentive distribution rights; |
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in some instances, our general partner may cause us to borrow funds in order to permit
the payment of cash distributions even if the purpose or effect of the borrowing is to make
incentive distributions to our general partner; |
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our general partner determines which costs incurred by it and its affiliates are
reimbursable by us; |
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our partnership agreement does not restrict our general partner from causing us to pay it
or its affiliates for any services rendered to us or entering into additional contractual
arrangements with any of these entities on our behalf; |
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our general partner intends to limit its liability regarding our contractual and other
obligations and in some circumstances is required to be indemnified by us; |
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our general partner may exercise its limited right to call and purchase common units if
it and its affiliates own more than 85% 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. |
Our partnership agreement limits our general partners fiduciary duties to unitholders and
restricts the remedies available to unitholders for actions taken by our general partner that
might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our general
partner would otherwise be held by state fiduciary duty law. The limitation and definition of these
duties is permitted by the Delaware law governing limited partnerships. In addition, our
partnership agreement restricts the remedies available to holders of our limited partner units for
actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
For example, our partnership agreement:
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permits our general partner to make a number of decisions in its individual capacity as
opposed to in its capacity as our general partner. This entitles our general partner to
consider only the interests and factors that it desires, and it has no duty or obligation to
give any consideration to any interest of, or factors affecting, us, our affiliates or any
limited partner. Examples include the exercise of its limited call right, its voting rights
with respect to the units it owns, its registration rights and its determination whether or
not to consent to any merger or consolidation of the partnership or amendment to the
partnership agreement; |
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provides that our general partner will not have any liability to us or our unitholders
for decisions made in its capacity as a general partner so long as it acted in good faith,
meaning it believed the decision was in the best interests of our partnership; |
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generally provides that affiliate transactions and resolutions of conflicts of interest
not approved by the conflicts committee of the board of directors of our general partner and
not involving a vote of unitholders must be on terms no less favorable to us than those
generally being provided to or available from unrelated third parties or be fair and
reasonable to us, as determined by our general partner in good faith. In determining
whether a transaction or resolution is fair and reasonable, our general partner may
consider the totality of the relationships between the parties involved, including other
transactions that may be particularly advantageous or beneficial to us; |
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provides that our general partner, its affiliates and their officers and directors will
not be liable for monetary damages to us or our limited partners or assignees for any acts
or omissions unless there has been a final and non-appealable judgment entered by a court of
competent jurisdiction determining that our general partner or those other persons acted in
bad faith or engaged in fraud or willful misconduct; and |
43
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provides that in resolving conflicts of interest, it will be presumed that in making its
decision our general partner or the conflicts committee of its board of directors acted in
good faith, and in any proceeding brought by or on behalf of any limited partner or us, the
person bringing or prosecuting such proceeding will have the burden of overcoming such
presumption. |
Common unitholders are bound by the provisions in the partnership agreement, including the
provisions discussed above.
Affiliates of our general partner, including Williams, may not be limited in their ability to
compete with us. Williams is also not obligated to offer us the opportunity to acquire
additional assets or businesses from it, which could limit our commercial activities or our
ability to grow. In addition, all of the executive officers and certain of the directors of our
general partner are also officers and/or directors of Williams, and these persons will also owe
fiduciary duties to it.
While our relationship with Williams and its affiliates is a significant attribute, it is also
a source of potential conflicts. For example, Williams is in the natural gas business and is not
restricted from competing with us. Williams and its affiliates may compete with us. Williams and
its affiliates may acquire, construct or dispose of natural gas industry assets in the future, some
or all of which may compete with our assets, without any obligation to offer us the opportunity to
purchase or construct such assets. In addition, all of the executive officers and certain of the
directors of our general partner are also officers and/or directors of Williams and WMZs general
partner and will owe fiduciary duties to those entities as well as our unitholders and us.
Holders of our common units have limited voting rights and are not entitled to elect our general
partner or its directors, which could reduce the price at which the common units will trade.
Unlike the holders of common stock in a corporation, unitholders have only limited voting
rights on matters affecting our business and, therefore, limited ability to influence managements
decisions regarding our business. Unitholders will have no right to elect our general partner or
its board of directors on an annual or other continuing basis. The board of directors of our
general partner, including the independent directors, will be chosen entirely by Williams and not
by the unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our
unitholders to elect directors or conduct other matters routinely conducted at annual meetings of
stockholders. Furthermore, if the unitholders become dissatisfied with the performance of our
general partner, they will have little ability to remove our general partner. As a result of these
limitations, the price at which the common units will trade could be diminished because of the
absence or reduction of a takeover premium in the trading price.
Cost reimbursements due to our general partner and its affiliates will reduce cash available to
pay distributions to unitholders.
We will reimburse our general partner and its affiliates, including Williams, for various
general and administrative services they provide for our benefit, including costs for rendering
administrative staff and support services to us, and overhead allocated to us. Our general partner
determines the amount of these reimbursements in its sole discretion. Payments for these services
will be substantial and will reduce the amount of cash available for distributions to unitholders.
In addition, under Delaware partnership law, our general partner has unlimited liability for our
obligations, such as our debts and environmental liabilities, except for our contractual
obligations that are expressly made without recourse to our general partner. To the extent our
general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If
we are unable or unwilling to reimburse or indemnify our general partner, our general partner may
take actions to cause us to make payments of these obligations and liabilities. Any such
payments could reduce the amount of cash otherwise available for distribution to our unitholders.
Even if unitholders are dissatisfied, they have little ability to remove our general partner
without its consent.
Unlike the holders of common stock in a corporation, unitholders have only limited voting
rights on matters affecting our business and, therefore, limited ability to influence managements
decisions regarding our business. Unitholders will have no right to elect our general partner or
its board of directors on an annual or other continuing basis. The board of directors of our
general partner is chosen by Williams. As a result of these limitations, the price at which our
common units will trade could be diminished because of the absence or reduction of a takeover
premium in the trading price.
Furthermore, if our unitholders are dissatisfied with the performance of our general partner,
they will have little ability to remove our general partner. The vote of the holders of at least 66
2/3% of all outstanding common units is required to remove our general partner.
44
We have a holding company structure in which our subsidiaries conduct our operations and own our
operating assets, which may affect our ability to make payments on our debt obligations and
distributions on our common units.
We have a holding company structure, and our subsidiaries conduct all of our operations and
own all of our operating assets. We have no significant assets other than the ownership interests
in these subsidiaries. As a result, our ability to make required payments on our debt obligations
and distributions on our common units depends on the performance of our subsidiaries and their
ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may
be restricted by, among other things, applicable state partnership and limited liability company
laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the
principal amount at maturity of our debt obligations, to repurchase our debt obligations upon the
occurrence of a change of control or make distributions on our common units, we may be required to
adopt one or more alternatives, such as a refinancing of our debt obligations or borrowing funds to
make distributions on our common units. We cannot assure you that we would be able to borrow funds
to make distributions on our common units.
Our allocation from Williams for costs
for its defined benefit pension
plans and other postretirement benefit plans are affected by factors beyond our and Williams
control.
As we have no employees, employees of Williams and its affiliates provide services to us. As a
result, we are allocated a portion of Williams costs in defined benefit pension plans covering
substantially all of Williams or its affiliates employees providing services to us, as well as a
portion of the costs of other postretirement benefit plans covering certain eligible participants
providing services to us. The timing and amount of our allocations under the defined benefit
pension plans depend upon a number of factors Williams controls, including changes to pension plan
benefits, as well as factors outside of Williams control, such as asset returns, interest rates
and changes in pension laws. Changes to these and other factors that can significantly increase our
allocations could have a significant adverse effect on our financial condition and results of
operations.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or
in a sale of all or substantially all of its assets without the consent of the unitholders.
Furthermore, our partnership agreement effectively permits a change of control without your
consent.
We may issue additional common units without unitholder approval, which would dilute unitholder
ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests
that we may issue at any time without the approval of unitholders. The issuance by us of additional
common units or other equity securities of equal or senior rank will have the following effects:
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our unitholders proportionate ownership interest in us will decrease; |
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the amount of cash available to pay distributions on each unit may decrease; |
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the ratio of taxable income to distributions may decrease; |
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the relative voting strength of each previously outstanding unit may be diminished; and |
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the market price of the common units may decline. |
Common units held by Williams eligible for future sale may adversely affect the price of our
common units.
As of December 31, 2009, Williams held 11,613,527 common units, representing a 21.6% limited
partnership interest in us. After the Dropdown, Williams held 214,613,527 common units and Class C
units, representing an 82% limited partnership interest in us. Williams may, from time to time,
sell all or a portion of its common units. Sales of substantial amounts of its common units, or the
anticipation of such sales, could lower the market price of our common units and may make it more
difficult for us to sell our equity securities in the future at a time and at a price that we deem
appropriate.
45
Our general partner has a limited call right that may require unitholders to sell their common
units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units,
our general partner will have the right, but not the obligation, to acquire all, but not less than
all, of the common units held by unaffiliated persons at a price not less than their then-current
market price. In connection with the closing of the Dropdown, we entered into a limited call right
forbearance agreement with our general partner, pursuant to which our general partner agreed not to
exercise this right unless it and its affiliates hold more than 85% of our common limited partner
units. The forbearance agreement will terminate when the ownership by our general partner and its
affiliates of our common limited partner units decreases below 75% (assuming the full conversion of
Class C Units that are held by our general partner and its affiliates). Our general partner may
assign this right to any of its affiliates or to us. As a result, non-affiliated unitholders may be
required to sell their common units at an undesirable time or price and may not receive any return
on their investment. Such unitholders may also incur a tax liability upon a sale of their units.
Our general partner is not obligated to obtain a fairness opinion regarding the value of the common
units to be repurchased by it upon exercise of the limited call right. There is no restriction in
our partnership agreement that prevents our general partner from issuing additional common units
and exercising its call right. If our general partner exercised its limited call right, the effect
would be to take us private and, if the units were subsequently deregistered, we would not longer
be subject to the reporting requirements of the Securities Exchange Act of 1934.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our
common units.
Our partnership agreement restricts unitholders voting rights by providing that any units
held by a person that owns 20% or more of any class of units then outstanding, other than our
general partner and its affiliates, their transferees and persons who acquired such units with the
prior approval of the board of directors of our general partner, cannot be voted on any matter. The
partnership agreement also contains provisions limiting the ability of unitholders to call
meetings, to acquire information about our operations and to influence the manner or direction of
management.
Your liability may not be limited if a court finds that unitholder action constitutes control of
our business.
A general partner of a partnership generally has unlimited liability for the obligations of
the partnership, except for those contractual obligations of the partnership that are expressly
made without recourse to the general partner. Our partnership is organized under Delaware law and
we conduct business in a number of other states. The limitations on the liability of holders of
limited partner interests for the obligations of a limited partnership have not been clearly
established in some of the other states in which we do business. You could be liable for any and
all of our obligations as if you were a general partner if a court or government agency were to
determine that:
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we were conducting business in a state but had not complied with that particular states
partnership statute; or |
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your right to act with other unitholders to remove or replace the general partner, to
approve some amendments to our partnership agreement or to take other actions under our
partnership agreement constitute control of our business. |
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or
distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act,
we may not make a distribution to you if the distribution would cause our liabilities to exceed the
fair value of our assets. Delaware law provides that for a period of three years from the date of
the impermissible distribution, limited partners who received the distribution and who knew at the
time of the distribution that it violated Delaware law will be liable to the limited partnership
for the distribution amount. Substituted limited partners are liable for the obligations of the
assignor to make contributions to the partnership that are known to the substituted limited partner
at the time it became a limited partner and for unknown obligations if the liabilities could be
determined from the partnership agreement. Liabilities to partners on account of their partnership
interest and liabilities that are non-recourse to the partnership are not counted for purposes of
determining whether a distribution is permitted.
Tax Risks
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well
as our not being subject to a material amount of entity-level taxation by states and localities.
If the Internal Revenue Service (IRS) were to treat us as a
46
corporation or if we were to become
subject to a material amount of entity-level taxation for state or local tax purposes, then our
cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends
largely on our being treated as a partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the IRS on this or any other tax matter
affecting us.
If we were treated as a corporation for federal income tax purposes, we would pay federal
income tax on our taxable income at the corporate tax rate, which currently has a top marginal rate
of 35%, and would likely pay state and local income tax at the corporate tax rate of the various
states and localities imposing a corporate income tax. Distributions to unitholders would generally
be taxed again as corporate distributions, and no income, gains, losses, deductions or credits
would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our
cash available to pay distributions to unitholders would be substantially reduced. Thus, treatment
of us as a corporation would result in a material reduction in the anticipated cash flow and
after-tax return to unitholders, likely causing a substantial reduction in the value of the common
units.
Current law may change, causing us to be treated as a corporation for federal income tax
purposes or otherwise subjecting us to entity-level taxation. In addition, because of widespread
state budget deficits and other reasons, several states are evaluating ways to subject partnerships
to entity-level taxation through the imposition of state income, franchise or other forms of
taxation. If any state were to impose a tax upon us as an entity, the cash available for distributions to unitholders would be reduced. The
partnership agreement provides that if a law is enacted or existing law is modified or interpreted
in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level
taxation for federal, state or local income tax purposes, then the minimum quarterly distribution
amount and the target distribution amounts will be adjusted to reflect the impact of that law on
us.
The tax treatment of publicly traded partnerships or an investment in our common units could be
subject to potential legislative, judicial or administrative changes and differing
interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us,
or an investment in our common units may be modified by administrative, legislative or judicial
interpretation at any time. Any modification to the U.S. federal income tax laws and
interpretations thereof may or may not be applied retroactively and could make it more difficult or
impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax
purposes that is not taxable as a corporation (the Qualifying Income Exception), affect or cause us
to change our business activities, affect the tax considerations of an investment in us, change the
character or treatment of portions of our income and adversely affect an investment in our common
units. For example, in response to certain recent developments, members of Congress are considering
substantive changes to the definition of qualifying income under Internal Revenue Code Section
7704(d) and the treatment of certain types of income earned from profits interests in partnerships.
It is possible that these legislative efforts could result in changes to the existing U.S. tax laws
that affect publicly traded partnerships, including us. Modifications to the U.S. federal income
tax laws and interpretations thereof may or may not be applied retroactively. We are unable to
predict whether any of these changes, or other proposals, will ultimately be enacted. Any such
changes could negatively impact the value of an investment in our common units.
We prorate our items of income, gain, loss and deduction between transferors and transferees of
the common units each month based upon the ownership of the common units on the first day of each
month, instead of on the basis of the date a particular common unit is transferred.
We prorate our items of income, gain, loss and deduction between transferors and transferees
of the common units each month based upon the ownership of the common units on the first day of
each month, instead of on the basis of the date a particular common unit is transferred. The use of
this proration method may not be permitted under existing Treasury regulations, and, accordingly,
our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this
method or new Treasury regulations were issued, we may be required to change the allocation of
items of income, gain, loss and deduction among our unitholders.
An IRS contest of the federal income tax positions we take may adversely impact the market for the
common units, and the costs of any contest will reduce our cash available for distribution to our
unitholders and our general partner.
We have not requested any ruling from the IRS with respect to our treatment as a partnership
for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that
differ from our counsels conclusions or from the positions we take. It may be necessary to resort
to administrative or court proceedings to sustain some or all of our counsels conclusions or the
positions we take. A court may not agree with some or all of our counsels conclusions or the
federal income tax positions we take. Any contest
47
with the IRS may materially and adversely impact
the market for the common units and the price at which they trade. In addition, the costs of any
contest with the IRS will result in a reduction in cash available to pay distributions to our
unitholders and our general partner and thus will be borne indirectly by our unitholders and our
general partner.
Unitholders will be required to pay taxes on their share of our income even if unitholders do not
receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income
which could be different in amount than the cash we distribute, unitholders will be required to pay
federal income taxes and, in some cases, state and local income taxes on their share of our taxable
income, whether or not they receive cash distributions from us. Unitholders may not receive cash
distributions from us equal to their share of our taxable income or even equal to the actual tax
liability that results from their share of our taxable income.
The tax gain or loss on the disposition of the common units could be different than expected.
If a unitholder sells its common units, it will recognize gain or loss equal to the difference
between the amount realized and its tax basis in those common units. Prior distributions to a
unitholder in excess of the total net taxable income that was allocated to a unitholder for a
common unit, which decreased its tax basis in that common unit, will, in effect, become taxable
income to the unitholder if the common unit is sold at a price greater than its tax basis in that
common unit, even if the price the unitholder receives is less than its original cost. A
substantial portion of the amount realized, regardless of whether such amount represents gain, may
be taxed as ordinary income to the unitholder due to potential recapture items, including
depreciation recapture. In addition, if a unitholder sells its common units, the unitholder may
incur a tax liability in excess of the amount of cash it received from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may
result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts
(known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of
our income allocated to the unitholders who are organizations that are exempt from federal income
tax, including IRAs and other retirement plans, may be taxable to them as unrelated business
taxable income. Distributions to non-U.S. persons will be reduced by withholding taxes at the
highest applicable effective tax rate, and non-U.S. persons will be required to file United States
federal income tax returns and pay tax on their share of our taxable income.
We will treat each purchaser of common units as having the same tax benefits without regard to the
actual common units purchased. The IRS may challenge this treatment, which could adversely affect
the value of the common units.
Because we cannot match transferors and transferees of common units, we will adopt
depreciation and amortization positions that may not conform with all aspects of applicable
Treasury regulations. Our counsel is unable to opine as to the validity of such filing positions. A
successful IRS challenge to those positions could adversely affect the amount of tax benefits
available to unitholders. It also could affect the timing of these tax benefits or the amount of
gain from the sale of common units and could have a negative impact on the value of the common
units or result in audit adjustments to unitholder tax returns.
Unitholders will likely be subject to state and local taxes and return filing requirements as a
result of investing in our common units.
In addition to federal income taxes, unitholders will likely be subject to other taxes, such
as state and local income taxes, unincorporated business taxes and estate, inheritance, or
intangible taxes that are imposed by the various jurisdictions in which we do business or own
property, even if the unitholder does not live in any of those jurisdictions. Unitholders will
likely be required to file state and local income tax returns and pay state and local income taxes
in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for
failure to comply with those requirements. As we make acquisitions or expand our business, we may
own assets or conduct business in additional states or foreign countries that impose a personal
income tax or an entity level tax. It is the unitholders responsibility to file all federal, state
and local tax returns. Our counsel has not rendered an opinion on the state and local tax
consequences of an investment in our common units.
48
The sale or exchange of 50% or more of the total interest in our capital and profits within a
12-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership for federal income tax purposes if
there is a sale or exchange of 50% or more of the total interests in our capital and profits within
a 12-month period. Our termination would, among other things, result in the closing of our taxable
year for all unitholders, which would result in us filing two tax returns for one fiscal year. Our
termination could also result in a deferral of depreciation deductions allowable in computing our
taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year
ending December 31, the closing of our taxable year may also result in more than 12 months of our
taxable income or loss being includable in the unitholders taxable income for the year of
termination. Our termination currently would not affect our classification as a partnership for
federal income tax purposes, but instead, we would be treated as a new partnership, we would be
required to make new tax elections and could be subject to penalties if we are unable to determine
that a termination occurred.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss
and deduction between the general partner and the unitholders. The IRS may challenge this
treatment, which could adversely affect the value of the common units.
When we issue additional common units or engage in certain other transactions, we determine
the fair market value of our assets and allocate any unrealized gain or loss attributable to our
assets to the capital accounts of our unitholders and our general partner. Our methodology may be
viewed as understating the value of our assets. In that case, there may be a shift of income, gain,
loss and deduction between certain unitholders and the general partner, which may be unfavorable to
such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common
units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated
to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may
challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to
our tangible and intangible assets, and allocations of income, gain, loss and deduction between the
general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount
of taxable income or loss being allocated to our unitholders. It also could affect the amount of
gain from a unitholders sale of common units and could have a negative impact on the value of the
common units or result in audit adjustments to the unitholders tax returns.
Item 1B. Unresolved Staff Comments
None.
Item 3. Legal Proceedings
The information called for by this item is provided below and in Note 16, Commitments and
Contingencies, in our Notes to Consolidated Financial Statements of this report, which information
in Note 16 is incorporated into this Item 3 by reference.
Environmental Matters
Since 1989, Transco has had studies underway to test certain of its facilities for the
presence of toxic and hazardous substances to determine to what extent, if any, remediation may be
necessary. Transco has responded to data requests from the U.S. Environmental Protection Agency
(EPA) and state agencies regarding such potential contamination of certain of its sites. Transco
has identified polychlorinated biphenyl (PCB) contamination in compressor systems, soils and
related properties at certain compressor station sites. Transco has also been involved in
negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs.
In addition, Transco commenced negotiations with certain environmental authorities and other
parties concerning investigative and remedial actions relative to potential mercury contamination
at certain gas metering sites. The costs of any such remediation will depend upon the scope of the
remediation. At December 31, 2009, Transco had accrued liabilities of $4.7
million related to PCB contamination, potential mercury contamination, and other toxic and
hazardous substances. Transco has been identified as a potentially responsible party at various
Superfund and state waste disposal sites. Based on present volumetric estimates and other factors,
Transco has estimated its aggregate exposure for remediation of these sites to be less than
$500,000, which is included in the environmental accrual discussed above. We expect that these
costs will be recoverable through Transcos rates.
Beginning in the mid-1980s, Northwest Pipeline evaluated many of its facilities for the
presence of toxic and hazardous substances to determine to what extent, if any, remediation might
be necessary. Consistent with other natural gas transmission
49
companies, Northwest Pipeline
identified PCB contamination in air compressor systems, soils and related properties at certain
compressor station sites. Similarly, Northwest Pipeline identified hydrocarbon impacts at these
facilities due to the former use of earthen pits and mercury contamination at certain gas metering
sites. The PCBs were remediated pursuant to a Consent Decree with the EPA in the late 1980s and
Northwest Pipeline conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the
early 1990s. In 2005, the Washington Department of Ecology required Northwest Pipeline to
reevaluate its previous mercury clean-ups in Washington. Consequently, Northwest Pipeline is
conducting additional remediation activities at certain sites to comply with Washingtons current
environmental standards. At December 31, 2009 Northwest Pipeline accrued liabilities of $7.8
million for these costs. We expect that these costs will be recoverable through Northwest
Pipelines rates.
In September 2007, the EPA requested, and Transco later provided, information regarding
natural gas compressor stations in the states of Mississippi and Alabama as part of the EPAs
investigation of our compliance with the Clean Air Act. On March 28, 2008, the EPA issued notice of
violations alleging violations of Clean Air Act requirements at these compressor stations. Transco
met with the EPA in May 2008 and submitted its response denying the allegations in June 2008. In
July 2009, the EPA requested additional information pertaining to these compressor stations and in
August 2009, Transco submitted the requested information.
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5. Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
Market Information, Holders and Distributions
Our common units are listed on the New York Stock Exchange under the symbol WPZ. At the
close of business on February 18, 2010, there were 52,777,452 common units outstanding, held by
approximately 29,122 holders, including common units held in street name and by affiliates of
Williams.
As
of February 18, 2010, there were 203,000,000 Class C units outstanding, held by three
subsidiaries of Williams. The Class C units are not publicly traded. Our Class C units are
identical to our common units except that the quarterly distribution they receive with respect to
first quarter 2010 will be prorated to reflect the fact that the Class C units were not outstanding
during the full quarterly period. The Class C units will automatically convert into common units
following the record date for the distribution with respect to the first quarter of 2010. Our
general partner holds all of our 2% general partner interest and incentive distribution rights. As
part of the consideration for the Dropdown, we increased the capital account of our general partner
to allow it to maintain its 2% general partner interest and issued additional general partner units
to our general partner equal to 2/98th of the number of Class C units issued (Additional
GP Units). Distributions on the Additional GP Units with respect to the first quarter 2010 will
also be prorated to reflect that they were not outstanding during the full quarterly period.
50
The following table sets forth, for the periods indicated, the high and low sales prices
for our common units, as reported on the New York Stock Exchange Composite Transactions Tape, and
quarterly cash distributions paid to our unitholders.
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Cash Distribution |
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High |
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Low |
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per Unit(a) |
2009 |
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Fourth Quarter |
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$ |
32.23 |
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$ |
22.20 |
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$ |
0.635 |
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Third Quarter |
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23.80 |
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17.10 |
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0.635 |
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Second Quarter |
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19.70 |
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10.89 |
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0.635 |
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First Quarter |
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17.88 |
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8.54 |
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0.635 |
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2008 |
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Fourth Quarter |
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$ |
26.25 |
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$ |
9.96 |
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$ |
0.635 |
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Third Quarter |
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32.84 |
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22.77 |
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0.635 |
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Second Quarter |
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37.66 |
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31.33 |
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0.625 |
|
First Quarter |
|
|
39.31 |
|
|
|
31.24 |
|
|
|
0.600 |
|
|
|
|
(a) |
|
Represents cash distributions attributable to the quarter and declared
and paid within 45 days after quarter end. We paid cash distributions
to our general partner with respect to its 2% general partner interest
and incentive distribution rights that totaled $2.7 million and
$30.0 million for the 2009 and 2008 periods, respectively. |
Distributions of Available Cash
Within 45 days after the end of each quarter we will distribute all of our available cash, as
defined in our partnership agreement, to unitholders of record on the applicable record date.
Available cash generally means, for each fiscal quarter, all cash on hand at the end of the
quarter:
|
|
|
less the amount of cash reserves established by our general partner to: |
|
|
|
provide for the proper conduct of our business (including reserves for future
capital expenditures and for our anticipated credit needs); |
|
|
|
|
comply with applicable law, any of our debt instruments or other agreements; or |
|
|
|
|
provide funds for distribution to our unitholders and to our general partner for any one
or more of the next four quarters; |
|
|
|
plus all cash on hand on the date of determination of available cash for the quarter
resulting from working capital borrowings made after the end of the quarter for which the
determination is being made. Working capital borrowings are borrowings used solely for
working capital purposes or to pay distributions made pursuant to a credit facility or other
arrangement to the extent such borrowings are required to be reduced to a relatively small
amount each year for an economically meaningful period of time. |
Subject to the proration on the distribution that Class C unitholders and the Additional GP
Units will receive with respect to the first quarter of 2010 described above, we will make
distributions of available cash from operating surplus for any quarter in the following manner:
|
|
|
first, 98% to all unitholders, pro rata, and 2% to our general partner, until each
outstanding unit has received the minimum quarterly distribution for that quarter; and |
|
|
|
|
thereafter, cash in excess of the minimum quarterly distributions is distributed to the
unitholders and the general partner based on the incentive percentages below. |
51
Our general partner is entitled to incentive distributions if the amount we distribute with
respect to any quarter exceeds specified target levels shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marginal Percentage |
|
|
Total Quarterly Distribution |
|
Interest in Distributions |
|
|
Target Amount |
|
Unitholders |
|
General Partner |
Minimum Quarterly Distribution |
|
$0.35 |
|
|
98 |
% |
|
|
2 |
% |
First Target Distribution |
|
up to $0.4025 |
|
|
98 |
% |
|
|
2 |
% |
Second Target Distribution |
|
above $0.4025 up to $0.4375 |
|
|
85 |
% |
|
|
15 |
% |
Third Target distribution |
|
above $0.4375 up to $0.5250 |
|
|
75 |
% |
|
|
25 |
% |
Thereafter |
|
Above $0.5250 |
|
|
50 |
% |
|
|
50 |
% |
If the unitholders remove our general partner other than for cause and units held by our
general partner and its affiliates are not voted in favor of such removal:
|
|
|
any existing arrearages in payment of the minimum quarterly distribution on the common
units will be extinguished; and |
|
|
|
|
our general partner will have the right to convert its general partner interest and, if
any, its incentive distribution rights into common units or to receive cash in exchange for
those interests. |
The preceding discussion is subject to the proration on the distribution that the Additional
GP Units will receive with respect to the first quarter of 2010 described above and is based on the
assumption that our general partner maintains its 2% general partner interest and that we do not
issue additional classes of equity securities. Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations Financial Condition and Liquidity.
Item 6. Selected Financial and Operational Data
The following table shows our selected financial and operating data and selected financial and
operating data of Wamsutter and Discovery for the periods and as of the dates indicated and do not
reflect the consummation of the Dropdown. We derived the financial data as of December 31, 2009 and
2008 and for the years ended December 31, 2009, 2008 and 2007 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.
52
The table should also be read together with Managements Discussion and Analysis of Financial
Condition and Results of Operations for information concerning significant trends in the financial
condition and results of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
(Dollars in thousands, except per-unit amounts) |
|
|
|
|
|
Statement of Income Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
470,189 |
|
|
$ |
637,060 |
|
|
$ |
572,817 |
|
|
$ |
563,410 |
|
|
$ |
514,972 |
|
Costs and expenses |
|
|
368,437 |
|
|
|
490,052 |
|
|
|
457,880 |
|
|
|
420,342 |
|
|
|
395,556 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
101,752 |
|
|
|
147,008 |
|
|
|
114,937 |
|
|
|
143,068 |
|
|
|
119,416 |
|
Equity earnings Wamsutter |
|
|
84,052 |
|
|
|
88,538 |
|
|
|
76,212 |
|
|
|
61,690 |
|
|
|
40,555 |
|
Discovery investment income |
|
|
27,243 |
|
|
|
22,357 |
|
|
|
28,842 |
|
|
|
18,050 |
|
|
|
11,880 |
|
Interest expense |
|
|
(60,679 |
) |
|
|
(67,220 |
) |
|
|
(58,348 |
) |
|
|
(9,833 |
) |
|
|
(8,238 |
) |
Interest income |
|
|
99 |
|
|
|
706 |
|
|
|
2,988 |
|
|
|
1,600 |
|
|
|
165 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle |
|
$ |
152,467 |
|
|
$ |
191,389 |
|
|
$ |
164,631 |
|
|
$ |
214,575 |
|
|
$ |
163,778 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income(a) |
|
$ |
152,467 |
|
|
$ |
191,389 |
|
|
$ |
164,631 |
|
|
$ |
214,575 |
|
|
$ |
162,373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting
principle per limited partner unit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unit |
|
$ |
2.88 |
|
|
$ |
3.08 |
|
|
$ |
1.99 |
|
|
$ |
1.73 |
|
|
$ |
0.49 |
(b) |
Subordinated unit |
|
|
N/A |
|
|
|
N/A |
|
|
$ |
1.99 |
|
|
$ |
1.73 |
|
|
$ |
0.49 |
(b) |
Net income per limited partner unit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unit |
|
$ |
2.88 |
|
|
$ |
3.08 |
|
|
$ |
1.99 |
|
|
$ |
1.73 |
|
|
$ |
0.44 |
(b) |
Subordinated unit |
|
|
N/A |
|
|
|
N/A |
|
|
$ |
1.99 |
|
|
$ |
1.73 |
|
|
$ |
0.44 |
(b) |
Balance Sheet Data (at period end): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,323,670 |
|
|
$ |
1,291,819 |
|
|
$ |
1,283,477 |
|
|
$ |
1,292,299 |
|
|
$ |
1,190,508 |
|
Property, plant and equipment, net |
|
|
634,233 |
|
|
|
640,520 |
|
|
|
642,289 |
|
|
|
647,578 |
|
|
|
658,965 |
|
Investment in Wamsutter |
|
|
272,549 |
|
|
|
277,707 |
|
|
|
284,650 |
|
|
|
262,245 |
|
|
|
240,156 |
|
Investment in Discovery |
|
|
188,511 |
|
|
|
184,466 |
|
|
|
214,526 |
|
|
|
221,187 |
|
|
|
225,337 |
|
Long-term debt |
|
|
1,000,000 |
|
|
|
1,000,000 |
|
|
|
1,000,000 |
|
|
|
750,000 |
|
|
|
|
|
Partners capital |
|
|
215,395 |
|
|
|
203,610 |
|
|
|
161,487 |
(c) |
|
|
471,341 |
(c) |
|
|
1,142,478 |
|
Cash Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distributions declared per unit |
|
$ |
2.540 |
|
|
$ |
2.435 |
|
|
$ |
2.045 |
|
|
$ |
1.605 |
|
|
$ |
0.1484 |
|
Cash distributions paid per unit |
|
$ |
2.540 |
|
|
$ |
2.435 |
|
|
$ |
2.045 |
|
|
$ |
1.605 |
|
|
$ |
0.1484 |
|
Operating Information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Four Corners gathering volumes (BBtu/d) |
|
|
1,344 |
|
|
|
1,380 |
|
|
|
1,442 |
|
|
|
1,500 |
|
|
|
1,522 |
|
Four Corners plant inlet natural gas volumes (BBtu/d) |
|
|
620 |
|
|
|
646 |
|
|
|
620 |
|
|
|
678 |
|
|
|
685 |
|
Four Corners NGL equity sales (million gallons) |
|
|
164 |
|
|
|
162 |
|
|
|
167 |
|
|
|
182 |
|
|
|
165 |
|
Four Corners NGL margin ($/gallon) |
|
$ |
.44 |
|
|
$ |
.75 |
|
|
$ |
.61 |
|
|
$ |
.47 |
|
|
$ |
.37 |
|
Four Corners NGL production (million gallons) |
|
|
525 |
|
|
|
518 |
|
|
|
545 |
|
|
|
569 |
|
|
|
550 |
|
Conway storage revenues |
|
$ |
33,209 |
|
|
$ |
31,429 |
|
|
$ |
28,016 |
|
|
$ |
25,237 |
|
|
$ |
20,290 |
|
Conway fractionation volumes (bpd) our 50% |
|
|
38,594 |
|
|
|
39,019 |
|
|
|
34,460 |
|
|
|
38,859 |
|
|
|
39,965 |
|
Carbonate Trend gathering volumes (BBtu/d) |
|
|
18 |
|
|
|
22 |
|
|
|
23 |
|
|
|
29 |
|
|
|
36 |
|
Wamsutter 100%: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wamsutter gathering volumes (BBtu/d) |
|
|
537 |
|
|
|
499 |
|
|
|
516 |
|
|
|
490 |
|
|
|
464 |
|
Wamsutter plant inlet natural gas volumes (BBtu/d) |
|
|
423 |
|
|
|
409 |
|
|
|
425 |
|
|
|
432 |
|
|
|
422 |
|
Wamsutter NGL equity sales (million gallons) |
|
|
149 |
|
|
|
139 |
|
|
|
113 |
|
|
|
141 |
|
|
|
160 |
|
Wamsutter NGL margin ($/gallon) |
|
$ |
.39 |
|
|
$ |
.59 |
|
|
$ |
.48 |
|
|
$ |
.29 |
|
|
$ |
.13 |
|
Wamsutter NGL production (million gallons) |
|
|
447 |
|
|
|
415 |
|
|
|
420 |
|
|
|
377 |
|
|
|
419 |
|
Discovery Producer Services 100%: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery plant inlet natural gas volumes (BBtu/d) |
|
|
485 |
|
|
|
457 |
|
|
|
582 |
|
|
|
467 |
|
|
|
345 |
|
Discovery gross processing margin ($/MMbtu) |
|
$ |
.26 |
|
|
$ |
.37 |
|
|
$ |
.33 |
|
|
$ |
.23 |
|
|
$ |
.19 |
|
Discovery NGL equity sales (million gallons) |
|
|
94 |
|
|
|
85 |
|
|
|
99 |
|
|
|
60 |
|
|
|
38 |
|
Discovery NGL production (million gallons) |
|
|
250 |
|
|
|
181 |
|
|
|
252 |
|
|
|
232 |
|
|
|
147 |
|
53
|
|
|
(a) |
|
Our operations are treated as a partnership with each member being
separately taxed on its ratable share of our taxable income.
|
|
(b) |
|
The period of August 23, 2005 through December 31, 2005. |
|
(c) |
|
Because Four Corners, Wamsutter and a 20% interest in Discovery were
owned by affiliates of Williams at the time of their acquisition by
us, the acquisitions are accounted for as a combination of entities
under common control, whereby the assets and liabilities acquired are
combined with ours at their historical amounts for all periods
presented. This accounting causes a reduction of the capital balance
for the general partner for the difference between the historical cost
of these assets and liabilities and the aggregate consideration paid
to the general partner. |
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.
Recent Developments
The Dropdown
On
February 17, 2010, we closed a transaction with our general
partner, our operating company, The Williams Companies, Inc. (Williams) and certain subsidiaries of Williams, pursuant to
which Williams contributed to us the ownership interests in the entities that make up Williams Gas
Pipeline and Midstream Gas & Liquids business segments, to the extent not already owned by us,
including Williams limited and general partner interests in Williams Pipeline Partners L.P. (WMZ),
but excluding Williams Canadian, Venezuelan and olefin operations and 25.5% of Gulfstream Natural
Gas System, L.L.C. (Gulfstream). Such entities are hereafter referred to as the Contributed
Entities. This contribution was made in exchange for aggregate consideration of:
|
|
|
$3.5 billion in cash, less certain expenses incurred by us relating to our acquisition
of the Contributed Entities. This cash consideration was financed through the private
issuance of $3.5 billion of senior unsecured notes with net
proceeds of $3.466 billion. |
|
|
|
|
203 million of our Class C limited partnership units, which are identical to our common
limited partnership units except that for the distribution with respect to the first
quarter of 2010 they will receive a prorated quarterly distribution since they were not
outstanding during the full quarterly period. The Class C units will automatically convert
into our common limited partnership units following the record date for the distribution
with respect to the first quarter of 2010. |
|
|
|
|
an increase in the capital account of our general partner to allow it to maintain its 2%
general partner interest. |
The transactions described in the preceding paragraph are referred to as the Dropdown.
Beginning
with reporting of first-quarter 2010 results,
our operations will be divided into two business segments: Gas Pipeline
and Midstream Gas & Liquids. All of the operations we conducted prior to the Dropdown will be
reported within the Midstream Gas & Liquids segment. The Contributed Entities business activities
will be included in our two business segments as follows:
|
|
|
Gas Pipeline will include Transcontinental Gas Pipe Line Company, LLC (Transco) and
Northwest Pipeline GP (Northwest Pipeline), which own and operate a combined total of
approximately 13,900 miles of pipelines with a total annual throughput of approximately
2,700 TBtu of natural gas and peak-day delivery capacity of approximately 12 MMdt of
natural gas. Gas Pipeline will also hold interests in joint venture interstate and
intrastate natural gas pipeline systems including a 24.5% interest in Gulfstream, which
owns an approximate 745-mile pipeline with the capacity to transport approximately 1.26
million Dth per day of natural gas. |
|
|
|
|
Midstream Gas & Liquids will include the Contributed Entities natural gas gathering,
processing and treating facilities located primarily in the Rocky Mountain and Gulf Coast
regions of the United States and natural gas and crude oil gathering and transportation
facilities in the Gulf Coast region of the United States. |
54
WMZ Exchange Offer
We have also announced our
intention to launch an exchange offer for the publicly traded common
units of WMZ at a future date (the WMZ Exchange Offer). We will offer a fixed exchange ratio of 0.7584 of our common units
for each WMZ common unit. The ratio is based on closing prices on the New York Stock Exchange on
Friday, January 15, 2010, the business date before our intention to make the exchange offer was
announced, of $23.35 for WMZ and $30.79 for us. The exact timing of the launch will be based upon
the filing of necessary offering documents with the Securities and Exchange Commission and upon
market conditions.
Please read Business and Properties Recent Events
WMZ Exchange Offer for more information.
New Credit Facility
In connection with the Dropdown,
we entered into a new $1.75 billion senior unsecured revolving
three-year credit facility with Transco and Northwest Pipeline, as
co-borrowers with borrowing sublimits of $400 million each, and
Citibank, N.A. as administrative agent, and other lenders named therein (New Credit Facility). The New Credit Facility
replaced our previous $450 million senior unsecured credit
agreement. At the closing of the Dropdown, we borrowed $250 million under the New Credit Facility to
repay the term loan outstanding under our existing credit facility.
Overview
The following discussion of our results of operations reflects our business as it existed
prior to the Dropdown and as reflected in the consolidated financial statements and related notes
included in Item 8 of this annual report.
During 2009, and in earlier periods, we were principally engaged in the business of gathering,
transporting, processing and treating natural gas and fractionating and storing natural gas liquids
(NGLs). We managed our business and analyzed our results of operations on a segment basis. Our
operations were divided into three business segments: Gathering and Processing West (West),
Gathering and Processing Gulf (Gulf) and NGL Services. (Please read Note 17, Segment
Disclosures, in our Notes to Consolidated Financial Statements for further discussion of these
segments.) The Dropdown transaction represents a dramatic expansion in the scale, scope and
diversification of our operations and our prospects for growth.
Our operating results throughout the second half of 2009 demonstrated significant continued
improvement from difficult circumstances experienced during the last quarter of 2008 and the first
half of 2009 when low NGL commodity prices and hurricane-related damages significantly decreased
the profitability of our gathering and processing businesses. These circumstances resulted in
significantly lower results of operations and cash flow from operations in 2009 compared to 2008.
During 2009, Williams provided us with significant, additional support, which assisted us in
maintaining a higher level of cash retention and a stronger overall liquidity position. Williams
waived its incentive distribution rights (IDRs) related to the 2009 distribution periods. These
IDRs represented approximately $29.0 million, on an annual basis. In addition, our omnibus
agreement with Williams was amended to increase the aggregate amount of the credit we could receive
related to certain general and administrative expenses for 2009. Williams additional support
during 2009 combined with the improved commodity environment in the second half of 2009 allowed us
to maintain our prior per-unit level of cash distributions throughout 2009.
Critical Accounting Policies and Estimates
Our financial statements reflect the selection and application of accounting policies that
require management to make significant estimates and assumptions. The selection of these policies
has been discussed with the audit committee of the board of directors of our general partner. We
believe that the following are the more critical judgment areas in the application of our
accounting policies that currently affect our financial condition and results of operations.
Accounting for Asset Retirement Obligations
We record asset retirement obligations for legal and contractual obligations associated with
the retirement of long-lived assets that result from the acquisition, construction, development
and/or normal use of the asset in the period in which it is incurred if a reasonable estimate of
fair value can be made. At December 31, 2009, we have accrued asset retirement obligations of
$14.8 million including estimated retirement costs associated with the abandonment of Four Corners
gas processing and compression facilities located on leased land, Four Corners wellhead
connections on federal land, Conways underground storage caverns and brine ponds in accordance
with Kansas Department of Health and Environment (KDHE) regulations and the Carbonate Trend
pipeline. Our estimate utilizes judgments and assumptions regarding the extent of our obligations,
the costs to abandon and the timing of abandonment. In 2009, we revised our estimated asset
retirement obligations by $0.4 million. Our recorded asset retirement obligation
55
is based on the assumption that the abandonment of our Four Corners and Conway assets
generally occurs in approximately 50 years. If this assumption had been changed to 30 years, and
the expected retirement date for the Carbonate Trend pipeline had been significantly shortened, the
recorded asset retirement obligation would have increased by an additional $12.0 million to
$14.0 million. (Please read Note 9, Property, Plant and Equipment, in our Notes to Consolidated
Financial Statements.)
Environmental Remediation Liabilities
We record liabilities for estimated environmental remediation obligations when we assess that
a loss is probable and the amount of the loss can be reasonably estimated. At December 31, 2009, we
have an accrual for estimated environmental remediation obligations of $6.6 million. This
remediation accrual is revised, and our associated income is affected, during periods in which new
or different facts or information become known or circumstances change that affect the previous
assumptions with respect to the likelihood or amount of loss. We base liabilities for environmental
remediation upon our assumptions and estimates regarding what remediation work and post-remediation
monitoring will be required and the costs of those efforts, which we develop from information
obtained from outside consultants and from discussions with the applicable governmental
authorities. As new developments occur or more information becomes available, it is possible that
our assumptions and estimates in these matters will change. Changes in our assumptions and
estimates or outcomes different from our current assumptions and estimates could materially affect
future results of operations for any particular quarter or annual period. (Please read
Environmental and Note 16, Commitments and Contingencies, in our Notes to Consolidated
Financial Statements.)
Results of Operations
Consolidated Overview
The following table and discussion summarize our consolidated results of operations for the
three years ended December 31, 2009 and do not reflect the consummation of the Dropdown. The
results of operations by segment are discussed in further detail following this consolidated
overview discussion and relate to the segment tables in Note 17, Segment Disclosures, in our Notes
to Consolidated Financial Statements.
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|
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|
%Change |
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|
%Change |
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|
|
|
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|
|
from |
|
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|
|
|
|
from |
|
|
|
|
|
|
2009 |
|
|
2008(1) |
|
|
2008 |
|
|
2007(1) |
|
|
2007 |
|
|
|
|
|
|
|
(Dollars in thousands) |
|
|
|
|
|
Revenues |
|
$ |
470,189 |
|
|
|
(26 |
)% |
|
$ |
637,060 |
|
|
|
+11 |
% |
|
$ |
572,817 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
103,225 |
|
|
|
+50 |
% |
|
|
206,078 |
|
|
|
(13 |
)% |
|
|
181,698 |
|
Operating and maintenance expense |
|
|
163,064 |
|
|
|
+12 |
% |
|
|
185,901 |
|
|
|
(15 |
)% |
|
|
162,343 |
|
Depreciation, amortization and accretion |
|
|
44,887 |
|
|
|
|
|
|
|
45,029 |
|
|
|
+3 |
% |
|
|
46,492 |
|
General and administrative expense |
|
|
51,245 |
|
|
|
(9 |
)% |
|
|
47,059 |
|
|
|
(3 |
)% |
|
|
45,628 |
|
Taxes other than income |
|
|
10,149 |
|
|
|
(7 |
)% |
|
|
9,508 |
|
|
|
+1 |
% |
|
|
9,624 |
|
Other (income) expense net |
|
|
(4,133 |
) |
|
|
+17 |
% |
|
|
(3,523 |
) |
|
NM |
|
|
12,095 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
368,437 |
|
|
|
+25 |
% |
|
|
490,052 |
|
|
|
(7 |
)% |
|
|
457,880 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
101,752 |
|
|
|
(31 |
)% |
|
|
147,008 |
|
|
|
+28 |
% |
|
|
114,937 |
|
Equity earnings Wamsutter |
|
|
84,052 |
|
|
|
(5 |
)% |
|
|
88,538 |
|
|
|
+16 |
% |
|
|
76,212 |
|
Discovery investment income |
|
|
27,243 |
|
|
|
+22 |
% |
|
|
22,357 |
|
|
|
(22 |
)% |
|
|
28,842 |
|
Interest expense |
|
|
(60,679 |
) |
|
|
+10 |
% |
|
|
(67,220 |
) |
|
|
(15 |
)% |
|
|
(58,348 |
) |
Interest income |
|
|
99 |
|
|
|
(86 |
)% |
|
|
706 |
|
|
|
(76 |
)% |
|
|
2,988 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
152,467 |
|
|
|
(20 |
)% |
|
$ |
191,389 |
|
|
|
+16 |
% |
|
$ |
164,631 |
|
|
|
|
|
|
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|
(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. |
2009 vs. 2008
Revenues decreased $166.9 million, or 26%, due primarily to lower product sales in our West
segment resulting from significantly lower average NGL sales prices, lower sales of NGLs on behalf
of third-party producers and lower condensate and LNG sales.
56
Product cost and shrink replacement decreased $102.9 million, or 50%, due primarily to lower
product cost and shrink replacement in our West segment related primarily to decreased purchases of
NGLs from third-party producers and lower average natural gas prices.
Operating and maintenance expense decreased $22.8 million, or 12%, due primarily to lower
system and imbalance losses in our West segment and lower fractionation fuel costs resulting from
sharply lower natural gas prices in our NGL Services segment.
General and administrative expense increased $4.2 million, or 9%, due primarily to higher
charges allocated by Williams to us for various administrative expenses and certain expenses
related to the Dropdown.
Operating income decreased $45.3 million, or 31%, due primarily to substantially lower average
per-unit NGL sales margins, lower sales margins for condensate and LNG and lower involuntary
conversion gains in our West segment. These decreases were partially offset by lower operating and
maintenance expenses in our West segment and the absence of a 2008 impairment of our Carbonate
Trend pipeline.
Equity earnings from Wamsutter decreased $4.5 million, or 5%, due primarily to lower per-unit
NGL sales margins, partially offset by a higher percentage allocation of Wamsutters net income in
2009. As described in Note 7, Equity Investments, of our Notes to Consolidated Financial
Statements, Wamsutters net income was allocated based upon the allocation, distribution, and
liquidation provisions of its limited liability company (LLC) agreement. For the year ended
December 31, 2008, this allocation resulted in a $15.2 million allocation of Wamsutters net income
to the Class C interest not owned by us.
Discovery investment income increased $4.9 million, or 22%, due primarily to higher gathering
and transportation revenue, lower operating and maintenance expense and higher hurricane-related
proceeds received under our Discovery business interruption policy. These increases were largely
offset by lower NGL sales margins resulting from sharply lower average per-unit margins on higher
volumes of NGL equity sales and an unfavorable change in other (income) expense, net.
Interest expense decreased $6.5 million, or 10%, due primarily to the lower interest rate on
our $250.0 million floating-rate term loan.
2008 vs. 2007
Revenues increased $64.2 million, or 11%, due primarily to higher product sales in our West
segment and higher fractionation, product sales and storage revenues in our NGL Services segment.
Product cost and shrink replacement increased $24.4 million, or 13%, due primarily to higher
cost of product sales in both our West and NGL Services segments and higher average natural gas
prices for shrink replacement in our West segment.
Operating and maintenance expense increased $23.6 million, or 15%, due primarily to higher
repairs and maintenance, materials and supplies and system losses in our West segment.
Other (income) expense net in 2008 reflects an $11.6 million involuntary conversion gain
related to the November 2007 Ignacio plant fire. Other (income) expense net for 2008 and 2007
includes a $6.2 million and $10.4 million impairment, respectively, of our Carbonate Trend pipeline
in our Gulf segment.
Operating income increased $32.1 million, or 28%, due primarily to higher per-unit NGL margins
on slightly lower sales volumes, an $11.6 million involuntary conversion gain in 2008, higher other
fee revenue and higher condensate sales margins in our West segment, combined with higher
fractionation and storage revenues in our NGL Services segment and a $4.2 million lower impairment
loss on the Carbonate Trend pipeline in our Gulf segment. Partially offsetting these favorable
variances were lower fee-based gathering revenues and higher operating and maintenance expenses in
our West segment.
Equity earnings Wamsutter increased $12.3 million, or 16%, due primarily to higher average
per-unit NGL margins on increased NGL sales volumes.
Discovery investment income decreased $6.5 million, or 22%, due primarily to lower equity
earnings caused by Hurricanes Ike and Gustav, partially offset by hurricane-related receipts under
our Discovery-related business interruption policy.
57
Interest expense increased $8.9 million, or 15%, due primarily to interest on our
$250.0 million term loan issued in December 2007 to finance a portion of our acquisition of
ownership interests in Wamsutter.
Interest income decreased $2.3 million, or 76%, due primarily to significantly lower daily
interest rates on higher fourth-quarter 2008 cash balances compared to fourth quarter 2007.
Results of operations Gathering and Processing West
The Gathering and Processing West segment includes our Four Corners natural gas gathering,
processing and treating assets and our ownership interest in Wamsutter.
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|
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2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Segment revenues |
|
$ |
406,598 |
|
|
$ |
560,138 |
|
|
$ |
513,787 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
93,387 |
|
|
|
189,192 |
|
|
|
170,434 |
|
Operating and maintenance expense |
|
|
136,509 |
|
|
|
156,713 |
|
|
|
135,782 |
|
Depreciation, amortization and accretion |
|
|
41,326 |
|
|
|
41,215 |
|
|
|
41,523 |
|
General and administrative expense direct |
|
|
9,008 |
|
|
|
8,333 |
|
|
|
7,790 |
|
Taxes other than income |
|
|
9,268 |
|
|
|
8,770 |
|
|
|
8,869 |
|
Other (income) expense net |
|
|
(4,453 |
) |
|
|
(9,709 |
) |
|
|
1,698 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
285,045 |
|
|
|
394,514 |
|
|
|
366,096 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
121,553 |
|
|
|
165,624 |
|
|
|
147,691 |
|
Equity earnings Wamsutter |
|
|
84,052 |
|
|
|
88,538 |
|
|
|
76,212 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
205,605 |
|
|
$ |
254,162 |
|
|
$ |
223,903 |
|
|
|
|
|
|
|
|
|
|
|
Four Corners
2009 vs. 2008
Four Corners segment operating income decreased $44.1 million, or 27%, due primarily to $49.1
million lower NGL sales margins resulting primarily from a 41% decrease in average per-unit NGL
margins, $5.4 million lower condensate and LNG sales margins and $7.6 million lower involuntary
conversion gains related to the 2007 Ignacio plant fire. These decreases were partially offset by
$20.2 million lower operating and maintenance expense. A more detailed analysis of the components
of the change in segment operating income is below.
Revenues decreased $153.5 million, or 27%, due primarily to the following lower product sales:
|
|
|
$91.6 million related to a 47% decrease in average NGL sales prices realized on sales of
NGLs which we received under keep-whole and percent-of-liquids processing contracts (NGL
equity sales). This decrease resulted from general decreases in market prices for these
commodities between the two periods. |
|
|
|
|
$47.5 million lower sales of NGLs on behalf of third-party producers. Under these
arrangements, we purchase the NGLs from the third-party producers and sell them to an
affiliate. This decrease was related to general decreases in market prices and lower volumes
and is offset by lower associated product costs of $47.2 million discussed below. |
|
|
|
|
$13.5 million lower condensate and LNG sales resulting from decreased average per-unit
prices and lower LNG volumes. |
Product cost and shrink replacement decreased $95.8 million, or 51%, due primarily to:
|
|
|
$47.2 million decrease from third-party producers who have us purchase their NGLs, which
was offset by the corresponding decrease in product sales discussed above. |
|
|
|
|
$37.7 million decrease from 54% lower average natural gas prices. |
|
|
|
|
$8.1 million decrease in condensate and LNG-related product cost. |
Operating and maintenance expense decreased $20.2 million, or 13%, due primarily to $20.6
million lower system and imbalance volume losses and $7.7 million lower unreimbursed gathering fuel
costs. Both imbalance losses and unreimbursed
58
gathering fuel costs were favorably impacted by lower natural gas costs. While our system
losses are generally an unpredictable component of our operating costs, they can be higher during
periods of prolonged, severe winter weather, such as those we experienced during January and
February of 2008. Additionally, operational inefficiencies caused by the fire at the Ignacio plant
impacted our system losses in 2008. These decreases in expense were partially offset by higher
right-of-way costs, increased labor costs and 2009 Ignacio pipeline rupture repair costs.
Other income decreased $5.3 million, or 54%, due primarily to $7.6 million lower involuntary
conversion gains in 2009 related to the November 2007 Ignacio plant fire.
2008 vs. 2007
Segment operating income increased $17.9 million, or 12%, due primarily to:
|
|
|
$20.0 million higher NGL margins resulting primarily from higher per-unit NGL margins.
Record NGL margins experienced during the first three quarters were impacted unfavorably in
the fourth-quarter 2008 when NGL sales prices declined significantly. |
|
|
|
|
$11.6 million of 2008 involuntary conversion gains. |
|
|
|
|
$9.0 million higher other revenues. |
Partially offsetting these increases were $20.9 million higher operating and maintenance
expenses and $7.1 million lower fee-based gathering revenues.
Revenues increased $46.4 million, or 9%, due primarily to $43.0 million higher product sales
revenues and $9.0 million improved other revenue, slightly offset by $7.1 million lower gathering
revenues. The significant components of the revenue fluctuations are addressed more fully below.
Product sales revenues increased $43.0 million due primarily to:
|
|
|
$35.3 million from 22% higher average per-unit NGL sales prices realized on NGL volumes
we received under keep-whole and percent-of-liquids processing contracts. NGL sales prices
were sharply higher in the first three quarters of 2008 compared to 2007; however, NGL sales
prices declined significantly in the fourth quarter of 2008. |
|
|
|
|
$6.6 million higher sales of NGLs on behalf of third-party producers. Under these
arrangements, we purchase NGLs from the third-party producers and sell them to an affiliate.
This increase is offset by higher associated product costs of $6.9 million discussed below. |
|
|
|
|
$4.6 million higher condensate sales resulting primarily from higher prices. |
These increases in product sales revenues were slightly offset by a $4.4 million impact of 3%
lower NGL sales volumes.
Other revenue improved $9.0 million due primarily to a $4.4 million fourth-quarter 2008
insurance reimbursement for lost profits under our business interruption insurance related to the
November 2007 Ignacio plant fire and the absence of a $3.5 million third-quarter 2007 unfavorable
revenue recognition correction for electronic flow measurement fees.
Fee-based gathering revenues decreased $7.1 million, or 4%, due primarily to a $7.6 million
decline in revenue from lower gathering volumes. This resulted from the prolonged, severe weather
during early 2008 which inhibited both our and our customers abilities to access facilities,
connect new wells and maintain production. The 2007 volumes were reduced by the fire at the Ignacio
gas processing plant in late November 2007.
Product cost and shrink replacement increased $18.8 million, or 11%, due primarily to
$10.7 million from higher average natural gas prices for shrink replacement and $6.9 million higher
NGL purchases from third-party producers who elected to have us purchase their NGLs (offset by the
corresponding increase in product sales discussed above).
59
Operating and maintenance expense increased $20.9 million, or 15%, due primarily to
$12.0 million higher system and imbalance losses and $9.1 million higher repairs and maintenance
and materials and supplies expense. During 2008 our volumetric system loss, as a percentage of
total volume received, was significantly higher than in 2007. While our system losses are generally
an unpredictable component of our operating costs, they can be higher during periods of prolonged,
severe weather, such as those we experienced during early 2008. Additionally, operating
inefficiencies caused by the fire at Ignacio plant unfavorably impacted our system losses.
Other (income) expense net improved $11.4 million due primarily to an $11.6 million
involuntary conversion gain recognized in 2008 related to the November 2007 Ignacio plant fire.
Wamsutter
Wamsutter was accounted for using the equity method of accounting. As such, our interest in
Wamsutters net operating results is reflected as equity earnings in our Consolidated Statements of
Income. The following discussion addresses in greater detail the results of operations for 100% of
Wamsutter. Please read Note 7, Equity Investments, of our Notes to Consolidated Financial
Statements for discussion of how Wamsutter allocated its net income between its member owners
including us.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Revenues |
|
$ |
195,887 |
|
|
$ |
239,534 |
|
|
$ |
175,309 |
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
52,300 |
|
|
|
78,809 |
|
|
|
46,039 |
|
Operating and maintenance expense |
|
|
20,527 |
|
|
|
20,973 |
|
|
|
18,257 |
|
Depreciation and accretion |
|
|
22,235 |
|
|
|
21,182 |
|
|
|
18,424 |
|
General and administrative expense |
|
|
15,207 |
|
|
|
13,507 |
|
|
|
12,623 |
|
Taxes other than income |
|
|
2,014 |
|
|
|
1,868 |
|
|
|
1,637 |
|
Other (income) expense, net |
|
|
(448 |
) |
|
|
(569 |
) |
|
|
944 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
111,835 |
|
|
|
135,770 |
|
|
|
97,924 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
84,052 |
|
|
$ |
103,764 |
|
|
$ |
77,385 |
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest |
|
$ |
84,052 |
|
|
$ |
88,538 |
|
|
$ |
76,212 |
|
|
|
|
|
|
|
|
|
|
|
2009 vs. 2008
Wamsutters net income decreased $19.7 million, or 19%, due primarily to $23.9 million lower
NGL sales margins resulting primarily from sharply decreased per-unit NGL margins.
As described in Note 7, Equity Investments, of our Notes to Consolidated Financial Statements,
Wamsutters net income was allocated based upon the allocation, distribution, and liquidation
provisions of its limited liability company agreement. Net income for 2009 was allocated as
presented in the table below:
|
|
|
|
|
|
|
Wamsutter |
|
Wamsutter Net Income Allocation 2009 |
|
Net Income |
|
|
|
(Millions) |
|
Net income for December 1, 2008 November 30, 2009 |
|
$ |
77.3 |
|
Less net income allocated for transition support contribution |
|
|
(9.7 |
) |
Less net income for December 2008 |
|
|
(1.0 |
) |
|
|
|
|
Net income for 2009 allocation |
|
$ |
66.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our Share |
|
|
Other |
|
|
Wamsutter |
|
|
|
Class A |
|
|
Class C |
|
|
WPZ Total |
|
|
Class C |
|
|
Net Income |
|
|
|
|
|
|
|
|
|
|
|
(Millions) |
|
|
|
|
|
|
|
|
|
Allocation up to $70 million (excluding December 2008 allocation) |
|
$ |
66.6 |
|
|
$ |
|
|
|
$ |
66.6 |
|
|
$ |
|
|
|
$ |
66.6 |
|
Income allocation for transition support contribution |
|
|
9.7 |
|
|
|
|
|
|
|
9.7 |
|
|
|
|
|
|
|
9.7 |
|
December 2009 income allocation |
|
|
7.8 |
|
|
|
|
|
|
|
7.8 |
|
|
|
|
|
|
|
7.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
$ |
84.1 |
|
|
$ |
|
|
|
$ |
84.1 |
|
|
$ |
|
|
|
$ |
84.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues decreased $43.7 million, or 18%, due primarily to $59.6 million lower product sales,
partially offset by $10.9 million higher fee-based gathering and processing revenue.
Product sales revenues decreased $59.6 million, or 38%, due primarily to:
60
|
|
|
$67.6 million related to a 41% decrease in average NGL sales prices realized on sales of
NGLs which Wamsutter received under keep-whole processing contracts. This decrease resulted
from general decreases in market prices for these commodities between the two periods. |
|
|
|
|
$3.1 million of favorable adjustments in the first quarter of 2008 related to the
margin-sharing provisions of one of Wamsutters significant contracts. |
These product sales decreases were partially offset by $9.1 million higher sales of NGLs on
behalf of third-party producers. This increase is offset by higher associated product costs
discussed below.
Gathering and processing fee-based revenues increased $10.9 million, or 16%, due to a 7%
increase in average volumes and an 8% increase in the average fee received for these services. The
increase in average volumes was due primarily to new wells connected in 2009 and production
problems in 2008 caused by severe winter weather conditions. The average fee increased as a result
of negotiated increases in gathering fees and fixed annual percentage or inflation-sensitive
contractual escalation clauses.
Product cost and shrink replacement decreased $26.5 million, or 34%, due primarily to a $39
million decrease from 49% lower average natural gas prices, partially offset by $9.1 million higher
product cost related to sales of NGLs on behalf of third-party producers as discussed above.
General and administrative expense increased $1.7 million due primarily to higher charges
allocated by Williams to us for various administrative support functions.
Depreciation and accretion expense increased $1.1 million due primarily to new assets placed
into service.
2008 vs. 2007
Net income increased $26.4 million, or 34%, due primarily to $27.9 million higher NGL margin
resulting from increased per-unit margins on higher NGL sales volumes.
As described in Note 7, Equity Investments, of our Notes to Consolidated Financial Statements,
Wamsutters net income is allocated based upon the allocation, distribution, and liquidation
provisions of its limited liability company agreement. Net income for 2008 was allocated as
presented in the table below:
|
|
|
|
|
|
|
Wamsutter |
|
Wamsutter Net Income Allocation 2008 |
|
Net Income |
|
|
|
(Millions) |
|
Net income for December 1, 2007 November 30, 2008 |
|
$ |
110.1 |
|
Less net income allocated for transition support contribution |
|
|
(7.6 |
) |
Less net income for December 2007 |
|
|
(7.4 |
) |
|
|
|
|
Net income for 2008 allocation |
|
$ |
95.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our Share |
|
|
Other |
|
|
Wamsutter |
|
|
|
Class A |
|
|
Class C |
|
|
WPZ Total |
|
|
Class C |
|
|
Net Income |
|
|
|
|
|
|
|
|
|
|
|
(Millions) |
|
|
|
|
|
|
|
|
|
Allocation up to $70 million (excluding December 2007 allocation) |
|
$ |
62.6 |
|
|
$ |
|
|
|
$ |
62.6 |
|
|
$ |
|
|
|
$ |
62.6 |
|
Allocation of net income over $70 million |
|
|
2.1 |
|
|
|
15.2 |
|
|
|
17.3 |
|
|
|
15.2 |
|
|
|
32.5 |
|
Income allocation for transition support contribution |
|
|
7.6 |
|
|
|
|
|
|
|
7.6 |
|
|
|
|
|
|
|
7.6 |
|
December 2008 income allocation |
|
|
1.0 |
|
|
|
|
|
|
|
1.0 |
|
|
|
|
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
$ |
73.3 |
|
|
$ |
15.2 |
|
|
$ |
88.5 |
|
|
$ |
15.2 |
|
|
$ |
103.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues increased $64.2 million, or 37%, due primarily to $61.6 million higher sales of NGLs
which Wamsutter received under keep-whole processing contracts. This increase reflects $39.5
million related to higher average sales prices and $22.1 million related to 23% higher sales
volumes. This volumetric increase was due primarily to a lower volume of gas delivered by
Wamsutters fee-based customers in the first quarter of 2008 due to inclement weather which allowed
Wamsutter to process additional keep-whole gas at the Echo Springs plant. Additionally, Wamsutter
benefited from the ability to process additional keep-whole gas at Colorado Interstate Gas
Companys Rawlins natural gas processing plant.
61
Product cost and shrink replacement increased $32.8 million, or 71%, due primarily to a $24.2
million increase from higher average natural gas prices and $9.5 million from higher volumetric
shrink requirements due to higher volumes processed under Wamsutters keep-whole processing
contracts. Gas prices in 2007 were impacted by very low local natural gas costs compared with other
natural gas markets.
Operating and maintenance expense increased $2.7 million, or 15%, due primarily to higher
gathering fuel, third-party processing, and material and supply costs, substantially offset by $5.0
million higher system gains.
Depreciation and accretion increased $2.8 million, or 15%, due primarily to new assets placed
into service.
Results of operations Gathering and Processing Gulf
The Gulf segment includes the Carbonate Trend gathering pipeline and our 60% ownership
interest in Discovery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Segment revenues |
|
$ |
1,708 |
|
|
$ |
2,096 |
|
|
$ |
2,119 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense |
|
|
1,459 |
|
|
|
1,668 |
|
|
|
1,875 |
|
Depreciation, amortization and accretion |
|
|
170 |
|
|
|
751 |
|
|
|
1,249 |
|
Other expense, net |
|
|
325 |
|
|
|
6,187 |
|
|
|
10,406 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
1,954 |
|
|
|
8,606 |
|
|
|
13,530 |
|
|
|
|
|
|
|
|
|
|
|
Segment operating loss |
|
|
(246 |
) |
|
|
(6,510 |
) |
|
|
(11,411 |
) |
Discovery investment income |
|
|
27,243 |
|
|
|
22,357 |
|
|
|
28,842 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
26,997 |
|
|
$ |
15,847 |
|
|
$ |
17,431 |
|
|
|
|
|
|
|
|
|
|
|
Carbonate Trend
2009 vs. 2008
Segment operating loss improved significantly as a result of the lack of asset impairment
expense in 2009. The Carbonate Trend pipeline was fully impaired in 2008.
2008 vs. 2007
Segment operating loss improved $4.9 million because the impairment loss recognized on the
Carbonate Trend pipeline was $4.2 million lower in 2008 than in 2007. (Please read Note 8, Other
(Income) Expense, of our Notes to Consolidated Financial Statements.)
62
Discovery
Discovery is accounted for using the equity method of accounting. As such, our interest in
Discoverys net operating results is reflected as equity earnings in our Consolidated Statements of
Income. The following discussion addresses in greater detail the results of operations for 100% of
Discovery.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Revenues |
|
$ |
161,019 |
|
|
$ |
241,248 |
|
|
$ |
260,672 |
|
Costs and expenses, including interest: |
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement |
|
|
72,506 |
|
|
|
146,998 |
|
|
|
155,704 |
|
Operating and maintenance expense |
|
|
23,445 |
|
|
|
36,670 |
|
|
|
28,988 |
|
Depreciation and accretion |
|
|
18,751 |
|
|
|
21,324 |
|
|
|
25,952 |
|
General and administrative expense |
|
|
6,000 |
|
|
|
4,500 |
|
|
|
2,280 |
|
Interest income |
|
|
(31 |
) |
|
|
(650 |
) |
|
|
(1,799 |
) |
Other (income) expense, net |
|
|
3,441 |
|
|
|
(1,994 |
) |
|
|
1,476 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
124,112 |
|
|
|
206,848 |
|
|
|
212,601 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
36,907 |
|
|
$ |
34,400 |
|
|
$ |
48,071 |
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest equity earnings |
|
$ |
23,023 |
|
|
$ |
20,641 |
|
|
$ |
28,842 |
|
Business interruption proceeds |
|
|
4,220 |
|
|
|
1,716 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery investment income |
|
$ |
27,243 |
|
|
$ |
22,357 |
|
|
$ |
28,842 |
|
|
|
|
|
|
|
|
|
|
|
2009 vs. 2008
Net income increased $2.5 million, or 7%, due primarily to $12.4 million higher gathering and
transportation revenue, $13.2 million lower operating and maintenance expense and $2.6 million
lower depreciation and accretion expense. These increases were largely offset by $18.5 million
lower NGL sales margins resulting from sharply lower average per-unit margins on higher volumes of
NGL equity sales and a $5.4 million unfavorable change in other (income) expense, net. A more
detailed analysis of the components of the change in net income is below.
Revenues decreased $80.2 million, or 33%, due primarily to
$94.2 million lower product sales,
partially offset by $12.4 million higher gathering and transportation revenue resulting primarily
from higher rates and higher volumes. The 2009 volumes were higher due primarily to the recovery
from the impact of the 2008 hurricanes and the receipt of volumes from the Tahiti spar beginning in
the second quarter of 2009.
The lower product sales are due primarily to:
|
|
|
$65.7 million related to 46% lower average per-unit prices on NGL equity sales as a
result of general decreases in market commodity prices. |
|
|
|
|
$40.3 million lower product sales resulting from lower NGL sales volumes sold on behalf
of third-party producers. |
These decreases in product sales are partially offset by $13.0 million higher product sales
from a 10% increase in NGL equity sales volumes.
Product cost and shrink replacement decreased $74.5 million, or 51%, due primarily to a
decrease in the related NGL sales on behalf of third-party producers discussed above, combined with
lower prices for natural gas purchased for shrink replacement.
Operating and maintenance expense decreased $13.2 million, or 36%, due primarily to the
absence of 2008 hurricane costs that were unrecoverable from insurance, combined with lower 2009
fuel costs resulting from lower prices for natural gas and favorable system gains.
Depreciation and accretion decreased $2.6 million, or 12%, due primarily to a 2008 change in
the estimated remaining useful lives of the Larose processing plant and the regulated pipeline and
gathering system, partially offset by the impact of the Tahiti assets placed into service in 2009.
63
Other (income) expense, net changed unfavorably by $5.4 million due to the absence of a 2008
favorable adjustment of $3.5 million for a FERC settlement, combined with higher property taxes in
2009 following the end of a tax abatement period.
2008 vs. 2007
Net income decreased $13.7 million, or 28%, due primarily to $8.0 million lower fee-based
gathering, processing, fractionation and transportation revenue resulting from third and fourth
quarter lost revenues in the aftermath of Hurricanes Ike and Gustav, $7.7 million higher operating
and maintenance expense and $5.4 million lower NGL sales margins, slightly offset by $4.6 million
lower depreciation and accretion expense.
Revenues decreased $19.4 million, or 7%, due primarily to $13.1 million lower product sales
described below and $8.0 million lower fee-based gathering, processing, fractionation and
transportation revenue resulting from lost revenues in the aftermath of Hurricanes Ike and Gustav.
The lower product sales revenues are due primarily to:
|
|
|
$21.5 million lower sales of NGLs on behalf of third-party producers as a result of the
hurricanes which is offset by lower associated product costs of $21.5 million discussed
below. |
|
|
|
|
$16.8 million decrease from lower NGL volumes processed under keep-whole and
percent-of-liquids arrangements, including lower NGL volumes following Hurricanes Ike and
Gustav. |
These decreases were partially offset by $26.3 million higher product sales from higher
average NGL sales prices realized on sales of NGLs which Discovery received under certain
processing contracts.
Product cost and shrink replacement decreased $8.7 million, or 6%, due primarily to a $21.5
million decrease in product purchased from third-party producers as a result of the impact of the
hurricanes, partially offset by $15.9 million from higher average natural gas prices.
Operating and maintenance expense increased $7.7 million, or 27%, due primarily to 2008
hurricane survey and repair costs on the gathering system damaged by Hurricane Ike that are not
recoverable from insurance.
Depreciation and accretion decreased $4.6 million, or 18%, due primarily to a change in the
estimated remaining useful lives of the Larose processing plant and the regulated pipeline and
gathering system.
General and administrative expense increased $2.2 million, or 97%, due to an increase in
Discoverys management fee charged by Williams.
Other (income) expense, net improved $3.5 million due to a recently approved FERC settlement
filing that allowed the 2008 reversal of a $3.5 million reserve for system fuel and lost and
unaccounted for gas related to 1998 through 2003.
Results of operations NGL Services
The NGL Services segment includes our three NGL storage facilities near Conway, Kansas and our
50% undivided interest in the Conway fractionator.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Segment revenues |
|
$ |
61,883 |
|
|
$ |
74,826 |
|
|
$ |
56,911 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Product cost |
|
|
9,838 |
|
|
|
16,886 |
|
|
|
11,264 |
|
Operating and maintenance expense |
|
|
25,096 |
|
|
|
27,520 |
|
|
|
24,686 |
|
Depreciation and accretion |
|
|
3,391 |
|
|
|
3,063 |
|
|
|
3,720 |
|
General and administrative expense direct |
|
|
3,245 |
|
|
|
2,582 |
|
|
|
2,190 |
|
Other expense, net |
|
|
876 |
|
|
|
737 |
|
|
|
746 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
42,446 |
|
|
|
50,788 |
|
|
|
42,606 |
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
19,437 |
|
|
$ |
24,038 |
|
|
$ |
14,305 |
|
|
|
|
|
|
|
|
|
|
|
64
2009 vs. 2008
NGL Services segment profit declined $4.6 million due primarily to higher
environmental-related operating costs. A more detailed analysis of the components of segment profit
is below.
Segment revenues decreased $12.9 million, or 17%, due primarily to lower product sales,
fractionation and other fee revenues, partially offset by higher storage revenues. The significant
components of the revenue fluctuations are addressed more fully below.
|
|
|
Product sales decreased $6.3 million due to a 23% decrease in average price per barrel.
The decrease in product sales revenue was more than offset by the related decrease in
product cost discussed below. |
|
|
|
|
Fractionation revenues decreased $6.9 million due primarily to a 41% decrease in average
fractionation price per barrel. The decrease in the average fractionation price per barrel
results from the decline in natural gas prices. |
|
|
|
|
Other fee revenues decreased $1.6 million due primarily to a decrease in customer fees to
upgrade butane. |
|
|
|
|
Storage revenues increased $1.8 million, or 6%, due primarily to higher overstorage
revenue. |
Product cost decreased $7.0 million, or 42%, due to the lower product prices discussed above.
Operating and maintenance expense decreased $2.4 million, or 9%, due primarily to $6.4 million
lower fractionation fuel costs resulting from sharply lower natural gas prices, largely offset by
higher environmental-related operating costs.
2008 vs. 2007
NGL Services segment profit increased $9.7 million, or 68%, due primarily to higher
fractionation and storage revenues, partially offset by higher operating and maintenance expenses.
Segment revenues increased $17.9 million, or 31%, due primarily to higher fractionation,
product sales and storage revenues. The significant components of the revenue fluctuations are
addressed more fully below.
|
|
|
Fractionation revenues increased $7.8 million due primarily to a 59% higher average
fractionation rate and 6% higher volumes. The higher average rate is due primarily to the
December 2007 expiration of a fractionation contract with a cap on the per-unit fee, which
limited our ability to pass through increases in fractionation fuel expense to this
customer. |
|
|
|
|
Product sales increased $5.4 million due to higher sales volumes and an increase in
average product sales prices. This increase was slightly offset by the related increase in
product cost discussed below. |
|
|
|
|
Storage revenues increased $3.4 million due primarily to higher storage revenues from new
storage leases. |
Product cost increased $5.6 million, or 50%, due to the higher product sales volumes and
prices discussed above.
Operating and maintenance expense increased $2.8 million, or 11%, due primarily to $4.0
million unfavorable storage product losses, $2.5 million higher maintenance costs and $1.3 million
higher fractionation fuel costs. These increases were partially offset by a $2.9 million product
imbalance adjustment in 2008 and $2.0 million of fractionation blending gains.
Performance Outlook for 2010
In the first quarter of 2010, we expect to record
approximately $10 million of estimated general and administrative
expenses related to the Dropdown. Additionally, beginning in 2010 as a result of the Dropdown, our operations will be divided into two
business segments: Gas Pipeline and Midstream Gas & Liquids. All of the operations we conducted
prior to the Dropdown are reported within the Midstream Gas & Liquids segment. Set forth below is
information regarding our performance expectations for 2010 for each of these business segments.
65
Gas Pipeline
Gas Pipelines strategy to create value focuses on maximizing the utilization of our pipeline
capacity by providing high quality, low cost transportation of natural gas to large and growing
markets.
Gas Pipelines interstate transmission and storage activities are subject to regulation by the
FERC and as such, our rates and charges for the transportation of natural gas in interstate
commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting,
among other things, are subject to regulation. The rates are established through the FERCs
ratemaking process. Changes in commodity prices and volumes transported have little near-term
impact on revenues because the majority of cost of service is recovered through firm capacity
reservation charges in transportation rates.
Outlook for 2010
In addition to the various in-progress expansion projects discussed in Capital Expenditures
below, we have several other proposed projects to meet customer demands. Subject to regulatory
approvals, construction of some of the other projects could begin as early as 2010.
Midstream Gas & Liquids
Midstreams ongoing strategy is to safely and reliably operate large-scale midstream
infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on
consistently attracting new business by providing highly reliable service to our customers.
Outlook for 2010
The following factors could impact our business in 2010.
Commodity price changes
|
|
|
NGL, crude and natural gas prices are highly volatile and
difficult to predict. However, we expect per-unit NGL margins in 2010 to be higher than our average per-unit margins
in 2009 and our rolling five-year average per-unit NGL margins. NGL price changes have historically
tracked somewhat with changes in the
price of crude oil. Margins in our NGL business are highly dependent upon continued demand
within the global economy. Although forecasted domestic and global demand for polyethylene,
or plastics, has been impacted by the weakness in the global economy, NGL products are
currently the preferred feedstock for ethylene and propylene production, which are the
building blocks of polyethylene. Propylene and ethylene production processes have
increasingly shifted from the more expensive crude-based feedstocks to NGL-based
feedstocks. Bolstered by abundant long-term natural gas supplies, we expect to benefit from
these dynamics in the broader global petrochemical markets. As natural gas pipeline
transportation capacity increases in the Rocky Mountain area, we anticipate that
historically favorable natural gas price differentials will decline. |
|
|
|
|
As part of our efforts to manage commodity price risks on an enterprise basis, we
continue to evaluate our commodity hedging strategies. To reduce the exposure to changes in
market prices, we have entered into NGL swap agreements to fix the prices of a small
portion of our anticipated NGL sales for 2010. In addition, we have entered into financial
contracts to fix the price of a portion of our shrink gas requirements for 2010. |
Gathering, processing and NGL sales volumes
|
|
|
The growth of natural gas supplies supporting our gathering and processing volumes are
impacted by producer drilling activities. Our customers are generally large producers, and
we have not experienced and do not anticipate an overall significant decline in volumes due
to reduced drilling activity. |
|
|
|
|
In the West, we expect higher fee revenues, NGL volumes, depreciation expense and
operating expenses in 2010 compared to 2009 as our Willow Creek facility moves into a full
year of operation and our expansion at Echo Springs is completed late in 2010. |
66
|
|
|
We expect fee revenues, NGL volumes, depreciation expense, and operating expenses in
our offshore Gulf Coast region to increase from 2009 levels as our new Perdido Norte
expansion begins start-up operations in the first quarter of 2010. Increases from our
Perdido Norte expansion are expected to be partially offset by lower NGL volumes in other
Gulf Coast areas due to expected changes in gas processing contracts, as described below,
and natural declines. |
|
|
|
|
Certain of our gas processing contracts contain provisions that allow customers to
periodically elect processing services on either a fee basis, keep-whole, or
percent-of-liquids basis. If customers switch from keep-whole to fee-based processing, this
would reduce our NGL equity sales volumes. |
Managements Discussion and Analysis of Financial Condition and Liquidity
Overview
As previously discussed in Recent DevelopmentsThe Dropdown, on February 17, 2010 Williams
contributed to us its ownership interests in the entities that make up Williams Gas Pipeline and
Midstream Gas & Liquids business segments (including its limited and general partner interests in
WMZ, but excluding its Canadian, Venezuelan and olefins operations, and a 25.5% interest in
Gulfstream), to the extent not already owned by us. This contribution was in exchange for the
aggregate consideration previously described.
The
Dropdown significantly increased the scale, proportion of fee-based
revenues and
diversity of our businesses and impacted our financial condition and liquidity as illustrated by
the following points:
|
|
|
Increased our total assets from $1.3 billion to approximately $12 billion and our total
long-term debt from $1.0 billion to $6.5 billion. |
|
|
|
|
Increased the number of limited partner units outstanding from 53 million to 256
million. |
|
|
|
|
Increased our cash flows from operations from $199 million in 2009 to a forecasted range
of $1.2 billion to $1.8 billion for 2010. |
|
|
|
|
Increased our expansion capital expenditures from $11 million in 2009 to a forecasted
range of $660 million to $870 million for 2010. |
|
|
|
|
Increased our maintenance capital expenditures from $19 million in 2009 to a forecasted
range of $290 million to $330 million for 2010. |
|
|
|
|
Increased our credit ratings to investment grade. |
|
|
|
|
Terminated our previous $450 million senior unsecured revolving credit facility and
established a new $1.75 billion senior unsecured revolving credit facility. |
Outlook
For 2010, we expect operating results and cash flows to improve from 2009 levels due to the
impact of expected higher energy commodity prices and the start-up of
certain expansion capital projects. However, as previously mentioned,
energy commodity prices are volatile and difficult to predict. Although our cash flows are impacted by
fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash
flow streams that are substantially insulated from unfavorable commodity price movements, as
follows:
|
|
|
Firm demand and capacity reservation transportation revenues under long-term contracts
at Gas Pipeline; |
|
|
|
|
Fee-based revenues from certain gathering and processing services at Midstream; |
|
|
|
|
Hedged NGL sales and natural gas purchases for a portion of activities at Midstream. |
67
We believe we have, or have access to, the financial resources and liquidity necessary to meet
our requirements for working capital, capital and investment expenditures, and debt service
payments while maintaining a sufficient level of liquidity. In particular, we note the following
expectations for 2010:
|
|
|
We expect to increase our per-unit quarterly distribution from $0.6350 to $0.6575
beginning with the distribution with respect to first quarter of 2010. |
|
|
|
|
We expect to fund capital and investment expenditures, debt service payments,
distributions to unitholders and working capital requirements primarily through cash flow
from operations, cash and cash equivalents on hand, cash proceeds from common unit and/or
long-term debt issuances and utilization of our revolving credit facilities as needed. |
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we
expect to have sufficient liquidity to manage our businesses in 2010. Our internal and external
sources of liquidity include:
|
|
|
Cash and cash equivalents on hand; |
|
|
|
|
Cash generated from operations, including cash distributions from our equity-method
investees; |
|
|
|
|
Cash proceeds from offerings of our common units and/or long-term debt; |
|
|
|
|
Capital contributions from Williams pursuant to the omnibus agreement; and |
|
|
|
|
Use of credit facilities, as needed and available. |
We anticipate our more significant uses of cash to be:
|
|
|
Maintenance and expansion capital expenditures; |
|
|
|
|
Contributions to our equity-method investees to fund their expansion capital
expenditures; |
|
|
|
|
Interest on our long-term debt; and |
|
|
|
|
Quarterly distributions to our unitholders and/or general partner. |
Potential risks associated with our planned levels of liquidity and the planned capital and
investment expenditures discussed above include:
|
|
|
Lower than expected levels of cash flow from operations. |
|
|
|
|
Sustained reductions in energy commodity prices from expected
2010 levels. |
|
|
|
|
Exposure associated with our efforts to resolve regulatory and litigation issues (Please
read Note 16, Commitments and Contingencies, of our Notes to Consolidated Financial
Statements). |
|
|
|
|
Physical damages to facilities, especially damage to offshore
facilities by named windstorms for which our aggregate policy limit is
$37.5 million in the event of a material loss. |
Available Liquidity
|
|
|
|
|
|
|
February 18, 2010 |
|
|
|
(In millions) |
|
Cash and cash equivalents |
|
$ |
117 |
|
Available capacity under our $1.75 billion three-year
senior unsecured credit facility (expires February 15,
2013) |
|
|
1,500 |
|
|
|
|
|
|
|
$ |
1,617 |
|
|
|
|
|
Shelf Registration
On October 28, 2009, we filed a shelf registration statement as a well-known seasoned issuer
that allows us to issue an unlimited amount of registered debt and limited partnership unit
securities.
68
Distributions from Equity Method Investees
Our equity method investees organizational documents require distribution of their available
cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by
reserves appropriate for operating their respective businesses. Our more significant equity method
investees include: Aux Sable Liquid Products, Discovery, Gulfstream and Laurel Mountain.
Omnibus Agreement with Williams
In connection with the closing of the Dropdown, we entered into an omnibus agreement with
Williams. Pursuant to this omnibus agreement, Williams is obligated to indemnify us from and
against or reimburse us for (i) amounts incurred by us or our subsidiaries for repair or
abandonment costs for damages to certain facilities caused by Hurricane Ike, up to a maximum of $10
million, (ii) maintenance capital expenditure amounts incurred by us or our subsidiaries in respect
of certain U.S. Department of Transportation projects, up to a maximum aggregate amount of $50
million, and (iii) an amount based on the amortization over time of deferred revenue amounts that
relate to cash payments received prior to the closing of the Dropdown for services to be rendered
by us in the future at the Devils Tower floating production platform located in Mississippi Canyon
Block 773. In addition, we will be obligated to pay to Williams the net proceeds of certain sales
of natural gas recovered from the Hester storage field pursuant to the FERC order dated March 7,
2008, approving a settlement agreement in Docket No. RP06-569.
Credit Facilities
At December 31, 2009, we had a $450 million senior unsecured credit agreement (Credit
Agreement) with Citibank, N.A. as administrative agent, comprised of a $200 million revolving
credit facility available for borrowings and letters of credit and a $250 million term loan. In
connection with the Dropdown, we terminated the Credit Agreement and entered into a new $1.75
billion three-year senior unsecured revolving credit facility (New Credit Facility) with Transco
and Northwest Pipeline, as co-borrowers, and Citibank, N.A. as the administrative agent, and
certain other lenders named therein. The full amount of the New Credit Facility is available to us, to the extent not otherwise utilized by Transco and Northwest Pipeline,
and may be increased by up to an additional $250 million. Transco and Northwest Pipeline are each
able to borrow up to $400 million under the New Credit Facility to the extent not otherwise
utilized by us. At closing, we borrowed $250 million under the New Credit Facility to repay the
$250 million term loan outstanding under the Credit Agreement.
Interest on borrowings under the New Credit Facility is payable at rates per annum equal to,
at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.s adjusted base
rate plus the applicable margin or (2) a periodic fixed rate equal to LIBOR plus the applicable
margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5%, (ii)
Citibank N.A.s publicly announced base rate and (iii) one-month LIBOR plus 1.0%. We pay a
commitment fee (currently 0.5%) based on the unused portion of the New Credit Facility. The
applicable margin and the commitment fee are determined by reference to a pricing schedule based on
a borrowers senior unsecured debt ratings.
The New Credit Facility contains various covenants that limit, among other things, a
borrowers and its respective subsidiaries ability to incur indebtedness, grant certain liens
supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter
into certain affiliate transactions, make certain distributions
during an event of default and allow
any material change in the nature of its business.
In addition, we are required to maintain a ratio of debt to EBITDA (each as defined in the New
Credit Facility) of no greater than 5.00 to 1.00 for us and our consolidated subsidiaries. For each
of Transco and Northwest Pipeline and their respective consolidated subsidiaries, the ratio of debt
to capitalization (defined as net worth plus debt) is not permitted to be greater than 55%. Each of
the above ratios will be tested, beginning June 30, 2010, at the
end of each fiscal quarter, and the
debt to EBITDA ratio will be measured on a rolling four-quarter basis.
The New Credit Facility includes customary events of default, including events of default
relating to non-payment of principal, interest or fees, inaccuracy of representations and
warranties in any material respect when made or when deemed made, violation of covenants,
cross-payment defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied
judgments and a change of control. If an event of default with respect to a borrower occurs under
the New Credit Facility, the lenders will be able to terminate the commitments for all borrowers
and accelerate the maturity of the loans of the defaulting borrower under the New Credit Facility
and exercise other rights and remedies.
We also had a $20 million revolving credit facility with Williams as the lender. The facility
was available exclusively to fund working capital borrowings. This credit facility was terminated
in connection with the Dropdown.
69
Credit ratings
The table below presents our current credit ratings and outlook on our senior unsecured
long-term debt.
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Unsecured |
Rating Agency |
|
Date of Last Change |
|
Outlook |
|
Debt Rating |
Standard & Poors
|
|
January 12, 2010
|
|
Positive
|
|
BBB- |
Moodys Investor Service
|
|
February 17, 2010
|
|
Stable
|
|
Baa3 |
Fitch Ratings
|
|
February 2, 2010
|
|
Stable
|
|
BBB- |
The ratings changes noted above reflect the announcement and completion of the Dropdown.
With respect to Moodys, a rating of Baa or above indicates an investment grade rating. A
rating below Baa is considered to have speculative elements. A Ba rating indicates an
obligation that is judged to have speculative elements and is subject to substantial credit risk.
The 1, 2 and 3 modifiers show the relative standing within a major category. A 1 indicates
that an obligation ranks in the higher end of the broad rating category, 2 indicates a mid-range
ranking, and 3 indicates a ranking at the lower end of the category.
With respect to Standard and Poors, a rating of BBB or above indicates an investment grade
rating. A rating below BBB indicates that the security has significant speculative
characteristics. A BB rating indicates that Standard and Poors believes the issuer has the
capacity to meet its financial commitment on the obligation, but adverse business conditions could
lead to insufficient ability to meet financial commitments. Standard and Poors may modify its
ratings with a + or a - sign to show the obligors relative standing within a major rating
category.
With respect to Fitch, a rating of BBB or above indicates an investment grade rating. A
rating below BBB is considered speculative grade. A BB rating from Fitch indicates that there
is a possibility of credit risk developing, particularly as the result of adverse economic change
over time; however, business or financial alternatives may be available to allow financial
commitments to be met. Fitch may add a + or a - sign to show the obligors relative standing
within a major rating category.
Credit rating agencies perform independent analyses when assigning credit ratings. No
assurance can be given that the credit rating agencies will assign us investment grade ratings even
if we meet or exceed their current criteria for investment grade ratios.
Capital Expenditures
Each of our businesses is 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 generally not discretionary, include 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, include certain
well connection expenditures and expenditures which are mandatory and/or essential for
maintaining the reliability of our operations; and |
|
|
|
|
Expansion capital expenditures, which are generally more discretionary than maintenance
capital expenditures, include expenditures to acquire additional assets to grow our
business, to expand and upgrade plant or pipeline capacity and to construct new plants,
pipelines and storage facilities and well connection expenditures which are not classified
as maintenance expenditures. |
The following table provides summary information related to our expected capital expenditures
for 2010 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance |
|
|
Expansion |
|
Segment |
|
Low |
|
|
Midpoint |
|
|
High |
|
|
Low |
|
|
Midpoint |
|
|
High |
|
Gas Pipeline |
|
$ |
210 |
|
|
$ |
220 |
|
|
$ |
230 |
|
|
$ |
340 |
|
|
$ |
355 |
|
|
$ |
370 |
|
Midstream |
|
|
80 |
|
|
|
90 |
|
|
|
100 |
|
|
|
320 |
|
|
|
410 |
|
|
|
500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
290 |
|
|
$ |
310 |
|
|
$ |
330 |
|
|
$ |
660 |
|
|
$ |
765 |
|
|
$ |
870 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expansion capital expenditures include expenditures for the following Gas Pipeline and
Midstream projects:
70
Gas Pipeline
Mobile Bay South
In May 2009, we received approval from the FERC to construct a compression facility in Alabama
allowing transportation service to various southbound delivery points. The cost of the project is
estimated to be $37 million. The estimated project in-service date is May 2010 and will increase
capacity by 253 Mdt/d.
85 North
In September 2009, we received approval from the FERC to construct an expansion of our
existing natural gas transmission system from Alabama to various delivery points as far north as
North Carolina. The cost of the project is estimated to be $241 million. Phase I service is
anticipated to begin in July 2010 and will increase capacity by 90 Mdt/d. Phase II service is
anticipated to begin in May 2011 and will increase capacity by 218 Mdt/d.
Mobile Bay South II
In November 2009, we filed an application with the FERC to construct additional compression
facilities and modifications to existing facilities in Alabama allowing transportation service to
various southbound delivery points. The cost of the project is estimated to be $36 million. The
estimated project in-service date is May 2011 and will increase capacity by 380 Mdt/d.
Sundance Trail
In November 2009, we received approval from the FERC to construct approximately 16 miles of
30-inch pipeline between our existing compressor stations in Wyoming. The project also includes an
upgrade to our existing compressor station and is estimated to cost up to $65 million. The
estimated in-service date is November 2010 and will increase capacity by 150 Mdt/d.
Midstream
Perdido Norte
The Perdido Norte project, in the western deepwater of the Gulf of Mexico, includes an
expansion of our Markham gas processing facility and oil and gas lines that will expand the scale
of our existing infrastructure. Significant milestones have been reached and, considering the
progress of our customers drilling and tie-in construction, we expect this project to begin
start-up operations in the first quarter of 2010.
Wamsutter
We expect additional processing and NGL production capacities at our Echo Springs facility and
related gathering system expansions in the Wamsutter area of Wyoming to be in service at the end of
2010.
Marcellus Shale
In conjunction with a long-term anchor tenant agreement with a major producer, we will expand
our business in the Marcellus Shale with the construction of a 28-mile natural gas gathering
pipeline that will gather gas from a third-partys central delivery point in Susquehanna County,
Pa. The gas will be delivered to the Gas Pipeline segments Transco interstate gas pipeline in
Luzerne County, Pa. Construction is expected to begin on the 20-inch pipeline in the latter part
of 2010 and it is expected to be placed into service during 2011. We will operate the pipeline,
which represents our second significant midstream expansion in the Marcellus Shale.
In addition to our initial investment in the Marcellus basin, it is our intent to invest
additional capital within our Laurel Mountain joint venture to grow the existing gathering
infrastructure in 2010 and beyond.
71
Cash Distributions to Unitholders
We have paid quarterly distributions to unitholders and our general partner interest after
every quarter since our initial public offering on August 23, 2005. We expect to increase our
quarterly distribution from $0.6350 to $0.6575 per unit effective with our distribution with
respect to the first quarter of 2010. As part of the consideration for the Dropdown, we issued 203
million Class C limited partnership units to Williams, which are identical to our common limited
partnership units except that for the first quarter of 2010 they will receive a prorated quarterly
distribution since they were not outstanding during the full quarterly period. These Class C units
will automatically convert into our common limited partnership units following the record date for
the first-quarter 2010 cash distribution.
Results of Operations Cash Flows
The following table summarizes our historical cash flows prior to the Dropdown.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
Net cash provided (used) by: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
199 |
|
|
$ |
239 |
|
|
$ |
186 |
|
Investing activities |
|
|
(31 |
) |
|
|
(7 |
) |
|
|
(393 |
) |
Financing activities |
|
|
(140 |
) |
|
|
(152 |
) |
|
|
185 |
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
$ |
28 |
|
|
$ |
80 |
|
|
$ |
(22 |
) |
|
|
|
|
|
|
|
|
|
|
Operating Activities
Net cash provided by operating activities decreased $40 million in 2009 as compared to 2008
due primarily to lower operating income excluding non-cash items and lower distributions from
Wamsutter.
Net cash provided by operating activities increased $53 million in 2008 as compared to 2007
due primarily to $96 million higher distributions related to our Wamsutter ownership interests
purchased in December 2007. This increase was partially offset by an additional $27 million of
interest payments related primarily to our $250.0 million term loan issued in December 2007 and
timing of interest payments on our $600.0 million senior unsecured notes and $20 million decrease
in working capital excluding accrued interest.
Investing Activities
Capital expenditures in 2009, 2008 and 2007 totaled $37 million, $49 million and $47 million.
The 2007 results include the purchase of the Wamsutter ownership interests on December 11, 2007 and
the additional 20% ownership interest in Discovery on June 28, 2007. Since these ownership
interests were purchased from Williams, the transactions were between entities under common
control, and have been accounted for at historical cost. Therefore the amount reflected as cash
used by investing activities for these purchases represents the historical cost to Williams.
Financing Activities
Net cash used by financing activities in 2009 and 2008 includes distributions to unitholders
and our general partner of $144 million and $155 million, respectively.
Net cash provided by financing activities in 2007 includes $266 million of net proceeds from
debt and equity issuances related to our acquisition of the Wamsutter ownership interests less the
related amounts distributed to Williams in excess of Wamsutters contributed basis and $87 million
of distributions to unitholders and our general partner.
72
Contractual Obligations before Completion of the Dropdown
A summary of our contractual obligations as of December 31, 2009, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2011-2012 |
|
|
2013-2014 |
|
|
2015+ |
|
|
Total |
|
|
|
(in millions) |
|
Long-term debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal |
|
$ |
|
|
|
$ |
400 |
|
|
$ |
|
|
|
$ |
600 |
|
|
$ |
1,000 |
|
Interest |
|
|
58 |
(a) |
|
|
98 |
|
|
|
87 |
|
|
|
109 |
|
|
|
352 |
|
Capital leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases (b) |
|
|
14 |
|
|
|
16 |
|
|
|
15 |
|
|
|
105 |
|
|
|
150 |
|
Purchase obligations (c) |
|
|
32 |
|
|
|
36 |
|
|
|
18 |
|
|
|
|
|
|
|
86 |
|
Other long term obligations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
104 |
|
|
$ |
550 |
|
|
$ |
120 |
|
|
$ |
814 |
|
|
$ |
1,588 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The assumed interest rate on our $250.0 million term loan is based on the forecasted forward LIBOR plus the
applicable margin. |
|
(b) |
|
Includes a right-of-way agreement with the Jicarilla Apache Nation, which is considered an operating lease. We
are required to make a fixed annual of $7.5 million and an additional annual payment, which varies depending on
per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the right-of-way
agreement. The table above for years 2011 and thereafter does not
include such variable amounts related to this agreement as the
variable amount is not yet determinable. |
|
(c) |
|
Includes a five-year service agreement for leased compression and open purchase orders as of December 31, 2009 to
be paid in 2010. |
Contractual Obligations after Completion of the Dropdown
As a result of the Dropdown and related transactions, our contractual obligations have
increased significantly. The following table summarizes our contractual obligations as updated for
the impact of the Dropdown and related debt and equity issuances only.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2011-2012 |
|
|
2013-2014 |
|
|
2015+ |
|
|
Total |
|
|
|
(in millions) |
|
Long-term debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal |
|
$ |
15 |
|
|
$ |
784 |
|
|
$ |
250 |
|
|
$ |
5,452 |
|
|
$ |
6,501 |
|
Interest |
|
|
291 |
(a) |
|
|
724 |
|
|
|
634 |
|
|
|
2,982 |
|
|
|
4,631 |
|
Capital leases |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases (b) |
|
|
27 |
|
|
|
40 |
|
|
|
33 |
|
|
|
125 |
|
|
|
225 |
|
Purchase obligations |
|
|
529 |
|
|
|
449 |
|
|
|
382 |
|
|
|
1,535 |
|
|
|
2,895 |
|
Other long term obligations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
862 |
|
|
$ |
1,997 |
|
|
$ |
1,299 |
|
|
$ |
10,094 |
|
|
$ |
14,252 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The assumed interest rate on our $250.0 million term loan is based on the forecasted forward LIBOR plus the applicable
margin. |
|
(b) |
|
Includes a right-of-way agreement with the Jicarilla Apache Nation, which is considered an operating lease. We are
required to make a fixed annual of $7.5 million and an additional annual payment, which varies depending on per-unit
NGL margins and the volume of gas gathered by our gathering facilities subject to the right-of-way agreement. The
table above for years 2011 and thereafter does not include such variable amounts related to this agreement as the
variable amount is not yet determinable. |
73
Off-Balance Sheet Arrangements
We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet
arrangements at December 31, 2009.
Effects of Inflation
Our operations have benefited from relatively low inflation rates. Following the Dropdown,
approximately 66% of our gross property, plant and equipment is at Gas Pipeline. Gas Pipeline is
subject to regulation, which limits recovery to historical cost. While amounts in excess of
historical cost are not recoverable under current FERC practices, we anticipate being allowed to
recover and earn a return based on increased actual cost incurred to replace existing assets.
Cost-based regulations, along with competition and other market factors, may limit our ability to
recover such increased costs. For Midstream, operating costs are influenced to a greater extent by
both competition for specialized services and specific price changes in oil and natural gas and
related commodities than by changes in general inflation. Crude, natural gas, and natural gas
liquids prices are particularly sensitive to the Organization of the Petroleum Exporting Countries
(OPEC) production levels and/or the market perceptions concerning the supply and demand balance in
the near future, as well as general economic conditions. However, our exposure to these price
changes is reduced through the use of hedging instruments and the fee-based nature of certain of
our services.
Environmental
We are a participant in certain environmental activities in various stages including
assessment studies, cleanup operations and/or remedial processes at certain sites. We are
monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S.
Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and
severally liable along with unrelated third parties in some of these activities and solely
responsible in others. Current estimates of the most likely costs of such activities are
approximately $19.3 million, of which $6.6 million are recorded as liabilities on our balance sheet
at December 31, 2009 and $12.7 million represents estimates associated with the operations we
acquired in the Dropdown. We will seek recovery of approximately $12.6 million of
these costs through future natural gas transmission rates. The remainder of these costs will be
funded from operations. During 2009, we paid approximately $0.6 million for cleanup and /or
remediation and monitoring activities associated with our operations prior to the Dropdown. We
expect to pay approximately $3.2 million in 2010 for these activities, including activities
associated with the operations acquired in the Dropdown. Estimates of the most
likely costs of cleanup are generally based on completed assessment studies, preliminary results of
studies or our experience with other similar cleanup operations. At December 31, 2009, certain
assessment studies were still in process for which the ultimate outcome may yield significantly
different estimates of most likely costs. Therefore, the actual costs incurred will depend on the
final amount, type and extent of contamination discovered at these sites, the final cleanup
standards mandated by the EPA or other governmental authorities, and other factors.
We are subject to the federal Clean Air Act and to the federal Clean Air Act Amendments of
1990, which require the EPA to issue new regulations. We are also subject to regulation at the
state and local level. In September 1998, the EPA promulgated rules designed to mitigate the
migration of ground-level ozone in certain states. Revisions to those rules were proposed in
January 2010 and may result in additional controls. In March 2004 and June 2004, the EPQ
promulgated additional regulation regarding hazardous air pollutants, which may result in
additional controls. Capital expenditures necessary to install emission control devices on the
Transco gas pipeline system (acquired in the Dropdown) to comply with rules are
estimated to be between $5 million and $10 million through 2013. The actual costs incurred will
depend on the final implementation plans developed by each state to comply with these regulations.
We consider these costs on the Transco system associated with compliance with these environmental
laws and regulations to be prudent costs incurred in the ordinary course of business and,
therefore, recoverable through its rates.
We have established systems and procedures to meet our reporting obligations under the
Mandatory Reporting Rule related to greenhouse gas emissions issued by the EPA in late 2009. Also,
certain states in which we have operations have established reporting obligations. We have not
incurred significant capital investment to meet the obligations imposed by these new rules. The EPA
is developing additional regulations that will expand the scope of the Mandatory Reporting Rule,
with particular emphasis on natural gas operations. We are participating directly and through trade
associations in developmental aspects of that prospective rulemaking. It is likely that additional
rules will be issued in 2010 which may expand our reporting obligations as early as 2011. As those
rules are still being developed, at this time we are unable to estimate any capital investment that
may be required to comply.
74
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 risks to which we are exposed are commodity price risk and interest rate risk.
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of NGLs and natural gas, as
well as other market factors, such as market volatility and commodity price correlations. We are
exposed to these risks in connection with our owned energy-related assets and our long-term
energy-related contracts. We manage a portion of the risks associated with these market
fluctuations using various derivative contracts. The fair value of derivative contracts is subject
to changes in energy-commodity market prices, the liquidity and volatility of the markets in which
the contracts are transacted, and changes in interest rates. (Please read Note 13, Fair Value
Measurements, of our Notes to Consolidated Financial Statements.)
We measure the risk in our portfolio using a value-at-risk methodology to estimate the
potential one-day loss from adverse changes in the fair value of the portfolio. Value at risk
requires a number of key assumptions and is not necessarily representative of actual losses in fair
value that could be incurred from the portfolio. Our value-at-risk model uses a Monte Carlo method
to simulate hypothetical movements in future market prices and assumes that, as a result of changes
in commodity prices, there is a 95% probability that the one-day loss in fair value of the
portfolio will not exceed the value at risk. The simulation method uses historical correlations and
market forward prices and volatilities. In applying the value-at-risk methodology, we do not
consider that the simulated hypothetical movements affect the positions or would cause any
potential liquidity issues, nor do we consider that changing the portfolio in response to market
conditions could affect market prices and could take longer than a one-day holding period to
execute. While a one-day holding period has historically been the industry standard, a longer
holding period could more accurately represent the true market risk given market liquidity and our
own credit and liquidity constraints. Our derivative contracts are contracts held for nontrading
purposes and hedge a portion of our commodity price risk exposure from natural gas liquid sales and
natural gas purchases.
The value at risk at December 31, 2009 for Four Corners derivative contracts was $0.1
million. Wamsutter had no derivatives outstanding at December 31, 2009 or 2008 and Four Corners had
no derivatives outstanding at December 31, 2008. The Dropdown did not have a significant impact on
our derivative portfolio.
All of the derivative contracts included in our value-at-risk calculation are accounted for as
cash flow hedges. Any change in the fair value of these hedge contracts would generally not be
reflected in earnings until the associated hedged item affects earnings.
Interest Rate Risk before Dropdown
Our interest rate risk exposure is related primarily to our debt portfolio. A majority of our
current debt portfolio is comprised of fixed interest rate debt, which mitigates the impact of
fluctuations in interest rates. Any borrowings under our credit agreements would be at a variable
interest rate and would expose us to the risk of increasing interest rates.
The table below provides information about our interest rate-sensitive instruments as of
December 31, 2009 and 2008 prior to the impact of the Dropdown and related debt issuance.
Long-term debt in the table represents principal cash flows by expected maturity date. The fair
value of our private debt is valued based on the prices of similar securities with similar terms
and credit ratings.
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2012 |
|
|
2017 |
|
|
Total |
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Long-term debt (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate |
|
$ |
150 |
|
|
$ |
|
|
|
$ |
600 |
|
|
$ |
750 |
|
|
$ |
763 |
|
|
$ |
592 |
|
Interest rate |
|
|
7.50 |
% |
|
|
|
|
|
|
7.25 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Variable rate |
|
$ |
|
|
|
$ |
250 |
|
|
$ |
|
|
|
$ |
250 |
|
|
$ |
237 |
|
|
$ |
233 |
|
Interest rate(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes unamortized discount and premium. |
|
(2) |
|
The variable interest rate at December 31, 2009 was 1.23%. The
weighted-average interest rate for 2009 is applicable base rate plus
0.89%. |
Interest
Rate Risk after Completion of the Dropdown
The Dropdown and related debt issuance had a significant impact on our debt portfolio. The
table below provides information about our interest rate-sensitive instruments following the
Dropdown and related debt issuance. Long-term debt in the table represents principal cash flows by
expected maturity date.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
|
2011 |
|
|
2012 |
|
|
2013 |
|
|
2014 |
|
|
Thereafter |
|
|
Total |
|
|
|
(In millions) |
|
Long-term debt,
including current
portion (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate |
|
$ |
15 |
|
|
$ |
459 |
|
|
$ |
325 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
5,452 |
|
|
$ |
6,251 |
|
Interest rate |
|
|
6.0 |
% |
|
|
6.0 |
% |
|
|
5.9 |
% |
|
|
5.8 |
% |
|
|
5.8 |
% |
|
|
6.2 |
% |
|
|
|
|
Variable rate |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
250 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
250 |
|
Interest rate (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes unamortized discount and premium. |
|
(2) |
|
The interest rate for the $250 million variable rate debt
under the New Credit Facility is LIBOR plus
2.75%. |
76
Item 8. Financial Statements and Supplementary Data
MANAGEMENTS ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over
financial reporting (as defined in Rules 13a 15(f) and 15d 15(f) under the Securities
Exchange Act of 1934). Our internal controls over financial reporting are designed to provide
reasonable assurance to our management and board of directors regarding the preparation and fair
presentation of financial statements in accordance with accounting principles generally accepted in
the United States. Our internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable
assurance that transactions are recorded as to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that our receipts and expenditures
are being made only in accordance with authorization of our management and board of directors; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of our assets that could have a material effect on our financial
statements.
All internal control systems, no matter how well designed, have inherent limitations including
the possibility of human error and the circumvention or overriding of controls. Therefore, even
those systems determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation.
Under the supervision and with the participation of our management, including our general
partners Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our
internal control over financial reporting as of December 31, 2009, based on the criteria set forth
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control
Integrated Framework. Based on our assessment we concluded that, as of December 31, 2009, our
internal control over financial reporting was effective.
Ernst & Young LLP, our independent registered public accounting firm, has audited our internal
control over financial reporting, as stated in their report which is included in this Annual Report
on Form 10-K.
77
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors of Williams Partners GP LLC
General Partner of Williams Partners L.P.
and the Limited Partners of Williams Partners L.P.
We have audited Williams Partners L.P.s internal control over financial reporting as of December
31, 2009, based on criteria established in Internal ControlIntegrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Williams
Partners L.P.s management is responsible for maintaining effective internal control over financial
reporting, and for its assessment of the effectiveness of internal control over financial reporting
included in the accompanying Managements Report on Internal Control Over Financial Reporting. Our
responsibility is to express an opinion on the Companys internal control over financial reporting
based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
companys internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Williams Partners L.P. maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2009 based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the accompanying consolidated balance sheets of Williams Partners L.P. as of
December 31, 2009 and 2008, and the related consolidated statements of income, partners capital,
and cash flows for each of the three years in the period ended December 31, 2009, and our report
dated February 25, 2010 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 25, 2010
78
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Williams Partners GP LLC
General Partner of Williams Partners L.P.
and the Limited Partners of Williams Partners L.P.
We have audited the accompanying consolidated balance sheets of Williams Partners L.P. as of
December 31, 2009 and 2008, and the related consolidated statements of income, partners capital,
and cash flows for each of the three years in the period ended December 31, 2009. These financial
statements are the responsibility of the Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the consolidated financial position of Williams Partners L.P. at December 31, 2009 and
2008, and the consolidated results of its operations and its cash flows for each of the three years
in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting
principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), Williams Partners L.P.s internal control over financial reporting as of
December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February
25, 2010 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 25, 2010
79
WILLIAMS
PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
ASSETS |
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
144,067 |
|
|
$ |
116,165 |
|
Accounts receivable: |
|
|
|
|
|
|
|
|
Trade |
|
|
17,210 |
|
|
|
16,279 |
|
Affiliate |
|
|
22,635 |
|
|
|
11,652 |
|
Other |
|
|
1,581 |
|
|
|
2,919 |
|
Product imbalance |
|
|
10,583 |
|
|
|
6,344 |
|
Prepaid expenses and other current assets |
|
|
7,392 |
|
|
|
7,744 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
203,468 |
|
|
|
161,103 |
|
Investment in Wamsutter |
|
|
272,549 |
|
|
|
277,707 |
|
Investment in Discovery Producer Services |
|
|
188,511 |
|
|
|
184,466 |
|
Property, plant and equipment, net |
|
|
634,233 |
|
|
|
640,520 |
|
Other noncurrent assets |
|
|
24,909 |
|
|
|
28,023 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,323,670 |
|
|
$ |
1,291,819 |
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL |
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable: |
|
|
|
|
|
|
|
|
Trade |
|
$ |
18,777 |
|
|
$ |
22,348 |
|
Affiliate |
|
|
20,231 |
|
|
|
11,122 |
|
Product imbalance |
|
|
12,437 |
|
|
|
8,926 |
|
Deferred revenue |
|
|
4,983 |
|
|
|
4,916 |
|
Accrued interest |
|
|
18,722 |
|
|
|
18,705 |
|
Other accrued liabilities |
|
|
13,626 |
|
|
|
6,172 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
88,776 |
|
|
|
72,189 |
|
Long-term debt |
|
|
1,000,000 |
|
|
|
1,000,000 |
|
Other noncurrent liabilities |
|
|
19,499 |
|
|
|
16,020 |
|
Commitments and contingent liabilities (Note 16) |
|
|
|
|
|
|
|
|
Partners capital: |
|
|
|
|
|
|
|
|
Common unitholders (52,777,452 units outstanding at December 31,
2009 and 2008) |
|
|
1,630,604 |
|
|
|
1,619,954 |
|
Accumulated other comprehensive loss |
|
|
(561 |
) |
|
|
|
|
General partner |
|
|
(1,414,648 |
) |
|
|
(1,416,344 |
) |
|
|
|
|
|
|
|
Total partners capital |
|
|
215,395 |
|
|
|
203,610 |
|
|
|
|
|
|
|
|
Total liabilities and partners capital |
|
$ |
1,323,670 |
|
|
$ |
1,291,819 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
80
WILLIAMS
PARTNERS L.P.
CONSOLIDATED STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(Dollars in thousands, except per-unit amounts) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Product sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
167,487 |
|
|
$ |
314,299 |
|
|
$ |
267,970 |
|
Third-party |
|
|
14,981 |
|
|
|
24,981 |
|
|
|
22,962 |
|
Gathering and processing: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
43,978 |
|
|
|
37,893 |
|
|
|
35,819 |
|
Third-party |
|
|
187,825 |
|
|
|
195,056 |
|
|
|
202,775 |
|
Storage |
|
|
33,209 |
|
|
|
31,429 |
|
|
|
28,016 |
|
Fractionation |
|
|
10,584 |
|
|
|
17,441 |
|
|
|
9,622 |
|
Other |
|
|
12,125 |
|
|
|
15,961 |
|
|
|
5,653 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
470,189 |
|
|
|
637,060 |
|
|
|
572,817 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
37,167 |
|
|
|
85,372 |
|
|
|
73,475 |
|
Third-party |
|
|
66,058 |
|
|
|
120,706 |
|
|
|
108,223 |
|
Operating and maintenance expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
48,199 |
|
|
|
76,735 |
|
|
|
61,633 |
|
Third-party |
|
|
114,865 |
|
|
|
109,166 |
|
|
|
100,710 |
|
Depreciation, amortization and accretion |
|
|
44,887 |
|
|
|
45,029 |
|
|
|
46,492 |
|
General and administrative expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
47,253 |
|
|
|
44,065 |
|
|
|
42,038 |
|
Third-party |
|
|
3,992 |
|
|
|
2,994 |
|
|
|
3,590 |
|
Taxes other than income |
|
|
10,149 |
|
|
|
9,508 |
|
|
|
9,624 |
|
Other (income) expense net |
|
|
(4,133 |
) |
|
|
(3,523 |
) |
|
|
12,095 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
368,437 |
|
|
|
490,052 |
|
|
|
457,880 |
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
101,752 |
|
|
|
147,008 |
|
|
|
114,937 |
|
Equity earnings Wamsutter |
|
|
84,052 |
|
|
|
88,538 |
|
|
|
76,212 |
|
Discovery investment income |
|
|
27,243 |
|
|
|
22,357 |
|
|
|
28,842 |
|
Interest expense |
|
|
(60,679 |
) |
|
|
(67,220 |
) |
|
|
(58,348 |
) |
Interest income |
|
|
99 |
|
|
|
706 |
|
|
|
2,988 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
152,467 |
|
|
$ |
191,389 |
|
|
$ |
164,631 |
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income for calculation of earnings per unit: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
152,467 |
|
|
$ |
191,389 |
|
|
$ |
164,631 |
|
Allocation of net income to general partner |
|
|
511 |
|
|
|
28,957 |
|
|
|
79,507 |
|
|
|
|
|
|
|
|
|
|
|
Allocation of net income to limited partners |
|
$ |
151,956 |
|
|
$ |
162,432 |
|
|
$ |
85,124 |
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net income per limited partner unit |
|
$ |
2.88 |
|
|
$ |
3.08 |
|
|
$ |
1.99 |
|
Weighted average number of common units outstanding |
|
|
52,777,452 |
|
|
|
52,775,710 |
(a) |
|
|
40,131,195 |
(a)(b) |
|
|
|
(a) |
|
Includes subordinated units converted to common on February 19, 2008. |
|
(b) |
|
Includes Class B units converted to common on May 21, 2007. |
See accompanying notes to consolidated financial statements.
81
WILLIAMS
PARTNERS L.P.
CONSOLIDATED STATEMENT OF PARTNERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited Partners |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General |
|
|
Comprehensive |
|
|
Partners |
|
|
|
Common |
|
|
Class B |
|
|
Subordinated |
|
|
Partner |
|
|
Loss |
|
|
Capital |
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
Balance December 31, 2006 |
|
$ |
733,878 |
|
|
$ |
241,923 |
|
|
$ |
108,862 |
|
|
$ |
(613,322 |
) |
|
$ |
|
|
|
$ |
471,341 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income 2007 |
|
|
64,546 |
|
|
|
9,212 |
|
|
|
14,995 |
|
|
|
75,878 |
|
|
|
|
|
|
|
164,631 |
|
Other comprehensive loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses on cash
flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,763 |
) |
|
|
(3,763 |
) |
Reclassification into earnings
of derivative instrument losses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,276 |
|
|
|
1,276 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,487 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
162,144 |
|
Cash distributions |
|
|
(59,573 |
) |
|
|
(6,601 |
) |
|
|
(14,315 |
) |
|
|
(6,792 |
) |
|
|
|
|
|
|
(87,281 |
) |
Conversion of Class B units into
common (6,805,492 units) |
|
|
244,534 |
|
|
|
(244,534 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to general partner
in exchange for additional
investment in Discovery Producer
Services |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(78,000 |
) |
|
|
|
|
|
|
(78,000 |
) |
Adjustment in basis of investment
in Discovery Producer Services |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,035 |
) |
|
|
|
|
|
|
(9,035 |
) |
Issuance of units to public
(9,250,000 common units) |
|
|
335,220 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
335,220 |
|
Issuance of units to general
partner (4,163,257 common units) |
|
|
157,173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
157,173 |
|
Distributions to general partner
in exchange for investment in
Wamsutter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(750,000 |
) |
|
|
|
|
|
|
(750,000 |
) |
Offering costs |
|
|
(1,927 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,927 |
) |
Adjustment in basis of investment
in Wamsutter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(53,807 |
) |
|
|
|
|
|
|
(53,807 |
) |
Contributions from general partner |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,334 |
|
|
|
|
|
|
|
10,334 |
|
Contributions pursuant to the
omnibus agreement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,362 |
|
|
|
|
|
|
|
5,362 |
|
Other |
|
|
(37 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(37 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007 |
|
|
1,473,814 |
|
|
|
|
|
|
|
109,542 |
|
|
|
(1,419,382 |
) |
|
|
(2,487 |
) |
|
|
161,487 |
|
Net income 2008 |
|
|
163,917 |
|
|
|
|
|
|
|
1,556 |
|
|
|
25,916 |
|
|
|
|
|
|
|
191,389 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized gains on cash flow
hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,903 |
|
|
|
2,903 |
|
Reclassification into earnings of
derivative instrument gains |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(416 |
) |
|
|
(416 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,487 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
193,876 |
|
Cash distributions |
|
|
(124,483 |
) |
|
|
|
|
|
|
(4,025 |
) |
|
|
(26,874 |
) |
|
|
|
|
|
|
(155,382 |
) |
Conversion of subordinated units
into common (7,000,000 units) |
|
|
107,073 |
|
|
|
|
|
|
|
(107,073 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Contributions pursuant to the
omnibus agreement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,981 |
|
|
|
|
|
|
|
2,981 |
|
Issuance of units to public
(800,000 common units) |
|
|
28,992 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28,992 |
|
Repurchase of units from Williams
(800,000 common units) |
|
|
(28,992 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(28,992 |
) |
Other |
|
|
(367 |
) |
|
|
|
|
|
|
|
|
|
|
1,015 |
|
|
|
|
|
|
|
648 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2008 |
|
|
1,619,954 |
|
|
|
|
|
|
|
|
|
|
|
(1,416,344 |
) |
|
|
|
|
|
|
203,610 |
|
Net income 2009 |
|
|
144,684 |
|
|
|
|
|
|
|
|
|
|
|
7,783 |
|
|
|
|
|
|
|
152,467 |
|
82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited Partners |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Other |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General |
|
|
Comprehensive |
|
|
Partners |
|
|
|
Common |
|
|
Class B |
|
|
Subordinated |
|
|
Partner |
|
|
Loss |
|
|
Capital |
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses on cash
flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,411 |
) |
|
|
(2,411 |
) |
Net unrealized losses on cash
flow hedges Wamsutter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(685 |
) |
|
|
(685 |
) |
Reclassification of losses into
earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,850 |
|
|
|
1,850 |
|
Reclassification of losses into
earnings Wamsutter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
685 |
|
|
|
685 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(561 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
151,906 |
|
Cash distributions |
|
|
(134,052 |
) |
|
|
|
|
|
|
|
|
|
|
(10,156 |
) |
|
|
|
|
|
|
(144,208 |
) |
Contributions pursuant to the
omnibus agreement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,069 |
|
|
|
|
|
|
|
4,069 |
|
Other |
|
|
18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2009 |
|
$ |
1,630,604 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,414,648 |
) |
|
$ |
(561 |
) |
|
$ |
215,395 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
83
WILLIAMS PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
152,467 |
|
|
$ |
191,389 |
|
|
$ |
164,631 |
|
Adjustments to reconcile to cash provided by operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, amortization and accretion |
|
|
44,887 |
|
|
|
45,029 |
|
|
|
46,492 |
|
Provision for loss on property, plant and equipment |
|
|
|
|
|
|
6,827 |
|
|
|
11,306 |
|
Amortization of gas purchase contract affiliate |
|
|
|
|
|
|
|
|
|
|
4,754 |
|
Gain on involuntary conversion |
|
|
(4,034 |
) |
|
|
(11,604 |
) |
|
|
|
|
Equity earnings of Wamsutter |
|
|
(84,052 |
) |
|
|
(88,538 |
) |
|
|
(76,212 |
) |
Equity earnings of Discovery Producer Services |
|
|
(23,023 |
) |
|
|
(20,641 |
) |
|
|
(28,842 |
) |
Distributions related to equity earnings of Wamsutter |
|
|
84,052 |
|
|
|
95,926 |
|
|
|
|
|
Distributions related to equity earnings of Discovery Producer Services |
|
|
23,023 |
|
|
|
20,641 |
|
|
|
26,240 |
|
Cash provided (used) by changes in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(10,576 |
) |
|
|
4,955 |
|
|
|
11,830 |
|
Prepaid expenses |
|
|
(955 |
) |
|
|
(46 |
) |
|
|
(369 |
) |
Reimbursable projects |
|
|
|
|
|
|
8,989 |
|
|
|
(8,989 |
) |
Other current assets |
|
|
1,307 |
|
|
|
(1,373 |
) |
|
|
(1,041 |
) |
Accounts payable |
|
|
5,118 |
|
|
|
(16,827 |
) |
|
|
13,959 |
|
Product imbalance |
|
|
(728 |
) |
|
|
1,769 |
|
|
|
162 |
|
Accrued liabilities |
|
|
9,290 |
|
|
|
(2,344 |
) |
|
|
15,914 |
|
Deferred revenue |
|
|
(167 |
) |
|
|
59 |
|
|
|
1,709 |
|
Other, including changes in noncurrent assets and liabilities |
|
|
2,001 |
|
|
|
4,632 |
|
|
|
4,313 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
198,610 |
|
|
|
238,843 |
|
|
|
185,857 |
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of additional investment in Discovery Producer Services |
|
|
|
|
|
|
|
|
|
|
(69,061 |
) |
Purchase of investment in Wamsutter |
|
|
|
|
|
|
|
|
|
|
(277,262 |
) |
Cumulative distributions in excess of equity earnings of Wamsutter |
|
|
6,169 |
|
|
|
3,213 |
|
|
|
|
|
Cumulative distributions in excess of equity earnings of Discovery Producer Services |
|
|
9,121 |
|
|
|
35,759 |
|
|
|
229 |
|
Capital expenditures |
|
|
(36,841 |
) |
|
|
(49,304 |
) |
|
|
(46,530 |
) |
Receipt of insurance proceeds |
|
|
5,000 |
|
|
|
13,140 |
|
|
|
|
|
Contribution to Wamsutter |
|
|
(1,012 |
) |
|
|
(3,658 |
) |
|
|
|
|
Contribution to Discovery Producer Services |
|
|
(13,166 |
) |
|
|
(5,700 |
) |
|
|
|
|
Proceeds from sales of property, plant and equipment |
|
|
162 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(30,567 |
) |
|
|
(6,550 |
) |
|
|
(392,624 |
) |
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from sales of common units |
|
|
|
|
|
|
28,992 |
|
|
|
492,393 |
|
Proceeds from debt issuances |
|
|
|
|
|
|
|
|
|
|
250,000 |
|
Redemption of common units from general partner |
|
|
|
|
|
|
(28,992 |
) |
|
|
|
|
Excess purchase price over the contributed basis of the investment in Discovery
Producer Services |
|
|
|
|
|
|
|
|
|
|
(8,939 |
) |
Excess purchase price over the contributed basis of the investment in Wamsutter |
|
|
|
|
|
|
|
|
|
|
(472,738 |
) |
Payment of debt issuance costs |
|
|
|
|
|
|
|
|
|
|
(1,781 |
) |
Payment of offering costs |
|
|
|
|
|
|
|
|
|
|
(1,927 |
) |
Distributions to unitholders and general partner |
|
|
(144,208 |
) |
|
|
(155,382 |
) |
|
|
(87,281 |
) |
General partner contributions |
|
|
4,069 |
|
|
|
2,981 |
|
|
|
15,696 |
|
Other |
|
|
(2 |
) |
|
|
76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities |
|
|
(140,141 |
) |
|
|
(152,325 |
) |
|
|
185,423 |
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
|
27,902 |
|
|
|
79,968 |
|
|
|
(21,344 |
) |
Cash and cash equivalents at beginning of year |
|
|
116,165 |
|
|
|
36,197 |
|
|
|
57,541 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
144,067 |
|
|
$ |
116,165 |
|
|
$ |
36,197 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
84
WILLIAMS PARTNERS L. P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization
Unless the context clearly indicates otherwise, references in this report to we, our, us
or similar language refer to Williams Partners L.P. and its subsidiaries. Unless the context
clearly indicates otherwise, references to we, our, and us include the operations of
Wamsutter LLC (Wamsutter) and Discovery Producer Services LLC (Discovery) in which we own interests
accounted for as equity investments that are not consolidated in our financial statements. When we
refer to Wamsutter or Discovery by name, we are referring exclusively to their businesses and
operations.
We are a publicly-traded Delaware limited partnership. Williams Partners GP LLC, a Delaware
limited liability company and wholly owned by The Williams Companies, Inc. (Williams), serves as
our general partner and owns a 2% general partner interest, a 6% limited partner interest (as of
December 31, 2009) and
incentive distribution rights in us. All of our activities are conducted through Williams Partners
Operating LLC (OLLC), an operating limited liability company (wholly owned by us).
We have evaluated our disclosure of subsequent events through February 25, 2010, the date that
the financial statements were filed.
Note 2. Dropdown
On February 17, 2010, we closed a transaction with our general partner, our operating company
and certain subsidiaries of and including Williams, pursuant to which Williams contributed to us
the ownership interests in the entities that make up Williams Gas Pipeline and Midstream Gas &
Liquids business segments to the extent not already owned by us, including Williams limited and
general partner interests in Williams Pipeline Partners L.P. (WMZ), but excluding Williams
Canadian, Venezuelan and olefins operations and 25.5% of Gulfstream Natural Gas System, L.L.C.
(Gulfstream), collectively referred to as the Contributed Entities. This contribution was made
in exchange for aggregate consideration of:
|
|
|
$3.5 billion in cash, less certain expenses incurred by us, |
|
|
|
|
203 million of our Class C limited partnership units, and |
|
|
|
|
an increase in the capital account of our general partner to allow it to maintain its
2% general partner interest. |
The transactions described in the preceding paragraph are referred to as the Dropdown. We
financed the cash portion of the consideration by issuing $3.5 billion of senior unsecured notes
(see Note 11, Long-Term Debt, Credit Facilities and Leasing Activities). Because the acquired
entities were affiliates of Williams at the time of the acquisition, this transaction will be
accounted for as a combination of entities under common control, similar to a pooling of interests,
whereby the assets and liabilities of the acquired entities will be combined with ours at their
historical amounts. During 2010, we will retrospectively adjust our financial statements to
reflect this accounting.
The following tables summarize the impact of the acquisition on our financial position and
results of operations as of and for the year ended December 31, 2009 on a retrospectively adjusted
basis and does not reflect the issuance of debt to finance that acquisition.
85
Supplemental Retrospectively Adjusted Balance Sheet Data (at December 31, 2009) (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams |
|
|
|
|
|
|
|
|
|
|
Partners L.P. |
|
Contributed |
|
|
|
|
|
Retrospectively |
|
|
Historical |
|
Entities |
|
Eliminations |
|
Adjusted |
|
|
(In millions) |
Total assets |
|
$ |
1,324 |
|
|
$ |
10,968 |
|
|
$ |
(286 |
)(a) |
|
$ |
12,006 |
|
Property, plant and
equipment, net |
|
|
634 |
|
|
|
9,591 |
|
|
|
|
|
|
|
10,225 |
|
Long-term debt, including current portion |
|
|
1,000 |
|
|
|
1,996 |
|
|
|
|
|
|
|
2,996 |
|
Total partners capital/equity |
|
|
215 |
|
|
|
7,681 |
|
|
|
(273 |
) |
|
|
7,623 |
|
|
|
|
(a) |
|
Includes the elimination of our equity investment in Wamsutter since
Wamsutter is consolidated by the Contributed Entities. Also includes
the elimination of $13 million in accounts receivable from the Contributed
Entities. |
Supplemental, Retrospectively Adjusted Statement of Income Data: (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners historical revenues |
|
$ |
470 |
|
|
$ |
637 |
|
|
$ |
573 |
|
Contributed Entities historical revenues |
|
|
4,226 |
|
|
|
5,455 |
|
|
|
5,326 |
|
Less: eliminations (a) |
|
|
(167 |
) |
|
|
(314 |
) |
|
|
(268 |
) |
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
4,529 |
|
|
$ |
5,778 |
|
|
$ |
5,631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income: |
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners historical net income |
|
$ |
152 |
|
|
$ |
191 |
|
|
$ |
165 |
|
Contributed Entities historical net income |
|
|
962 |
|
|
|
1,997 |
|
|
|
1,360 |
|
Less: equity earnings Wamsutter (b) |
|
|
(84 |
) |
|
|
(89 |
) |
|
|
(76 |
) |
|
|
|
|
|
|
|
|
|
|
Net income (c) (d) |
|
$ |
1,030 |
|
|
$ |
2,099 |
|
|
$ |
1,449 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes elimination of product sales revenues derived from
sales between us and the Contributed Entities. |
|
(b) |
|
Includes the elimination of equity earnings from Wamsutter since Wamsutter is consolidated by
the Contributed Entities. |
|
(c) |
|
Does not reflect interest associated with the $3.5 billion senior unsecured notes. Future
operating results will include additional interest expense associated with this new long-term
debt. |
|
(d) |
|
The Contributed Entities historical net income includes income taxes related to Transco and
Northwest Pipeline (as defined in Note 3). Transco and Northwest Pipeline converted from
corporations to limited liability companies on December 31, 2008 and October 1, 2007,
respectively, and are not subject to income taxes after those respective dates. The effect
of Transco and Northwest Pipelines change in tax status resulted in a significant benefit
for income taxes during 2008 and 2007 for the Contributed Entities. |
Note 3. Description of Business
We are principally engaged in the business of gathering, transporting, processing and treating
natural gas and fractionating and storing natural gas liquids (NGL). Operations of our businesses
are located in the United States and are organized into three reporting segments: (1) Gathering and
Processing-West, (2) Gathering and Processing-Gulf and (3) NGL Services. Our Gathering and
86
Processing-West segment includes the Four Corners gathering and processing operations and our
equity investment in Wamsutter. Our Gathering and Processing-Gulf segment includes the Carbonate
Trend gathering pipeline and our equity investment in Discovery. Our NGL Services segment includes
the Conway fractionation and storage operations.
Gathering and Processing-West. Our Four Corners natural gas gathering, processing and
treating assets consist of, among other things, (1) an approximately 3,800-mile natural gas
gathering system in the San Juan Basin in New Mexico and Colorado with a capacity of two billion
cubic feet per day, (2) the Ignacio natural gas processing plant in Colorado and the Kutz and
Lybrook natural gas processing plants in New Mexico, which have a combined processing capacity of
765 million cubic feet per day (MMcf/d) and (3) the Milagro and Esperanza natural gas treating
plants in New Mexico, which have a combined carbon dioxide removal capacity of 70 MMcf/d.
Wamsutter owns (1) an approximate 1,880-mile natural gas gathering system in the Washakie
Basin in south-central Wyoming that currently connects approximately 2,100 wells, with a typical
operating capacity of approximately 500 MMcf/d at current operating pressures, and (2) the Echo
Springs cryogenic processing plant near Wamsutter, Wyoming which has 390 MMcf/d of inlet cryogenic
processing capacity and NGL production capacity of 30,000 barrels per day (bpd).
Gathering and Processing-Gulf. We own a 60% interest in Discovery, which includes a wholly
owned subsidiary, Discovery Gas Transmission LLC. Discovery owns (1) an approximate 350-mile
natural gas gathering and transportation pipeline system, located primarily off the coast of
Louisiana in the Gulf of Mexico, (2) a 600 MMcf/d cryogenic natural gas processing plant in Larose,
Louisiana, (3) a 32,000 bpd natural gas liquids fractionator in Paradis, Louisiana and (4) a
22-mile mixed NGL pipeline connecting the gas processing plant to the fractionator. Although
Discovery includes fractionation operations, which would normally fall within the NGL Services
segment, it is primarily engaged in gathering and processing and is managed as such. Hence, this
equity investment is considered part of the Gathering and Processing-Gulf segment.
Our Carbonate Trend gathering pipeline is an unregulated sour gas gathering pipeline
consisting of approximately 34 miles of pipeline off the coast of Alabama.
NGL Services. Our Conway storage facilities include three underground NGL storage facilities
in the Conway, Kansas area with a storage capacity of approximately 21 million barrels. The
facilities are connected via a series of pipelines. The storage facilities receive daily shipments
of a variety of products, including mixed NGLs and fractionated products. In addition to pipeline
connections, one facility offers truck and rail service.
Our Conway fractionation facility is located near Conway, Kansas and has a capacity of
approximately 107,000 bpd. We own a 50% undivided interest in these facilities representing
capacity of approximately 53,500 bpd. ConocoPhillips and ONEOK Partners, L.P. are the other owners.
We operate the facility pursuant to an operating agreement that extends until May 2011. The
fractionator separates mixed NGLs into five products: ethane, propane, normal butane, isobutane and
natural gasoline. Portions of these products are then transported and stored at our Conway storage
facilities.
Dropdown. Following the Dropdown, our business activities will be organized into two
reporting segments: Gas Pipeline and Midstream Gas & Liquids. Our current operations will be part
of the Midstream Gas & Liquids segment, and the newly acquired businesses will be reflected in Gas
Pipeline and Midstream Gas & Liquids as follows:
|
|
|
Gas Pipeline will include Transcontinental Gas Pipe Line Company, LLC (Transco) and
Northwest Pipeline GP (Northwest Pipeline), which own and operate a combined total of
approximately 13,900 miles of pipelines with a total annual throughput of approximately
2,700 trillion British thermal units of natural gas and peak-day delivery capacity of
approximately 12 million dekatherms of gas. Gas Pipeline will also hold interests in
joint venture interstate and intrastate natural gas pipeline systems including a 24.5%
interest in Gulfstream, which owns an approximately 745-mile pipeline with the capacity
to transport approximately 1.26 million dekatherms per day of natural gas. |
|
|
|
|
Midstream Gas & Liquids will include the contributed midstream entities with large
natural gas gathering, treating, and processing operations and oil transportation
pipelines. These facilities serve major producing basins in Colorado, Wyoming,
Pennsylvania, the Gulf Coast and the Gulf of Mexico. |
87
Note 4. Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include the accounts of
our parent company, Williams Partners L.P., the OLLC and our wholly owned subsidiaries and our
investments. We apply the equity method of accounting for our investments (see Note 7, Equity
Investments). We eliminated all intercompany accounts and transactions and reclassified certain
amounts to conform to the current classifications.
Use of Estimates. The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make estimates and
assumptions that affect the amounts reported in the consolidated financial statements and
accompanying notes. Actual results could differ from those estimates.
Estimates and assumptions which, in the opinion of management, are significant to the
underlying amounts included in the financial statements and for which it would be reasonably
possible that future events or information could change those estimates include:
|
|
|
loss contingencies; |
|
|
|
|
valuations of derivatives; |
|
|
|
|
impairment assessments of long-lived assets; |
|
|
|
|
environmental remediation obligations; and |
|
|
|
|
asset retirement obligations. |
These estimates are discussed further throughout the accompanying notes.
Proportional Accounting for the Conway Fractionator. No separate legal entity exists for the
fractionator. We hold a 50% undivided interest in the fractionator property, plant and equipment,
and we are responsible for our proportional share of the costs and expenses of the fractionator. As
operator of the facility, we incur the liabilities of the fractionator (except for certain fuel
costs purchased directly by one of the co-owners) and are reimbursed by the co-owners for their
proportional share of the total costs and expenses. Each co-owner is responsible for the marketing
of their proportional share of the fractionators capacity. Accordingly, we reflect our
proportionate share of the revenues and costs and expenses of the fractionator in the Consolidated
Statements of Income, and we reflect our proportionate share of the fractionator property, plant
and equipment in the Consolidated Balance Sheets. Liabilities in the Consolidated Balance Sheets
include those incurred on behalf of the co-owners with corresponding receivables from the
co-owners. Accounts receivable also includes receivables from our customers for fractionation
services.
Cash and Cash Equivalents. Cash and cash equivalents include amounts primarily invested in
funds with high-quality, short-term securities and instruments that are issued or guaranteed by the
U.S. government. These have maturities of three months or less when acquired.
Accounts Receivable. Accounts receivable are carried on a gross basis, with no discounting,
less an allowance for doubtful accounts. We do not recognize an allowance for doubtful accounts at
the time the revenue which generates the accounts receivable is recognized. We estimate the
allowance for doubtful accounts based on existing economic conditions, the financial condition of
our customers, and the amount and age of past due accounts. We consider receivables past due if
full payment is not received by the contractual due date. Past due accounts are generally written
off against the allowance for doubtful accounts only after all collection attempts have been
unsuccessful. The allowance for doubtful accounts at December 31, 2009 and 2008 was immaterial.
Product Imbalances. In the course of providing gathering, processing and treating services to
our customers, we realize over and under deliveries of our customers products and over and under
purchases of shrink replacement gas when our purchases vary from operational requirements. In
addition, in the course of providing gathering, processing, treating, fractionation and storage
services to our customers, we realize gains and losses due to (1) the product blending process at
the Conway fractionator, (2) the periodic emptying of storage caverns at Conway and (3)
inaccuracies inherent in the gas measurement process. These gains and losses impact our results of
operations and are included in operating and maintenance expense in the Consolidated Statements of
Income. These imbalance positions are reflected as product imbalance receivables and payables on
the Consolidated Balance Sheets. We value product imbalance receivables based on the lower of
current market prices or current cost of natural gas in the system or, in the case of our Conway
facilities, lower of the current market prices or weighted average value of NGLs. We value product
imbalance payables at
88
current market prices. The majority of Four Corners product imbalance settlements are through
in-kind arrangements whereby incremental volumes are delivered to a customer (in the case of an
imbalance payable) or received from a customer (in the case of an imbalance receivable). Such
in-kind deliveries are on-going and take place over several periods. In some cases, settlements of
imbalances build up over a period of time and are ultimately settled in cash and are generally
negotiated at values which approximate average market prices over a period of time. These gains and
losses impact our results of operations and are included in operating and maintenance expense in
the Consolidated Statements of Income.
Prepaid Expenses and Leasing Activities. Prepaid expenses include the unamortized balance of
minimum lease payments made to date under a right-of-way renewal agreement. We capitalize land and
right-of-way lease payments made at the time of initial construction or placement of plant and
equipment on leased land as part of the cost of the assets. Lease payments made in connection with
subsequent renewals or amendments of these leases are classified as prepaid expenses. The minimum
lease payments for the lease term, including any renewal, are expensed on a straight-line basis
over the lease term.
Derivative Instruments and Hedging Activities. We may utilize derivatives to manage a portion
of our commodity price risk. These instruments consist primarily of swap agreements and forward
contracts involving short- and long-term purchases and sales of a physical energy commodity. The
counterparty to these instruments is a Williams affiliate. We execute these transactions in
over-the-counter markets in which quoted prices exist for active periods. We report the fair value
of derivatives, except those for which the normal purchases and normal sales exception has been
elected, on the Consolidated Balance Sheets in other current assets, other accrued liabilities,
other assets or other noncurrent liabilities. We determine the current and noncurrent
classification based on the timing of expected future cash flows of individual contracts. We
report these amounts on a gross basis.
The accounting for changes in the fair value of derivatives depends on whether the derivative
has been designated in a hedging relationship and what type of hedging relationship it is. The
accounting for the change in fair value can be summarized as follows:
|
|
|
|
Derivative Treatment |
|
Accounting Method |
Normal purchases and normal sales exception
|
|
Accrual accounting |
Designated in qualifying hedging relationship
|
|
Hedge accounting |
All other derivatives
|
|
Mark-to-market accounting |
We have elected the normal purchases and normal sales exception for certain short- and
long-term purchases and sales of physical energy commodities. Under accrual accounting, any change
in the fair value of these derivatives is not reflected on the balance sheet since we made the
election of this exception at the inception of these contracts.
For a derivative to qualify for designation in a hedging relationship it must meet specific
criteria and we must maintain appropriate documentation. We establish hedging relationships
pursuant to our risk management policies. We evaluate the hedging relationships at the inception of
the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected
to remain, highly effective in achieving offsetting changes in fair value or cash flows
attributable to the underlying risk being hedged. We also regularly assess whether the hedged
forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer
expected to be highly effective, or if we believe the likelihood of occurrence of the hedged
forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and
future changes in the fair value of the derivative are recognized currently in other revenues.
For derivatives designated as a cash flow hedge, the effective portion of the change in fair
value of the derivative is reported in other comprehensive income (loss) and reclassified into
product sales revenues in the period in which the hedged item affects earnings. Any ineffective
portion of the derivatives change in fair value is recognized currently in product sales revenues.
Gains or losses deferred in accumulated other comprehensive loss associated with terminated
derivatives, derivatives that cease to be highly effective hedges, derivatives for which the
forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow
hedges that have been otherwise discontinued remain in accumulated other comprehensive loss until
the hedged item affects earnings. If it becomes probable that the forecasted transaction designated
as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in accumulated
other comprehensive loss is recognized in other revenues at that time. The change in likelihood of
a forecasted transaction is a judgmental decision that includes qualitative assessments made by
management.
Investments. At December 31, 2009, our ownership interests in Wamsutter consist of 100% of
the Class A limited liability company interests and 108 Class C units representing 69% of the Class
C ownership interests (collectively the Wamsutter Ownership Interests). At December 31, 2008, our
ownership interests consisted of 100% of the Class A interests and 20 Class C units representing
50% of the Class C interests. We account for our Wamsutter Ownership Interests and our 60%
investment in Discovery under the
89
equity method due to the voting provisions of their limited liability company agreements which
provide the other members of these entities significant participatory rights such that we do not
control these investments. Discoverys underlying equity exceeds the carrying value of our
investment at December 31, 2009 and 2008 due to an other-than-temporary impairment of that
investment that we recognized in 2004 and the acquisition of an additional interest in Discovery at
a cost that was less than the corresponding share of the underlying net assets of Discovery. These
differences are being amortized over the expected remaining life of the Discovery assets.
Property, Plant and Equipment. Property, plant and equipment is recorded at cost. We base the
carrying value of these assets on estimates, assumptions and judgments relative to capitalized
costs, useful lives and salvage values. Depreciation of property, plant and equipment is provided
on the straight-line basis over estimated useful lives. Expenditures for maintenance and repairs
are expensed as incurred. Expenditures that enhance the functionality or extend the useful lives of
the assets are capitalized. We remove the cost of property, plant and equipment sold or retired and
the related accumulated depreciation from the accounts in the period of sale or disposition. Gains
and losses on the disposal of property, plant and equipment are recorded in other (income) expense
net in the Consolidated Statements of Income.
We record an asset and a liability equal to the present value of each expected future asset
retirement obligation (ARO) at the time the liability is initially incurred, typically when the
asset is acquired or constructed. The ARO asset is depreciated in a manner consistent with the
depreciation of the underlying physical asset. We measure changes in the liability due to passage
of time by applying an interest method of allocation. This amount is recognized as an increase in
the carrying amount of the liability and as corresponding accretion expense.
Revenue Recognition. The nature of our businesses results in various forms of revenue
recognition. Our Gathering and Processing segments recognize (1) revenue from fee-based gathering
and processing of gas in the period the service is provided based on contractual terms and the
related natural gas and liquid volumes and (2) product sales revenue when the product has been
delivered. Our NGL Services segment recognizes (1) fractionation revenues when services have been
performed and product has been delivered, (2) storage revenues under prepaid contracted storage
capacity evenly over the life of the contract as services are provided and (3) product sales
revenue when the product has been delivered.
Impairment of Long-Lived Assets and Investments. We evaluate our long-lived assets of
identifiable business activities for impairment when events or changes in circumstances indicate
the carrying value of such assets may not be recoverable. When an indicator of impairment has
occurred, we compare our managements estimate of undiscounted future cash flows attributable to
the assets to the carrying value of the assets to determine whether the carrying value of the
assets is recoverable. We apply a probability-weighted approach to consider the likelihood of
different cash flow assumptions and possible outcomes. If the carrying value is not recoverable, we
determine the amount of the impairment recognized in the financial statements by estimating the
fair value of the assets and recording a loss for the amount that the carrying value exceeds the
estimated fair value.
We evaluate our investments for impairment when events or changes in circumstances indicate,
in our managements judgment, that the carrying value of such investments may have experienced an
other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our
estimate of fair value of the investment to the carrying value of the investment to determine
whether an impairment has occurred. If the estimated fair value is less than the carrying value and
we consider the decline in value to be other than temporary, the excess of the carrying value over
the estimated fair value is recognized in the financial statements as an impairment.
Judgments and assumptions are inherent in our managements estimate of undiscounted future
cash flows used to determine recoverability of an asset and the estimate of an assets or
investments fair value used to calculate the amount of impairment to recognize. The use of
alternate judgments and/or assumptions could result in the recognition of different levels of
impairment charges in the financial statements.
Environmental. Environmental expenditures that relate to current or future revenues are
expensed or capitalized based upon the nature of the expenditures. Expenditures that relate to an
existing contamination caused by past operations that do not contribute to current or future
revenue generation are expensed. Accruals related to environmental matters are generally determined
based on site-specific plans for remediation, taking into account our prior remediation experience,
and are not discounted. Environmental contingencies are recorded independently of any potential
claim for recovery.
90
Capitalized Interest. We capitalize interest during construction on major projects with
construction periods of at least three months and a total project cost in excess of $1.0 million.
Interest is capitalized based on our average interest rate on debt to the extent we incur interest
expense. Capitalized interest for the periods presented is immaterial.
Income Taxes. We are not a taxable entity for federal and state income tax purposes. The tax
on our net income is borne by the individual partners through the allocation of taxable income. Net
income for financial statement purposes may differ significantly from taxable income of unitholders
as a result of differences between the tax basis and financial reporting basis of assets and
liabilities and the taxable income allocation requirements under our partnership agreement. The
aggregated difference in the basis of our net assets for financial and tax reporting purposes
cannot be readily determined because information regarding each partners tax attributes in us is
not available to us.
Earnings Per Unit. We use the two-class method to calculate basic and diluted earnings per
unit whereby net income, adjusted for items specifically allocated to our general partner, is
allocated on a pro-rata basis between unitholders and our general partner. Basic and diluted
earnings per unit are based on the average number of common, Class B and subordinated units
outstanding. Basic and diluted earnings per unit are equivalent as there are no dilutive securities
outstanding.
Recent Accounting Standards. In January 2010, the Financial Accounting Standards Board (FASB)
issued Accounting Standards Update No. 2010-06, Fair Value Measurements and Disclosures (Topic
820) Improving Disclosures about Fair Value Measurements. This Update requires new disclosures
regarding the amount of transfers in or out of Level 1 and Level 2 fair value measurements along
with the reason for such transfers and also requires a greater level of disaggregation when
disclosing valuation techniques and inputs used in estimating Level 2 and Level 3 fair value
measurements. The disclosures will be required for reporting beginning in the first quarter 2010.
Also, beginning with the first quarter of 2011, the Update requires additional categorization of
items included in the rollforward of activity for Level 3 fair value measurements on a gross basis.
We are assessing the application of this Update to disclosures in our Consolidated Financial
Statements.
Note 5. Allocation of Net Income and Distributions
The allocation of net income between our general partner and limited partners, as reflected in
the Consolidated Statement of Partners Capital, for the years ended December 31, 2009, 2008 and
2007 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Allocation of net income to general partner: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
152,467 |
|
|
$ |
191,389 |
|
|
$ |
164,631 |
|
Net income applicable to pre-partnership operations allocated to general partner |
|
|
|
|
|
|
|
|
|
|
(71,426 |
) |
Beneficial conversion of Class B units* |
|
|
|
|
|
|
|
|
|
|
(5,308 |
) |
Reimbursable general and administrative and other costs charged directly to
general partner |
|
|
2,590 |
|
|
|
1,712 |
|
|
|
2,400 |
|
|
|
|
|
|
|
|
|
|
|
Income subject to 2% allocation of general partner interest |
|
|
155,057 |
|
|
|
193,101 |
|
|
|
90,297 |
|
General partners share of net income |
|
|
2.0 |
% |
|
|
2.0 |
% |
|
|
2.0 |
% |
|
|
|
|
|
|
|
|
|
|
General partners allocated share of net income before items directly allocable
to general partner interest |
|
|
3,101 |
|
|
|
3,861 |
|
|
|
1,806 |
|
Incentive distributions paid to general partner** |
|
|
7,272 |
|
|
|
23,767 |
|
|
|
5,046 |
|
Charges allocated directly to general partner |
|
|
(2,590 |
) |
|
|
(1,712 |
) |
|
|
(2,400 |
) |
Pre-partnership net income allocated to general partner interest |
|
|
|
|
|
|
|
|
|
|
71,426 |
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to general partner |
|
$ |
7,783 |
|
|
$ |
25,916 |
|
|
$ |
75,878 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
152,467 |
|
|
$ |
191,389 |
|
|
$ |
164,631 |
|
Net income allocated to general partner |
|
|
7,783 |
|
|
|
25,916 |
|
|
|
75,878 |
|
|
|
|
|
|
|
|
|
|
|
Net income allocated to limited partners |
|
$ |
144,684 |
|
|
$ |
165,473 |
|
|
$ |
88,753 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
The $5.3 million allocation of income to the Class B units reflects
the Class B unit beneficial conversion feature resulting from the May
2007 conversion of these units into common units on a one-for-one
basis. We computed the $5.3 million beneficial conversion feature as
the product of the 6,805,492 Class B units and the difference between
the fair value of a privately placed common unit on the date of
issuance ($36.59) and the issue price of a privately placed Class B
unit ($35.81). |
91
|
|
|
** |
|
In the calculation of basic and diluted net income per limited partner
unit, the net income allocated to the general partner includes IDRs
pertaining to the current reporting period, but paid in the subsequent
period. The net income allocated to the general partners capital
account reflects IDRs paid during the current reporting period. In
April 2009, Williams waived the IDRs related to 2009 distribution
periods. The IDRs paid in 2009 relate to the fourth-quarter 2008
distribution. |
Pursuant to the partnership agreement, we allocate income on a quarterly basis. Common and
subordinated unitholders shared equally, on a per-unit basis, in the net income allocated to
limited partners before the conversion of the subordinated units into common units in 2008.
The reimbursable general and administrative and other costs represent the costs charged
against our income that our general partner is required to reimburse us under the terms of the
omnibus agreement.
We paid or have authorized payment of the following cash distributions during 2007, 2008 and
2009 (in thousands, except for per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General Partner |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incentive |
|
|
|
|
Per Unit |
|
Common |
|
Subordinated |
|
Class B |
|
|
|
|
|
Distribution |
|
Total Cash |
Payment Date |
|
Distribution |
|
Units |
|
Units |
|
Units |
|
2% |
|
Rights |
|
Distribution |
2/14/2007 |
|
$ |
0.4700 |
|
|
$ |
12,010 |
|
|
$ |
3,290 |
|
|
$ |
3,198 |
|
|
$ |
390 |
|
|
$ |
603 |
|
|
$ |
19,491 |
|
5/15/2007 |
|
$ |
0.5000 |
|
|
$ |
12,777 |
|
|
$ |
3,500 |
|
|
$ |
3,403 |
|
|
$ |
421 |
|
|
$ |
965 |
|
|
$ |
21,066 |
|
8/14/2007 |
|
$ |
0.5250 |
|
|
$ |
16,989 |
|
|
$ |
3,675 |
|
|
$ |
|
|
|
$ |
447 |
|
|
$ |
1,267 |
|
|
$ |
22,378 |
|
11/14/2007 |
|
$ |
0.5500 |
|
|
$ |
17,799 |
|
|
$ |
3,850 |
|
|
$ |
|
|
|
$ |
487 |
|
|
$ |
2,211 |
|
|
$ |
24,347 |
|
2/14/2008 |
|
$ |
0.5750 |
|
|
$ |
26,321 |
|
|
$ |
4,025 |
|
|
$ |
|
|
|
$ |
706 |
|
|
$ |
4,231 |
|
|
$ |
35,283 |
|
5/15/2008 |
|
$ |
0.6000 |
|
|
$ |
31,665 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
758 |
|
|
$ |
5,499 |
|
|
$ |
37,922 |
|
8/14/2008 |
|
$ |
0.6250 |
|
|
$ |
32,984 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
811 |
|
|
$ |
6,765 |
|
|
$ |
40,560 |
|
11/14/2008 |
|
$ |
0.6350 |
|
|
$ |
33,513 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
832 |
|
|
$ |
7,272 |
|
|
$ |
41,617 |
|
2/13/2009 |
|
$ |
0.6350 |
|
|
$ |
33,513 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
832 |
|
|
$ |
7,272 |
|
|
$ |
41,617 |
|
5/15/2009 |
|
$ |
0.6350 |
|
|
$ |
33,513 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
684 |
|
|
$ |
|
|
|
$ |
34,197 |
|
8/14/2009 |
|
$ |
0.6350 |
|
|
$ |
33,513 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
684 |
|
|
$ |
|
|
|
$ |
34,197 |
|
11/13/2009 |
|
$ |
0.6350 |
|
|
$ |
33,513 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
684 |
|
|
$ |
|
|
|
$ |
34,197 |
|
2/12/2010(a) |
|
$ |
0.6350 |
|
|
$ |
33,513 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
684 |
|
|
$ |
|
|
|
$ |
34,197 |
|
|
|
|
(a) |
|
On February 12, 2010, we paid a cash distribution of $0.635 per unit
on our outstanding common units to unitholders of record on February
5, 2010. |
Note 6. Related Party Transactions
The employees of our operated assets and all of our general and administrative employees are
employees of Williams. Williams directly charges us for the payroll costs associated with the
operations employees. Williams carries the obligations for most employee-related benefits in its
financial statements, including the liabilities related to the employee retirement and medical
plans and paid time off. We charge back certain of the payroll costs associated with the operations
employees to the other Conway fractionator co-owners. Our share of those costs is charged to us
through affiliate billings and reflected in Operating and maintenance expense Affiliate in the
accompanying Consolidated Statements of Income.
We are charged for certain administrative expenses by Williams and its Midstream segment of
which we are a part. These charges are either directly identifiable or allocated to our assets.
Direct charges are for goods and services provided by Williams and Midstream at our request.
Allocated charges are either (1) charges allocated to the Midstream segment by Williams and then
reallocated from the Midstream segment to us or (2) Midstream-level administrative costs that are
allocated to us. These allocated corporate administrative expenses are based on a three-factor
formula, which considers revenues; property, plant and equipment; and payroll. We charge certain of
these costs back to the other Conway fractionator co-owners. Our share of direct and allocated
administrative expenses is reflected in General and administrative expense Affiliate in the
accompanying Consolidated Statements of Income. In managements estimation, the allocation
methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing
business incurred by Williams. Under the omnibus agreement, Williams gives us a quarterly credit
for general and administrative expenses. These amounts are reflected as capital contributions from
our general partner. The annual amounts of the credits are as follows: $2.4 million in 2007, $1.6
million in 2008 and $0.8 million in 2009. In 2009 we amended our omnibus agreement to increase the
aggregate amount of the credit we could receive related to certain general and administrative
expenses for
92
2009. Williams agreed to provide up to an additional $10.0 million credit, in addition to the
$0.8 million annual credit previously provided under the original omnibus agreement, to the extent
that 2009 non-segment profit general and administrative expenses exceeded $36.0 million (exclusive
of certain expenses related to the Dropdown). We recorded total general and administrative
expenses (including those expenses subject to the credit by Williams) as an expense, and we
recorded any credits as capital contributions from Williams. 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. The total general and
administrative credit received from Williams in 2009 was $2.6 million.
At December 31, 2009 and 2008 we have a contribution receivable from our general partner of
$0.8 million and $0.2 million, respectively, for amounts reimbursable to us under the omnibus
agreement. We net this receivable against Partners capital on the Consolidated Balance Sheets.
During 2009 and 2008, Williams reimbursed us $1.8 million and $1.6 million, respectively, for
capital expenditures in connection with Discoverys Tahiti pipeline lateral expansion project.
We purchase
natural gas for shrink replacement and fuel for Four Corners and the Conway
fractionator, including fuel on behalf of the Conway co-owners, from Williams Gas Marketing, Inc.
(WGM), a wholly owned subsidiary of Williams. Natural gas purchased for fuel is reflected in
Operating and maintenance expense Affiliate, and natural gas purchased for shrink replacement is
reflected in Product cost and shrink replacement Affiliate in the accompanying Consolidated
Statements of Income. These purchases are generally made at market
rates at the time of purchase or contract execution.
In connection with our 2005 initial public offering, Williams transferred to us a gas purchase
contract for the purchase of a portion of our fuel requirements at the Conway fractionator at a
market price not to exceed a specified level. We reflect the amortization of this contract in
Operating and maintenance expense Affiliate in the accompanying Consolidated Statements of
Income. This contract terminated on December 31, 2007.
Four Corners uses waste heat from a co-generation plant located adjacent to the Milagro
treating plant. Williams Flexible Generation, LLC, an affiliate of Williams, owns the co-generation
plant. Waste heat is required for the natural gas treating process, which occurs at Milagro. The
charge to us for the waste heat is based on the natural gas needed to generate the waste heat. We
purchase this natural gas from WGM. We reflect this cost in Operations and maintenance expense
Affiliate.
The operation of the Four Corners gathering system includes the routine movement of gas across
gathering systems. We refer to this activity as crosshauling. Crosshauling typically involves the
movement of some natural gas between gathering systems at established interconnect points to
optimize flow, reduce expenses or increase profitability. As a result, we must purchase gas for
delivery to customers at certain plant outlets and we have excess volumes to sell at other plant
outlets. WGM conducts these purchase and sales transactions at current market prices at each
location. These transactions are included in Product sales Affiliate and Product cost and shrink
replacement Affiliate on the Consolidated Statements of Income. Historically, WGM has not
charged us a fee for providing this service, but has occasionally benefited from price
differentials that historically existed from time to time between the plant outlets.
We sell the NGLs to which we take title on the Four Corners system to Williams NGL Marketing
LLC (WNGLM), a wholly owned subsidiary of Williams. We reflect revenues associated with these
activities as Product sales Affiliate on the Consolidated Statements of Income. We conduct these
transactions at current market prices for the products.
We periodically enter into financial swap contracts with WGM and WNGLM to hedge forecasted NGL
sales. These contracts are priced based on market rates at the time of execution and are reflected
in Other accrued liabilities on the Consolidated Balance Sheets.
One of our major customers is Williams Production Company (WPC), a wholly owned subsidiary of
Williams. WPC is one of the largest natural gas producers in the San Juan Basin and we provide
natural gas gathering, treating and processing services to WPC under several contracts. One of the
contracts with WPC is adjusted annually based on changes in the average price of natural gas. We
reflect revenues associated with these activities in the Gathering and processing Affiliate on
the Consolidated Statements of Income.
We sell Conways surplus propane and other NGLs to WNGLM, which takes title to the product and
resells it, for its own account, to end users. Revenues associated with these activities are
reflected as Product sales Affiliate on the Consolidated Statements of Income. Correspondingly,
we purchase ethane and other NGLs for Conway from WNGLM to replenish
deficit product imbalance
positions. We conduct transactions between us and WNGLM at current market prices for the products.
93
Under our stand-alone cash management program, we reflect amounts owed by us or to us by
Williams or its subsidiaries as Accounts receivable Affiliate or Accounts payable Affiliate
in the accompanying Consolidated Balance Sheets.
Note 7. Equity Investments
Wamsutter
The interests in Wamsutter not held by us are held by a Williams affiliate, and Williams is
the operator of Wamsutter. As such, Williams is reimbursed on a monthly basis for all direct and
indirect expenses it incurs on behalf of Wamsutter including Wamsutters allocable share of general
and administrative costs.
Wamsutter purchases natural gas for fuel and shrink replacement from WGM and sells NGLs to
WNGLM. Wamsutter conducts these transactions at current market prices for the products.
Wamsutter participates in Williams cash management program and, therefore, carries no cash
balances.
Our consolidated financial statements and notes reflect our Wamsutter Ownership Interests,
which we acquired in December 2007. However, certain cash transactions resulting from Wamsutters
participation in Williams cash management program, which occurred between Wamsutter and Williams
prior to this acquisition, are not reflected in our Consolidated Statements of Cash Flows even
though these transactions affect the carrying value of our Wamsutter Ownership Interests. These
transactions were omitted from our Consolidated Statements of Cash Flows because they did not
affect our cash. Our Consolidated Statement of Partners Capital reflects the total of these
transactions as an adjustment in the basis of our investment in Wamsutter.
The Wamsutter LLC Agreement provides for quarterly distributions of available cash beginning
in March 2008. Available cash is defined as cash generated from Wamsutters business less reserves
that are necessary or appropriate to provide for the conduct of its business and to comply with
applicable law and or debt instrument or other agreement to which it is a party.
Wamsutter distributes its available cash as follows:
|
|
|
First, an amount equal to $17.5 million per quarter to the holder of the Class A
membership interests. We currently own 100% of the Class A interests; |
|
|
|
|
Second, an amount equal to the amount the distribution on the Class A membership
interests in prior quarters of the current distribution year was less than $17.5 million per
quarter to the holder of the Class A membership interests; and |
|
|
|
|
Third, 5% of remaining available cash shall be distributed to the holder of the Class A
membership interests and 95% shall be distributed to the holders of the Class C units, on a
pro rata basis. At December 31, 2009 and 2008, we owned 69% and 50% of the Class C units,
respectively. |
In addition, to the extent that at the end of the fourth quarter of a distribution year, the
Class A member has received less than $70.0 million under the first and second bullets above, the
Class C members will be required to repay any distributions they received in that distribution year
such that the Class A member receives $70.0 million for that distribution year. If this repayment
is insufficient to result in the Class A member receiving $70.0 million, the shortfall will not
carry forward to the next distribution year. The distribution year for Wamsutter commences each
year on December 1 and ends on November 30.
Wamsutter allocates net income (equity earnings) to us based upon the allocation,
distribution, and liquidation provisions of its limited liability company agreement applied as
though liquidation occurs at book value. In general, the agreement allocates income in a manner
that will maintain capital account balances reflective of the amounts each membership interest
would receive if Wamsutter were dissolved and liquidated at carrying value. The income allocation
for the quarterly periods during a year reflects the preferential rights of the Class A member to
any distributions made to the Class C member until the Class A member has received $70.0 million in
distributions for the year. The Class B member receives no income or loss allocation. As the owner
of 100% of the Class A membership interest, we will receive 100% of Wamsutters annual net income
up to $70.0 million. Income in excess of $70.0 million will be shared between the Class A member
and Class C member. For annual periods in which Wamsutters net income exceeds $70.0 million, this
will result in a higher allocation of equity earnings to us early in the year and a lower
allocation of equity earnings to us later in the year. Wamsutters net income allocation does not
affect the amount of available cash it distributes for any quarter. All
94
of the 2009 net income was allocated to the Class A member. The following table presents the
allocation of Wamsutters 2008 and 2009 net income to its unitholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wamsutter |
|
Wamsutter Net Income Allocation 2008 |
|
Net Income |
|
Net income for December 1, 2007 November 30, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
110.1 |
|
Less net income allocated for transition support contribution |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7.6 |
) |
Less net income for December 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income for 2008 allocation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
95.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our Share |
|
|
Other |
|
|
Wamsutter |
|
|
|
Class A |
|
|
Class C |
|
|
WPZ Total |
|
|
Class C |
|
|
Net Income |
|
|
|
|
|
|
|
|
|
|
|
(Millions) |
|
|
|
|
|
|
|
|
|
Allocation up to $70 million (excluding December 2007 allocation) |
|
$ |
62.6 |
|
|
$ |
|
|
|
$ |
62.6 |
|
|
$ |
|
|
|
$ |
62.6 |
|
Allocation of net income over $70 million |
|
|
2.1 |
|
|
|
15.2 |
|
|
|
17.3 |
|
|
|
15.2 |
|
|
|
32.5 |
|
Income allocation for transition support contribution |
|
|
7.6 |
|
|
|
|
|
|
|
7.6 |
|
|
|
|
|
|
|
7.6 |
|
December 2008 income allocation |
|
|
1.0 |
|
|
|
|
|
|
|
1.0 |
|
|
|
|
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
$ |
73.3 |
|
|
$ |
15.2 |
|
|
$ |
88.5 |
|
|
$ |
15.2 |
|
|
$ |
103.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wamsutter |
|
Wamsutter Net Income Allocation 2009 |
|
Net Income |
|
Net income for December 1, 2008 November 30, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
77.3 |
|
Less net income allocated for transition support contribution |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9.7 |
) |
Less net income for December 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income for 2009 allocation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
66.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our Share |
|
|
Other |
|
|
Wamsutter |
|
|
|
Class A |
|
|
Class C |
|
|
WPZ Total |
|
|
Class C |
|
|
Net Income |
|
|
|
|
|
|
|
|
|
|
|
(Millions) |
|
|
|
|
|
|
|
|
|
Allocation up to $70 million (excluding December 2008 allocation) |
|
$ |
66.6 |
|
|
$ |
|
|
|
$ |
66.6 |
|
|
$ |
|
|
|
$ |
66.6 |
|
Income allocation for transition support contribution |
|
|
9.7 |
|
|
|
|
|
|
|
9.7 |
|
|
|
|
|
|
|
9.7 |
|
December 2009 income allocation |
|
|
7.8 |
|
|
|
|
|
|
|
7.8 |
|
|
|
|
|
|
|
7.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals |
|
$ |
84.1 |
|
|
$ |
|
|
|
$ |
84.1 |
|
|
$ |
|
|
|
$ |
84.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wamsutters LLC agreement provides that it receive a transition support payment related to a
cap on general and administrative expenses from its Class B membership interest each quarter
through 2012. Although the full amount of expenses is recorded by Wamsutter, this support increases
the cash distributable and income allocable to the Class A membership interest.
During 2009 and 2008, we made capital contributions of $1.0 million and $3.7 million,
respectively, to Wamsutter for capital projects and received total cash distributions of $80.5
million and $91.5 million, respectively, from Wamsutter, as well as transition support payments of
$9.7 million and $7.6 million, respectively.
During 2009, Wamsutter issued an additional 88.5 and 28.8 Class C units to us and Williams,
respectively, related to the funding of expansion capital expenditures placed in service during
2009 and 2008. As of December 31, 2009, Williams contributed an additional $82.9 million for an
expansion capital project that is expected to be placed in service during 2010. Williams
contributed $28.8 million for that project in 2008. Williams will receive Class C units related to
these expenditures after the assets are placed in service.
Following the February 2010 Dropdown, we own 100% of Wamsutter and consolidate them.
95
The summarized financial position and results of operations for 100% of Wamsutter are
presented below (in thousands).
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Current assets |
|
$ |
21,691 |
|
|
$ |
17,147 |
|
Property, plant and equipment |
|
|
408,429 |
|
|
|
318,072 |
|
Non-current assets |
|
|
3,071 |
|
|
|
468 |
|
Current liabilities |
|
|
(29,220 |
) |
|
|
(16,960 |
) |
Non-current liabilities |
|
|
(4,846 |
) |
|
|
(4,353 |
) |
|
|
|
|
|
|
|
Members capital |
|
$ |
399,125 |
|
|
$ |
314,374 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Product sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
95,734 |
|
|
$ |
134,776 |
|
|
$ |
93,744 |
|
Third-party |
|
$ |
15,348 |
|
|
|
27,384 |
|
|
|
7,447 |
|
Gathering and processing services |
|
|
79,523 |
|
|
|
68,670 |
|
|
|
67,904 |
|
Other revenues |
|
|
5,282 |
|
|
|
8,704 |
|
|
|
6,214 |
|
Costs and expenses excluding depreciation and accretion: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
51,478 |
|
|
|
74,388 |
|
|
|
46,834 |
|
Third-party |
|
|
38,122 |
|
|
|
40,200 |
|
|
|
32,666 |
|
Depreciation and accretion |
|
|
22,235 |
|
|
|
21,182 |
|
|
|
18,424 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
84,052 |
|
|
$ |
103,764 |
|
|
$ |
77,385 |
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest equity earnings |
|
$ |
84,052 |
|
|
$ |
88,538 |
|
|
$ |
76,212 |
|
|
|
|
|
|
|
|
|
|
|
Discovery Producer Services
Williams is the operator of Discovery. Discovery reimburses Williams for actual operations
related payroll and employee benefit costs incurred on its behalf. In addition, Discovery pays
Williams a monthly operations and management fee to cover the cost of accounting services, computer
systems and management services provided to it. Discovery also has an agreement with Williams
pursuant to which (1) Discovery purchases a portion of the natural gas from WGM to meet its fuel
and shrink replacement needs at its processing plant and (2) WNGLM purchases the NGLs and excess
natural gas to which Discovery takes title.
Our consolidated financial statements and notes reflect the additional 20% interest in
Discovery which we acquired in mid-2007. Prior to this acquisition, Discovery distributed $9
million of cash to Williams that related to the additional 20% interest. This distribution is not
reflected in our Consolidated Statements of Cash Flows even though these distributions affect the
carrying value of our investment in Discovery because they did not affect our cash. Our
Consolidated Statement of Partners Capital reflects the total of these distributions as an
adjustment in the basis of our investment in Discovery.
During 2009 and 2008, we contributed $13.2 million and $5.7 million, respectively to Discovery
for capital projects.
During 2009, 2008 and 2007 we received total cash distributions of $32.1 million, $56.4
million and $35.5 million, respectively, from Discovery for the 60% interest we currently own or
the 40% interest we owned at the time of distribution.
The summarized financial position and results of operations for 100% of Discovery are
presented below (in thousands).
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Current assets |
|
$ |
39,454 |
|
|
$ |
50,978 |
|
Non-current restricted cash |
|
|
|
|
|
|
3,470 |
|
Property, plant and equipment |
|
|
364,932 |
|
|
|
370,482 |
|
Current liabilities |
|
|
(16,708 |
) |
|
|
(45,234 |
) |
Non-current liabilities |
|
|
(23,355 |
) |
|
|
(19,771 |
) |
|
|
|
|
|
|
|
Members capital |
|
$ |
364,323 |
|
|
$ |
359,925 |
|
|
|
|
|
|
|
|
96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
115,354 |
|
|
$ |
209,994 |
|
|
$ |
220,960 |
|
Third-party |
|
|
45,665 |
|
|
|
31,254 |
|
|
|
39,712 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
35,815 |
|
|
|
96,912 |
|
|
|
101,581 |
|
Third-party |
|
|
88,160 |
|
|
|
110,508 |
|
|
|
113,207 |
|
Interest income |
|
|
(31 |
) |
|
|
(650 |
) |
|
|
(1,799 |
) |
Foreign exchange (gain) loss |
|
|
168 |
|
|
|
78 |
|
|
|
(388 |
) |
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
36,907 |
|
|
$ |
34,400 |
|
|
$ |
48,071 |
|
|
|
|
|
|
|
|
|
|
|
Discovery investment income: |
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners interest equity earnings |
|
$ |
23,023 |
|
|
$ |
20,641 |
|
|
$ |
28,842 |
|
Business interruption insurance proceeds (a) |
|
|
4,220 |
|
|
|
1,716 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discovery investment income |
|
$ |
27,243 |
|
|
$ |
22,357 |
|
|
$ |
28,842 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Proceeds received due to hurricane damage sustained in 2008. |
Note 8. Other (Income) Expense
Other (income) expense net reflected on the Consolidated Statements of Income consists of
the following items (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Involuntary conversion gains |
|
$ |
(4,034 |
) |
|
$ |
(11,604 |
) |
|
$ |
|
|
Impairment of Carbonate Trend pipeline |
|
|
|
|
|
|
6,187 |
|
|
|
10,406 |
|
Other |
|
|
(99 |
) |
|
|
1,894 |
|
|
|
1,689 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(4,133 |
) |
|
$ |
(3,523 |
) |
|
$ |
12,095 |
|
|
|
|
|
|
|
|
|
|
|
Involuntary conversion gains. On November 28, 2007, the Ignacio gas processing plant
sustained significant damage from a fire. The involuntary conversion gains result from insurance
proceeds received to replace the capital assets destroyed by the fire in excess of the net book
value of those assets being replaced.
Impairment of Carbonate Trend Pipeline. During 2007 and again in 2008, we determined that the
carrying value of this pipeline, included in our Gathering and Processing Gulf segment, may not
be recoverable because of forecasted declining cash flows. As a result, we recognized impairment
charges of $6.2 million and $10.4 million in 2008 and 2007, respectively, to reduce the carrying
value to managements estimate of fair value. As of December 31, 2008, the carrying value of this
asset was written down to zero. We estimated fair value using discounted cash flow projections.
Note 9. Property, Plant and Equipment
Property, plant and equipment, at cost, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
Estimated |
|
|
|
2009 |
|
|
2008 |
|
|
Depreciable Lives |
|
|
|
(In thousands) |
|
Land and right of way |
|
$ |
43,650 |
|
|
$ |
43,246 |
|
|
0-30 years |
Gathering pipelines and related equipment |
|
|
850,067 |
|
|
|
838,214 |
|
|
20-30 years |
Processing plants and related equipment |
|
|
195,474 |
|
|
|
183,222 |
|
|
30 years |
Fractionation plant and related equipment |
|
|
16,681 |
|
|
|
16,540 |
|
|
30 years |
Storage plant and related equipment |
|
|
96,347 |
|
|
|
87,803 |
|
|
30 years |
Buildings and other equipment |
|
|
77,228 |
|
|
|
77,287 |
|
|
3-45 years |
Construction work in progress |
|
|
17,351 |
|
|
|
18,841 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment |
|
|
1,296,798 |
|
|
|
1,265,153 |
|
|
|
|
|
Accumulated depreciation |
|
|
662,565 |
|
|
|
624,633 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment |
|
$ |
634,233 |
|
|
$ |
640,520 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation expense for 2009, 2008 and 2007 was $42.4 million, $42.7 million and $42.2
million, respectively.
97
Our asset retirement obligations relate to gas processing and compression facilities located
on leased land, wellhead connections on federal land, underground storage caverns and the
associated brine ponds and offshore pipelines. At the end of the useful life of each respective
asset, we are legally or contractually obligated to remove certain surface equipment and cap
certain gathering pipelines at the wellhead connections, properly abandon the storage caverns and
offshore pipelines, empty the brine ponds and restore the surface, and remove any related surface
equipment.
A rollforward of our asset retirement obligation for 2009 and 2008 is presented below.
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Balance, January 1 |
|
$ |
13,465 |
|
|
$ |
8,743 |
|
Liabilities incurred during the period |
|
|
|
|
|
|
355 |
|
Liabilities settled during the period. |
|
|
|
|
|
|
|
|
Accretion expense |
|
|
972 |
|
|
|
752 |
|
Estimate revisions |
|
|
361 |
|
|
|
3,615 |
|
|
|
|
|
|
|
|
Balance, December 31 |
|
$ |
14,798 |
|
|
$ |
13,465 |
|
|
|
|
|
|
|
|
Note 10. Major Customers and Concentrations of Credit Risk
Major customers
Our largest customer, on a percentage of revenues basis, is WNGLM, which purchases and resells
substantially all of the NGLs to which we take title. WNGLM accounted for 37%, 49% and 49% of
revenues in 2009, 2008 and 2007, respectively. The remaining largest customer, ConocoPhillips, from
our Gathering and Processing West segment, accounted for 23%, 17% and 22% of revenues in 2009,
2008 and 2007, respectively.
Concentrations of Credit Risk
Our cash equivalents are primarily invested in funds with high-quality, short-term securities
and instruments that are issued or guaranteed by the U.S. government. The counterparties to our
derivative contracts are affiliates of Williams, which minimized our credit risk exposure.
The following table summarizes the concentration of accounts receivable by service and
segment.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Gathering and Processing West: |
|
|
|
|
|
|
|
|
Natural gas gathering and processing |
|
$ |
15,063 |
|
|
$ |
14,516 |
|
Other |
|
|
897 |
|
|
|
801 |
|
Gathering and Processing Gulf: |
|
|
|
|
|
|
|
|
Natural gas gathering |
|
|
205 |
|
|
|
203 |
|
NGL Services: |
|
|
|
|
|
|
|
|
Fractionation services |
|
|
839 |
|
|
|
1,025 |
|
Amounts due from fractionator partners |
|
|
650 |
|
|
|
1,439 |
|
Storage |
|
|
1,102 |
|
|
|
681 |
|
Other |
|
|
35 |
|
|
|
34 |
|
Accrued interest and other |
|
|
|
|
|
|
499 |
|
Affiliate |
|
|
22,635 |
|
|
|
11,652 |
|
|
|
|
|
|
|
|
|
|
$ |
41,426 |
|
|
$ |
30,850 |
|
|
|
|
|
|
|
|
At December 31, 2009 and 2008, a substantial portion of our accounts receivable results from
product sales and gathering and processing services provided to two of our customers. One customer
is an affiliate of Williams which minimizes our credit risk exposure. The remaining customer may
impact our overall credit risk either positively or negatively, in that this entity may be affected
by industry-wide changes in economic or other conditions. As a general policy, collateral is not
required for receivables, but customers financial conditions and credit worthiness are evaluated
regularly. Our credit policy and the relatively short duration of receivables mitigate the risk of
uncollectible receivables.
98
Note 11. Long-Term Debt, Credit Facilities and Leasing Activities
Long-Term Debt
Long-term debt at December 31, 2009 and 2008 includes the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
|
December 31, |
|
|
|
Rate |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
(Millions) |
|
Credit agreement term loan, adjustable rate, due 2012 |
|
|
(a |
) |
|
$ |
250.0 |
|
|
$ |
250.0 |
|
Senior unsecured notes, fixed rate, due 2017 |
|
|
7.25 |
% |
|
|
600.0 |
|
|
|
600.0 |
|
Senior unsecured notes, fixed rate, due 2011 |
|
|
7.50 |
% |
|
|
150.0 |
|
|
|
150.0 |
|
|
|
|
|
|
|
|
|
|
|
|
Total Long-term debt |
|
|
|
|
|
$ |
1,000.0 |
|
|
$ |
1,000.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
1.23% at December 31, 2009 |
The terms of the senior unsecured notes are governed by indentures that contain covenants
that, among other things, limit (1) our ability and the ability of our subsidiaries to incur
indebtedness or liens securing indebtedness and (2) mergers, consolidations and transfers of all or
substantially all of our properties or assets. The indentures also contain customary events of
default, upon which the trustee or the holders of the senior unsecured notes may declare all
outstanding senior unsecured notes to be due and payable immediately.
We may redeem the senior unsecured notes at our option in whole or in part at any time or from
time to time prior to the respective maturity dates, at a redemption price per note equal to the
sum of (1) the then outstanding principal amount thereof, plus (2) accrued and unpaid interest, if
any, to the redemption date (subject to the right of holders of record on the relevant record date
to receive interest due on an interest payment date that is on or prior to the redemption date),
plus (3) a specified make-whole premium (as defined in the indenture). Additionally, upon a
change of control (as defined in the indenture), each holder of the senior unsecured notes will
have the right to require us to repurchase all or any part of such holders senior unsecured notes
at a price equal to 101% of the principal amount of the senior unsecured notes plus accrued and
unpaid interest, if any, to the date of settlement. Except upon a change of control as described in
the prior sentence, we are not required to make mandatory redemption or sinking fund payments with
respect to the senior unsecured notes or to repurchase the senior unsecured notes at the option of
the holders.
Cash payments for interest during 2009, 2008 and 2007 were $57.9 million, $65.5 million and
$38.8 million, respectively.
In connection with the February 2010 Dropdown, we issued
$3.5 billion face value of senior unsecured
notes and assumed $2.0 billion face value of outstanding debt of Transco, Northwest Pipeline and Williams
Laurel Mountain, LLC as follows:
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
|
|
|
|
|
Rate |
|
|
Millions |
|
Senior unsecured notes, fixed rate, due 2015 |
|
|
3.80 |
% |
|
$ |
750.0 |
|
Senior unsecured notes, fixed rate, due 2020 |
|
|
5.25 |
% |
|
|
1,500.0 |
|
Senior unsecured notes, fixed rate, due 2040 |
|
|
6.30 |
% |
|
|
1,250.0 |
|
|
|
|
|
|
|
|
|
Total debt
issuance at face value |
|
|
|
|
|
|
3,500.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transco, 6.05% to 8.875%, payable through 2026 |
|
|
7.24 |
% |
|
|
1,282.5 |
|
Northwest, 5.95% to 7.125%, payable through 2025 |
|
|
6.39 |
% |
|
|
695.0 |
|
Williams Laurel Mountain, LLC, 8.00% to 10.00%, payable through 2012 |
|
|
8.00 |
% |
|
|
23.8 |
|
|
|
|
|
|
|
|
|
Total debt
assumed at face value, including current portion |
|
|
|
|
|
|
2,001.3 |
|
|
|
|
|
|
|
|
|
Total additional long-term debt at face value, including current portion |
|
|
|
|
|
$ |
5,501.3 |
|
|
|
|
|
|
|
|
|
In
connection with the issuance of the $3.5 billion notes discussed
above, we entered into
registration rights agreements with the initial purchasers of the
notes. We are obligated to file a
registration statement for an offer to exchange the notes for a new issue of substantially
identical notes registered under the Securities Act of 1933, as amended, within 180 days from
closing and use its commercially reasonable efforts to cause the registration statement to be
declared effective within 270 days after closing and to consummate the exchange offers within 30
business days after such effective date. We may also be required to provide a shelf
99
registration
statement to cover resales of the notes under certain circumstances.
If we fail to fulfill these obligations, additional interest will accrue on the affected securities. The rate
of additional interest will be 0.25% per annum on the principal amount of the affected
securities for the first 90-day period immediately following the occurrence of default, increasing
by an additional 0.25% per annum with respect to each subsequent 90-day period thereafter,
up to a maximum amount for all such defaults of 0.5% annually. Following the cure of any
registration defaults, the accrual of additional interest will cease.
Credit Facilities
At December 31, 2009, we had a $450.0 million senior unsecured credit agreement (Credit Agreement)
with Citibank, N.A. as administrative agent, comprised initially of a $200.0 million revolving credit
facility available for borrowings and letters of credit and a $250.0 million term loan. We expect that our
ability to borrow under this facility is reduced by $12.0 million due to the bankruptcy of a participating
bank. However, debt covenants may restrict the full use of the credit facility. We must repay
borrowings under the Credit Agreement by December 11, 2012. At December 31, 2009 and 2008, we
had a $250.0 million term loan outstanding under the term loan provisions and no other amounts
outstanding under the Credit Agreement. As a result of the second-quarter 2009 Fitch Ratings
downgrade of our senior unsecured debt rating from BB+ to BB, our applicable margin on the $250.0
million term loan increased 0.25% to 1.0% and the commitment fee on the unused capacity of our
revolver increased 0.05% to 0.175%.
In connection with the Dropdown, we terminated the Credit Agreement and entered into a new $1.75
billion three-year senior unsecured revolving credit facility (New Credit Facility) with Transco and
Northwest Pipeline, as co-borrowers, and Citibank, N.A. as the administrative agent, and certain other
lenders named therein. The full amount of the New Credit Facility is available to us,
to the extent not otherwise utilized by Transco and Northwest Pipeline, and may be
increased by up to an additional $250 million. Transco and Northwest Pipeline are each able to borrow
up to $400 million under the New Credit Facility to the extent not otherwise utilized by us. At closing,
we borrowed $250 million under the New Credit Facility to repay the $250 million term loan
outstanding under the Credit Agreement.
Interest on borrowings under the New Credit
Facility is payable at rates per annum equal to,
at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.s adjusted base
rate plus the applicable margin or (2) a periodic fixed rate equal to LIBOR plus the applicable
margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5%, (ii)
Citibank N.A.s publicly announced base rate and (iii) one-month LIBOR plus 1.0%. We pay a
commitment fee (currently 0.5%) based on the unused portion of the New Credit Facility. The
applicable margin and the commitment fee are determined by reference to a pricing schedule based on
a borrowers senior unsecured debt ratings.
The New Credit Facility contains various covenants that limit, among other things, a
borrowers and its respective subsidiaries ability to incur indebtedness, grant certain liens
supporting indebtedness, merge, or consolidate, sell all or substantially all of its assets, enter
into certain affiliate transactions, make certain distributions
during an event of default and allow
any material change in the nature of its business.
In addition, we are required to maintain a ratio of debt to EBITDA (each as defined in the New
Credit Facility) of no greater than 5.00 to 1.00 for us and our consolidated subsidiaries. For each
of Transco and Northwest Pipeline and their respective consolidated subsidiaries, the ratio of debt
to capitalization (defined as net worth plus debt) is not permitted to be greater than 55%. Each
of the above ratios will be tested, beginning June 30, 2010, at the end of each fiscal quarter, and
the debt to EBITDA ratio will be measured on a rolling four-quarter basis.
The New Credit Facility includes customary events of default, including events of default
relating to non-payment of principal, interest or fees, inaccuracy of representations and
warranties in any material respect when made or when deemed made, violation of covenants,
cross-payment defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied
judgments and a change of control. If an event of default with respect to a borrower occurs under
the New Credit Facility, the lenders will be able to terminate the commitments for all borrowers
and accelerate the maturity of the loans of the defaulting borrower under the New Credit Facility
and exercise other rights and remedies.
We also had a $20.0 million revolving credit facility with Williams as the lender. The
facility was available exclusively to fund working capital requirements. We paid a commitment fee
to Williams on the unused portion of the credit facility of 0.125% annually. As of December 31,
2009, we had no outstanding borrowings under the working capital credit facility. This facility
was terminated in connection with the Dropdown.
100
Leasing Activities
We lease the land on which a significant portion of Four Corners pipeline assets are located.
The primary landowners are the Bureau of Land Management (BLM) and several Indian tribes. The BLM
leases are for thirty years with renewal options. A significant Indian tribal lease in Colorado
will expire at the end of 2022.
Under our right-of-way agreement with the Jicarilla Apache Nation (JAN), beginning in 2010, we
will make annual payments of approximately $7.5 million and an additional annual payment which
varies depending on the prior years per-unit NGL margins and the volume of gas gathered by our
gathering facilities subject to the agreement. Depending primarily on the per-unit NGL margins for
any given year, the additional annual payments could approximate the fixed amount. Additionally, on
April 1, 2014, the JAN will have the option to acquire up to a 50% joint venture interest for 20
years in certain of Four Corners assets existing at the time the option is exercised. The joint
venture option includes Four Corners gathering assets subject to the agreement and portions of
Four Corners gathering and processing assets located in an area adjacent to the JAN lands. If the
JAN selects the joint venture option, the value of the assets contributed by each party to the
joint venture will be based upon a market value determined by a neutral third party at the time the
joint venture is formed.
We also lease other minor office, warehouse equipment and automobiles under non-cancelable
leases. The future minimum annual rentals under these non-cancelable leases as of December 31, 2009
are payable as follows:
|
|
|
|
|
|
|
(In thousands) |
|
2010 |
|
$ |
13,849 |
|
2011 |
|
|
8,149 |
|
2012 |
|
|
7,823 |
|
2013 |
|
|
7,571 |
|
2014 and thereafter |
|
|
112,920 |
|
|
|
|
|
|
|
$ |
150,312 |
|
|
|
|
|
Total rent expense was $13.2 million, $24.4 million and $21.2 million for 2009, 2008 and 2007,
respectively.
Note 12. Partners Capital
At December 31, 2009, the public held 76% of our total units outstanding, and affiliates of
Williams held the remaining units.
In connection with the Dropdown, we issued 203 million Class C limited partnership units to
Williams. The Class C units are identical to our common limited partnership units except that for
the first quarter of 2010 they will receive a prorated quarterly distribution since they were not
outstanding during the full quarterly period. The Class C units will automatically convert into
our common limited partnership units following the record date for the first-quarter 2010
distribution.
Limited Partners Rights
Significant rights of the limited partners include the following:
|
|
|
Right to receive distributions of available cash within 45 days after the end of each
quarter. |
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|
|
No limited partner shall have any management control over our business and affairs; the
general partner shall conduct, direct and manage our activities. |
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|
|
|
The general partner may be removed if such removal is approved by the unitholders holding
at least 66 2/3% of the outstanding units voting as a single class, including units held by
our general partner and its affiliates. |
Subordinated Units
Our subordination period ended on February 19, 2008 when we met the requirements for early
termination pursuant to our partnership agreement. As a result of the termination, the 7,000,000
outstanding subordinated units owned by four subsidiaries of Williams converted one-for-one to
common units and now participate pro rata with the other common units in distributions of available
cash.
101
Class B Units
On May 21, 2007, the Class B units were converted into common units on a one-for-one basis and
now participate pro rata with the other common units in distributions of available cash.
Incentive Distribution Rights
Our general partner is entitled to incentive distributions if the amount we distribute to
unitholders with respect to any quarter exceeds specified target levels shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General |
Quarterly Distribution Target Amount (per unit) |
|
Unitholders |
|
Partner |
Minimum quarterly distribution of $0.35 |
|
|
98 |
% |
|
|
2 |
% |
Up to $0.4025 |
|
|
98 |
|
|
|
2 |
|
Above $0.4025 up to $0.4375 |
|
|
85 |
|
|
|
15 |
|
Above $0.4375 up to $0.5250 |
|
|
75 |
|
|
|
25 |
|
Above $0.5250 |
|
|
50 |
|
|
|
50 |
|
In April 2009, Williams waived the incentive distribution rights related to 2009 distribution
periods.
In the event of liquidation, all property and cash in excess of that required to discharge all
liabilities will be distributed to the unitholders and our general partner in proportion to their
capital account balances, as adjusted to reflect any gain or loss upon the sale or other
disposition of our assets in liquidation.
Issuances of Additional Partnership Securities
Our partnership agreement allows us to issue additional partnership securities for any
partnership purpose at any time and from time to time for consideration and on terms and conditions
as our general partner determines, all without the approval of any limited partners.
Note 13. Fair Value Measurements
Fair value is the amount received to sell an asset or the amount paid to transfer a liability
in an orderly transaction between market participants (an exit price) at the measurement date. Fair
value is a market-based measurement from the perspective of a market participant. We use market
data or assumptions that market participants would use in pricing the asset or liability, including
assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be
readily observable, market corroborated, or unobservable. We apply both market and income
approaches for recurring fair value measurements using the best available information while
utilizing valuation techniques that maximize the use of observable inputs and minimize the use of
unobservable inputs.
Effective January 1, 2009, we applied new fair value accounting requirements to nonfinancial
assets and nonfinancial liabilities that are not recognized or disclosed at fair value on a
recurring basis. We applied a prospective transition as we did not have any financial instrument
transactions that required a cumulative-effect adjustment to beginning equity. This adoption did
not materially impact our Consolidated Financial Statements.
The fair-value hierarchy prioritizes the inputs used to measure fair value. The hierarchy
gives the highest priority to quoted prices in active markets for identical assets or liabilities
(Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We
classify fair-value balances based on the observability of those inputs. The three levels of the
fair-value hierarchy are as follows:
|
|
|
Level 1 Quoted prices in active markets for identical assets or liabilities that we
have the ability to access. Active markets are those in which transactions for the asset or
liability occur in sufficient frequency and volume to provide pricing information on an
ongoing basis. |
102
|
|
|
Level 2 Inputs are other than quoted prices in active markets included in Level 1,
that are either directly or indirectly observable. These inputs are either directly
observable in the marketplace or indirectly observable through corroboration with market
data for substantially the full contractual term of the asset or liability being measured. |
|
|
|
|
Level 3 Includes inputs that are not observable for which there is little, if any,
market activity for the asset or liability being measured. These inputs reflect managements
best estimate of the assumptions market participants would use in determining fair value.
Our Level 3 consists of instruments valued with valuation methods that utilize unobservable
pricing inputs that are significant to the overall fair value. |
In valuing certain contracts, the inputs used to measure fair value may fall into different
levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified
in their entirety in the fair value hierarchy level based on the lowest level of input that is
significant to the overall fair value measurement. Our assessment of the significance of a
particular input to the fair-value measurement requires judgment and may affect the placement
within the fair-value hierarchy levels.
The following table presents, by level within the fair value hierarchy, our assets and
liabilities that are measured at fair value on a recurring basis. At December 31, 2008 we had no
assets or liabilities measured at fair value on a recurring basis.
Fair Value Measurements Using:
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|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
|
(In thousands) |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy derivatives |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy derivatives |
|
$ |
|
|
$ |
|
|
$ |
561 |
|
$ |
561 |
|
Energy derivatives include commodity-based contracts with WGM that are similar to
exchange-traded contracts and over-the-counter (OTC) contracts. Exchange-traded contracts could
include futures, swaps and options. OTC contracts could include forwards, swaps and options.
Certain instruments trade in less active markets with lower availability of pricing
information requiring valuation models using inputs that may not be readily observable or
corroborated by other market data. These instruments are classified within Level 3 when these
inputs have a significant impact on the measurement of fair value. Our commodity-based NGL
financial swap contracts are included in Level 3.
The determination of fair value for our assets and liabilities also incorporates the time
value of money and various credit risk factors which can include the credit standing of the
counterparties involved, master netting arrangements, the impact of credit enhancements (such as
collateral posted and letters of credit), and our nonperformance risk on our liabilities.
The following table sets forth a reconciliation of changes in the fair value of net
derivatives classified as Level 3 in the fair-value hierarchy.
103
Level 3 Fair-Value Measurements Using Significant Unobservable Inputs
Years Ended December 31, 2009 and 2008
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
Net Derivative |
|
|
|
Asset (Liability) |
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Beginning balance |
|
$ |
|
|
|
$ |
(2,487 |
) |
Realized and unrealized gains (losses): |
|
|
|
|
|
|
|
|
Included in net income |
|
|
(1,892 |
) |
|
|
(200 |
) |
Included in other comprehensive income (loss) |
|
|
(561 |
) |
|
|
416 |
|
Purchases, issuances and settlements |
|
|
1,892 |
|
|
|
2,487 |
|
(Gains) losses realized in settlements |
|
|
|
|
|
|
(216 |
) |
Transfers in/(out) of Level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance |
|
$ |
(561 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
Unrealized gains included in net income relating to instruments still held at December 31 |
|
$ |
|
|
|
$ |
|
|
Realized and unrealized gains (losses) included in net income are reported in revenues in our
Consolidated Statements of Income. During the year ended December 31, 2009, there were no assets
or liabilities measured at fair value on a nonrecurring basis.
Note 14. Financial Instruments and Energy Commodity Derivatives
Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial
instruments.
Cash and cash equivalents. The carrying amounts reported in the balance sheets approximate
fair value due to the short-term maturity of these instruments.
Long-term debt. The fair value of our publicly traded long-term debt is valued using
indicative year-end traded bond market prices. We base the fair value of our private long-term debt
on market rates and the prices of similar securities with similar terms and credit ratings. We
consider our non-performance risk in estimating fair value. At December 31, 2009 and 2008
approximately 75% of our long-term debt was publicly traded.
Energy commodity swap agreements. We base the fair value of our swap agreements on prices of
the underlying energy commodities over the contract life and contractual or notional volumes with
the resulting expected future cash flows discounted to a present value using a risk-free market
interest rate. Many contracts have bid and ask prices that can be observed in the market. Our
policy is to use a mid-market price (the mid-point price between bid and ask prices) convention to
value individual positions and then adjust on a portfolio level to a point within the bid and ask
range that represents our best estimate of fair value. For offsetting positions by location, the
mid-market price is used to measure both the long and short positions.
Carrying amounts and fair values of our financial instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
Asset (Liability) |
|
Amount |
|
Value |
|
Amount |
|
Value |
|
|
(In thousands) |
Cash and cash equivalents |
|
$ |
144,067 |
|
|
$ |
144,067 |
|
|
$ |
116,165 |
|
|
$ |
116,165 |
|
Long-term debt |
|
|
(1,000,000 |
) |
|
|
(999,867 |
) |
|
|
(1,000,000 |
) |
|
|
(825,289 |
) |
Energy derivative liabilities |
|
|
(561 |
) |
|
|
(561 |
) |
|
|
|
|
|
|
|
|
104
Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations.
Our Four Corners operation receives NGL volumes as compensation for certain processing services and
purchases natural gas to satisfy the required fuel and shrink replacement needed to extract these
NGLs. To reduce exposure to a decrease in revenues from fluctuations in NGL market prices or
increases in costs and operating expenses from fluctuations in natural gas market prices, we may
enter NGL or natural gas swap agreements, financial or physical forward contracts, and financial
option contracts to mitigate these commodity price risks.
All of these derivatives utilized for risk management purposes have been designated as cash
flow hedges. Our cash flow hedges are expected to be highly effective in offsetting cash flows
attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be
recognized primarily as a result of locational differences between the hedging derivative and the
hedged item. No net gains or losses from hedge ineffectiveness are included in our Consolidated
Statements of Income in either 2009 or 2007. We recognized a $0.2 million net loss from hedge
ineffectiveness in our Consolidated Statements of Income in 2008. There were no derivative gains or
losses excluded from the assessment of hedge effectiveness for the periods presented. Changes in
the fair value of our cash flow hedges, to the extent effective, are deferred in accumulated other
comprehensive loss and are reclassified into earnings in the same period or periods in which the
hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged
forecasted transaction will not occur by the end of the originally specified time period.
Volumes
Our energy commodity derivatives are comprised of contracts to sell NGLs at a fixed location
price. The following table depicts the notional volumes in our commodity derivatives portfolio as
of December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
Period |
|
Volumes |
Designated as hedging instruments: |
|
|
|
|
|
|
|
|
NGL sales propane (million gallons) |
|
JanuaryDecember 2010 |
|
|
4.3 |
|
Financial Statement Presentation
The fair value of our energy commodity derivatives designated as hedging instruments is
included in other accrued liabilities in our Consolidated Balance Sheets at December 31, 2009. We
had no energy commodity derivatives at December 31, 2008. There are no derivatives recognized on
the Consolidated Balance Sheets that have not been designated as hedging instruments. The fair
value amounts are presented on a gross basis and do not reflect the netting of asset and liability
positions permitted under the terms of our master netting arrangements.
The following table presents gains and losses for our energy commodity derivatives designated
as cash flow hedges and recognized in accumulated other comprehensive income (AOCI) or revenues.
There were no gains or losses recognized in income as a result of excluding amounts from the
assessment of hedge effectiveness for the periods presented.
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
Classification |
|
|
(In thousands) |
Net loss recognized in other comprehensive income (effective portion) |
|
$ |
2,411 |
|
|
AOCI |
Net loss reclassified from accumulated other comprehensive loss into
income (effective portion) |
|
$ |
1,850 |
|
|
Revenues |
Gain recognized in income (ineffective portion) |
|
$ |
|
|
|
Revenues |
Based on recorded values at December 31, 2009, $0.6 million of net losses will be reclassified
into earnings within the next twelve months. These recorded values are based on market prices of
the commodities as of December 31, 2009. Due to the volatile nature of commodity prices and changes
in the creditworthiness of counterparties, actual gains or losses realized in 2010 will likely
differ from these values. These gains or losses are expected to substantially offset net losses or
gains that will be realized in earnings from previous unfavorable or favorable market movements for
the volumes associated with underlying hedged transactions.
105
Credit-Risk
We have a risk of loss from counterparties not performing pursuant to the terms of their
contractual obligations. Risk of loss is impacted by several factors, including credit
considerations. We attempt to minimize credit-risk exposure to derivative counterparties through
formal credit policies, consideration of credit ratings from public ratings agencies, monitoring
procedures and collateral support under certain circumstances. Our NGL financial swap contracts
are with WGM. These agreements do not contain any provisions that require us to post collateral
related to net liability positions. Historically, WGM has not passed any counterparty risk back to
us when they enter offsetting NGL financial contracts with third parties.
Note 15. Long-Term Incentive Plan
Our general partner maintains the Williams Partners GP LLC Long-Term Incentive Plan (the Plan)
for employees, consultants and directors of our general partner and its affiliates who perform
services for us. Initially, the Plan permitted granting of awards covering an aggregate of 700,000
common units, in the form of options, restricted units, phantom units or unit appreciation rights.
During 2009 the Directors Compensation Policy under the Plan was amended to a 100% cash
compensation program, thereby eliminating the issuance of any partnership units. The revisions to
the policy do not affect restricted units previously granted.
During 2008 and 2007 our general partner granted 2,724 and 2,403 restricted units,
respectively, pursuant to the Plan to members of our general partners board of directors who are
not officers or employees of our general partner or its affiliates. These restricted units vested
180 days from the grant date. We recognized compensation expense of $20,000, $98,000 and $77,000
associated with the Plan in 2009, 2008 and 2007, respectively, based on the market price of our
common units at the date of grant. No awards were granted under the plan in 2009.
Note 16. Commitments and Contingencies
Commitments. A summary of our commitments for goods and services used in our operations and
for construction and acquisition of property, plant and equipment at December 31, 2009, is as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
Total |
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
$ |
5,163 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
5,163 |
|
Outstanding purchase orders |
|
|
4,661 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,661 |
|
Purchase obligations (a) |
|
|
22,563 |
|
|
|
17,587 |
|
|
|
17,938 |
|
|
|
17,938 |
|
|
$ |
76,026 |
|
|
|
|
(a) |
|
Represents a five-year service agreement for leased compression. |
Environmental Matters-Four Corners. Current federal regulations require that certain unlined
liquid containment pits located near named rivers and catchment areas be taken out of use, and
current state regulations required all unlined, earthen pits to be either permitted or closed by
December 31, 2005. Operating under a New Mexico Oil Conservation Division-approved work plan, we
have physically closed all of our pits that were slated for closure under those regulations. We are
presently awaiting agency approval of the closures for 40 to 50 of those pits. We are also a
participant in certain hydrocarbon removal and groundwater monitoring activities associated with
certain well sites in New Mexico. Of nine remaining active sites, product removal is ongoing at
four and groundwater monitoring is ongoing at each site. As groundwater concentrations reach and
sustain closure criteria levels and state regulator approval is received, the sites will be
properly abandoned. We expect the remaining sites will be closed within four to seven years.
In April 2007, the New Mexico Environment Departments Air Quality Bureau (NMED) issued a
Notice of Violation (NOV) that alleges various emission and reporting violations in connection with
our Lybrook gas processing plants flare and leak detection and repair program. In December 2007,
the NMED proposed a penalty of approximately $3 million. In July 2008, the NMED issued an NOV that
alleged air emissions permit exceedances for three glycol dehydrators at one of our compressor
facilities and proposed a penalty of approximately $103,000. We are discussing the proposed
penalties with the NMED.
In March 2008, the Environmental Protection Agency (EPA) proposed a penalty of $370,000 for
alleged violations relating to leak detection and repair program delays at our Ignacio gas plant in
Colorado and for alleged permit violations at a compressor station. We met with the EPA and are
exchanging information in order to resolve the issues.
We have accrued liabilities totaling $1.4 million at December 31, 2009 for these environmental
activities. It is reasonably possible that we will incur losses in excess of our accrual for these
matters. However, a reasonable estimate of such amounts cannot be determined at this time because
actual costs incurred will depend on the actual number of contaminated sites identified, the amount
and extent of contamination discovered, the final cleanup standards mandated by governmental
authorities, negotiations with the applicable agencies, and other factors.
106
Environmental Matters-Conway. We are a participant in certain environmental remediation
activities associated with soil and groundwater contamination at our Conway storage facilities.
These activities relate to four projects that are in various remediation stages including
assessment studies, cleanups and/or remedial operations and monitoring. We continue to coordinate
with the Kansas Department of Health and Environment (KDHE) to develop screening, sampling, cleanup
and monitoring programs. The costs of such activities will depend upon the program scope ultimately
agreed to by the KDHE and are expected to be paid over the life of the assets. At December 31,
2009, we had accrued liabilities totaling $5.2 million for these costs. It is reasonably possible
that we will incur losses in excess of our accrual for these matters. However, a reasonable
estimate of such amounts cannot be determined at this time because actual costs incurred will
depend on the actual number of contaminated sites identified, the amount and extent of
contamination discovered, the final cleanup standards mandated by KDHE and other governmental
authorities and other factors.
Under an omnibus agreement with Williams entered into at the closing of our initial public
offering, Williams agreed to indemnify us for certain Conway environmental remediation costs. At
December 31, 2009, approximately $6.9 million remains available for future indemnification.
Payments received under this indemnification are accounted for as a capital contribution to us by
Williams as the costs are reimbursed.
Will Price. In 2001, we were named, along with other subsidiaries of Williams, as defendants
in a nationwide class action lawsuit in Kansas state court that had been pending against other
defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the
defendants have engaged in mismeasurement techniques that distort the heating content of natural
gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and
sought an unspecified amount of damages. The defendants have opposed class certification, and on
September 18, 2009, the court denied plaintiffs most recent motion to certify the class. On
October 2, 2009, the plaintiffs filed a motion for reconsideration of the denial. We are awaiting a
decision from the court. The amount of any possible liability cannot be reasonably estimated at
this time.
GEII Litigation. General Electric International, Inc. (GEII) worked on turbines at our
Ignacio, New Mexico plant. We disagree with GEII on the quality of GEIIs work and the appropriate
compensation. GEII asserts that it is entitled to additional extra work charges under the
agreement, which we deny are due. In 2006, we filed suit in federal court in Tulsa, Oklahoma
against GEII, GE Energy Services, Inc., and Qualified Contractors, Inc. We alleged, among other
claims, breach of contract, breach of the duty of good faith and fair dealing, and negligent
misrepresentation and sought unspecified damages. In 2007, the defendants and GEII filed
counterclaims in the amount of $1.9 million against us that alleged breach of contract and breach
of the duty of good faith and fair dealing. This matter was settled in 2009.
Other. In addition to the foregoing, various other proceedings are pending against us which
are incidental to our operations.
Summary. Litigation, arbitration, regulatory matters and environmental matters are subject to
inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a
material adverse impact on the results of operations in the period in which the ruling occurs.
Management, including internal counsel, currently believes that the ultimate resolution of the
foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage,
recovery from customers or other indemnification arrangements, will not have a material adverse
effect upon our future liquidity or financial position.
107
Note 17. Segment Disclosures
Our reportable segments are strategic business units that offer different products and
services. We manage the segments separately because each segment requires different industry
knowledge, technology and marketing strategies. The accounting policies of the segments are the
same as those described in Note 4, Summary of Significant Accounting Policies. Long-lived assets
are comprised of property, plant and equipment.
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
Gathering & |
|
|
|
|
|
|
|
|
|
Processing - |
|
|
Processing - |
|
|
NGL |
|
|
|
|
|
|
West |
|
|
Gulf |
|
|
Services |
|
|
Total |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales |
|
$ |
172,038 |
|
|
$ |
|
|
|
$ |
10,430 |
|
|
$ |
182,468 |
|
Gathering and processing |
|
|
230,095 |
|
|
|
1,708 |
|
|
|
|
|
|
|
231,803 |
|
Storage |
|
|
|
|
|
|
|
|
|
|
33,209 |
|
|
|
33,209 |
|
Fractionation |
|
|
|
|
|
|
|
|
|
|
10,584 |
|
|
|
10,584 |
|
Other |
|
|
4,465 |
|
|
|
|
|
|
|
7,660 |
|
|
|
12,125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
406,598 |
|
|
|
1,708 |
|
|
|
61,883 |
|
|
|
470,189 |
|
Product cost and shrink replacement |
|
|
93,387 |
|
|
|
|
|
|
|
9,838 |
|
|
|
103,225 |
|
Operating and maintenance expense |
|
|
136,509 |
|
|
|
1,459 |
|
|
|
25,096 |
|
|
|
163,064 |
|
Depreciation, amortization and accretion |
|
|
41,326 |
|
|
|
170 |
|
|
|
3,391 |
|
|
|
44,887 |
|
Direct general and administrative expenses |
|
|
9,008 |
|
|
|
|
|
|
|
3,245 |
|
|
|
12,253 |
|
Other, net |
|
|
4,815 |
|
|
|
325 |
|
|
|
876 |
|
|
|
6,016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
121,553 |
|
|
|
(246 |
) |
|
|
19,437 |
|
|
|
140,744 |
|
Investment income |
|
|
84,052 |
|
|
|
27,243 |
|
|
|
|
|
|
|
111,295 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
205,605 |
|
|
$ |
26,997 |
|
|
$ |
19,437 |
|
|
$ |
252,039 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statement of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
140,744 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(35,536 |
) |
Third-party direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,456 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
101,752 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets |
|
$ |
1,377,437 |
|
|
$ |
491,867 |
|
|
$ |
159,882 |
|
|
$ |
2,029,186 |
|
Other assets
and eliminations (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(705,516 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,323,670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity method investments |
|
$ |
272,549 |
|
|
$ |
188,511 |
|
|
$ |
|
|
|
$ |
461,060 |
|
Additions to long-lived assets |
|
$ |
27,032 |
|
|
$ |
33 |
|
|
$ |
10,196 |
|
|
$ |
37,261 |
|
(a) |
|
Relates primarily to the elimination of
intercompany accounts receivable generated by our centralized cash
management program. Also includes the assets of the OLLC. |
108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
Gathering & |
|
|
|
|
|
|
|
|
|
Processing - |
|
|
Processing - |
|
|
NGL |
|
|
|
|
|
|
West |
|
|
Gulf |
|
|
Services |
|
|
Total |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales |
|
$ |
322,583 |
|
|
$ |
|
|
|
$ |
16,697 |
|
|
$ |
339,280 |
|
Gathering and processing |
|
|
230,853 |
|
|
|
2,096 |
|
|
|
|
|
|
|
232,949 |
|
Storage |
|
|
|
|
|
|
|
|
|
|
31,429 |
|
|
|
31,429 |
|
Fractionation |
|
|
|
|
|
|
|
|
|
|
17,441 |
|
|
|
17,441 |
|
Other |
|
|
6,702 |
|
|
|
|
|
|
|
9,259 |
|
|
|
15,961 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
560,138 |
|
|
|
2,096 |
|
|
|
74,826 |
|
|
|
637,060 |
|
Product cost and shrink replacement |
|
|
189,192 |
|
|
|
|
|
|
|
16,886 |
|
|
|
206,078 |
|
Operating and maintenance expense |
|
|
156,713 |
|
|
|
1,668 |
|
|
|
27,520 |
|
|
|
185,901 |
|
Depreciation, amortization and accretion |
|
|
41,215 |
|
|
|
751 |
|
|
|
3,063 |
|
|
|
45,029 |
|
Direct general and administrative expenses |
|
|
8,333 |
|
|
|
|
|
|
|
2,582 |
|
|
|
10,915 |
|
Other, net |
|
|
(939 |
) |
|
|
6,187 |
|
|
|
737 |
|
|
|
5,985 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
165,624 |
|
|
|
(6,510 |
) |
|
|
24,038 |
|
|
|
183,152 |
|
Investment income |
|
|
88,538 |
|
|
|
22,357 |
|
|
|
|
|
|
|
110,895 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
254,162 |
|
|
$ |
15,847 |
|
|
$ |
24,038 |
|
|
$ |
294,047 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statement of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
183,152 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(33,707 |
) |
Third-party direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,437 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
147,008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets |
|
$ |
1,248,110 |
|
|
$ |
379,060 |
|
|
$ |
127,315 |
|
|
$ |
1,754,485 |
|
Other assets
and eliminations (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(462,666 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,291,819 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity method investments |
|
$ |
277,707 |
|
|
$ |
184,466 |
|
|
$ |
|
|
|
$ |
462,173 |
|
Additions to long-lived assets |
|
$ |
36,833 |
|
|
$ |
|
|
|
$ |
9,020 |
|
|
$ |
45,853 |
|
(a) |
|
Relates primarily to the elimination of
intercompany accounts receivable generated by our centralized cash
management program. Also includes the assets of the OLLC. |
109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering & |
|
|
Gathering & |
|
|
|
|
|
|
|
|
|
Processing - |
|
|
Processing - |
|
|
NGL |
|
|
|
|
|
|
West |
|
|
Gulf |
|
|
Services |
|
|
Total |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product sales |
|
$ |
279,600 |
|
|
$ |
|
|
|
$ |
11,332 |
|
|
$ |
290,932 |
|
Gathering and processing |
|
|
236,475 |
|
|
|
2,119 |
|
|
|
|
|
|
|
238,594 |
|
Storage |
|
|
|
|
|
|
|
|
|
|
28,016 |
|
|
|
28,016 |
|
Fractionation |
|
|
|
|
|
|
|
|
|
|
9,622 |
|
|
|
9,622 |
|
Other |
|
|
(2,288 |
) |
|
|
|
|
|
|
7,941 |
|
|
|
5,653 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
513,787 |
|
|
|
2,119 |
|
|
|
56,911 |
|
|
|
572,817 |
|
Product cost and shrink replacement |
|
|
170,434 |
|
|
|
|
|
|
|
11,264 |
|
|
|
181,698 |
|
Operating and maintenance expense |
|
|
135,782 |
|
|
|
1,875 |
|
|
|
24,686 |
|
|
|
162,343 |
|
Depreciation, amortization and accretion |
|
|
41,523 |
|
|
|
1,249 |
|
|
|
3,720 |
|
|
|
46,492 |
|
Direct general and administrative expenses |
|
|
7,790 |
|
|
|
|
|
|
|
2,190 |
|
|
|
9,980 |
|
Other, net |
|
|
10,567 |
|
|
|
10,406 |
|
|
|
746 |
|
|
|
21,719 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss) |
|
|
147,691 |
|
|
|
(11,411 |
) |
|
|
14,305 |
|
|
|
150,585 |
|
Investment
income |
|
|
76,212 |
|
|
|
28,842 |
|
|
|
|
|
|
|
105,054 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit |
|
$ |
223,903 |
|
|
$ |
17,431 |
|
|
$ |
14,305 |
|
|
$ |
255,639 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation to the Consolidated Statement of Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
150,585 |
|
General and administrative expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated affiliate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(32,546 |
) |
Third-party direct |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,102 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
114,937 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment assets |
|
$ |
1,112,652 |
|
|
$ |
268,471 |
|
|
$ |
98,730 |
|
|
$ |
1,479,853 |
|
Other assets
and eliminations (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(196,376 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,283,477 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity method investments |
|
$ |
284,650 |
|
|
$ |
214,526 |
|
|
$ |
|
|
|
$ |
499,176 |
|
Additions to long-lived assets |
|
$ |
39,391 |
|
|
$ |
|
|
|
$ |
9,090 |
|
|
$ |
48,481 |
|
(a) |
|
Relates primarily to the elimination of
intercompany accounts receivable generated by our centralized cash
management program. Also includes the assets of the OLLC. |
110
QUARTERLY FINANCIAL DATA
(Unaudited)
Summarized quarterly financial data are as follows (thousands, except per-unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
105,468 |
|
|
$ |
106,327 |
|
|
$ |
125,153 |
|
|
$ |
133,241 |
|
Costs and operating expenses |
|
|
87,847 |
|
|
|
88,912 |
|
|
|
88,639 |
|
|
|
103,039 |
|
Net income |
|
|
18,672 |
|
|
|
25,368 |
|
|
|
55,947 |
|
|
|
52,480 |
|
Basic and diluted net income per limited partner unit |
|
$ |
0.36 |
|
|
$ |
0.48 |
|
|
$ |
1.04 |
|
|
$ |
0.99 |
|
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
150,362 |
|
|
$ |
178,245 |
|
|
$ |
175,713 |
|
|
$ |
132,740 |
|
Costs and operating expenses |
|
|
124,050 |
|
|
|
136,033 |
|
|
|
127,737 |
|
|
|
102,232 |
|
Net income |
|
|
43,629 |
|
|
|
71,822 |
|
|
|
60,833 |
|
|
|
15,105 |
(a)(b) |
Basic and diluted net income per limited partner unit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units |
|
$ |
0.71 |
|
|
$ |
1.21 |
|
|
$ |
1.00 |
|
|
$ |
0.15 |
|
Subordinated units(c) |
|
$ |
0.71 |
|
|
$ |
|
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$ |
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$ |
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(a) |
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During September 2008, Discoverys offshore gathering system sustained
hurricane damage and was unable to accept gas from producers while
repairs were being made through the end of 2008. In addition,
throughout the fourth quarter of 2008 we experienced significantly
lower per-unit margins as NGL prices, especially ethane, declined
along with the price of crude oil. These lower NGL margins
significantly reduced the profitability of our gathering and
processing businesses including Four Corners and our ownership
interests in Wamsutter and Discovery. |
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(b) |
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The fourth quarter of 2008 includes a $6.2 million impairment of the
Carbonate Trend pipeline (see Note 8, Other (Income) Expense). |
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(c) |
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Subordinated units converted to common on February 19, 2008. |
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Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Our management, including our general partners Chief Executive Officer and Chief Financial
Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a
15(e) and 15d 15(e) of the Securities Exchange Act) (Disclosure Controls) will prevent all
errors and all fraud. A control system, no matter how well conceived and operated, can provide only
reasonable, not absolute, assurance that the objectives of the control system are met. Further, the
design of a control system must reflect the fact that there are resource constraints, and the
benefits of controls must be considered relative to their costs. Because of the inherent
limitations in all control systems, no evaluation of controls can provide absolute assurance that
all control issues and instances of fraud, if any, within Williams Partners L.P. have been
detected. These inherent limitations include the realities that judgments in decision-making can be
faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls
can be circumvented by the individual acts of some persons, by collusion of two or more people, or
by management override of the control. The design of any system of controls also is based in part
upon certain assumptions about the likelihood of future events, and there can be no assurance that
any design will succeed in achieving its stated goals under all potential future conditions.
Because of the inherent limitations in a cost-effective control system, misstatements due to error
or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications
as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems
change and conditions warrant.
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was
performed as of the end of the period covered by this report. This evaluation was performed under
the supervision and with the participation of our management, including our general partners Chief
Executive Officer and Chief Financial Officer. Based upon that evaluation, our general partners
Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are
effective at a reasonable assurance level.
Managements Annual Report on Internal Control over Financial Reporting
See report set forth above in Item 8, Financial Statements and Supplementary Data.
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
See report set forth above in Item 8, Financial Statements and Supplementary Data.
Changes in Internal Controls Over Financial Reporting
There have been no changes during the fourth quarter of 2009 that have materially affected, or
are reasonably likely to materially affect, our Internal Controls over financial reporting.
Item 9B. Other Information
There have been no events that occurred in the fourth quarter of 2009 that would need to be
reported on Form 8-K that have not been previously reported.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
As a limited partnership, we have no directors or officers. Instead, our general partner,
Williams Partners GP LLC, manages our operations and activities. Our general partner is not elected
by our unitholders and is not subject to re-election on a regular basis in the future. Unitholders
are not entitled to elect the directors of our general partner or directly or indirectly
participate in our management or operation.
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We are managed and operated by the directors and officers of our general partner. All of our
operational personnel are employees of affiliates 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. Our non-executive directors devote as much time as
is necessary to prepare for and attend board of directors and committee meetings.
The following table shows information for the directors and executive officers of our general
partner as of February 25, 2010.
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Name |
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Age |
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Position with Williams Partners GP LLC |
Steven J. Malcolm
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61 |
|
|
Chairman of the Board and Chief Executive Officer |
Donald R. Chappel
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58 |
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Chief Financial Officer and Director |
Alan S. Armstrong |
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47 |
|
|
Senior Vice President Midstream and Director |
Phillip D. Wright
|
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54 |
|
|
Senior Vice President Gas Pipeline and Director |
James J. Bender
|
|
|
53 |
|
|
General Counsel |
H. Michael Krimbill
|
|
|
56 |
|
|
Director and Member of Audit and Conflicts Committees |
Bill Z. Parker
|
|
|
62 |
|
|
Director and Member of Audit and Conflicts Committees |
Alice M. Peterson
|
|
|
57 |
|
|
Director and Member of Audit and Conflicts Committees |
The directors of our general partner are elected for one-year terms and hold office until the
earlier of their death, resignation, removal or disqualification or until their successors have
been elected and qualified. Officers serve at the discretion of the board of directors of our
general partner. There are no family relationships among any of the directors or executive officers
of our general partner.
Steven J. Malcolm has served as the chairman of the board of directors and chief executive
officer of our general partner since February 2005. Mr. Malcolm has served as president of Williams
since September 2001, chief executive officer of Williams since January 2002 and chairman of the
board of directors of Williams since May 2002. From September 2001 to January 2002, he served as
chief operating officer of Williams and from May 2001 to September 2001, he served as an executive
vice president of Williams. From 1998 to 2001, he served as president and chief executive officer
of Williams Energy Services, LLC, a subsidiary of Williams. From 1994 to 1998, Mr. Malcolm served
as the senior vice president and general manager of Williams Field Services Company, a subsidiary
of Williams. Mr. Malcolm has served as chairman of the board of directors and chief executive
officer of the general partner of Williams Pipeline Partners L.P. since 2007. Mr. Malcolm has
served as a member of the board of directors of BOK Financial Corporation and Bank of Oklahoma,
N.A. since 2002.
Donald R. Chappel has served as the chief financial officer and a director of our general
partner since February 2005. Mr. Chappel has served as senior vice president and chief financial
officer of Williams since April 2003. Mr. Chappel has served as chief financial officer and a
director of the general partner of Williams Pipeline Partners L.P. since 2007.
Alan
S. Armstrong has served as a senior vice president of our general partner and
president of our midstream business unit since February 17, 2010 and a director of our general
partner since February 2005. Since February 2002, Mr. Armstrong has served as a senior vice
president of Williams and president of Williams midstream business unit. From 2005 to February
2010, Mr. Armstrong served as the chief operating officer of our general partner. 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.
Phillip
D. Wright has served as a senior vice president and a director of our general partner
and president of our gas pipeline business unit since February 17, 2010. Mr. Wright has served as
a senior vice president of Williams and president of Williams gas pipeline unit since January
2005. Mr. Wright previously served as a director of our general partner from April 2005 to October
2007. 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 also serves as a director, senior vice president and chief operating officer of Williams
Pipeline GP LLC, the general partner of Williams Pipeline Partners L.P.
James J. Bender has served as the general counsel of our general partner since February 2005.
Mr. Bender has served as senior vice president and general counsel of Williams since December 2002.
Mr. Bender has served as the general counsel of the general partner of Williams Pipeline Partners
L.P. since August 2007. From June 2000 to June 2002, Mr. Bender was senior vice president and
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general counsel with NRG Energy, Inc. Mr. Bender was vice president, general counsel and
secretary of NRG Energy from June 1997 to June 2000.
H. Michael Krimbill has served as a director of our general partner since August 2007. Mr.
Krimbill has served as a director of Seminole Energy Services, LLC, a privately held natural gas
marketing company, from November 2007 to February 5, 2010. Mr. Krimbill was the president and chief
financial officer of Energy Transfer Partners, L.P. from 2004 until his resignation in January
2007. Mr. Krimbill joined Heritage Propane Partners, L.P. (the predecessor of Energy Transfer
Partners) as vice president and chief financial officer in 1990. Mr. Krimbill served as president
of Heritage from 1999 to 2004 and as president and chief executive officer of Heritage from 2000 to
2005. Mr. Krimbill also served as a director of Energy Transfer Equity, the general partner of
Energy Transfer Partners from 2000 to January 2007.
Bill Z. Parker has served as a director of our general partner since August 2005. Mr. Parker
has served as a director of Laredo Petroleum L.L.C., a privately held independent oil and gas
producing company, since 2007. Mr. Parker served as a director for Latigo Petroleum, Inc., a
privately held independent oil and gas production company, from 2003 to May 2006, when it was
acquired by POGO Producing Company. From April 2000 to November 2002, Mr. Parker served as
executive vice president of Phillips Petroleum Companys worldwide upstream operations. Mr. Parker
was executive vice president of Phillips Petroleum Companys worldwide downstream operations from
September 1999 to April 2000.
Alice M. Peterson has served as a director of our general partner since September 2005. Ms.
Peterson has served as the chief ethics officer of SAI Global since April 2009. Since 2000, Ms.
Peterson has served as a director of RIM Finance, LLC, a wholly owned subsidiary of Research in
Motion, Ltd., the maker of Blackberrytm handheld device. Ms. Peterson has
served as a director of Navistar Financial Corporation, a wholly owned subsidiary of Navistar
International, since 2006. She founded and served as the president of Syrus Global, a provider of
ethics, compliance and reputation management solutions from 2002 to April 2009, when it was
acquired by SAI Global. Ms. Peterson served as a director of Hanesbrands Inc., an apparel company,
from 2006 to 2009. 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 2004, she served as a director of Fleming Companies. From 2000
to 2001, Ms. Peterson served as president and general manager of RIM Finance, LLC. From April 2000
to September 2000, Ms. Peterson served as the chief executive officer of Guidance Resources.com, a
start-up business focused on providing online behavioral health and concierge services to employer
groups and other associations. From 1998 to 2000, Ms. Peterson served as vice president of Sears
Online and from 1993 to 1998, as vice president and treasurer of Sears, Roebuck and Co.
Governance
Our general partner adopted governance guidelines that address, among other areas, director
independence standards, policies on meeting attendance and preparation, executive sessions of
non-management directors and communications with non-management directors.
Director Independence
Because we are a limited partnership, the New York Stock Exchange does not require our general
partners board of directors to be composed of a majority of directors who meet the criteria for
independence required by the New York Stock Exchange or to maintain nominating/corporate governance
and compensation committees composed entirely of independent directors.
Our general partners board of directors has adopted director independence standards, which
are included in our governance guidelines and set forth below. Our governance guidelines are
available on our Internet website at http://www.williamslp.com under the Investor Relations
caption. Under the director independence standards, a director will not be considered to be
independent if:
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the director, or an immediate family member of the director, has received during any
twelve-month period within the last three years more than $120,000 per year in direct
compensation from our general partner, us and any parent or subsidiary in a consolidated
group with such entities (collectively, the Partnership Group), other than board and
committee fees and pension or other forms of deferred compensation for prior service
(provided such compensation is not contingent in any way on continued service). Neither
compensation received by a director for former service as an interim chairman or chief
executive officer or other executive officer nor compensation received by an immediate
family member for service as an employee (other than an executive officer) of the
Partnership Group will be considered in determining independence under this standard. |
114
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the director is a current employee, or has an immediate family member who is a current
executive officer, of another company that has made payments to, or received payments from,
the Partnership Group for property or services in an amount which, in any of the last three
fiscal years, exceeds the greater of $1.0 million, or 2% of the other companys consolidated
gross annual revenues. Contributions to tax exempt organizations are not considered
payments for purposes of this standard. |
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the director is, or has been within the last three years, an employee of the Partnership
Group, or an immediate family member is, or has been within the last three years, an
executive officer, of the Partnership Group. Employment as an interim chairman or chief
executive officer or other executive officer will not disqualify a director from being
considered independent following that employment. |
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(i) the director is a current partner or employee of a firm that is the present or former
internal or external auditor for the Partnership Group, (ii) the director has an immediate
family member who is a current partner of such a firm, (iii) the director has an immediate
family member who is a current employee of such a firm and personally works on the
Partnership Groups audit (iv) the director or an immediately family member was within the
last three years a partner or employee of such a firm and personally worked on an audit for
the Partnership Group within that time. |
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if the director or an immediate family member is, or has been within the last three
years, employed as an executive officer of another company where any of the Partnership
Groups present executive officers at the same time serves or served on that companys
compensation committee. |
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if the board of directors determines that a discretionary contribution made by any member
of the Partnership Group to a non-profit organization with which a director, or a directors
spouse, has a relationship, impacts the directors independence. |
Our general partners board of directors has affirmatively determined that each of Ms.
Peterson and Messrs. Krimbill and Parker is an independent director under the current listing
standards of the New York Stock Exchange and our director independence standards. In so doing, the
board of directors determined that each of these individuals met the bright line independence
standards of the New York Stock Exchange. In addition, the board of directors considered
transactions and relationships between each director and the Partnership Group, either directly or
indirectly. The purpose of this review was to determine whether any such relationships or
transactions were inconsistent with a determination that the director is independent. The board of
directors considered the fact that Mr. Krimbill served as a director of Seminole Energy Services
LLC until February 5, 2010, which is a customer and vendor to certain subsidiaries of us and
Williams. The board of directors noted that, since Mr. Krimbill did not serve as an executive
officer and does not own a significant amount of voting securities of Seminole Energy Services LLC,
this relationship is not material. Accordingly, the board of directors of our general partner
affirmatively determined that all of the directors mentioned above are independent. Because Messrs.
Armstrong, Chappel, Malcolm, Rod J. Sailor (who served as a director of our general partner until
February 17, 2010) and Wright are employees, officers and/or directors of Williams, they are not
independent under these standards.
Ms. Peterson and Messrs. Krimbill and Parker do not serve as an executive officer of any
non-profit organization to which the Partnership Group made contributions within any single year of
the preceding three years that exceeded the greater of $1.0 million or 2% of such organizations
consolidated gross revenues. Further, in accordance with our director independence standards, there
were no discretionary contributions made by any member of the Partnership Group to a non-profit
organization with which such director, or such directors spouse, has a relationship that impact
the directors independence.
In addition, our general partners board of directors determined that each of Ms. Peterson and
Messrs. Krimbill and Parker, who constitute the members of the audit committee of the board of
directors, meet the heightened independence requirements of the New York Stock Exchange for audit
committee members.
Meeting Attendance and Preparation
Members of the board of directors of our general partner are expected to attend at least 75%
of regular board meetings and meetings of the committees on which they serve, either in person or
telephonically. In addition, directors are expected to be prepared for each meeting of the board by
reviewing written materials distributed in advance.
115
Executive Sessions of Non-Management Directors
Our general partners non-management board members periodically meet outside the presence of
our general partners executive officers. The chairman of the audit committee serves as the
presiding director for executive sessions of non-management board members. The current chairman of
the audit committee and the presiding director is Ms. Alice M. Peterson.
Communications with Directors
Interested parties wishing to communicate with our general partners non-management directors,
individually or as a group, may do so by contacting our general partners corporate secretary or
the presiding director. The contact information is maintained on the investor relations/corporate
governance page of our website at http://www.williamslp.com.
The current contact information is as follows:
Williams Partners L.P.
c/o Williams Partners GP LLC
One Williams Center, Suite 4700
Tulsa, Oklahoma 74172
Attn: Corporate Secretary
Williams Partners L.P.
c/o Williams Partners GP LLC
One Williams Center, Suite 4700
Tulsa, Oklahoma 74172
Attn: Presiding Director
E-mail: lafleur.browne@williams.com
Board Committees
The board of directors of our general partner has a separately-designated standing audit
committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934
and a conflicts committee. The following is a description of each of the committees and committee
membership as of February 25, 2010.
Board Committee Membership
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Audit |
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Conflicts |
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Committee |
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Committee |
H. Michael Krimbill |
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ü |
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ü |
Bill Z. Parker |
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ü |
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Alice M. Peterson |
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ü |
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ü |
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= committee member |
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= chairperson |
Audit Committee
Our general partners board of directors has determined that all members of the audit
committee meet the heightened independence requirements of the New York Stock Exchange for audit
committee members and that all members are financially literate as defined by the rules of the New
York Stock Exchange. The board of directors has further determined that Ms. Alice M. Peterson and
Mr. H. Michael Krimbill qualify as audit committee financial experts as defined by the rules of
the SEC. Biographical information for Ms. Peterson and Mr. Krimbill is set forth above. The audit
committee is governed by a written charter adopted by the board of directors. For further
information about the audit committee, please read the Report of the Audit Committee below and
Principal Accountant Fees and Services.
Conflicts Committee
The conflicts committee of our general partners board of directors reviews specific matters
that the board believes may involve conflicts of interest. The conflicts committee determines if
resolution of the conflict is fair and reasonable to us. The members of the
116
conflicts committee may not be officers or employees of our general partner or directors,
officers or employees of its affiliates and must meet the independence and experience requirements
established by the New York Stock Exchange and the Sarbanes-Oxley Act of 2002 and other federal
securities laws. Any matters approved by the conflicts committee will be conclusively deemed fair
and reasonable to us, approved by all of our partners and not a breach by our general partner of
any duties it may owe to us or our unitholders.
Code of Business Conduct and Ethics
Our general partner has adopted a code of business conduct and ethics for directors, officers
and employees. We intend to disclose any amendments to or waivers of the code of business conduct
and ethics on behalf of our general partners chief executive officer, chief financial officer,
controller and persons performing similar functions on our Internet website at
http://www.williamslp.com under the Investor Relations caption, promptly following the date of
any such amendment or waiver.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our general partners executive
officers and directors and persons who own more than 10% of a registered class of our equity
securities to file with the SEC and the New York Stock Exchange reports of ownership of our
securities and changes in reported ownership. Executive officers and directors of our general
partner and greater than 10% unitholders are required to by SEC rules to furnish to us copies of
all Section 16(a) reports that they file. Based solely on a review of reports furnished to our
general partner, or written representations from reporting persons that all reportable transactions
were reported, we believe that during the fiscal year ended December 31, 2009 our general partners
officers, our directors and our greater than 10% common unitholders filed all reports they were
required to file under Section 16(a) on a timely basis.
Transfer Agent and Registrar
Computershare Trust Company, N.A. serves as registrar and transfer agent for our common units.
Contact information for Computershare is as follows:
Computershare Trust Company, N.A.
P.O. Box 43069
Providence, Rhode Island 02940-3069
Phone: (781) 575-2879 or toll-free, (877) 498-8861
Hearing impaired: (800) 952-9245
Internet: www.computershare.com/investor
Send overnight mail to:
Computershare
250 Royall St.
Canton, Massachusetts 02021
REPORT OF THE AUDIT COMMITTEE
The audit committee oversees our financial reporting process on behalf of the board of
directors. Management has the primary responsibility for the financial statements and the reporting
process including the systems of internal controls. The audit committee operates under a written
charter approved by the board. The charter, among other things, provides that the audit committee
has authority to appoint, retain, oversee and terminate when appropriate 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; |
117
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received the written disclosures and the letter from Ernst & Young LLP required by
applicable requirements of the Public Company Accounting Oversight Board regarding Ernst &
Young LLPs communications with the audit committee concerning independence, and discussed
with Ernst & Young LLP its independence; |
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discussed with Ernst & Young LLP the matters required to be discussed by the statement on
Auditing Standards No. 61, as amended, as adopted by the Public Company Accounting Oversight
Board in Rule 3200T; |
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discussed with Williams Partners L.P.s internal auditors and Ernst & Young LLP the
overall scope and plans for their respective audits. The audit committee meets with the
internal auditors and Ernst & Young LLP, with and without management present, to discuss the
results of their examinations, their evaluations of Williams Partners L.P.s internal
controls and the overall quality of Williams Partners L.P.s
financial reporting; and |
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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, 2009, for filing with the SEC. |
This report has been furnished by the members of the audit committee of the board of
directors:
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Alice M. Peterson chairman |
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Bill Z. Parker |
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H. Michael Krimbill |
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.
Item 11. Executive Compensation
Compensation Discussion and Analysis
We and our general partner, Williams Partners GP LLC, were formed in February 2005. We are
managed by the executive officers of our general partner who are also executive officers of
Williams. Neither we nor our general partner have a compensation committee. The executive officers
of our general partner are compensated directly by Williams. All decisions as to the compensation
of the executive officers of our general partner who are involved in our management are made by the
compensation committee of Williams. Therefore, we do not have any policies or programs relating to
compensation of the executive officers of our general partner and we make no decisions relating to
such compensation. None of the executive officers of our general partner have employment agreements
with us or are otherwise specifically compensated for their service as an executive officer of our
general partner. A full discussion of the policies and programs of the compensation committee of
Williams will be set forth in the proxy statement for Williams 2010 annual meeting of stockholders
which will be available upon its filing on the SECs website at http://www.sec.gov and on Williams
website at http://www.williams.com under the heading Investors SEC Filings. We reimburse our
general partner for direct and indirect general and administrative expenses attributable to our
management (which expenses include the share of the compensation paid to the executive officers of
our general partner attributable to the time they spend managing our business). Please read
Certain Relationships and Related Transactions, and Director Independence Reimbursement of
Expenses of Our General Partner for more information regarding this arrangement.
Executive Compensation
Information regarding the portion of Mr. Armstrongs, Mr. Benders, Mr. Chappels and Mr.
Malcolms compensation and employment-related expenses allocable to us may be found in this filing
under the heading Certain Relationships and Related Transactions, and Director Independence
Reimbursement of Expenses of Our General Partner.
Further information regarding the compensation of our principal executive officer, Steven J.
Malcolm, who also serves as the chairman, president and chief executive officer of Williams, our
principal financial officer, Donald R. Chappel, who also serves as the
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chief financial officer of Williams, Alan S. Armstrong, our senior vice president
midstream, who also serves as a senior vice president of Williams, and Phillip D. Wright, who was
appointed our senior vice president gas pipeline on February 17, 2010, who also serves as a
senior vice president of Williams, will be set forth in the proxy statement for Williams 2010
annual meeting of stockholders which will be available upon its filing on the SECs website at
http://www.sec.gov and on Williams website at http:/www.williams.com under the heading Investors
SEC Filings.
Compensation Committee Interlocks and Insider Participation
As previously discussed, our general partners board of directors is not required to maintain,
and does not maintain, a compensation committee. Steven J. Malcolm, our general partners chief
executive officer and chairman of the board of directors serves as the chairman of the board and
chief executive officer of Williams. Alan S. Armstrong, Donald R. Chappel and Phillip D. Wright,
who are directors of our general partner, are also executive officers of Williams. Rodney J.
Sailor, who was a director of our general partner until February 17, 2010, is also a non-executive
officer and an employee of Williams. However, all compensation decisions with respect to each of
these persons are made by Williams and none of these individuals receive any compensation directly
from us or our general partner. Please read Certain Relationships and Related Transactions, and
Director Independence below for information about relationships among us, our general partner and
Williams.
Board Report on Compensation
Neither we nor our general partner has a compensation committee. The board of directors of our
general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above
and based on this review and discussion has approved it for inclusion in this Form 10-K.
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The Board of Directors of Williams Partners GP LLC:
Alan S. Armstrong, Donald R. Chappel,
H. Michael Krimbill, Steven J. Malcolm
Bill Z. Parker, Alice M. Peterson,
Phillip D. Wright
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Compensation of Directors
We are managed by the board of directors of our general partner. Members of the board of
directors who are also officers or employees of Williams or an affiliate of us or Williams do not
receive additional compensation for serving on the board of directors. Please read Certain
Relationships and Related Transactions, and Director Independence Reimbursement of Expenses of
Our General Partner for information about how we reimburse our general partner for direct and
indirect general and administrative expenses attributable to our management. Non-employees
directors receive a bi-annual compensation package consisting of the following, which amounts are
paid on August 22 and February 1: (a) $37,500 cash retainer; and (b) $2,500 cash each for service
on the conflicts or audit committees of the board of directors. If a non-employee directors
service on the board of directors commences between December 1 and January 31 or between February 2
and August 21, the non-employee director will receive a prorated bi-annual compensation package.
In addition to the bi-annual compensation package, each non-employee director will receive a
one-time cash payment of $25,000 on the date of first election to the board of directors. Also,
each non-employee director serving as a member of the conflicts committee of the board of directors
receives $1,250 cash for each conflicts committee meeting attended by such director. Fees for
attendance at meetings of the conflicts committee are paid on August 22 and February 1 of each year
for meetings held during the preceding months. Each non-employee director is also reimbursed for
out-of-pocket expenses in connection with attending meetings of the board of directors or its
committees. Each director will be fully indemnified by us for actions associated with being a
director to the extent permitted under Delaware law. We also reimburse non-employee directors for
the costs of education programs relevant to their duties as board members.
For their service, non-management directors received the following compensation in 2009:
Director Compensation Fiscal Year 2009
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Change in Pension |
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Value and |
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Nonqualified |
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Non-Equity |
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Deferred |
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Fees Earned or Paid |
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Unit |
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Option |
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Incentive Plan |
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|
Compensation |
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All Other |
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|
Name |
|
in Cash (1) |
|
|
Awards (2) |
|
|
Awards |
|
|
Compensation |
|
|
Earnings |
|
|
Compensation |
|
|
Total |
|
H. Michael Krimbill |
|
$ |
56,250 |
|
|
$ |
6,664 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
62,914 |
|
Bill Z. Parker |
|
$ |
56,250 |
|
|
$ |
6,664 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
62,914 |
|
Alice M. Peterson |
|
$ |
56,250 |
|
|
$ |
6,664 |
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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$ |
62,914 |
|
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(1) |
|
In May 2009, our director compensation policy was revised to include
two payments for the annual director compensation package. As a
result, the table above reflects only one bi-annual cash payment made
on August 22. Fees earned for attending 11 conflicts committee
meetings in 2009 are also reflected in this column. |
|
(2) |
|
Prior to 2009, non-employee directors received a portion of their
compensation in the form of restricted units. The last grant of
restricted units occurred in August of 2008 and the expense related to
the grant is reflected in this column. Restricted units awarded to
non-employee directors in 2008 were granted under the Williams
Partners GP LLC Long-Term Incentive Plan and vested 180 days after the
date of grant. Cash distributions were paid on these restricted
units. |
Long-Term Incentive Plan
Our general partner adopted the Williams Partners GP LLC Long-Term Incentive Plan for
employees, consultants and directors of our general partner and employees and consultants of its
affiliates who perform services for our general partner or its affiliates. To date, the only grants
under the plan have been grants of restricted units to directors who are not officers or employees
of us or our affiliates. In 2006, the board of directors of our general partner dissolved its
compensation committee. The only function performed by the committee prior to its dissolution was
to administer the Williams Partners GP LLC Long-Term Incentive Plan. Accordingly, also in 2006, the
board of directors approved an amendment to the long-term incentive plan to allow the full board of
directors to administer the plan. On December 2, 2008, the board of directors of our general
partner approved an amendment to the long-term incentive plan to comply with Section 409A of the
Internal Revenue Code of 1986 and its relevant regulations. The long-term incentive plan consists
of four components: restricted units, phantom units, unit options and unit appreciation rights. The
long-term incentive plan currently permits the grant of awards covering an aggregate of 700,000
units. There were no grants or awards under the long-term incentive plan in 2009.
Our general partners board of directors, in its discretion may terminate, suspend or
discontinue the long-term incentive plan at any time with respect to any award that has not yet
been granted. Our general partners board of directors also has the right to alter or
120
amend the long-term incentive plan or any part of the plan from time to time, including
increasing the number of units that may be granted subject to unitholder approval as required by
the exchange upon which the common units are listed at that time. However, except for specific
adjustment rights detailed in the plan, no change in any outstanding grant may be made that would
materially impair the rights of the participant without the consent of the participant.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth the beneficial ownership of common units of Williams Partners
L.P. that are owned by:
|
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each person known by us to be a beneficial owner of more than 5% of the units; |
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|
each of the directors of our general partner; |
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each of the executive officers of our general partner; and |
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all directors and executive officers of our general partner as a group. |
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.
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|
|
|
Percentage |
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|
|
|
Percentage of |
|
Percentage of |
|
|
|
|
|
|
of Total Common |
|
Class C Units |
|
Class C Units |
|
Total Units |
|
|
Common Units |
|
Units Beneficially |
|
Beneficially |
|
Beneficially |
|
Beneficially |
Name of Beneficial Owner |
|
Beneficially Owned |
|
Owned |
|
Owned |
|
Owned |
|
Owned |
The Williams Companies, Inc.(a) |
|
|
11,613,527 |
|
|
|
22.00 |
% |
|
|
203,000,000 |
|
|
|
100 |
% |
|
|
83.91 |
% |
Williams Gas Pipeline Company, LLC(a) |
|
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|
|
|
119,932,400 |
|
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|
59.08 |
% |
|
|
46.89 |
% |
Williams Energy Services, LLC(a) |
|
|
8,787,149 |
|
|
|
16.65 |
% |
|
|
83,067,600 |
|
|
|
40.92 |
% |
|
|
35.91 |
% |
Williams Partners GP LLC(a) |
|
|
3,363,527 |
|
|
|
6.37 |
% |
|
|
|
|
|
|
|
|
|
|
1.32 |
% |
Williams Energy, L.L.C.(a) |
|
|
2,952,233 |
|
|
|
5.59 |
% |
|
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|
|
|
|
|
|
|
|
1.15 |
% |
MAPCO Inc.(a) |
|
|
2,952,233 |
|
|
|
5.59 |
% |
|
|
|
|
|
|
|
|
|
|
1.15 |
% |
Williams Partners Holdings LLC(a) |
|
|
2,826,378 |
|
|
|
5.36 |
% |
|
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|
|
|
|
|
|
|
|
1.11 |
% |
Kayne Anderson Capital Advisors,
L.P./Richard A. Kayne(b) |
|
|
4,459,179 |
|
|
|
8.45 |
% |
|
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|
|
|
|
|
|
|
|
1.74 |
% |
Alan S. Armstrong(c) |
|
|
20,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
James J. Bender(d) |
|
|
10,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Donald R. Chappel |
|
|
10,000 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
H. Michael Krimbill |
|
|
57,151 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Steven J. Malcolm(e) |
|
|
25,100 |
|
|
|
* |
|
|
|
|
|
|
|
|
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|
|
* |
|
Bill Z. Parker |
|
|
9,524 |
|
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|
* |
|
|
|
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|
|
|
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|
|
|
* |
|
Alice M. Peterson |
|
|
4,524 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Phillip D. Wright |
|
|
4,425 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
All directors and executive officers
as a group (eight persons) |
|
|
140,724 |
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
* |
|
Percentage of common units beneficially owned is based on 52,777,452 common units outstanding.
Percentage of Class C units owned is based on 203,000,000 Class C units outstanding. Percentage of
total units beneficially owned is based on 255,777,452 common units and Class C units outstanding.
Our general partner, Williams Partners GP LLC, also owns all of our 2% general partner
interest and IDRs.
|
|
|
* |
|
Less than 1%. |
|
(a) |
|
As noted in the Schedule 13D/A filed with the SEC on February 19, 2010, The Williams Companies, Inc. is
the ultimate parent company of Williams Energy Services, LLC, Williams Partners GP LLC, Williams Energy,
L.L.C., Williams Discovery Pipeline LLC, Williams Partners Holdings LLC, Williams Gas Pipeline LLC and
Williams Gulfstream Pipeline LLC and may, therefore, be deemed to beneficially own the units held by each
of these companies. The Williams Companies, Inc.s common stock is |
121
|
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|
|
|
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). WGP Gulfstream Pipeline Company, L.L.C. is the record holder of
4,242,700 Class C units. Williams Gas Pipeline Company LLC is the record owner of 115,689,700 Class C
units, and, as the sole member of WGP Gulfstream Pipeline Company, L.L.C., may, pursuant to Rule 13d-3,
be deemed to beneficially own the Class C units owned by WGP Gulfstream Pipeline Company, L.L.C. Williams
Discovery Pipeline LLC is the record holder of 1,425,466 common units. Williams Partners Holdings LLC is
the record holder of 2,826,378 common units. Williams Energy, L.L.C. is the record holder of 2,952,233
common units. Williams Partners GP LLC is the record holder of 3,363,527 common units. Williams Energy
Services, LLC is the record owner of 1,045,923 common units and, as the sole stockholder of MAPCO Inc.
and the sole member of Williams Discovery Pipeline LLC and Williams Partners GP LLC, may, pursuant to
Rule 13d-3, be deemed to beneficially own the units beneficially owned by MAPCO Inc., Williams Discovery
Pipeline LLC and Williams Partners GP LLC. MAPCO Inc., as the sole member of Williams Energy, L.L.C.,
may, pursuant to Rule 13d-3, be deemed to beneficially own the units held by Williams Energy, L.L.C. The
address of these companies is One Williams Center, Tulsa, Oklahoma 74172. |
|
(b) |
|
Based solely on the Schedule 13G/A filed with the SEC on February 12, 2010, Kayne Anderson Capital
Advisors, L.P. (Kayne Capital), an investment advisor registered under Section 203 of the Investment
Advisors Act of 1940, and Richard A. Kayne, a U.S. citizen, may be deemed to be the beneficial owner of
units owned by investment accounts (investment limited partnerships, a registered investment company and
institutional accounts) managed, with discretion to purchase or sell securities, by Kayne Capital. The
Schedule 13G notes that Mr. Kayne is the controlling shareholder of the corporate owner of Kayne Anderson
Investment Management, Inc., the general partner of Kayne Capital, and is also a limited partner of each
of the limited partnerships and a shareholder of the registered investment company. The address of Kayne
Capital and Mr. Kayne is 1800 Avenue of the Stars, Second Floor, Los Angeles, California 90067. |
|
(c) |
|
Mr. Armstrong is the trustee of The Shelly Stone Armstrong Trust dated August 10, 2004, and has the right
to receive or the power to direct the receipt of dividends from, or the proceeds from the sale of, 10,000
common units that are held by the trust. |
|
(d) |
|
Represents units beneficially owned by Mr. Bender that are held by the James J. Bender Revocable Trust. |
|
(e) |
|
Represents units beneficially owned by Mr. Malcolm that are held by the Steven J. Malcolm Revocable Trust. |
122
The following table sets forth, as of February 1, 2010, the number of shares of common stock
of The Williams Companies, Inc. owned by each of the executive officers and directors of our
general partner and all directors and executive officers of our general partner as a group.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares of Common |
|
|
|
|
|
|
|
|
Stock Owned |
|
Shares Underlying |
|
|
|
|
|
|
Directly or |
|
Options Exercisable |
|
|
|
|
Name of Beneficial Owner |
|
Indirectly(a) |
|
Within 60 Days(b) |
|
Total |
|
Percent of Class |
Alan S. Armstrong |
|
|
224,996 |
|
|
|
423,976 |
|
|
|
648,972 |
|
|
|
* |
|
James J. Bender |
|
|
190,585 |
|
|
|
192,455 |
|
|
|
383,040 |
|
|
|
* |
|
Donald R. Chappel |
|
|
348,550 |
|
|
|
491,051 |
|
|
|
839,601 |
|
|
|
* |
|
Steven J. Malcolm |
|
|
1,082,520 |
|
|
|
2,204,650 |
|
|
|
3,287,170 |
|
|
|
* |
|
Phillip D. Wright |
|
|
350,569 |
|
|
|
545,552 |
|
|
|
896,121 |
|
|
|
* |
|
Bill Z. Parker |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alice M. Peterson |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
H. Michael Krimbill |
|
|
10,000 |
|
|
|
|
|
|
|
10,000 |
|
|
|
* |
|
All directors and executive officers as a group (eight persons) |
|
|
2,207,220 |
|
|
|
3,857,684 |
|
|
|
6,064,904 |
|
|
|
* |
|
|
|
|
* |
|
Less than 1%. |
|
(a) |
|
Includes shares held under the terms of incentive and investment plans
as follows: Mr. Armstrong, 15 shares in The Williams Companies
Investment Plus Plan, 152,871 restricted stock units and 72,110
beneficially owned shares; Mr. Bender, 2,800 shares owned by children,
130,927 restricted stock units and 56,858 beneficially owned shares;
Mr. Chappel, 206,023 restricted stock units and 142,527 beneficially
owned shares; Mr. Malcolm, 47,998 shares in The Williams Companies
Investment Plus Plan, 370,593 restricted stock units and 663,929
beneficially owned shares; and Mr. Wright, 15,857 shares in The
Williams Investment Plus Plan, 152,871 restricted stock units and
181,841 beneficially owned shares. Restricted stock units do not
provide the holder with voting or investment power. |
|
(b) |
|
The shares indicated represent stock options granted under Williams
current or previous stock option plans, which are currently
exercisable or which will become exercisable within 60 days of
February 1, 2009. Shares subject to options cannot be voted. |
The following table sets forth, as of February 1, 2010, the number of common units of Williams
Pipeline Partners L.P. 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.
|
|
|
|
|
|
|
|
|
|
|
Common |
|
Percentage |
|
|
Units Beneficially |
|
of Common Units |
Name of Beneficial Owner |
|
Owned |
|
Beneficially Owned |
Alan S. Armstrong |
|
|
|
|
|
|
|
|
James J. Bender |
|
|
10,000 |
|
|
|
* |
|
Donald R. Chappel |
|
|
10,000 |
|
|
|
* |
|
Steven J. Malcolm |
|
|
10,000 |
|
|
|
* |
|
Phillip D. Wright |
|
|
10,100 |
|
|
|
* |
|
Bill Z. Parker |
|
|
|
|
|
|
|
|
Alice M. Peterson |
|
|
|
|
|
|
|
|
H. Michael Krimbill |
|
|
|
|
|
|
|
|
All directors and executive officers as a group (eight persons) |
|
|
40,100 |
|
|
|
* |
|
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information concerning common units that were potentially subject
to issuance under the Williams Partners GP LLC Long-Term Incentive Plan as of December 31, 2010.
For more information about this plan, which did not require
123
approval by our limited partners, please read Note 15, Long-Term Incentive Plan, of our Notes
to Consolidated Financial Statements and Executive Compensation Long-Term Incentive Plan.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities |
|
|
|
|
|
|
|
|
|
|
Remaining Available |
|
|
Number of Securities |
|
Weighted-Average |
|
for Future Issuance |
|
|
to be Issued Upon |
|
Exercise Price of |
|
Under Equity |
|
|
Exercise of Outstanding |
|
Outstanding |
|
Compensation Plan |
|
|
Options, Warrants |
|
Options, Warrants |
|
(Excluding Securities |
|
|
and Rights |
|
and Rights |
|
Reflected in Column(a)) |
Plan Category |
|
(a) |
|
(b) |
|
(c) |
Equity compensation plans approved by security holders |
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plans not approved by security holders. |
|
|
|
|
|
|
|
|
|
|
686,597 |
|
Total |
|
|
|
|
|
|
|
|
|
|
686,597 |
|
Item 13. Certain Relationships and Related Transactions, and Director Independence
Transactions with Related Persons
As of February 18, 2010, our general partner and its affiliates own 11,613,527 common units
and 203,000,000 Class C units. The Class C units are not publicly traded. Our Class C units are
identical to our common units except that the quarterly distribution they receive with respect to
first quarter 2010 will be prorated to reflect the fact that the Class C units were not outstanding
during the full quarterly period. The Class C units will automatically convert into common units
following the record date for the distribution with respect to the first quarter in 2010.
Williams ownership in the common units and Class C units represents an approximate 82% limited
partner interest in us.
Williams also indirectly owns 100% of our general partner, which allows it to control us.
Certain officers and directors of our general partner also serve as officers and/or directors of
Williams. In addition, our general partner owns a 2% general partner interest and incentive
distribution rights in us.
In addition to the related transactions and relationships discussed below, information about
such transactions and relationships is included in Note 6, Related Party Transactions, of our Notes
to Consolidated Financial Statements and is incorporated herein by reference in its entirety.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments made or to be made by us to our
general partner and its affiliates, which include Williams, in connection with the ongoing
operation and liquidation of 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 |
Distributions of available cash to our general
partner and its affiliates
|
|
We will generally make
cash distributions 98%
to unitholders,
including our general
partner and its
affiliates as holders of
an aggregate of
11,613,527 common units,
203,000,000 Class C
units and the remaining
2% to our general
partner. |
|
|
|
|
|
In addition, if
distributions exceed the
minimum quarterly
distribution and other
higher target levels,
our general partner will
be entitled to
increasing percentages
of the distributions, up
to 50% of the
distributions above the
highest target level. We
refer to the rights to
the increasing
distributions as
incentive distribution
rights. For further
information about
distributions, please
read Market for
Registrants Common
Equity, Related
Stockholder Matters and
Issuer Purchases of
Equity Securities. |
|
|
|
Reimbursement of expenses to our general partner
|
|
Our general partner does not receive a management fee or other compensation for |
124
|
|
|
|
|
Operational Stage |
and its affiliates
|
|
the management of our
partnership. Our general
partner and its
affiliates are
reimbursed, however, for
all direct and indirect
expenses incurred on our
behalf. Our general
partner determines the
amount of these
expenses. |
|
|
|
Withdrawal or removal of our general partner
|
|
If our general partner
withdraws or is removed,
its general partner
interest and its
incentive distribution
rights will either be
sold to the new general
partner for cash or
converted into common
units, in each case for
an amount equal to the
fair market value of
those interests. |
|
|
|
|
|
Liquidation Stage |
|
|
|
Liquidation
|
|
Upon our liquidation,
the partners, including
our general partner,
will be entitled to
receive liquidating
distributions according
to their particular
capital account
balances. |
Reimbursement of Expenses of Our General Partner
Our general partner does not receive any management fee or other compensation for its
management of our business. However, we reimburse our general partner for expenses incurred on our
behalf, including expenses incurred in compensating employees of an affiliate of our general
partner who perform services on our behalf. These expenses include all allocable expenses necessary
or appropriate to the conduct of our business. Our partnership agreement provides that our general
partner will determine in good faith the expenses that are allocable to us. There is no minimum or
maximum amount that may be paid or reimbursed to our general partner for expenses incurred on our
behalf, except that pursuant to an omnibus agreement, Williams provided a partial credit for
general and administrative expenses that we incurred for a period of five years following our
initial public offering (IPO) of common units in August 2005. Please read Initial Omnibus
Agreement below for more information.
For
the fiscal year ended December 31, 2009, our general partner
allocated $219,546 of
salary and non-equity incentive plan compensation expense to us for Steven J. Malcolm, the chairman
of the board and chief executive officer of our general partner,
$108,733 of salary and
non-equity incentive plan compensation expense to us for Donald R. Chappel, the chief financial
officer of our general partner, $289,160 of salary and non-equity incentive plan compensation
expense to us for Alan S. Armstrong, the senior vice president-midstream of our general partner,
$79,539 of salary and non-equity incentive plan compensation expense to us for James J. Bender,
the general counsel of our general partner and $55,882 of salary and non-equity incentive plan
compensation expense to us for Rodney J. Sailor, who served as a director of our general partner
until February 17, 2010 and is also a non-executive officer and employee of Williams. Our general
partner also allocated to us $238,302 for
Mr. Malcolm, $107,959 for Mr. Chappel,
$286,089 for
Mr. Armstrong, $70,438 for Mr. Bender and
$33,835 for Mr. Sailor, which expenses are
attributable to additional compensation paid to each of them and other employment-related expenses,
including Williams restricted stock unit and stock option awards, retirement plans, health and
welfare plans, employer-related payroll taxes, matching contributions made under a Williams 401(k)
plan and premiums for life insurance. Our general partner also allocated to us a portion of
Williams expenses related to perquisites for each of Messrs. Malcolm, Chappel, Bender and
Armstrong, which allocation did not exceed $10,000 for any of these persons. The foregoing amounts
exclude expenses allocated by Williams to Discovery, Wamsutter and the Contributed Entities. No
awards were granted to our general partners executive officers under the Williams Partners GP LLC
Long-Term Incentive Plan in 2008 or 2009. The total compensation received by Mr. Malcolm, the
chairman of the board and chief executive officer of our general partner who is also the chairman,
president and chief executive officer of Williams, Mr. Chappel, the chief financial officer of our
general partner who is also the chief financial officer of Williams, and Messrs. Armstrong and
Wright, senior vice presidents of our general partner who are also senior vice presidents of
Williams, will be set forth in the proxy statement for Williams 2010 annual meeting of
stockholders which will be available upon its filing on the SECs website at http://www.sec.gov and
on Williams website at http://www.williams.com under the heading Investors SEC Filings.
For the year ended December 31, 2009, we incurred approximately $95.5 million in total
operating and maintenance and general and administrative expenses from Williams incurred on our
behalf pursuant to the partnership agreement.
Initial Omnibus Agreement
Upon the closing of our IPO, we entered into an omnibus agreement with Williams and its
affiliates that was not the result of arms-length negotiations. The omnibus agreement governs our
relationship with Williams regarding the following matters:
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reimbursement of certain general and administrative expenses; |
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indemnification for certain environmental liabilities, tax liabilities and right-of-way
defects; |
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reimbursement for certain expenditures; and |
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a license for the use of certain software and intellectual property. |
General and Administrative Expenses
In our initial omnibus agreement, Williams provided us with a five-year partial credit for
general and administrative (G&A) expenses incurred on our behalf. In 2007, 2008 and 2009, the
amounts of the G&A credit were $2.4 million, $1.6 million and $0.8 million, respectively. 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.
In 2009, our omnibus agreement with Williams was amended to increase the aggregate amount of
the credit we could receive related to certain general and administrative expenses for 2009.
Consequently, for 2009, Williams provided an additional $1.0 million credit, in addition to the
$0.8 million annual credit previously provided under the original omnibus agreement. We recorded
total general and administrative expenses (including those expenses that are subject to the credit
by Williams) as an expense, and we recorded the credits as capital contributions from Williams.
Accordingly, our net income did not reflect the benefit of the credit received from Williams.
However, the costs subject to this credit will be allocated entirely to our general partner. As a
result, the net income allocated to limited partners on a per-unit basis reflected the benefit of
this credit. We expect to receive an additional $0.8 million credit in 2010 from Williams under
the 2009 omnibus amendment.
Indemnification for Environmental and Related Liabilities
In our initial omnibus agreement, 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 our initial public offering. These liabilities
include both known and unknown environmental and related liabilities, such as remediation costs
associated with the KDHE Consent Orders and certain NGLs associated with our Conway storage
facilities.
Williams will not be required to indemnify us for any project management or monitoring costs.
This indemnification obligation terminated in August 2008, 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. Please read
Managements Discussion and Analysis of Financial Condition and Results of Operations
Environmental. In addition, we are not entitled to indemnification until the aggregate amounts of
claims exceed $250,000. Liabilities resulting from a change of law after the closing of our IPO are
excluded from the environmental indemnity by Williams for the unknown environmental liabilities.
Williams will also indemnify us for liabilities related to certain income tax liabilities
attributable to the operation of the assets contributed to us in connection with our IPO prior to
the time they were contributed.
For the year ended December 31, 2009, Williams indemnified us $0.4 million for Conways
KDHE-related compliance. Including 2009, Williams has indemnified us for an aggregate of $7.1
million pursuant to the omnibus agreement.
Reimbursement for Certain Expenditures Attributable to Discovery
Williams agreed to reimburse us for certain capital expenditures, subject to limits, including
certain excess capital expenditures in connection with Discoverys Tahiti pipeline lateral
expansion project. The initial expected cost of the Tahiti pipeline lateral expansion project was
approximately $69.5 million, of which our 40% share, included in the IPO and reimbursed under the
omnibus agreement, was approximately $27.8 million. Williams agreed to reimburse us for the excess
(up to $3.4 million) of the total cost of the Tahiti pipeline lateral expansion project above the
amount of the required escrow deposit ($24.4 million) attributable to our 40% interest in
Discovery, included in the IPO and reimbursed under the omnibus agreement. The cost of the Tahiti
pipeline lateral expansion project, which was completed in second quarter 2009, was $76.2 million.
Williams reimbursed us $1.8 million in 2009 and an aggregate $3.4 million over the life of the
project, for Discoverys capital calls related to this project.
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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.
Amendments
The omnibus agreement may not be amended without the prior approval of the conflicts committee
if the proposed amendment will, in the reasonable discretion of our general partner, adversely
affect holders of our common units. Please read the discussion of the amendment related to the
Dropdown discussed below in Amendment to our Limited Partnership Agreement
Competition
Williams is not restricted under the omnibus agreement from competing with us. Williams may
acquire, construct or dispose of additional midstream or other assets in the future without any
obligation to offer us the opportunity to purchase or construct those assets.
Credit Facilities
Working Capital Facility
In February 2010, we established a new $1.75 billion senior unsecured revolving three-year
credit facility (New Credit Facility) with Citibank, N.A. as administrative agent and Transco and
Northwest Pipeline as co-borrowers. After this transaction, we terminated our $20.0 million
working capital revolving credit facility with Williams as the lender. As of December 31, 2009, we
had no outstanding borrowings under the revolving credit facility with Williams.
Wamsutter Credit Facility
Pursuant to the Dropdown, the $20.0 million revolving credit facility that Wamsutter had with
Williams as the lender was terminated. As of December 31, 2009, Wamsutter had no outstanding
borrowings under the credit facility.
Wamsutter Limited Liability Company Agreement
In connection with the Wamsutter Ownership Interests in December 2007, we and an affiliate of
Williams entered into an amended and restated limited liability company agreement for Wamsutter.
This agreement governed the ownership and management of Wamsutter and provided for quarterly
distributions of available cash to the members.
Additionally, Wamsutters limited liability company agreement appointed Williams as the
operator. As such, effective December 1, 2007 Williams was reimbursed on a monthly basis for all
direct and indirect expenses it incurred on behalf of Wamsutter including Wamsutters allocable
share of general and administrative costs.
In connection with the closing of the Dropdown, the Wamsutter Limited Liability Company
Agreement was amended to reflect that we are the sole member.
Discovery Operating and Maintenance Agreements
Discovery is party to three operating and maintenance agreements with Williams: one relating
to Discovery Producer Services LLC, one relating to Discovery Gas Transmission LLC and another
relating to the Paradis Fractionation Facility and the Larose Gas Processing Plant. Under these
agreements, Discovery is required to reimburse Williams for direct payroll and employee benefit
costs incurred on Discoverys behalf. Most costs for materials, services and other charges are
third-party charges and are invoiced directly to Discovery. Discovery is required to pay Williams a
monthly operation and management fee to cover the cost of accounting services, computer systems and
management services provided to Discovery under each of these agreements. Discovery also pays
Williams a project management fee to cover the cost of managing capital projects. This fee is
determined on a project by project basis.
For the year ended December 31, 2009, Discovery reimbursed Williams $5.4 million for direct
payroll and employee benefit costs, as well as $0.3 million for capitalized labor costs, pursuant
to the operating and maintenance agreements and paid Williams
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$6.0 million for operation and management fees, as well as a $0.3 million fee for managing
capitalized projects, pursuant to the operating and maintenance agreements.
Natural Gas and NGL Purchasing Contracts
Certain subsidiaries of Williams market substantially all of the NGLs and excess natural gas
to which Wamsutter and Discovery, our Conway fractionation and storage facility and our Four
Corners system control. Wamsutter and Discovery, our Conway fractionation and storage facility and
our Four Corners system conduct the sales of the NGLs and excess natural gas to which they control
pursuant to base contracts for sale and purchase of natural gas and a NGLs master purchase, sale
and exchange agreement. These agreements contain the general terms and conditions governing the
transactions such as apportionment of taxes, timing and manner of payment, choice of law and
confidentiality. Historically, the sales of natural gas and NGLs to which Wamsutter and Discovery,
our Conway fractionation and storage facility and our Four Corners system control have been
conducted at market prices with certain subsidiaries of Williams as the counter parties.
Additionally, Wamsutter and Discovery, our Conway fractionation and storage facility and our Four
Corners system may purchase natural gas to meet their fuel and other requirements and our Conway
storage facility may purchase NGLs as needed to maintain inventory balances.
For the year ended December 31, 2009, we sold $167.5 million of products to subsidiaries of
Williams that purchase substantially all of the NGLs and excess natural gas to which our Conway
fractionation and storage facility and our Four Corners system take title based on market pricing,
Wamsutter sold $95.7 million of products to subsidiaries of Williams that purchase substantially
all of the NGLs and excess natural gas to which Wamsutter takes title based on market pricing and
Discovery sold $114.7 million of products to subsidiaries of Williams that purchase substantially
all of the NGLs and excess natural gas to which Discovery controls based on market pricing.
Following the Dropdown, we will consolidate Williams NGL Marketing LLC (WNGLM), the entity which
purchased the NGLs from us. As a result, the majority of our affiliate product sales will be
eliminated against the related affiliate product cost recorded by WNGLM.
In 2009, we
entered into financial swap contracts with Williams Gas Marketing, Inc. (WGM), an affiliate of Williams, based on market
rates at the time of execution, to hedge 32 million gallons of forecasted NGL sales for the second
half of 2009 with a range of fixed prices of $0.465 per gallon to $1.404 per gallon depending on
the specific product and 4.3 million gallons of forecasted 2010 NGL sales with a fixed price of
$1.103 per gallon. In 2009, Wamsutter entered into financial swap
contracts with WGM, based on market rates at the time of execution, to hedge 21 million gallons of forecasted NGL sales for the second half of 2009 with a
range of fixed prices of $0.465 per gallon to $0.923 per gallon depending on the specific product.
Gathering, Processing and Treating Contracts
We have a gas gathering and treating contract and a gas gathering and processing contract with
an affiliate of Williams. Pursuant to the gas gathering and treating contract, our Four Corners
system gathers and treats coal seam gas delivered by the affiliate to our Four Corners gathering
systems. The term of this agreement expires on December 31, 2022, but will continue thereafter on a
year-to-year basis subject to termination by either party giving at least six months written notice
of termination prior to the expiration of each one year period.
Pursuant to gas gathering and processing contracts, our Four Corners system gathers and
processes conventional and coal seam gas delivered by the affiliate to our Four Corners gathering
systems. The primary terms of these agreements ended on March 1, 2004, but continue to remain in
effect on a year-to-year basis subject to termination by either party giving at least three months
written notice of termination prior to the expiration of each one-year period.
Revenues recognized pursuant to these contracts totaled $44.0 million in 2009.
Natural Gas Purchases
We, Wamsutter and Discovery purchase natural gas primarily for fuel and shrink replacement
from WGM, an affiliate of Williams. These purchases are made at
current market prices. For Four Corners, we purchased approximately $50.4 million of natural gas
from WGM during 2009. Wamsutter purchased approximately $20.5 million and Discovery purchased
approximately $22.9 million of natural gas for fuel and shrink replacement from WGM during 2009.
Four Corners uses waste heat from a co-generation plant located adjacent to the Milagro
treating plant. The co-generation plant is owned by an affiliate of Williams, Williams Flexible
Generation, LLC. Waste heat is required for the natural gas treating process,
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which occurs at Milagro. The charge to us for the waste heat is based on the natural gas
needed to generate this waste heat. We purchase this natural gas from WGM. Included in the $50.4
million presented in the immediately preceding paragraph is $10.5 million of natural gas purchases
made to pursuant to this arrangement. These purchases are generally made at market prices at the
time of the purchase. Following the Dropdown, we will consolidate Williams Flexible Generation,
LLC. As a result, our cost of waste heat will be eliminated against the related revenue recorded
by this entity.
For the year ended December 31, 2009 we purchased a gross amount of $9.3 million of natural
gas for our Conway fractionator from WGM.
In 2009, we entered into fixed price natural gas purchase contracts with WGM, based on market
rates at the time of execution, to hedge a range of 7 BBtu/d to 14.5 BBtu/d forecasted natural gas
purchases for shrink replacement at a range of fixed prices from $2.95 to $5.05 per MMBtu for the
last half of 2009. In 2009, Wamsutter entered into fixed price natural gas purchase contracts
with WGM, based on market rates at the time of execution, to hedge a range of 5 BBtu/d to 10 BBtu/d
forecasted natural gas purchases for shrink replacement costs at a range of fixed prices from $2.91
to $3.48 per MMBtu for the last half of 2009.
Balancing Services Agreement
We maintain a balancing services contract with WGM, an affiliate of Williams. Pursuant to this
agreement, WGM balances deliveries of natural gas processed by us between certain points on our
Four Corners gathering system. We determine on a daily basis the volumes of natural gas to be moved
between gathering systems at established interconnect points to optimize flow, an activity referred
to as crosshauling. Under the balancing services contract, WGM purchases gas for delivery to
customers at certain plant outlets and sells such volumes at other designated plant outlets to
implement the crosshaul. These purchase and sales transactions are conducted for us by WGM at
current market prices. Historically, WGM has not charged a fee for providing this service, but has
occasionally benefited from price differentials that historically existed from time to time between
the designated plant outlets. The revenues and costs related to the purchases and sales pursuant to
this arrangement have historically tended to offset each other. The term of this agreement will
expire upon six months or more written notice of termination from either party. To date, neither
party has provided six months notice to terminate the agreement.
Summary of Other Transactions with Williams
For the year ended December 31, 2009:
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we distributed $39.7 million to affiliates of Williams as quarterly distributions on
their common units, subordinated units, 2% general partner interest and incentive
distribution rights for the fourth quarter 2008 distribution period which was paid in 2009.
In 2009, Williams waived the incentive distribution rights (IDRs) related to the 2009
distribution periods. These IDRs represented $29.0 million, on an annual basis. |
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we purchased $8.7 million of NGLs to replenish deficit product positions from WNGLM based
on market pricing. Following the Dropdown, we will consolidate WNGLM. As a result, our
affiliate product costs will be eliminated against the related affiliate product sales
recorded by WNGLM. |
ADDITIONAL TRANSACTIONS WITH RELATED PERSONS ASSOCIATED WITH THE DROPDOWN
Agreements Related to the Dropdown
We,
our general partner, our operating company, other affiliates of Williams and Williams
entered into certain agreements that effected our acquisition of the Contributed Entities, and the
application of the proceeds of the offering of notes in connection with our acquisition of the
Contributed Entities. These agreements are the result of arms-length negotiations between Williams
and the conflicts committee of the board of directors of our general partner, which is composed
solely of independent directors unaffiliated with Williams.
Contribution Agreement
On February 17, 2010, we closed the transaction associated with the Contribution Agreement
with our general partner, our operating company and certain subsidiaries of Williams, pursuant to
which Williams contributed to us the ownership interests in the
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entities that make up Williams Gas Pipeline and Midstream Gas & Liquids business segments, to
the extent not already owned by us, including Williams limited and general partner interests in
Williams Pipeline Partners L.P. (WMZ), but excluding Williams Canadian, Venezuelan and olefin
operations and 25.5% of Gulfstream Natural Gas System, L.L.C. (Gulfstream). Such entities are
hereafter referred to as the Contributed Entities. The transactions associated with the
Contribution Agreement are referred to as the Dropdown. Please read Business and Properties
Recent Events the Dropdown for more information about the Contribution Agreement and the
transactions related to this agreement.
Conveyance, Contribution and Assumption Agreement
In connection with the closing of the Dropdown, the parties to the Contribution Agreement
entered into a conveyance, contribution and assumption agreement. This conveyance, contribution
and assumption agreement effected the contribution of the ownership interests in the Contributed
Entities to us and further transferred such ownership interests from us to our operating company.
Transco Administrative Services Agreement
In connection with the closing of the Dropdown, Transco entered into an administrative
services agreement with Transco Pipeline Services Company LLC, a subsidiary of Williams (Transco
Pipeline Services), pursuant to which Transco Pipeline Services will provide personnel, facilities,
goods, and equipment not otherwise provided by Transco necessary to operate Transcos businesses.
In return, Transco reimburses Transco Pipeline Services for all direct and indirect expenses
Transco Pipeline Services incurs or payments it makes (including salary, bonus, incentive
compensation, and benefits) in connection with these services.
Northwest Pipeline Administrative Services Agreement
Prior to the closing of the
Dropdown, Northwest entered into an administrative services agreement with Northwest Pipeline Services LLC, a wholly-owned subsidiary of Williams, to provide services that Northwest determines may be reasonable and necessary to operate its business, including employees, accounting, information technology, company development, operations, administration, insurance,
risk management, tax, audit,
finance, land, marketing, legal, and engineering, which services may be expanded, modified or reduced from time to time as agreed upon by the parties.
Secondment Agreement
In connection with the closing of the
Dropdown, we, our general partner and Williams entered
into a secondment agreement pursuant to which Williams agreed to cause its affiliates to provide
personnel necessary to operate, manage, maintain and report the
operating results of certain assets owned
by one of our midstream entities. During the period that such personnel are providing such
services, they are subject to the direction, supervision and control of our general partner. Our
general partner is responsible for the costs and expenses related to such services, which are
reimbursed in accordance with our partnership agreement.
Dropdown Omnibus Agreement
In connection with the closing of the Dropdown, we entered into an omnibus agreement with
Williams. Pursuant to this omnibus agreement, Williams is obligated to indemnify us from and
against or reimburse us for (i) amounts incurred by us or our subsidiaries for repair or
abandonment costs for damages to certain facilities caused by Hurricane Ike, up to a maximum of
$10,000,000, (ii) maintenance capital expenditure amounts incurred by us or our subsidiaries in
respect of certain U.S. Department of Transportation projects, up to a maximum aggregate amount of
$50,000,000, and (iii) an amount based on the amortization over time of deferred revenue amounts
that relate to cash payments received prior to the closing of the Dropdown for services to be
rendered by us in the future at the Devils Tower floating production platform located in
Mississippi Canyon Block 773. In addition, we are obligated to pay to Williams the proceeds of
certain sales of natural gas recovered from the Hester storage field pursuant to the FERC order
dated March 7, 2008, approving a settlement agreement in Docket No. RP06-569.
Limited Call Right Forbearance Agreement
In connection with the closing of the Dropdown, we entered into a limited call right
forbearance agreement with our general partner. Pursuant to this forbearance agreement, our
general partner agreed to forbear exercising a right in certain circumstances that is granted to it
under our partnership agreement. Currently, if our general partner and its affiliates hold more
than 80% of our common limited partner units, our general partner has the right to purchase all of
the remaining common limited partner units. In this forbearance agreement, our general partner
agreed not to exercise this right unless it and its affiliates hold more than 85% of our common
limited partner units. This forbearance agreement will terminate when the ownership by our general
partner and its affiliates of our common limited partner units decreases below 75% (assuming the
full conversion of Class C units that are held by our general partner and its affiliates).
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Amendment to our Limited Partnership Agreement
In connection with the closing of the Dropdown, our general partner entered into an amendment
to our partnership agreement. Pursuant to this amendment, our partnership agreement was amended to
(i) authorize the issuance of the Class C units that will comprise part of the consideration for
the Dropdown and to make certain other changes in connection with the authorization of the issuance
of the Class C units, (ii) provide for the proration of distributions, with respect to the first
fiscal quarter in which the Class C units and the additional general partner units being issued are
outstanding, on the Class C units and the additional general partner units to reflect the fact that
the Class C units and the additional general partner units will not be outstanding during the full
quarterly period, and (iii) provide that certain amounts received by us under the omnibus agreement
are to be treated as a capital contribution to us by Williams in the amount of such payment.
The Contributed Entities
Reimbursement of Expenses of Williams
Williams affiliates charge the
Contributed Entities for the payroll and benefit costs associated with the employees that operate the Contributed Entities
assets.
The Contributed Entities share of those costs
totaled $147 million for the year ended December 31, 2009.
In addition,
general and administrative services are provided to the Contributed Entities by employees of
Williams, and the Contributed Entities are charged for certain administrative expenses incurred by
Williams. These charges are either directly identifiable or allocated to their operations.
Direct charges are
for goods and services provided by Williams at their request.
Allocated charges are based on a three-factor
formula, which considers revenues; property, plant and equipment; and payroll.
The Contributed Entities
share of direct administrative expenses was $181 million for the year ended December 31, 2009.
The Contributed Entities share of allocated administrative expenses was $93 million for the year ended
December 31, 2009. In managements estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to the Contributed
Entities of their costs of doing business incurred by Williams.
Commodity Sales Contracts
The Contributed Entities sell (a) feedstock commodities to Williams Olefins, LLC (Williams
Olefins), a wholly owned subsidiary of Williams, for use in its facilities, (b) NGLs to our Conway
fractionation and storage facility for its inventory balancing needs, and (c) waste heat from their
co-generation plant to our Four Corners system for the natural gas treating process at its Milagro
treating plant. Revenues from these product sales were $84 million for the year ended December 31,
2009. These sales are generally made at market prices at the time of sale. The rate the
Contributed Entities charge for the waste heat is based on the volume and price of the natural gas
needed to generate the waste heat. Following the Dropdown, we will consolidate the entities which
sell NGLs and waste heat to Conway and Four Corners, respectively. As a result, the related
purchases and sales amounts will be eliminated.
Gathering, Processing and Treating Contracts
The Contributed Entities provide gathering, treating and processing services for Williams
Production Company (WPC), a wholly owned subsidiary of Williams, under several contracts. Revenues
from these services were $29 million for the year ended December 31, 2009. The rates charged to
provide these services are considered reasonable as compared to those that are charged to
similarly-situated nonaffiliated customers.
Transportation and Exchange Contracts
The Contributed Entities provide natural gas transportation and exchange services and rental
of communication facilities to subsidiaries of Williams. These revenues were $29 million for the
year ended December 31, 2009. The rates charged to provide sales and services to affiliates are
comparable to those that are charged to similarly-situated nonaffiliated customers.
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Commodity Purchase Contracts
The Contributed Entities purchase for resale from WPC and Williams Olefins and certain of our
subsidiaries substantially all of the NGLs to which those entities take title. The Contributed
Entities conduct the purchases of the NGLs at market prices at the time of purchase. These
purchases, excluding Wamsutter LLC, totaled $209 million for the year ended December 31, 2009. Following the Dropdown, we
will consolidate the entity that purchases these products from us. As a result, our product sales
will be eliminated against the related product cost recorded by this entity.
The Contributed Entities purchase natural gas for shrink replacement and fuel for processing
plants and the co-generation plant from WGM at market prices at the time of purchase. They also
purchase natural gas for Gas Pipelines merchant gas sales program from WGM at contract or market
prices. These purchases, excluding Wamsutter LLC, totaled $281 million for the year ended December 31, 2009.
In addition, through an agency agreement, WGM manages Transcos jurisdictional merchant gas
sales. WGM is authorized to make gas sales on Transcos behalf in order to manage its gas purchase
obligations. WGM receives all margins associated with jurisdictional merchant gas sales business
and, as Transcos agent, assumes all market and credit risk associated with such sales.
Consequently, Transcos merchant gas sales service has no impact on its operating income or results
of operations. Transcos gas sales volumes managed by WGM for the year ended December 31, 2009 in
TBtus was .4.
Other Contracts
In
2009, the Contributed Entities, excluding Wamsutter LLC, entered into
forward month financial swap contracts with WGM, based on market
rates at the time of execution, to hedge 33 million gallons of
forecasted NGL sales for the second half of 2009 with a range of
fixed prices of $.490 to $1.405 per gallon depending on the specific
product and 58 million gallons of forecasted 2010 NGL sales with
fixed prices of $.725 to $1.830 per gallon. In 2009, the Contributed
Entities, excluding Wamsutter LLC, entered into fixed price natural gas purchase contracts for
2010 with WGM, based on market rates at the time of execution, to
hedge the price of our natural gas shrink replacement costs for 41
BBtu/d at a range of fixed prices from $5.635 to $5.985 per MMBtu
The
Contributed Entities transferred a transportation capacity contract
to WGM in a previous year. To the extent WGM does not utilize this
transportation capacity for its needs (primarily transporting
third-party gas volumes), the Contributed Entities reimburse WGM for
these transportation costs. These cost reimbursements totaled $9
million in 2009.
The Contributed Entities historically participated in Williams cash management program under
unsecured promissory note agreements with Williams for both advances to and from Williams. Under
the Contribution Agreement, the outstanding advances were distributed to Williams.
In June 2009, the Contributed Entities issued a $26 million note payable to Laurel Mountain,
an equity method investee, in connection with its formation.
Review, Approval or Ratification of Transactions with Related Persons
Our partnership agreement contains specific provisions that address potential conflicts of
interest between our general partner and its affiliates, including Williams, on one hand, and us
and our subsidiaries, on the other hand. Whenever such a conflict of interest arises, our general
partner will resolve the conflict. Our general partner may, but is not required to, seek the
approval of such resolution from the conflicts committee of the board of directors of our general
partner, which is comprised of independent directors. The partnership agreement provides that our
general partner will not be in breach of its obligations under the partnership agreement or its
duties to us or to our unitholders if the resolution of the conflict is:
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approved by the conflicts committee; |
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approved by the vote of a majority of the outstanding common units, excluding any common
units owned by our general partner or any of its affiliates; |
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on terms no less favorable to us than those generally being provided to or available from
unrelated third parties; or |
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fair and reasonable to us, taking into account the totality of the relationships between
the parties involved, including other transactions that may be particularly favorable or
advantageous to us. |
If our general partner does not seek approval from the conflicts committee and the board of
directors of our general partner determines that the resolution or course of action taken with
respect to the conflict of interest satisfies either of the standards set forth in the third and
fourth bullet points above, then it will be presumed that, in making its decision, the board of
directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner
or the partnership, the person bringing or prosecuting such
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proceeding will have the burden of overcoming such presumption. Unless the resolution of a
conflict is specifically provided for in our partnership agreement, our general partner or the
conflicts committee may consider any factors it determines in good faith to consider when resolving
a conflict. When our partnership agreement requires someone to act in good faith, it requires that
person to reasonably believe that he is acting in the best interests of the partnership, unless the
context otherwise requires. See Directors, Executive Officers and Corporate Governance
Governance Board Committees Conflict Committee.
In addition, our code of business conduct and ethics requires that all employees, including
employees of affiliates of Williams who perform services for us and our general partner, avoid or
disclose any activity that may interfere, or have the appearance of interfering, with their
responsibilities to us and our unitholders. Conflicts of interest that cannot be avoided must be
disclosed to a supervisor who is then responsible for establishing and monitoring procedures to
ensure that we are not disadvantaged.
Director Independence
Please read Directors, Executive Officers and Corporate Governance Governance Director
Independence above for information about the independence of our general partners board of
directors and its committees, which information is incorporated herein by reference in its
entirety.
Item 14. Principal Accounting Fees and Services
Fees for professional services provided by our independent auditors for each of the last two
fiscal years were as follows:
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2009 |
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2008 |
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Audit Fees |
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1,111 |
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$ |
1,066 |
|
Audit-Related Fees |
|
|
|
|
|
|
|
|
Tax Fees |
|
|
35 |
|
|
|
35 |
|
All Other Fees |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,146 |
|
|
$ |
1,101 |
|
|
|
|
|
|
|
|
Fees for audit services in 2009 and 2008 include fees associated with the annual audit, the
reviews of our quarterly reports on Form 10-Q, the audit of our assessment of internal controls as
required by Section 404 of the Sarbanes-Oxley Act of 2002 and services provided in connection with
other filings with the SEC. The fees for audit services do not include audit costs for stand-alone
audits for equity investees, including Discovery or Wamsutter. Tax fees for 2009 and 2008 include
fees for review of our federal tax return. Ernst & Young LLP does not provide tax services to our
general partners executive officers.
The audit committee of our general partners board of directors is responsible for appointing,
setting compensation for and overseeing the work of Ernst & Young LLP, our independent auditors.
The audit committee has established a policy regarding pre-approval of all audit and non-audit
services provided by Ernst & Young LLP. On an ongoing basis, our general partners management
presents specific projects and categories of service to the audit committee to request advance
approval. The audit committee reviews those requests and advises management if the audit committee
approves the engagement of Ernst & Young LLP. On a quarterly basis, the management of our general
partner reports to the audit committee regarding the services rendered by, including the fees of,
the independent accountant in the previous quarter and on a cumulative basis for the fiscal year.
The audit committee may also delegate the ability to pre-approve 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. In 2009 and 2008, 100% of Ernst & Young LLPs fees were pre-approved by the
audit committee.
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) 1 and 2. Williams Partners L.P. financials
|
|
|
|
|
Page |
Covered by reports of independent auditors: |
|
|
|
|
80 |
|
|
81 |
|
|
82 |
|
|
84 |
|
|
85 |
Not covered by reports of independent auditors: |
|
|
|
|
111 |
133
All other schedules have been omitted since the required information is not present or is not
present in amounts sufficient to require submission of the schedule, or because the information
required is included in the financial statements and notes thereto.
(a)3 and (b). The following documents are included as exhibits to this report:
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
§Exhibit 2.1 |
|
|
|
Purchase and Sale Agreement, dated April 6, 2006, by and among Williams Energy
Services, LLC, Williams Field Services Group, LLC, Williams Field Services
Company, LLC, Williams Partners GP LLC, Williams Partners L.P. and Williams
Partners Operating LLC (filed on April 7, 2006 as Exhibit 2.1 to Williams Partners
L.P.s current report on Form 8-K (File No.001-32599)) and incorporated herein by
reference. |
|
|
|
|
|
§Exhibit 2.2 |
|
|
|
Purchase and Sale Agreement, dated November 16, 2006, by and among Williams Energy
Services, LLC, Williams Field Services Group, LLC, Williams Field Services
Company, LLC, Williams Partners GP LLC, Williams Partners L.P. and Williams
Partners Operating LLC (filed on November 21, 2006 as Exhibit 2.1 to Williams
Partners L.P.s current report on Form 8-K (File No.001-32599)) and incorporated
herein by reference. |
|
|
|
|
|
§Exhibit 2.3 |
|
|
|
Purchase and Sale Agreement, dated June 20, 2007, by and among Williams Energy,
L.L.C., Williams Energy Services, LLC and Williams Partners Operating LLC (filed
on June 25, 2007 as Exhibit 2.1 to Williams Partners L.P.s current report on Form
8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
§Exhibit 2.4 |
|
|
|
Purchase and Sale Agreement, dated November 30, 2007, by and among Williams Energy
Services, LLC, Williams Field Services Group, LLC, Williams Field Services
Company, LLC, Williams Partners GP LLC, Williams Partners L.P. and Williams
Partners Operating LLC (filed on December 3, 2007 as Exhibit 2.1 to Williams
Partners L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated
herein by reference. |
|
|
|
|
|
Exhibit 2.5 |
|
|
|
Contribution Agreement, dated as of January 15, 2010, by and among Williams Energy
Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline
Company, L.L.C., Williams Partners GP LLC, Williams Partners L.P., Williams
Partners Operating LLC and, for a limited purpose, The Williams Companies, Inc,
including exhibits thereto (filed on January 19, 2010 as Exhibit 10.1 to Williams
Partners L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated
herein by reference. |
|
|
|
|
|
Exhibit 3.1 |
|
|
|
Certificate of Limited Partnership of Williams Partners L.P. (filed on May 2, 2005
as Exhibit 3.1 to Williams Partners L.P.s registration statement on Form S-1
(File No. 333-124517)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 3.2 |
|
|
|
Certificate of Formation of Williams Partners GP LLC (filed on May 2, 2005 as
Exhibit 3.3 to Williams Partners L.P.s registration statement on Form S-1 (File
No. 333-124517)) and incorporated herein by reference. |
|
|
|
|
|
*Exhibit 3.3 |
|
|
|
Amended and Restated Agreement of Limited Partnership of Williams Partners L.P.
(including form of common unit certificate), as amended by Amendments Nos. 1, 2,
3, 4, 5, and 6. |
|
|
|
|
|
Exhibit 3.4 |
|
|
|
Amended and Restated Limited Liability Company Agreement of Williams Partners GP
LLC (filed on August 26, 2005 as Exhibit 3.2 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.1 |
|
|
|
Indenture, dated June 20, 2006, by and among Williams Partners L.P., Williams
Partners Finance Corporation and JPMorgan Chase Bank, N.A. (filed on June 20, 2006
as Exhibit 4.1 to Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.2 |
|
|
|
Form of 7 1/2% Senior Note due 2011 (filed on June 20, 2006 as Exhibit 1 to Rule
144A/Regulation S Appendix of Exhibit 4.1 attached to Williams Partners L.P.s
current report on Form 8-K (File No. 001-32599)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.3 |
|
|
|
Certificate of Incorporation of Williams Partners Finance Corporation (filed on
September 22, 2006 as Exhibit 4.5 to Williams Partners L.P.s registration
statement on Form S-3 (File No. 333-137562)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.4 |
|
|
|
Bylaws of Williams Partners Finance Corporation (filed on September 22, 2006 as
Exhibit 4.6 to |
134
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
Williams Partners L.P.s registration statement on Form S-3 (File
No. 333-137562)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.5
|
|
|
|
Indenture, dated December 13, 2006, by and among Williams Partners L.P., Williams
Partners Finance Corporation and The Bank of New York (filed on December 19, 2006
as Exhibit 4.1 to Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.6
|
|
|
|
Form of 7 1/4% Senior Note due 2017 (filed on December 19, 2006 as Exhibit 1 to Rule
144A/Regulation S Appendix of Exhibit 4.1 attached to Williams Partners L.P.s
current report on Form 8-K (File No. 001-32599)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.7
|
|
|
|
Indenture, dated as of February 9, 2010, between Williams Partners L.P. and The
Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit
4.1 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.8
|
|
|
|
Registration Rights Agreement, dated as of February 9, 2010, among Williams
Partners L.P. and Barclays Capital Inc. and Citigroup Global Markets Inc., each
acting on behalf of themselves and the initial purchasers listed on Schedule I
thereto (filed on February 10, 2010 as Exhibit 10.1 to Williams Partners L.P.s
current report on Form 8-K (File No. 001-32599)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.9
|
|
|
|
Limited Call Right Forbearance Agreement, dated as of February 17, 2010, by and
between Williams Partners L.P. and Williams Partners GP LLC (filed on February 22,
2010 as Exhibit 4.1 to Williams Partners L.P.s current report on Form 8-K (File
No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.10
|
|
|
|
Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline
Corporation and Chemical Bank, Trustee with regard to Northwest Pipelines 7.125%
Debentures, due 2025 (filed September 14, 1995 as Exhibit 4.1 to Northwest
Pipeline Corporations Form S-3 (File No. 033-62639)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.11
|
|
|
|
Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and
JPMorgan Chase Bank, N.A., as Trustee, with regard to Northwest Pipelines $175
million aggregate principal amount of 7.00% Senior Notes due 2016 (filed on June
23, 2006 as Exhibit 4.1 to Northwest Pipeline Corporations Form 8-K (File. No.
001-07414) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.12
|
|
|
|
Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and
The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline
Corporations Form 8-K (File No. 001-07414)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.13
|
|
|
|
Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New
York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to
Northwest Pipeline GPs Form 8-K File No. 001-07414)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.14
|
|
|
|
Registration Rights Agreement, dated as of May 23, 2008, among Northwest Pipeline
GP and Banc of America Securities, LLC, BNP Paribas Securities Corp, and Greenwich
Capital Markets, Inc., acting on behalf of themselves and the several initial
purchasers listed on Schedule I thereto (filed on May 23, 2008 as Exhibit 10.1 to
Northwest Pipeline GPs Form 8-K (File No. 001-07414)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.15
|
|
|
|
Senior Indenture, dated as of July 15, 1996 between Transcontinental Gas Pipe Line
Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1
to Transcontinental Gas Pipe Line Corporations Form S-3 (File No. 333-02155)) and
incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.16
|
|
|
|
Senior Indenture, dated as of January 16, 1998, between Transcontinental Gas Pipe
Line Corporation and Citibank, N.A., as Trustee (filed on September 8, 1997 as
Exhibit 4.1 to Transcontinental Gas Pipe Line Corporations Form S-3 (File No.
333-27311)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.17
|
|
|
|
Indenture, dated as of August 27, 2001, between Transcontinental Gas Pipe Line
Corporation and Citibank, N.A., as Trustee (filed on November 8, 2001 as Exhibit
4.1 to Transcontinental Gas Pipe Line Corporations Form S-4 (File No. 333-72982))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.18
|
|
|
|
Indenture, dated as of July 3, 2002, between Transcontinental Gas Pipe Line
Corporation and Citibank, N.A., as Trustee (filed August 14, 2002 as Exhibit 4.1
to The Williams Companies Inc.s Form 10-Q (File No. 001-07584)) and incorporated
herein by reference. |
|
|
|
|
|
Exhibit 4.19
|
|
|
|
Indenture, dated December 17, 2004, between Transcontinental Gas Pipe Line
Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on December 21, 2004
as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporations Form 8-K (File No.
001-07584)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.20
|
|
|
|
Indenture, dated as of April 11, 2006, between Transcontinental Gas Pipe Line
Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to
Transcontinental Gas Pipe Lines $200 million |
135
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental
Gas Pipe Line Corporations Form 8-K (File No. 001-07584)) and incorporated herein
by reference. |
|
|
|
|
|
Exhibit 4.21
|
|
|
|
Indenture, dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation
and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as
Exhibit 4.1 to Transcontinental Gas Pipe Line Corporations Form 8-K (File No.
001-07584)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.22
|
|
|
|
Registration Rights Agreement, dated as of May 22, 2008, among Transcontinental
Gas Pipe Line Corporation and Banc of America Securities LLC, Greenwich Capital
Markets, Inc., and J. P. Morgan Securities Inc., acting on behalf of themselves
and the several initial purchasers listed on Schedule I thereto (filed on May 23,
2008 as Exhibit 10.1 to Transcontinental Gas Pipe Line Corporations Form 8-K
(File No. 001-07584)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.1
|
|
|
|
Credit Agreement, dated as of December 11, 2007, by and among Williams Partners
L.P., the lenders party hereto, Citibank, N.A., as Administrative Agent and
Issuing Bank, and The Bank of Nova Scotia, as Swingline Lender (filed on December
17, 2007 as Exhibit 10.5 to Williams Partners L.P.s current report on Form 8-K
(File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
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. (filed on
August 26, 2005 as Exhibit 10.1 to Williams Partners L.P.s current report on Form
8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.3
|
|
|
|
Amendment No. 1 to 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.
(filed on April 20, 2009 as Exhibit 10.1 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.4
|
|
|
|
Omnibus Agreement, dated as of February 17, 2010, by and between The Williams
Companies, Inc. and Williams Partners L.P. (filed on February 22, 2010 as Exhibit
10.2 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.5
|
|
|
|
Contribution, Conveyance and Assumption Agreement, dated August 23, 2005, by and
among Williams Partners L.P., Williams Energy, L.L.C., Williams Partners GP LLC,
Williams Partners Operating LLC, Williams Energy Services, LLC, Williams Discovery
Pipeline LLC, Williams Partners Holdings LLC and Williams Natural Gas Liquids,
Inc. (filed on August 26, 2005 as Exhibit 10.3 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.6
|
|
|
|
Contribution, Conveyance and Assumption Agreement, dated June 20, 2006, by and
among Williams Energy Services, LLC, Williams Field Services Company, LLC,
Williams Field Services Group, LLC, Williams Partners GP LLC, Williams Partners
L.P. and Williams Partners Operating LLC (filed on June 20, 2006 as Exhibit 10.1
to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599)) and
incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.7
|
|
|
|
Contribution, Conveyance and Assumption Agreement, dated June 20, 2006, by and
among Williams Field Services Company, LLC and Williams Four Corners LLC (filed on
June 20, 2006 as Exhibit 10.4 to Williams Partners L.P.s current report on Form
8-K (File No. 001-32599) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.8
|
|
|
|
Contribution, Conveyance and Assumption Agreement, dated December 13, 2006, by and
among Williams Energy Services, LLC, Williams Field Services Company, LLC,
Williams Field Services Group, LLC, Williams Partners GP LLC, Williams Partners
L.P. and Williams Partners Operating LLC (filed on December 19, 2006 as Exhibit
10.1 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.9
|
|
|
|
Contribution, Conveyance and Assumption Agreement, dated December 11, 2007, by and
among Williams Energy Services, LLC, Williams Field Services Company, LLC,
Williams Field Services Group, LLC, Williams Partners GP LLC, Williams Partners
L.P. and Williams Partners Operating LLC (filed on December 17, 2007 as Exhibit
10.2 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.10
|
|
|
|
Conveyance, Contribution and Assumption Agreement, dated as of February 17, 2010,
by and among Williams Energy Services, LLC, Williams Gas Pipeline Company, LLC,
WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC, Williams
Partners L.P. and Williams Partners Operating |
136
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
LLC (filed on February 22, 2010 as Exhibit 10.1 to Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.11
|
|
|
|
Assignment Agreement, dated December 11, 2007, by and between Williams Field
Services Company, LLC and Wamsutter LLC (filed on December 17, 2007 as Exhibit
10.1 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.12
|
|
|
|
Third Amended and Restated Limited Liability Company Agreement for Discovery
Producer Services LLC (filed on June 24, 2005 as Exhibit 10.7 to Amendment No. 1
to Williams Partners L.P.s registration statement on Form S-1 (File No.
333-124517)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.13
|
|
|
|
Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement
for Discovery Producer Services LLC (filed on August 8, 2006 as Exhibit 10.6 to
Williams Partners L.P.s quarterly report on Form 10-Q (File No. 001-32599)) and
incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.14
|
|
|
|
Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement
for Discovery Producer Services LLC (filed on August 6, 2009 as Exhibit 10.3 to
Williams Partners L.P.s quarterly report on Form 10-Q (File No. 001-32599)) and
incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.15
|
|
|
|
Amended and Restated Limited Liability Company Agreement of Wamsutter LLC, dated
December 1, 2007, by and between Williams Field Services Company, LLC and Williams
Partners Operating LLC (filed on December 17, 2007 as Exhibit 10.3 to Williams
Partners L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated
herein by reference. |
|
|
|
|
|
Exhibit 10.16
|
|
|
|
Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of
Wamsutter LLC, dated as of February 17, 2010, by and between Williams Field
Services Company, LLC and Williams Partners Operating LLC (filed on February 22,
2010 as Exhibit 10.4 to Williams Partners L.P.s current report on Form 8-K (File
No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
#Exhibit 10.17
|
|
|
|
Williams Partners GP LLC Long-Term Incentive Plan (filed on August 26, 2005 as
Exhibit 10.2 to Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
|
|
|
|
|
#Exhibit 10.18
|
|
|
|
Amendment to the Williams Partners GP LLC Long-Term Incentive Plan, dated November
28, 2006 (filed on December 4, 2006 as Exhibit 10.1 to Williams Partners L.P.s
current report on Form 8-K (File No. 001-32599)) and incorporated herein by
reference. |
|
|
|
|
|
#Exhibit 10.19
|
|
|
|
Amendment No. 2 to the Williams Partners GP LLC Long-Term Incentive Plan, dated
December 2, 2008 (filed on February 26, 2009, as Exhibit 10.4 to Williams Partners
L.P.s annual report on Form 10-K (File No. 001-32599)) and incorporated herein by
reference. |
|
|
|
|
|
#Exhibit 10.20
|
|
|
|
Director Compensation Policy dated November 29, 2005, as revised May 28, 2009
(filed on August 6, 2009 as Exhibit 10.2 to Williams Partners L.P.s quarterly
report on Form 10-Q (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
#Exhibit 10.21
|
|
|
|
Form of Grant Agreement for Restricted Units (filed on December 1, 2005 as Exhibit
10.2 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.22
|
|
|
|
Administrative Services Agreement between Northwest Pipeline Services LLC and
Northwest Pipeline GP, dated October 1, 2007 (filed on January 30, 2008 as Exhibit
10.1 to Williams Pipeline Partners L.P.s Form 8-K (File No. 001-33917) and
incorporated herein by reference). |
|
|
|
|
|
Exhibit 10.23
|
|
|
|
Administrative Services Agreement, dated as of February 17, 2010, by and between
Transco Pipeline Services LLC and Transcontinental Gas Pipe Line Company, LLC
(filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.24
|
|
|
|
Credit Agreement, dated as of February 17, 2010, by and among Williams Partners
L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the
lenders party thereto and Citibank, N.A., as Administrative Agent (filed on
February 22, 2010 as Exhibit 10.5 to Williams Partners L.P.s current report on
Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
*Exhibit 12
|
|
|
|
Computation of Ratio of Earnings to Fixed Charges |
|
|
|
|
|
*Exhibit 21
|
|
|
|
List of subsidiaries of Williams Partners L.P. |
|
|
|
|
|
*Exhibit 23.1
|
|
|
|
Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP. |
|
|
|
|
|
*Exhibit 23.2
|
|
|
|
Consent of Independent Auditors, Ernst & Young LLP. |
|
|
|
|
|
*Exhibit 24
|
|
|
|
Power of attorney. |
137
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
*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. |
|
|
|
* |
|
Filed herewith. |
|
§ |
|
Pursuant to item 601(b) (2) of Regulation S-K, the registrant agrees
to furnish supplementally a copy of any omitted exhibit or schedule to
the SEC upon request. |
|
# |
|
Management contract or compensatory plan or arrangement. |
|
(c) |
|
Wamsutter LLC financial statements and notes thereto Discovery
Producer Services LLC financial statements and notes thereto |
138
Report of Independent Auditors
To the Management Committee of
Wamsutter LLC
We have audited the accompanying balance sheets of Wamsutter LLC as of December 31, 2009 and 2008,
and the related statements of income, members capital, and cash flows for each of the three years
in the period ended December 31, 2009. These financial statements are the responsibility of the
Companys management. Our responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United
States. Those standards require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. We were not engaged to
perform an audit of Wamsutter LLCs internal control over financial reporting. Our audits included
consideration of internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of Wamsutter LLCs internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the financial position of Wamsutter LLC at December 31, 2009 and 2008, and the results of
its operations and its cash flows for each of the three years in the period ended December 31, 2009
in conformity with U.S. generally accepted accounting principles.
|
|
|
|
|
|
|
|
|
/s/ Ernst & Young LLP
|
|
|
|
|
|
Tulsa, Oklahoma |
|
|
February 25, 2010 |
|
|
139
WAMSUTTER LLC
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Accounts receivable: |
|
|
|
|
|
|
|
|
Trade |
|
$ |
6,116 |
|
|
$ |
8,755 |
|
Affiliate |
|
|
10,895 |
|
|
|
7,178 |
|
Other |
|
|
252 |
|
|
|
100 |
|
Product imbalance |
|
|
4,199 |
|
|
|
1,032 |
|
Other current assets |
|
|
229 |
|
|
|
82 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
21,691 |
|
|
|
17,147 |
|
Property, plant and equipment, net |
|
|
408,429 |
|
|
|
318,072 |
|
Other noncurrent assets |
|
|
3,071 |
|
|
|
468 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
433,191 |
|
|
$ |
335,687 |
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS CAPITAL |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable: |
|
|
|
|
|
|
|
|
Trade |
|
$ |
15,215 |
|
|
$ |
9,582 |
|
Affiliate |
|
|
2,734 |
|
|
|
2,407 |
|
Product imbalance |
|
|
986 |
|
|
|
1,753 |
|
Accrued liabilities |
|
|
10,285 |
|
|
|
3,218 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
29,220 |
|
|
|
16,960 |
|
Other noncurrent liabilities |
|
|
4,846 |
|
|
|
4,353 |
|
Commitments and contingencies (Note 10) |
|
|
|
|
|
|
|
|
Members capital |
|
|
399,125 |
|
|
|
314,374 |
|
|
|
|
|
|
|
|
Total liabilities and members capital |
|
$ |
433,191 |
|
|
$ |
335,687 |
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
140
WAMSUTTER LLC
STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Product sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
95,734 |
|
|
$ |
134,776 |
|
|
$ |
93,744 |
|
Third-party |
|
|
15,348 |
|
|
|
27,384 |
|
|
|
7,447 |
|
Gathering and processing services |
|
|
79,523 |
|
|
|
68,670 |
|
|
|
67,904 |
|
Other revenues |
|
|
5,282 |
|
|
|
8,704 |
|
|
|
6,214 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
195,887 |
|
|
|
239,534 |
|
|
|
175,309 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Product cost: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
33,928 |
|
|
|
63,064 |
|
|
|
34,973 |
|
Third-party |
|
|
18,372 |
|
|
|
15,745 |
|
|
|
11,066 |
|
Operating and maintenance expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
2,749 |
|
|
|
(1,513 |
) |
|
|
36 |
|
Third-party |
|
|
17,778 |
|
|
|
22,486 |
|
|
|
18,221 |
|
Depreciation and accretion |
|
|
22,235 |
|
|
|
21,182 |
|
|
|
18,424 |
|
General and administrative expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
14,801 |
|
|
|
12,837 |
|
|
|
11,825 |
|
Third-party |
|
|
406 |
|
|
|
670 |
|
|
|
798 |
|
Taxes other than income |
|
|
2,014 |
|
|
|
1,868 |
|
|
|
1,637 |
|
Other (income) expense net |
|
|
(448 |
) |
|
|
(569 |
) |
|
|
944 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
111,835 |
|
|
|
135,770 |
|
|
|
97,924 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
84,052 |
|
|
$ |
103,764 |
|
|
$ |
77,385 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
141
WAMSUTTER LLC
STATEMENT OF MEMBERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Class C* |
|
|
|
|
|
|
Predecessor |
|
|
Williams |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Owners |
|
|
Partners |
|
|
Williams |
|
|
|
|
|
|
Williams |
|
|
|
|
|
|
Equity |
|
|
Class A |
|
|
Class B |
|
|
Williams |
|
|
Partners |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
Balance December 31, 2006 |
|
$ |
263,245 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
263,245 |
|
Net income through November 30, 2007 |
|
|
70,023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70,023 |
|
Distributions |
|
|
(55,006 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(55,006 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
278,262 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
278,262 |
|
Conversion of predecessor owners equity to
member capital |
|
|
(278,262 |
) |
|
|
276,262 |
|
|
|
|
|
|
|
1,000 |
|
|
|
1,000 |
|
|
|
|
|
Net income December 2007 |
|
|
|
|
|
|
7,362 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,362 |
|
Capital contributions |
|
|
|
|
|
|
|
|
|
|
1,088 |
|
|
|
|
|
|
|
|
|
|
|
1,088 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007 |
|
|
|
|
|
|
283,624 |
|
|
|
1,088 |
|
|
|
1,000 |
|
|
|
1,000 |
|
|
|
286,712 |
|
Net income 2008 |
|
|
|
|
|
|
73,312 |
|
|
|
|
|
|
|
15,226 |
|
|
|
15,226 |
|
|
|
103,764 |
|
Capital contributions |
|
|
|
|
|
|
3,658 |
|
|
|
31,240 |
|
|
|
|
|
|
|
|
|
|
|
34,898 |
|
Transition support contribution (distribution) |
|
|
|
|
|
|
(7,614 |
) |
|
|
7,614 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions |
|
|
|
|
|
|
(72,050 |
) |
|
|
|
|
|
|
(19,475 |
) |
|
|
(19,475 |
) |
|
|
(111,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2008 |
|
|
|
|
|
|
280,930 |
|
|
|
39,942 |
|
|
|
(3,249 |
) |
|
|
(3,249 |
) |
|
|
314,374 |
|
Net income 2009 |
|
|
|
|
|
|
84,052 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84,052 |
|
Capital contributions |
|
|
|
|
|
|
1,011 |
|
|
|
84,688 |
|
|
|
|
|
|
|
|
|
|
|
85,699 |
|
Transition support contribution (distribution) |
|
|
|
|
|
|
(9,718 |
) |
|
|
9,718 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions |
|
|
|
|
|
|
(70,750 |
) |
|
|
|
|
|
|
(4,496 |
) |
|
|
(9,754 |
) |
|
|
(85,000 |
) |
Class C units issued |
|
|
|
|
|
|
(4,621 |
) |
|
|
(1,439 |
) |
|
|
1,439 |
|
|
|
4,621 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2009 |
|
$ |
|
|
|
$ |
280,904 |
|
|
$ |
132,909 |
|
|
$ |
(6,306 |
) |
|
$ |
(8,382 |
) |
|
$ |
399,125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Williams Partners and Williams held 108.45 and 48.79 Class C units,
respectively, as of December 31, 2009. |
See accompanying notes to financial statements.
142
WAMSUTTER LLC
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
84,052 |
|
|
$ |
103,764 |
|
|
$ |
77,385 |
|
Adjustments to reconcile to cash provided by operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and accretion |
|
|
22,235 |
|
|
|
21,182 |
|
|
|
18,424 |
|
Provision for loss on property plant & equipment |
|
|
|
|
|
|
|
|
|
|
1,392 |
|
Cash provided (used) by changes in current assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(1,230 |
) |
|
|
7,334 |
|
|
|
(16,655 |
) |
Other current assets |
|
|
(147 |
) |
|
|
1,627 |
|
|
|
(29 |
) |
Accounts payable |
|
|
5,699 |
|
|
|
(753 |
) |
|
|
6,113 |
|
Product imbalance |
|
|
(3,934 |
) |
|
|
463 |
|
|
|
(1,335 |
) |
Accrued liabilities |
|
|
322 |
|
|
|
115 |
|
|
|
(662 |
) |
Deferred revenue |
|
|
400 |
|
|
|
335 |
|
|
|
882 |
|
Other, including changes in other noncurrent assets and liabilities |
|
|
(2,560 |
) |
|
|
(426 |
) |
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
104,837 |
|
|
|
133,641 |
|
|
|
85,541 |
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(105,536 |
) |
|
|
(57,539 |
) |
|
|
(31,624 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(105,536 |
) |
|
|
(57,539 |
) |
|
|
(31,624 |
) |
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Distributions |
|
|
(85,000 |
) |
|
|
(111,000 |
) |
|
|
(55,005 |
) |
Capital contributions |
|
|
85,699 |
|
|
|
34,898 |
|
|
|
1,088 |
|
Transition support payments received from Class B member |
|
|
9,718 |
|
|
|
7,614 |
|
|
|
|
|
Transition support payments distributed to Class A member |
|
|
(9,718 |
) |
|
|
(7,614 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities |
|
|
699 |
|
|
|
(76,102 |
) |
|
|
(53,917 |
) |
|
|
|
|
|
|
|
|
|
|
Increase in cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
143
WAMSUTTER LLC
NOTES TO FINANCIAL STATEMENTS
Note 1. Basis of Presentation
References in this report to we, our, us or like terms refer to Wamsutter LLC. In June
2007, Williams Field Services Company, LLC (WFSC) formed Wamsutter LLC, and on December 11, 2007,
WFSC conveyed a natural gas gathering and processing system in Wyoming previously held by WFSC (the
Wamsutter assets) into Wamsutter LLC in connection with the acquisition of certain ownership
interests in Wamsutter LLC by Williams Partners L.P. (the Partnership). WFSC is a wholly owned
subsidiary of The Williams Companies, Inc (Williams). The Partnership owned 100% of our Class A
membership interests and 50% of our initial Class C units (or 20 Class C units). WFSC owned 100% of
our Class B membership interests and the remaining 50% of our initial Class C units (or 20 Class C
units). In 2009 we issued an additional 88.5 and 28.8 Class C units to the Partnership and WFSC,
respectively, related to their funding of expansion capital expenditures. Therefore, the
Partnership owns 69% and WFSC owns 31% of our outstanding Class C units as of December 31, 2009.
See Note 8, Members Capital, for more information about these different forms of ownership and
Note 11, Subsequent Event, for a discussion of a subsequent change of ownership.
Note 2. Description of Business
We operate a natural gas gathering and processing system in Wyoming. The system includes
approximately 1,900 miles of natural gas gathering pipelines with typical operating capacity of
approximately 500 million cubic feet per day (MMcf/d) at current operating pressures. The system
has total compression of approximately 69,000 horsepower. The assets also include the Echo Springs
natural gas processing plant, which has an inlet capacity of 500 MMcf/d and can produce
approximately 30,000 barrels per day of natural gas liquids.
Note 3. Summary of Significant Accounting Policies
Basis of Presentation. The financial statements have been prepared based upon accounting
principles generally accepted in the United States.
Use of Estimates. The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make estimates and
assumptions that affect the amounts reported in the financial statements and accompanying notes.
Actual results could differ from those estimates.
Estimates and assumptions which, in the opinion of management, are significant to the
underlying amounts included in the financial statements and for which it would be reasonably
possible that future events or information could change those estimates include asset retirement
obligations. These estimates are discussed further in the accompanying notes.
Accounts Receivable. Accounts receivable are carried on a gross basis, with no discounting,
less an allowance for doubtful accounts. We do not recognize an allowance for doubtful accounts at
the time the revenue which generates the accounts receivable is recognized. We estimate the
allowance for doubtful accounts based on existing economic conditions, the financial condition of
our customers and the amount and age of past due accounts. We consider receivables past due if full
payment is not received by the contractual due date. Past due accounts are generally written off
against the allowance for doubtful accounts only after all collection attempts have been
unsuccessful. There was no allowance for doubtful accounts as of December 31, 2009 and 2008.
Product Imbalances. In the course of providing gathering and processing services to our
customers, we realize over and under deliveries of our customers products, and over and under
purchases of shrink replacement gas when our purchases vary from operational requirements. In
addition, we realize gains and losses which we believe are related to inaccuracies inherent in the
gas measurement process. These items are reflected as product imbalance receivables and payables on
the Balance Sheets. Product imbalance receivables are valued based on the lower of the current
market prices or current cost of natural gas in the system. Product imbalance payables are valued
at current market prices. The majority of our settlements are through in-kind arrangements whereby
incremental volumes are delivered to a customer (in the case of an imbalance payable) or received
from a customer (in the case of an imbalance receivable). Such in-kind deliveries are ongoing and
take place over several periods. In some cases, settlements of imbalances built up over a period of
time are ultimately settled in cash and are generally negotiated at values which approximate
average market prices over a period of time. These gains and losses impact our results of
operations and are included in operating and maintenance expense in the Statements of Income.
144
Property, Plant and Equipment. Property, plant and equipment is recorded at cost. We base the
carrying value of these assets on estimates, assumptions and judgments relative to capitalized
costs, useful lives and salvage values. Depreciation of property, plant and equipment is provided
on a straight-line basis over estimated useful lives. Expenditures for maintenance and repairs are
expensed as incurred. Expenditures that extend the useful lives of the assets or increase their
functionality are capitalized. We remove the cost of property, plant and equipment sold or retired
and the related accumulated depreciation from the accounts in the period of sale or disposition.
Gains and losses on the disposal of property, plant and equipment are recorded in the Statements of
Income.
We record an asset and a liability equal to the present value of each expected future asset
retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the
depreciation of the underlying physical asset. We measure changes in the liability due to passage
of time by applying an interest method of allocation. This amount is recognized as an increase in
the carrying amount of the liability and as corresponding accretion expense included in operating
income.
Revenue Recognition. We recognize revenue for sales of products when the product has been
delivered, and we generally recognize revenues from the gathering and processing of gas in the
period the service is provided based on contractual terms and the related natural gas and liquid
volumes. One gathering agreement provides incremental fee-based revenues upon the completion of
projects that lower system pressures. This revenue is recognized on a units-of-production basis as
gas is produced under this agreement. Additionally, revenue from customers for the installation and
operation of electronic flow measurement equipment is recognized evenly over the life of the
underlying agreements.
Income Taxes. We are not a taxable entity for federal and state income tax purposes. The tax
on our net income is borne by the individual members through the allocation of taxable income. Net
income for financial statement purposes may differ significantly from taxable income of members as
a result of differences between the tax basis and financial reporting basis of assets and
liabilities.
Note 4. Related Party Transactions
The employees supporting our operations are employees of Williams. Their payroll costs are
directly charged to us by Williams. Williams carries the accruals for most employee-related
liabilities in its financial statements, including the liabilities related to the employee
retirement and medical plans and paid time off. Our share of these costs is charged to us through
affiliate billing and reflected in Operating and maintenance expense Affiliate in the
accompanying Statements of Income.
We
purchase natural gas for fuel and shrink replacement from Williams
Gas Marketing, Inc., a
wholly owned indirect subsidiary of Williams. These purchases are made at market rates at the time
of purchase.
In 2009, we entered into fixed price natural gas purchase contracts
with WGM, based on market rates at the time of execution, to hedge a
range of 5 BBtu/d to 10 BBtu/d forecasted natural gas purchases for
shrink replacement costs at a range of fixed prices from $2.91 to
$3.48 per MMBtu for the last half of 2009.
These costs are reflected in Operating and maintenance expense Affiliate and
Product cost Affiliate in the accompanying Statements of Income.
A summary of affiliate operating and maintenance expense directly charged to us for the
periods stated is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Operating and maintenance expense Affiliate: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas fuel purchases and system (gains) losses |
|
$ |
(3,392 |
) |
|
$ |
(7,287 |
) |
|
$ |
(5,225 |
) |
Salaries, benefits and other |
|
|
6,141 |
|
|
|
5,774 |
|
|
|
5,261 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,749 |
|
|
$ |
(1,513 |
) |
|
$ |
36 |
|
|
|
|
|
|
|
|
|
|
|
We are charged for certain administrative expenses by Williams and its Midstream segment of
which we are a part. These charges are either directly identifiable or allocated to our assets.
Direct charges are for goods and services provided by Williams and Midstream at our request.
Allocated charges are either (1) charges allocated to the Midstream segment by Williams and then
reallocated from the Midstream segment to us or (2) Midstream-level administrative costs that are
allocated to us. These expenses are allocated based on a three-factor formula, which considers
revenues, property, plant and equipment and payroll. These costs are reflected in General and
administrative expenses Affiliate in the accompanying Statements of Income. In managements
estimation, the allocation methodologies used are reasonable and result in a reasonable allocation
to us of our costs of doing business incurred by Williams and its Midstream segment.
145
We sell the NGLs to which we take title to Williams NGL Marketing, LLC (WNGLM), a wholly owned
indirect subsidiary of Williams. These sales are made at market rates at the time of
sale. In 2009, we
entered into financial swap contracts with WGM, based on market rates
at the time of execution, to hedge 21 million gallons of forecasted
NGL sales for the second half of 2009 with a range of fixed prices of
$0.465 per gallon to $0.923 per gallon depending on the specific
product. Revenues associated with these activities are reflected as Product
sales Affiliate on the Statements of Income.
We participate in Williams cash management program under unsecured promissory note agreements
with Williams for both advances to and from Williams; hence, we maintain no cash balances. As of
December 31, 2009 and 2008 we had receivables from Williams of $2.4 million and $4.8 million,
respectively. Interest is paid to us on amounts receivable from Williams under the cash management
program based on the rate received by Williams on the overnight investment of its excess cash.
Note 5. Property, Plant and Equipment
Property, plant and equipment, at cost, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
December 31, |
|
|
Depreciable |
|
|
2009 |
|
|
2008 |
|
|
Lives |
|
|
(In thousands) |
|
Land, rights of way and other |
|
$ |
24,406 |
|
|
$ |
22,365 |
|
|
0- 30 years |
Gathering pipelines and related equipment |
|
|
349,681 |
|
|
|
336,041 |
|
|
10-30 years |
Processing plants and related equipment |
|
|
55,275 |
|
|
|
50,771 |
|
|
30 years |
Buildings and related equipment |
|
|
11,594 |
|
|
|
11,476 |
|
|
3-30 years |
Construction work in progress |
|
|
134,571 |
|
|
|
42,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment |
|
|
575,527 |
|
|
|
462,979 |
|
|
|
|
|
Accumulated depreciation |
|
|
167,098 |
|
|
|
144,907 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment |
|
$ |
408,429 |
|
|
$ |
318,072 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our asset retirement obligation relates to gas processing and compression facilities located
on leased land and wellhead connections on federal land. At the end of the useful life of each
respective asset, we are legally or contractually obligated to remove certain surface equipment and
cap certain gathering pipelines at the wellhead connection.
A rollforward of our asset retirement obligation for 2009 and 2008 is presented below.
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Balance, January 1 |
|
$ |
1,656 |
|
|
$ |
221 |
|
Liabilities incurred during the period |
|
|
86 |
|
|
|
|
|
Accretion expense |
|
|
38 |
|
|
|
15 |
|
Estimate revisions |
|
|
112 |
|
|
|
1,420 |
|
|
|
|
|
|
|
|
Balance, December 31 |
|
$ |
1,892 |
|
|
$ |
1,656 |
|
|
|
|
|
|
|
|
Note 6. Accrued Liabilities
Accrued liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Taxes other than income |
|
$ |
1,009 |
|
|
$ |
933 |
|
Construction retainage |
|
|
8,766 |
|
|
|
2,206 |
|
Other |
|
|
510 |
|
|
|
79 |
|
|
|
|
|
|
|
|
|
|
$ |
10,285 |
|
|
$ |
3,218 |
|
|
|
|
|
|
|
|
146
Note 7. Credit Facilities and Leasing Activities
We have a $20.0 million revolving credit facility with Williams as the lender. The credit
facility is available exclusively to fund working capital requirements. Borrowings under the credit
facility mature on December 12, 2010 with three, one-year automatic extensions which can be
terminated by either party. We pay a commitment fee to Williams on the unused portion of the credit
facility of 0.125% annually. Interest on any borrowings under the facility will be based upon a
periodic fixed rate equal to LIBOR plus an applicable margin, or a base rate plus the applicable
margin. As of December 31, 2009, we had no outstanding borrowings under the credit facility. See
Note 11, Subsequent Event, for information regarding the termination of this credit facility.
We lease the land on which a significant portion of our pipeline assets are located. The
primary landowner is the Bureau of Land Management (BLM). The BLM leases are for thirty years with
renewal options. We also lease compression units under a lease agreement which terminates November
18, 2010. In addition, we lease vehicles under non-cancelable leases, which are for lease terms of
about 45 months. These leases are accounted for as operating leases. The future minimum annual
rentals under these non-cancelable leases as of December 31, 2009 are payable as follows:
|
|
|
|
|
|
|
(In thousands) |
|
2010 |
|
$ |
1,221 |
|
2011 |
|
|
150 |
|
2012 |
|
|
60 |
|
2013 and thereafter |
|
|
8 |
|
|
|
|
|
|
|
$ |
1,439 |
|
|
|
|
|
Total rent expense for the years ended 2009, 2008 and 2007 was $2.0 million, $2.1 million and
$2.0 million, respectively.
Note 8. Members Capital
Governance.
Most decisions regarding our day-to-day operations are made by Williams in its
capacity as the Class B member. However, certain decisions require the consent of the Class A
member, including, but not limited to, (i) the sale or disposition of assets over $20.0 million,
(ii) the merger or consolidation with another entity, (iii) the purchase or acquisition of assets
or businesses, (iv) the making of an investment in a third party in excess of $20.0 million, (v)
the guarantee or incurrence of any debt, (vi) the cancelling or settling of any claim in excess of
$20.0 million, (vii) the selling or redeeming of any equity interests in us, (viii) the declaration
of distributions not described below, (ix) the entering into certain transactions outside the
ordinary course of business with our affiliates and (x) the approval of our annual business plan.
Williams also controls the Class A member through its ownership of the Class A members general
partner.
Distributions. Our limited liability company (LLC) agreement provides for distributions of
available cash to be made quarterly. We distribute our available cash as follows:
|
|
|
First, an amount equal to $17.5 million per quarter to the holder of our Class A
membership interests; |
|
|
|
|
Second, an amount, if needed, to the holder of our Class A membership interests to
increase the distribution on our Class A membership interests in prior quarters of the
current distribution year to $17.5 million per quarter; and |
|
|
|
|
Third, 5% of remaining available cash shall be distributed to the holder of our Class A
membership interests and 95% shall be distributed to the holders of our Class C units, on a
pro rata basis. |
In addition, to the extent that at the end of the fourth quarter of a distribution year, our
Class A member has received less than $70.0 million under the first and second bullets above, our
Class C members will be required to repay any distributions they received in that distribution year
such that our Class A member receives $70.0 million for that distribution year. If this repayment
is insufficient to result in the Class A member receiving $70.0 million, the shortfall will not
carry forward to the next distribution year. Our initial distribution year began on December 1,
2007 and ended on November 30, 2008. Subsequent distribution years commence on December 1 and end
on November 30.
147
Our LLC agreement provides that we will receive a transition support payment, related to a cap
on general and administrative expenses, from our Class B membership interest each quarter during
2008 through 2012. This payment is distributed directly to our Class A membership interest who
receives allocated income equal to the distribution. The reimbursement is treated as a capital
contribution by our Class B membership interest.
Income Allocation. The allocation of our net income is based upon the allocation and
distribution provisions of our LLC agreement. In general, the agreement allocates income to the
Class A, B and C membership interests in a manner that will maintain capital account balances
reflective of the amounts each membership interest would receive if we were dissolved and
liquidated at our carrying value. The Class A membership interest will receive 100% of our annual
net income up to $70.0 million. Income in excess of $70 million will be shared between the Class A
membership interest and Class C membership interest. Our net income allocation does not affect the
amount of available cash we distribute for any quarter.
Contributions for Capital Expenditures. We fund expansion capital expenditures through
capital contributions from our members as specified in our LLC agreement. The agreement specifies
that expansion capital expenditures with expected total expenditures in excess of $2.5 million at
the time of approval and well connections that grow gathered volumes as defined in our LLC
agreement be funded by contributions from our Class B member. Our Class A member will provide
capital contributions related to expansion projects with expected total expenditures less than $2.5
million at the time of approval. On the first day of the quarter following the quarter the asset
related to these expansion capital expenditures is placed in service, we will issue to each
contributing member one Class C unit for each $50,000 contributed by it, including the interest
accrued on the investment prior to the issuance of the Class C units. We will issue fractional
Class C units as necessary. As of December 31, 2009 Williams has contributed an additional $82.9
million for an expansion capital project that is expected to be placed in service during 2010.
Williams will receive Class C units related to these expenditures after the asset is placed in
service.
Limitations
of members liability. Our LLC agreement provides that we will indemnify and hold
harmless each member from and against all losses, claims, damages, liabilities, expenses (including
attorneys fees), and other amounts, that arise out of or are incidental to our business or the
members status as a member, unless incurred due to the actual fraud or willful misconduct of the
member. The LLC agreement further provides that no member will be personally liable for any of our
debts, liabilities or obligations with the exception of certain capital contributions provided by
the terms of our LLC agreement and the amount of any distribution made to such member that must be
returned to us pursuant to the Delaware Limited Liability Company Act.
Liquidation preferences. Our LLC agreement provides that proceeds from liquidation would be
distributed in preferential order to the Class B, A and C members with each of these members fully
recovering its unrecovered capital account balance before moving to the next class of ownership.
Any remaining proceeds would be distributed 5% to the Class A membership interest and 95% to the
Class C membership interest.
Note 9. Major Customers and Concentrations of Credit Risk
At December 31, 2009 and 2008, substantially all of our accounts receivable result from
product sales and gathering and processing services provided to our five largest customers. One
customer is an affiliate of Williams which minimizes our credit risk exposure. The remaining
customers may impact our overall credit risk either positively or negatively, in that these
entities may be similarly affected by industry-wide changes in economic or other conditions. As a
general policy, collateral is not required for receivables, but customers financial condition and
credit worthiness are evaluated regularly. Our credit policy and the relatively short duration of
receivables mitigate the risk of uncollected receivables.
Our largest customer, on a percentage of revenues basis, is WNGLM, which purchases and resells
substantially all of the NGLs to which we take title. WNGLM accounted for 51%, 56% and 56% of
revenues in 2009, 2008 and 2007, respectively. The percentages for the remaining three largest
customers are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
2007 |
Customer A |
|
|
21 |
% |
|
|
15 |
% |
|
|
20 |
% |
Customer B |
|
|
8 |
|
|
|
7 |
|
|
|
10 |
|
Customer C |
|
|
7 |
|
|
|
10 |
|
|
|
4 |
|
148
Note 10. Commitments and Contingencies
Will Price. In 2001, we were named, along with other subsidiaries of Williams, as defendants
in a nationwide class action lawsuit in Kansas state court that had been pending against other
defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the
defendants have engaged in mismeasurement techniques that distort the heating content of natural
gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and
sought an unspecified amount of damages. The defendants have opposed class certification, and on
September 18, 2009, the court denied plaintiffs most recent motion to certify the class. On
October 2, 2009, the plaintiffs filed a motion for reconsideration of the denial. We are awaiting a
decision from the court. The amount of any possible liability cannot be reasonably estimated at
this time.
Other. We are not currently a party to any other legal proceedings but are a party to various
administrative and regulatory proceedings that have arisen in the ordinary course of our business.
Summary. Litigation, arbitration, regulatory matters and environmental matters are subject to
inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a
material adverse impact on the results of operations in the period in which the ruling occurs.
Management, including internal counsel, currently believes that the ultimate resolution of the
foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage,
recovery from customers or other indemnification arrangements, will not have a material adverse
effect upon our future liquidity or financial position.
Note 11. Subsequent Event
On February 17, 2010, the Partnership, its general partner, its operating company and certain
subsidiaries of Williams closed a transaction pursuant to which the Partnership acquired certain
subsidiaries of Williams, including WFSC. As a result, we became wholly owned by the Partnership.
In connection with this transaction, our revolving credit facility with Williams was terminated.
We have evaluated our disclosure of subsequent events through February 25, 2010.
149
Report of Independent Registered Public Accounting Firm
To the Management Committee of
Discovery Producer Services LLC
We have audited the accompanying consolidated balance sheets of Discovery Producer Services LLC as
of December 31, 2009 and 2008, and the related consolidated statements of income, members capital,
and cash flows for each of the three years in the period ended December 31, 2009. These financial
statements are the responsibility of the Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. We
were not engaged to perform an audit of the Companys internal control over financial reporting.
Our audits included consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Companys internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the consolidated financial position of Discovery Producer Services LLC at December 31,
2009 and 2008, and the consolidated results of its operations and its cash flows for each of the
three years in the period ended December 31, 2009, in conformity with U.S. generally accepted
accounting principles.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 25, 2010
150
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
10,074 |
|
|
$ |
42,052 |
|
Trade accounts receivable: |
|
|
|
|
|
|
|
|
Affiliate |
|
|
12,399 |
|
|
|
202 |
|
Other |
|
|
8,665 |
|
|
|
1,899 |
|
Insurance receivable |
|
|
4,647 |
|
|
|
3,373 |
|
Prepaid insurance |
|
|
2,484 |
|
|
|
2,700 |
|
Other current assets |
|
|
1,185 |
|
|
|
752 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
39,454 |
|
|
|
50,978 |
|
Restricted cash |
|
|
|
|
|
|
3,470 |
|
Property, plant, and equipment, net |
|
|
364,932 |
|
|
|
370,482 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
404,386 |
|
|
$ |
424,930 |
|
|
|
|
|
|
|
|
LIABILITIES AND MEMBERS CAPITAL |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable: |
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
1,986 |
|
|
$ |
3,125 |
|
Other |
|
|
12,329 |
|
|
|
34,779 |
|
Accrued liabilities |
|
|
1,101 |
|
|
|
5,714 |
|
Other current liabilities |
|
|
1,292 |
|
|
|
1,616 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
16,708 |
|
|
|
45,234 |
|
Asset retirement obligations |
|
|
23,325 |
|
|
|
19,684 |
|
Other noncurrent liabilities |
|
|
30 |
|
|
|
87 |
|
Members capital |
|
|
364,323 |
|
|
|
359,925 |
|
|
|
|
|
|
|
|
Total liabilities and members capital |
|
$ |
404,386 |
|
|
$ |
424,930 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
151
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENTS OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Product sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
$ |
114,738 |
|
|
$ |
207,706 |
|
|
$ |
216,889 |
|
Third-party |
|
|
66 |
|
|
|
1,324 |
|
|
|
5,251 |
|
Gas and condensate transportation services: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
485 |
|
|
|
782 |
|
|
|
979 |
|
Third-party |
|
|
20,155 |
|
|
|
13,308 |
|
|
|
15,553 |
|
Gathering and processing services: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
131 |
|
|
|
1,506 |
|
|
|
3,092 |
|
Third-party |
|
|
17,831 |
|
|
|
12,709 |
|
|
|
17,767 |
|
Other revenues |
|
|
7,613 |
|
|
|
3,913 |
|
|
|
1,141 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
161,019 |
|
|
|
241,248 |
|
|
|
260,672 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Product cost and shrink replacement: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
20,235 |
|
|
|
83,576 |
|
|
|
93,722 |
|
Third-party |
|
|
52,271 |
|
|
|
63,422 |
|
|
|
61,982 |
|
Operating and maintenance expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate |
|
|
9,580 |
|
|
|
8,836 |
|
|
|
5,579 |
|
Third-party |
|
|
13,865 |
|
|
|
27,834 |
|
|
|
23,409 |
|
Depreciation and accretion |
|
|
18,751 |
|
|
|
21,324 |
|
|
|
25,952 |
|
Taxes other than income |
|
|
3,263 |
|
|
|
1,439 |
|
|
|
1,330 |
|
General and administrative expenses affiliate |
|
|
6,000 |
|
|
|
4,500 |
|
|
|
2,280 |
|
Other (income) expense, net |
|
|
10 |
|
|
|
(3,511 |
) |
|
|
534 |
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
123,975 |
|
|
|
207,420 |
|
|
|
214,788 |
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
37,044 |
|
|
|
33,828 |
|
|
|
45,884 |
|
Interest income |
|
|
31 |
|
|
|
650 |
|
|
|
1,799 |
|
Foreign exchange gain (loss) |
|
|
(168 |
) |
|
|
(78 |
) |
|
|
388 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
36,907 |
|
|
$ |
34,400 |
|
|
$ |
48,071 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
152
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENT OF MEMBERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams |
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners |
|
|
DCP Assets |
|
|
|
|
|
|
Williams |
|
|
Operating |
|
|
Holding, |
|
|
|
|
|
|
Energy, L.L.C. |
|
|
LLC |
|
|
LP |
|
|
Total |
|
Balance at December 31, 2006 |
|
$ |
83,825 |
|
|
$ |
167,765 |
|
|
$ |
162,040 |
|
|
$ |
413,630 |
|
Contributions |
|
|
|
|
|
|
|
|
|
|
3,920 |
|
|
|
3,920 |
|
Distributions |
|
|
(7,233 |
) |
|
|
(28,270 |
) |
|
|
(23,669 |
) |
|
|
(59,172 |
) |
Net income |
|
|
2,602 |
|
|
|
26,241 |
|
|
|
19,228 |
|
|
|
48,071 |
|
Sale of Williams Energy,
L.L.C.s 20% interest to
Williams Partners Operating LLC |
|
|
(79,194 |
) |
|
|
79,194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007 |
|
|
|
|
|
|
244,930 |
|
|
|
161,519 |
|
|
|
406,449 |
|
Contributions |
|
|
|
|
|
|
5,700 |
|
|
|
7,376 |
|
|
|
13,076 |
|
Distributions |
|
|
|
|
|
|
(56,400 |
) |
|
|
(37,600 |
) |
|
|
(94,000 |
) |
Net income |
|
|
|
|
|
|
20,641 |
|
|
|
13,759 |
|
|
|
34,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008 |
|
|
|
|
|
|
214,871 |
|
|
|
145,054 |
|
|
|
359,925 |
|
Contributions |
|
|
|
|
|
|
13,166 |
|
|
|
6,967 |
|
|
|
20,133 |
|
Distributions |
|
|
|
|
|
|
(30,747 |
) |
|
|
(20,498 |
) |
|
|
(51,245 |
) |
Special Distribution of Interest
Earned on Tahiti Escrow Account
to Williams Partners Operating
LLC |
|
|
|
|
|
|
(1,397 |
) |
|
|
|
|
|
|
(1,397 |
) |
Net income |
|
|
|
|
|
|
22,703 |
|
|
|
14,204 |
|
|
|
36,907 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009 |
|
$ |
|
|
|
$ |
218,596 |
|
|
$ |
145,727 |
|
|
$ |
364,323 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
153
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
36,907 |
|
|
$ |
34,400 |
|
|
$ |
48,071 |
|
Adjustments to reconcile to cash provided by operations: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and accretion |
|
|
18,751 |
|
|
|
21,324 |
|
|
|
25,952 |
|
Net loss on disposal of equipment |
|
|
|
|
|
|
175 |
|
|
|
603 |
|
Cash provided (used) by changes in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Trade accounts receivable |
|
|
(18,963 |
) |
|
|
26,213 |
|
|
|
(9,389 |
) |
Insurance receivable |
|
|
(1,274 |
) |
|
|
2,319 |
|
|
|
6,931 |
|
Prepaid insurance |
|
|
216 |
|
|
|
(267 |
) |
|
|
1,004 |
|
Other current assets |
|
|
(433 |
) |
|
|
2,335 |
|
|
|
(1,713 |
) |
Accounts payable |
|
|
(14,124 |
) |
|
|
5,932 |
|
|
|
(7,540 |
) |
Accrued liabilities |
|
|
(4,613 |
) |
|
|
(725 |
) |
|
|
1,320 |
|
Cash-out deferred revenue |
|
|
(10 |
) |
|
|
75 |
|
|
|
(249 |
) |
Other current liabilities |
|
|
(373 |
) |
|
|
(127 |
) |
|
|
(2,898 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
16,084 |
|
|
|
91,654 |
|
|
|
62,092 |
|
INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in restricted cash |
|
|
3,470 |
|
|
|
2,752 |
|
|
|
22,551 |
|
Property, plant, and equipment: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(19,023 |
) |
|
|
(9,939 |
) |
|
|
(29,114 |
) |
Proceeds from sale of property, plant and equipment |
|
|
|
|
|
|
|
|
|
|
649 |
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(15,553 |
) |
|
|
(7,187 |
) |
|
|
(5,914 |
) |
FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to members |
|
|
(52,642 |
) |
|
|
(94,000 |
) |
|
|
(59,172 |
) |
Capital contributions |
|
|
20,133 |
|
|
|
13,076 |
|
|
|
3,920 |
|
|
|
|
|
|
|
|
|
|
|
Net cash used by financing activities |
|
|
(32,509 |
) |
|
|
(80,924 |
) |
|
|
(55,252 |
) |
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
|
(31,978 |
) |
|
|
3,543 |
|
|
|
926 |
|
Cash and cash equivalents at beginning of period |
|
|
42,052 |
|
|
|
38,509 |
|
|
|
37,583 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
10,074 |
|
|
$ |
42,052 |
|
|
$ |
38,509 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
154
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization and Description of Business
Unless the context clearly indicates otherwise, references in this report to we, our, us
or similar language refer to Discovery Producer Services LLC and its wholly owned subsidiary,
Discovery Gas Transmission LLC (DGT). We are a Delaware limited liability company formed on June
24, 1996 for the purpose of constructing and operating a 600 million cubic feet per day (MMcf/d)
cryogenic natural gas processing plant near Larose, Louisiana and a 32,000 barrel per day (bpd)
natural gas liquids fractionator near Paradis, Louisiana. DGT is a Delaware limited liability
company formed on June 24, 1996 for the purpose of constructing and operating a natural gas
pipeline from offshore deep water in the Gulf of Mexico to our gas processing plant in Larose,
Louisiana. The mainline has a design capacity of 600 MMcf/d and consists of approximately 105 miles
of pipe. We have since connected several laterals to the DGT pipeline to expand our presence in the
Gulf.
At the beginning of the periods presented, we were owned 20% by Williams Energy, L.L.C. (a
wholly owned subsidiary of The Williams Companies, Inc.), 40% by DCP Assets, LP (DCP) and 40% by
Williams Partners Operating LLC (a wholly owned subsidiary of Williams Partners L.P) (WPZ).
Williams Energy, L.L.C. is our operator. Herein, The Williams Companies, Inc. and its subsidiaries
are collectively referred to as Williams.
On June 28, 2007, WPZ acquired the 20% interest in us previously held by Williams Energy,
L.L.C. Hence, at December 31, 2007, we were, and continue to be, owned 60% by WPZ and 40% by DCP.
We evaluated our disclosure of subsequent events through the date, February 25, 2010, that our
financial statements were filed.
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 the
parent and our wholly owned subsidiary, DGT. Intercompany accounts and transactions have been
eliminated.
Use of Estimates. The preparation of consolidated financial statements in conformity with
accounting principles generally accepted in the United States requires management to make estimates
and assumptions that affect the amounts reported in the consolidated financial statements and
accompanying notes. Actual results could differ from those estimates.
Estimates and assumptions used in the calculation of asset retirement obligations are, in the
opinion of management, significant to the underlying amounts included in the consolidated financial
statements. It is reasonably possible that future events or information could change those
estimates.
Cash and Cash Equivalents. The cash and cash equivalent balance is primarily invested in
funds with high-quality, short term securities and instruments that are issued or guaranteed by the
U.S. government. These securities have maturities of three months or less when acquired.
Trade Accounts Receivable. Trade accounts receivable are carried on a gross basis, with no
discounting, less an allowance for doubtful accounts. We do not recognize an allowance for doubtful
accounts at the time the revenue that generates the accounts receivable is recognized. We estimate
the allowance for doubtful accounts based on existing economic conditions, the financial condition
of the customers, and the amount and age of past due accounts. Receivables are considered past due
if full payment is not received by the contractual due date. Past due accounts are generally
written off against the allowance for doubtful accounts only after all collection attempts have
been exhausted. There was no allowance for doubtful accounts at December 31, 2009 and 2008.
Insurance Receivable. Hurricane Katrina damaged our pipeline and onshore facilities in 2005,
and Hurricane Ike damaged the 30 mainline and 18 lateral in 2008. Expenditures incurred for the
repair of these damages considered probable of recovery when incurred are recorded as insurance
receivable. We expense expenditures up to the insurance deductible ($6.4 million in 2008), amounts
not covered by insurance ($2.0 million in 2008) and amounts subsequently determined not to be
recoverable.
Prepaid Insurance. Prepaid insurance represents the unamortized balance of insurance
premiums. These payments are amortized on a straight line basis over the policy term.
155
Gas Imbalances. In the course of providing transportation services to customers, we may
receive different quantities of gas from shippers than the quantities delivered on behalf of those
shippers. This results in gas transportation imbalance receivables and payables which are recovered
or repaid in cash, based on market-based prices, or through the receipt or delivery of gas in the
future. Imbalance receivables and payables are included in Other current assets and Other current
liabilities in the Consolidated Balance Sheets. Imbalance receivables are valued based on the lower
of the current market prices or weighted average cost of natural gas in the system. Imbalance
payables are valued at current market prices. Settlement of imbalances requires agreement between
the pipelines and shippers as to allocations of volumes to specific transportation contracts and
the timing of delivery of gas based on operational conditions. Pursuant to a settlement with our
shippers issued by the Federal Energy Regulatory Commission (FERC) on February 5, 2008, if a
cash-out refund is due and payable to a shipper during any year pursuant to Transporters FERC Gas
Tariff, shipper will be deemed to have immediately assigned its right to the refund amount to us.
Restricted Cash. Restricted cash within non-current assets relates to escrow funds
contributed by our members for the construction of the Tahiti pipeline lateral expansion. The
restricted cash is classified as non-current because the funds will be used to construct a
long-term asset. The restricted cash is primarily invested in short-term money market accounts with
financial institutions.
Property, Plant and Equipment. Property, plant and equipment is recorded at cost. We base the
carrying value of these assets on estimates, assumptions and judgments relative to capitalized
costs, useful lives and salvage values. The natural gas and natural gas liquids maintained in the
pipeline facilities necessary for their operation (line fill) are included in property, plant and
equipment. Depreciation of property, plant and equipment is provided on a straight-line basis over
the estimated useful lives of 25 to 35 years. Expenditures for maintenance and repairs are expensed
as incurred. Expenditures that extend the useful lives of the assets or increase their
functionality are capitalized. The cost of property, plant and equipment sold or retired and the
related accumulated depreciation is removed from the accounts in the period of sale or disposition.
Gains and losses on the disposal of property, plant and equipment are recorded in the Statements of
Income.
We record an asset and a liability equal to the present value of each expected future asset
retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the
depreciation of the underlying physical asset. We measure changes in the liability due to passage
of time by applying an interest method of allocation. This amount is recognized as an increase in
the carrying amount of the liability and as corresponding accretion expense included in operating
income.
Revenue Recognition. Revenue for sales of products is recognized in the period of delivery,
and revenues from the gathering, transportation and processing of gas are recognized in the period
the service is provided based on contractual terms and the related natural gas and liquid volumes.
DGT is subject to FERC regulations, and accordingly, certain revenues collected may be subject to
possible refunds upon final orders in pending cases. DGT records rate refund liabilities
considering its and other third parties regulatory proceedings, advice of counsel, estimated total
exposure as discounted and risk weighted, and collection and other risks. There were no rate refund
liabilities accrued at December 31, 2009 or 2008.
Impairment of Long-Lived Assets. We evaluate long-lived assets for impairment on an
individual asset or asset group basis when events or changes in circumstances indicate that, in our
managements judgment, the carrying value of such assets may not be recoverable. When such a
determination has been made, we compare our managements estimate of undiscounted future cash flows
attributable to the assets to the carrying value of the assets to determine whether the carrying
value is recoverable. If the carrying value is not recoverable, we determine the amount of the
impairment recognized in the financial statements by estimating the fair value of the assets and
recording a loss for the amount that the carrying value exceeds the estimated fair value.
Income Taxes. For federal tax purposes, we have elected to be treated as a partnership with
each member being separately taxed on its ratable share of our taxable income. This election, to be
treated as a pass-through entity, also applies to our wholly owned subsidiary, DGT. Therefore, no
income taxes or deferred income taxes are reflected in the consolidated financial statements.
Foreign Currency Transactions. Transactions denominated in currencies other than the
functional currency are recorded based on exchange rates at the time such transactions arise.
Subsequent changes in exchange rates result in transaction gains or losses which are reflected in
the Consolidated Statements of Income.
Note 3. Related Party Transactions
We have various business transactions with our members and subsidiaries and affiliates of our
members. Revenues include the following:
156
|
|
|
sales to Williams of NGLs to which we take title and excess gas at current market prices
for the products and |
|
|
|
|
processing and sales of natural gas liquids and transportation of gas and condensate for
DCPs affiliates, Texas Eastern Corporation and ConocoPhillips Company. |
The following table summarizes these related-party revenues during 2009, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Williams |
|
$ |
114,869 |
|
|
$ |
207,782 |
|
|
$ |
217,012 |
|
Texas Eastern Corporation |
|
|
190 |
|
|
|
1,953 |
|
|
|
3,912 |
|
ConocoPhillips |
|
|
295 |
|
|
|
259 |
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
115,354 |
|
|
$ |
209,994 |
|
|
$ |
220,960 |
|
|
|
|
|
|
|
|
|
|
|
We have no employees. Pipeline and plant operations are performed under operation and
maintenance agreements with Williams. Most costs for materials, services and other charges are
third-party charges and are invoiced directly to us. Operating and maintenance expenses affiliate
includes the following:
|
|
|
direct payroll and employee benefit costs incurred on our behalf by Williams, and |
|
|
|
|
rental expense under a 10-year leasing agreement for pipeline capacity through 2015 from
Texas Eastern Transmission, LP (an affiliate of DCP) |
Product costs and shrink replacement affiliate includes natural gas purchases from Williams
for fuel and shrink requirements made at market rates at the time of purchase.
General and administrative expenses affiliate includes a monthly operation and management
fee paid to Williams to cover the cost of accounting services, computer systems and management
services provided to us.
We also pay Williams a project management fee to cover the cost of managing capital projects.
This fee is determined on a project by project basis and is capitalized as part of the construction
costs. A summary of the payroll costs and project fees charged to us by Williams and capitalized
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Capitalized labor |
|
$ |
280 |
|
|
$ |
317 |
|
|
$ |
222 |
|
Capitalized project fee |
|
|
312 |
|
|
|
375 |
|
|
|
651 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
592 |
|
|
$ |
692 |
|
|
$ |
873 |
|
|
|
|
|
|
|
|
|
|
|
Note 4. Property, Plant, and Equipment
Property, plant, and equipment consisted of the following at December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Years Ended December 31, |
|
|
Depreciable |
|
|
|
2009 |
|
|
2008 |
|
|
Lives |
|
|
|
(In thousands) |
|
Property, plant, and equipment: |
|
|
|
|
|
|
|
|
|
|
|
|
Construction work in progress |
|
$ |
5,256 |
|
|
$ |
76,302 |
|
|
|
|
|
Buildings |
|
|
5,055 |
|
|
|
5,054 |
|
|
25 35 years |
Land and land rights |
|
|
5,556 |
|
|
|
5,575 |
|
|
0 35 years |
Transportation lines |
|
|
320,956 |
|
|
|
305,172 |
|
|
25 35 years |
Plant and other equipment |
|
|
283,001 |
|
|
|
216,189 |
|
|
25 35 years |
|
|
|
|
|
|
|
|
|
|
|
Total property, plant, and equipment |
|
|
619,824 |
|
|
|
608,292 |
|
|
|
|
|
Less accumulated depreciation |
|
|
254,892 |
|
|
|
237,810 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant, and equipment |
|
$ |
364,932 |
|
|
$ |
370,482 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
157
Commitments for construction and acquisition of property, plant, and equipment at Grand Isle
115 for an interconnect with ATP are approximately $223 thousand at December 31, 2009.
Our asset retirement obligations relate primarily to our offshore platform and pipelines and
our onshore processing and fractionation facilities. At the end of the useful life of each
respective asset, we are legally or contractually obligated to dismantle the offshore platform,
properly abandon the offshore pipelines, remove the onshore facilities and related surface
equipment and restore the surface of the property.
A rollforward of our asset retirement obligation for 2009 and 2008 is presented below.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Balance at January 1 |
|
$ |
19,684 |
|
|
$ |
12,118 |
|
Accretion expense |
|
|
1,669 |
|
|
|
1,082 |
|
Estimate revisions |
|
|
396 |
|
|
|
3,327 |
|
Liabilities incurred |
|
|
1,576 |
|
|
|
3,157 |
|
|
|
|
|
|
|
|
Balance at December 31 |
|
$ |
23,325 |
|
|
$ |
19,684 |
|
|
|
|
|
|
|
|
Note 5. Leasing Activities
We lease the land on which the Paradis fractionator and the Larose processing plant are
located. The initial term of each lease is 20 years with renewal options for an additional 30
years. We also have a ten-year leasing agreement for pipeline capacity from Texas Eastern
Transmission, LP that includes renewal options and options to increase capacity which would also
increase rentals. The future minimum annual rentals under these non-cancelable leases as of
December 31, 2009 are payable as follows:
|
|
|
|
|
|
|
(In thousands) |
|
2010 |
|
$ |
1,241 |
|
2011 |
|
|
1,241 |
|
2012 |
|
|
1,245 |
|
2013 |
|
|
1,245 |
|
2014 |
|
|
1,245 |
|
Thereafter |
|
|
759 |
|
|
|
|
|
|
|
$ |
6,976 |
|
|
|
|
|
Total rent expense for 2009, 2008 and 2007, including a cancelable platform space lease and
month-to-month leases, was $1.8 million, $1.6 million and $1.4 million, respectively.
Note 6. Financial Instruments, Concentrations of Credit Risk and Major Customers
Financial Instruments Fair Value
We used the following methods and assumptions to estimate the fair value of financial
instruments:
Cash and cash equivalents. The carrying amounts reported in the consolidated balance
sheets approximate fair value due to the short-term maturity of these instruments.
Restricted cash. The carrying amounts reported in the consolidated balance sheets
approximate fair value as these instruments have interest rates approximating market.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
2008 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
|
|
Amount |
|
Value |
|
Amount |
|
Value |
|
|
|
|
|
|
(In thousands) |
|
|
|
|
Cash and cash equivalents |
|
$ |
10,074 |
|
|
$ |
10,074 |
|
|
$ |
42,052 |
|
|
$ |
42,052 |
|
Restricted cash |
|
|
|
|
|
|
|
|
|
|
3,470 |
|
|
|
3,470 |
|
158
Concentrations of Credit Risk
Our cash equivalent balance is primarily invested in funds with high-quality, short-term
securities and instruments that are issued or guaranteed by the U.S. government.
At December 31, 2009, substantially all of our customer accounts receivable result from gas
transmission services provided for our largest three customers. This concentration of customers may
impact our overall credit risk either positively or negatively, in that these entities may be
similarly affected by industry-wide changes in economic or other conditions. As a general policy,
collateral is not required for receivables, but customers financial condition and credit
worthiness are evaluated regularly. Our credit policy and the relatively short duration of
receivables mitigate the risk of uncollected receivables. We did not incur any credit losses on
receivables during 2009 and 2008.
Major Customers
Williams accounted for approximately $114.9 million (71%), $208.0 million (86%), $217.0
million (83%) respectively, of our total revenues in 2009, 2008 and 2007. These revenues were for
the sale of NGLs received as compensation under processing contracts with third-party producers.
Note 7. Rate and Regulatory Matters
Rate and Regulatory Matters. Annually, DGT files a request with the FERC for a fuel
lost-and-unaccounted-for gas percentage to be allocated to shippers for the upcoming fiscal year
beginning July 1. On June 1, 2009, DGT filed to maintain a lost-and-unaccounted-for percentage of
zero percent until July 1, 2010 and to retain the 2008 net system gains of $5.4 million that are
unrelated to the lost-and-unaccounted-for gas over recovered from its shippers. By Order dated June
30, 2009 the filing was approved. The approval was subject to a 30-day protest period, which passed
without protest. As of December 31, 2009 and 2008, DGT has deferred amounts of $211,000 and $5.4
million, respectively, included in current accrued liabilities in the accompanying Consolidated
Balance Sheets for unrecognized net system gains.
On February 25, 2009, DGT filed with the FERC to adjust its Hurricane Mitigation and
Reliability Enhancement surcharge (HMRE). The HMRE was approved in DGTs rate case settlement in
2008. Normally, DGT files to establish a new HMRE no later than November 15 of each year, to be
effective January 1 the following year. This filing was made out-of-cycle to recover approximately
$6.9 million in costs spent to repair a lateral displaced by Hurricane Ike. On March 30, 2009, the
FERC issued an order accepting the revised HMRE surcharge of $0.05/dt effective April 1, 2009.
On March 17, 2009, we and DGT filed a joint application to amend DGTs certificate and our
limited jurisdiction certificate, to permit us to provide an additional 50,000 Dth per day of
compression services to DGT at our Larose processing plant. DGT did not request any related change
in rates. On August 28, 2009, the FERC issued an order granting the certificate amendment
requests.
On November 13, 2009, DGT filed its annual HMRE surcharge adjustment. The filing proposed to
reduce the surcharge from $0.05 to $0.0374 per Dt, effective January 1, 2010. The FERC approved
the filing on December 23, 2009.
Environmental Matters. We are subject to extensive federal, state, and local environmental
laws and regulations which affect our operations related to the construction and operation of our
facilities. Appropriate governmental authorities may enforce these laws and regulations with a
variety of civil and criminal enforcement measures, including monetary penalties, assessment and
remediation requirements and injunctions as to future compliance. We have not been notified and are
not currently aware of any material noncompliance under the various environmental laws and
regulations.
Other. We are party to various other claims, legal actions and complaints arising in the
ordinary course of business. Litigation, arbitration and environmental matters are subject to
inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a
material adverse impact on the results of operations in the period in which the ruling occurs.
Management, including internal counsel, currently believes that the ultimate resolution of the
foregoing matters, taken as a whole, and after consideration of
159
amounts accrued, insurance coverage or other indemnification arrangements, will not have a
material adverse effect upon our future liquidity or financial position.
160
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
|
|
|
|
|
|
Williams Partners L.P.
(Registrant)
|
|
|
By: |
Williams Partners GP LLC,
|
|
|
|
its general partner |
|
|
|
|
|
By: |
/s/ Ted T. Timmermans
|
|
|
|
Ted T. Timmermans |
|
|
|
Controller (Duly Authorized Officer and Principal
Accounting Officer) |
|
|
Date: February 25, 2010
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signature |
|
Title |
|
Date |
|
|
/s/ STEVEN J. MALCOLM
|
|
President, Chief Executive Officer and
|
|
February 25, 2010 |
|
|
|
|
|
|
|
Steven J. Malcolm
|
|
Chairman of the Board (Principal Executive Officer) |
|
|
|
|
|
|
|
|
|
|
|
/s/ DONALD R. CHAPPEL
|
|
Chief Financial Officer and Director |
|
|
|
|
|
|
|
|
|
Donald R. Chappel
|
|
(Principal Financial Officer)
|
|
February 25, 2010 |
|
|
|
|
|
|
|
|
|
/s/ TED T. TIMMERMANS
|
|
Chief Accounting Officer and Controller
|
|
February 25, 2010 |
|
|
|
|
|
|
|
Ted T. Timmermans
|
|
(Principal Accounting Officer) |
|
|
|
|
|
|
|
|
|
|
|
/s/ ALAN S. ARMSTRONG*
|
|
Director
|
|
February 25, 2010 |
|
|
|
|
|
|
|
Alan S. Armstrong |
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ BILL Z. PARKER*
|
|
Director
|
|
February 25, 2010 |
|
|
|
|
|
|
|
Bill Z. Parker |
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ ALICE M. PETERSON*
|
|
Director
|
|
February 25, 2010 |
|
|
|
|
|
|
|
Alice M. Peterson |
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ H. MICHAEL KRIMBILL*
|
|
Director
|
|
February 25, 2010 |
|
|
|
|
|
|
|
H. Michael Krimbill |
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ PHILLIP D. WRIGHT*
|
|
Director
|
|
February 25, 2010 |
|
|
|
|
|
|
|
Phillip D. Wright |
|
|
|
|
|
|
|
|
|
|
|
*By:
|
|
/s/ WILLIAM H. GAULT |
|
|
|
|
|
|
William H. Gault
Attorney-in-fact
|
|
|
|
February 25, 2010 |
161
INDEX TO EXHIBITS
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
§Exhibit 2.1 |
|
|
|
Purchase and Sale Agreement, dated April 6, 2006, by and among Williams Energy
Services, LLC, Williams Field Services Group, LLC, Williams Field Services
Company, LLC, Williams Partners GP LLC, Williams Partners L.P. and Williams
Partners Operating LLC (filed on April 7, 2006 as Exhibit 2.1 to Williams Partners
L.P.s current report on Form 8-K (File No.001-32599)) and incorporated herein by
reference. |
|
|
|
|
|
§Exhibit 2.2 |
|
|
|
Purchase and Sale Agreement, dated November 16, 2006, by and among Williams Energy
Services, LLC, Williams Field Services Group, LLC, Williams Field Services
Company, LLC, Williams Partners GP LLC, Williams Partners L.P. and Williams
Partners Operating LLC (filed on November 21, 2006 as Exhibit 2.1 to Williams
Partners L.P.s current report on Form 8-K (File No.001-32599)) and incorporated
herein by reference. |
|
|
|
|
|
§Exhibit 2.3 |
|
|
|
Purchase and Sale Agreement, dated June 20, 2007, by and among Williams Energy,
L.L.C., Williams Energy Services, LLC and Williams Partners Operating LLC (filed
on June 25, 2007 as Exhibit 2.1 to Williams Partners L.P.s current report on Form
8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
§Exhibit 2.4 |
|
|
|
Purchase and Sale Agreement, dated November 30, 2007, by and among Williams Energy
Services, LLC, Williams Field Services Group, LLC, Williams Field Services
Company, LLC, Williams Partners GP LLC, Williams Partners L.P. and Williams
Partners Operating LLC (filed on December 3, 2007 as Exhibit 2.1 to Williams
Partners L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated
herein by reference. |
|
|
|
|
|
Exhibit 2.5 |
|
|
|
Contribution Agreement, dated as of January 15, 2010, by and among Williams Energy
Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline
Company, L.L.C., Williams Partners GP LLC, Williams Partners L.P., Williams
Partners Operating LLC and, for a limited purpose, The Williams Companies, Inc,
including exhibits thereto (filed on January 19, 2010 as Exhibit 10.1 to Williams
Partners L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated
herein by reference. |
|
|
|
|
|
Exhibit 3.1 |
|
|
|
Certificate of Limited Partnership of Williams Partners L.P. (filed on May 2, 2005
as Exhibit 3.1 to Williams Partners L.P.s registration statement on Form S-1
(File No. 333-124517)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 3.2 |
|
|
|
Certificate of Formation of Williams Partners GP LLC (filed on May 2, 2005 as
Exhibit 3.3 to Williams Partners L.P.s registration statement on Form S-1 (File
No. 333-124517)) and incorporated herein by reference. |
|
|
|
|
|
*Exhibit 3.3 |
|
|
|
Amended and Restated Agreement of Limited Partnership of Williams Partners L.P.
(including form of common unit certificate), as amended by Amendments Nos. 1, 2,
3, 4, 5, and 6. |
|
|
|
|
|
Exhibit 3.4 |
|
|
|
Amended and Restated Limited Liability Company Agreement of Williams Partners GP
LLC (filed on August 26, 2005 as Exhibit 3.2 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.1 |
|
|
|
Indenture, dated June 20, 2006, by and among Williams Partners L.P., Williams
Partners Finance Corporation and JPMorgan Chase Bank, N.A. (filed on June 20, 2006
as Exhibit 4.1 to Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.2 |
|
|
|
Form of 7 1/2% Senior Note due 2011 (filed on June 20, 2006 as Exhibit 1 to Rule
144A/Regulation S Appendix of Exhibit 4.1 attached to Williams Partners L.P.s
current report on Form 8-K (File No. 001-32599)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.3 |
|
|
|
Certificate of Incorporation of Williams Partners Finance Corporation (filed on
September 22, 2006 as Exhibit 4.5 to Williams Partners L.P.s registration
statement on Form S-3 (File No. 333-137562)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.4 |
|
|
|
Bylaws of Williams Partners Finance Corporation (filed on September 22, 2006 as
Exhibit 4.6 to Williams Partners L.P.s registration statement on Form S-3 (File
No. 333-137562)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.5 |
|
|
|
Indenture, dated December 13, 2006, by and among Williams Partners L.P., Williams
Partners Finance Corporation and The Bank of New York (filed on December 19, 2006
as Exhibit 4.1 to Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
162
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
Exhibit 4.6
|
|
|
|
Form of 7 1/4% Senior Note due 2017 (filed on December 19, 2006 as Exhibit 1 to Rule
144A/Regulation S Appendix of Exhibit 4.1 attached to Williams Partners L.P.s
current report on Form 8-K (File No. 001-32599)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.7
|
|
|
|
Indenture, dated as of February 9, 2010, between Williams Partners L.P. and The
Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit
4.1 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.8
|
|
|
|
Registration Rights Agreement, dated as of February 9, 2010, among Williams
Partners L.P. and Barclays Capital Inc. and Citigroup Global Markets Inc., each
acting on behalf of themselves and the initial purchasers listed on Schedule I
thereto (filed on February 10, 2010 as Exhibit 10.1 to Williams Partners L.P.s
current report on Form 8-K (File No. 001-32599)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.9
|
|
|
|
Limited Call Right Forbearance Agreement, dated as of February 17, 2010, by and
between Williams Partners L.P. and Williams Partners GP LLC (filed on February 22,
2010 as Exhibit 4.1 to Williams Partners L.P.s current report on Form 8-K (File
No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.10
|
|
|
|
Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline
Corporation and Chemical Bank, Trustee with regard to Northwest Pipelines 7.125%
Debentures, due 2025 (filed September 14, 1995 as Exhibit 4.1 to Northwest
Pipeline Corporations Form S-3 (File No. 033-62639)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.11
|
|
|
|
Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and
JPMorgan Chase Bank, N.A., as Trustee, with regard to Northwest Pipelines $175
million aggregate principal amount of 7.00% Senior Notes due 2016 (filed on June
23, 2006 as Exhibit 4.1 to Northwest Pipeline Corporations Form 8-K (File. No.
001-07414) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.12
|
|
|
|
Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and
The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline
Corporations Form 8-K (File No. 001-07414)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.13
|
|
|
|
Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New
York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to
Northwest Pipeline GPs Form 8-K File No. 001-07414)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.14
|
|
|
|
Registration Rights Agreement, dated as of May 23, 2008, among Northwest Pipeline
GP and Banc of America Securities, LLC, BNP Paribas Securities Corp, and Greenwich
Capital Markets, Inc., acting on behalf of themselves and the several initial
purchasers listed on Schedule I thereto (filed on May 23, 2008 as Exhibit 10.1 to
Northwest Pipeline GPs Form 8-K (File No. 001-07414)) and incorporated herein by
reference. |
|
|
|
|
|
Exhibit 4.15
|
|
|
|
Senior Indenture, dated as of July 15, 1996 between Transcontinental Gas Pipe Line
Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1
to Transcontinental Gas Pipe Line Corporations Form S-3 (File No. 333-02155)) and
incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.16
|
|
|
|
Senior Indenture, dated as of January 16, 1998, between Transcontinental Gas Pipe
Line Corporation and Citibank, N.A., as Trustee (filed on September 8, 1997 as
Exhibit 4.1 to Transcontinental Gas Pipe Line Corporations Form S-3 (File No.
333-27311)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.17
|
|
|
|
Indenture, dated as of August 27, 2001, between Transcontinental Gas Pipe Line
Corporation and Citibank, N.A., as Trustee (filed on November 8, 2001 as Exhibit
4.1 to Transcontinental Gas Pipe Line Corporations Form S-4 (File No. 333-72982))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.18
|
|
|
|
Indenture, dated as of July 3, 2002, between Transcontinental Gas Pipe Line
Corporation and Citibank, N.A., as Trustee (filed August 14, 2002 as Exhibit 4.1
to The Williams Companies Inc.s Form 10-Q (File No. 001-07584)) and incorporated
herein by reference. |
|
|
|
|
|
Exhibit 4.19
|
|
|
|
Indenture, dated December 17, 2004, between Transcontinental Gas Pipe Line
Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on December 21, 2004
as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporations Form 8-K (File No.
001-07584)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 4.20
|
|
|
|
Indenture, dated as of April 11, 2006, between Transcontinental Gas Pipe Line
Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to
Transcontinental Gas Pipe Lines $200 million aggregate principal amount of 6.4%
Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental
Gas Pipe Line Corporations Form 8-K (File No. 001-07584)) and incorporated herein
by reference. |
|
|
|
|
|
Exhibit 4.21
|
|
|
|
Indenture, dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation
and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as
Exhibit 4.1 to Transcontinental Gas Pipe Line Corporations Form 8-K (File No.
001-07584)) and incorporated herein by reference. |
163
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
|
|
Description |
Exhibit 4.22
|
|
|
|
Registration Rights Agreement, dated as of May 22, 2008, among Transcontinental
Gas Pipe Line Corporation and Banc of America Securities LLC, Greenwich Capital
Markets, Inc., and J. P. Morgan Securities Inc., acting on behalf of themselves
and the several initial purchasers listed on Schedule I thereto (filed on May 23,
2008 as Exhibit 10.1 to Transcontinental Gas Pipe Line Corporations Form 8-K
(File No. 001-07584)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.1
|
|
|
|
Credit Agreement, dated as of December 11, 2007, by and among Williams Partners
L.P., the lenders party hereto, Citibank, N.A., as Administrative Agent and
Issuing Bank, and The Bank of Nova Scotia, as Swingline Lender (filed on December
17, 2007 as Exhibit 10.5 to Williams Partners L.P.s current report on Form 8-K
(File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
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. (filed on
August 26, 2005 as Exhibit 10.1 to Williams Partners L.P.s current report on Form
8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.3
|
|
|
|
Amendment No. 1 to 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.
(filed on April 20, 2009 as Exhibit 10.1 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.4
|
|
|
|
Omnibus Agreement, dated as of February 17, 2010, by and between The Williams
Companies, Inc. and Williams Partners L.P. (filed on February 22, 2010 as Exhibit
10.2 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
|
|
|
|
|
Exhibit 10.5
|
|
|
|
Contribution, Conveyance and Assumption Agreement, dated August 23, 2005, by and
among Williams Partners L.P., Williams Energy, L.L.C., Williams Partners GP LLC,
Williams Partners Operating LLC, Williams Energy Services, LLC, Williams Discovery
Pipeline LLC, Williams Partners Holdings LLC and Williams Natural Gas Liquids,
Inc. (filed on August 26, 2005 as Exhibit 10.3 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
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Exhibit 10.6
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Contribution, Conveyance and Assumption Agreement, dated June 20, 2006, by and
among Williams Energy Services, LLC, Williams Field Services Company, LLC,
Williams Field Services Group, LLC, Williams Partners GP LLC, Williams Partners
L.P. and Williams Partners Operating LLC (filed on June 20, 2006 as Exhibit 10.1
to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599)) and
incorporated herein by reference. |
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Exhibit 10.7
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Contribution, Conveyance and Assumption Agreement, dated June 20, 2006, by and
among Williams Field Services Company, LLC and Williams Four Corners LLC (filed on
June 20, 2006 as Exhibit 10.4 to Williams Partners L.P.s current report on Form
8-K (File No. 001-32599) and incorporated herein by reference. |
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Exhibit 10.8
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Contribution, Conveyance and Assumption Agreement, dated December 13, 2006, by and
among Williams Energy Services, LLC, Williams Field Services Company, LLC,
Williams Field Services Group, LLC, Williams Partners GP LLC, Williams Partners
L.P. and Williams Partners Operating LLC (filed on December 19, 2006 as Exhibit
10.1 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
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Exhibit 10.9
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Contribution, Conveyance and Assumption Agreement, dated December 11, 2007, by and
among Williams Energy Services, LLC, Williams Field Services Company, LLC,
Williams Field Services Group, LLC, Williams Partners GP LLC, Williams Partners
L.P. and Williams Partners Operating LLC (filed on December 17, 2007 as Exhibit
10.2 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
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Exhibit 10.10
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Conveyance, Contribution and Assumption Agreement, dated as of February 17, 2010,
by and among Williams Energy Services, LLC, Williams Gas Pipeline Company, LLC,
WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC, Williams
Partners L.P. and Williams Partners Operating LLC (filed on February 22, 2010 as
Exhibit 10.1 to Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
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Exhibit 10.11
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Assignment Agreement, dated December 11, 2007, by and between Williams Field
Services Company, LLC and Wamsutter LLC (filed on December 17, 2007 as Exhibit
10.1 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
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Exhibit |
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Number |
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Description |
Exhibit 10.12
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Third Amended and Restated Limited Liability Company Agreement for Discovery
Producer Services LLC (filed on June 24, 2005 as Exhibit 10.7 to Amendment No. 1
to Williams Partners L.P.s registration statement on Form S-1 (File No.
333-124517)) and incorporated herein by reference. |
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Exhibit 10.13
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Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement
for Discovery Producer Services LLC (filed on August 8, 2006 as Exhibit 10.6 to
Williams Partners L.P.s quarterly report on Form 10-Q (File No. 001-32599)) and
incorporated herein by reference. |
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Exhibit 10.14
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Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement
for Discovery Producer Services LLC (filed on August 6, 2009 as Exhibit 10.3 to
Williams Partners L.P.s quarterly report on Form 10-Q (File No. 001-32599)) and
incorporated herein by reference. |
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Exhibit 10.15
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Amended and Restated Limited Liability Company Agreement of Wamsutter LLC, dated
December 1, 2007, by and between Williams Field Services Company, LLC and Williams
Partners Operating LLC (filed on December 17, 2007 as Exhibit 10.3 to Williams
Partners L.P.s current report on Form 8-K (File No. 001-32599)) and incorporated
herein by reference. |
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Exhibit 10.16
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Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of
Wamsutter LLC, dated as of February 17, 2010, by and between Williams Field
Services Company, LLC and Williams Partners Operating LLC (filed on February 22,
2010 as Exhibit 10.4 to Williams Partners L.P.s current report on Form 8-K (File
No. 001-32599)) and incorporated herein by reference. |
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#Exhibit 10.17
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Williams Partners GP LLC Long-Term Incentive Plan (filed on August 26, 2005 as
Exhibit 10.2 to Williams Partners L.P.s current report on Form 8-K (File No.
001-32599)) and incorporated herein by reference. |
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#Exhibit 10.18
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Amendment to the Williams Partners GP LLC Long-Term Incentive Plan, dated November
28, 2006 (filed on December 4, 2006 as Exhibit 10.1 to Williams Partners L.P.s
current report on Form 8-K (File No. 001-32599)) and incorporated herein by
reference. |
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#Exhibit 10.19
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Amendment No. 2 to the Williams Partners GP LLC Long-Term Incentive Plan, dated
December 2, 2008 (filed on February 26, 2009, as Exhibit 10.4 to Williams Partners
L.P.s annual report on Form 10-K (File No. 001-32599)) and incorporated herein by
reference. |
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#Exhibit 10.20
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Director Compensation Policy dated November 29, 2005, as revised May 28, 2009
(filed on August 6, 2009 as Exhibit 10.2 to Williams Partners L.P.s quarterly
report on Form 10-Q (File No. 001-32599)) and incorporated herein by reference. |
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#Exhibit 10.21
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Form of Grant Agreement for Restricted Units (filed on December 1, 2005 as Exhibit
10.2 to Williams Partners L.P.s current report on Form 8-K (File No. 001-32599))
and incorporated herein by reference. |
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Exhibit 10.22
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Administrative Services Agreement between Northwest Pipeline Services LLC and
Northwest Pipeline GP, dated October 1, 2007 (filed on January 30, 2008 as Exhibit
10.1 to Williams Pipeline Partners L.P.s Form 8-K (File No. 001-33917) and
incorporated herein by reference). |
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Exhibit 10.23
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Administrative Services Agreement, dated as of February 17, 2010, by and between
Transco Pipeline Services LLC and Transcontinental Gas Pipe Line Company, LLC
(filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.s current
report on Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
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Exhibit 10.24
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Credit Agreement, dated as of February 17, 2010, by and among Williams Partners
L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the
lenders party thereto and Citibank, N.A., as Administrative Agent (filed on
February 22, 2010 as Exhibit 10.5 to Williams Partners L.P.s current report on
Form 8-K (File No. 001-32599)) and incorporated herein by reference. |
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*Exhibit 12
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Computation of Ratio of Earnings to Fixed Charges |
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*Exhibit 21
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List of subsidiaries of Williams Partners L.P. |
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*Exhibit 23.1
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Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP. |
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*Exhibit 23.2
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Consent of Independent Auditors, Ernst & Young LLP. |
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*Exhibit 24
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Power of attorney. |
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*Exhibit 31.1
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Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer. |
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*Exhibit 31.2
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Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer. |
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*Exhibit 32
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Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer. |
165
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* |
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Filed herewith. |
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§ |
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Pursuant to item 601(b) (2) of Regulation S-K, the registrant agrees
to furnish supplementally a copy of any omitted exhibit or schedule to
the SEC upon request. |
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# |
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Management contract or compensatory plan or arrangement. |
166