WILLIAMS COMPANIES, INC.
10-Qs and 10-Ks
PROXIES
Table of Contents
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C. 20549
Washington, D.C. 20549
Form 10-K
| (Mark One) | ||
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the fiscal year ended December 31, 2010 | ||
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or
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|
o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the transition period from to | ||
Commission file number 1-4174
The Williams Companies,
Inc.
(Exact Name of Registrant as
Specified in Its Charter)
|
Delaware
(State or Other Jurisdiction of Incorporation or Organization) |
73-0569878
(IRS Employer Identification No.) |
|
|
One Williams Center, Tulsa, Oklahoma
(Address of Principal Executive Offices) |
74172
(Zip Code) |
918-573-2000
(Registrant’s Telephone
Number, Including Area Code)
Securities registered pursuant
to Section 12(b) of the Act:
|
Name of Each Exchange
|
||
| Title of Each Class | on Which Registered | |
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Common Stock, $1.00 par value
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New York Stock Exchange | |
|
Preferred Stock Purchase Rights
|
New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the
Act:
5.50% Junior Subordinated Convertible Debentures due 2033
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
þ
No
o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant’s
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K.
o
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):
|
Large accelerated filer
þ
|
Accelerated filer o |
Non-accelerated filer
o
(Do not check if a smaller reporting company) |
Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes
o
No
þ
The aggregate market value of the voting and non-voting common
equity held by non-affiliates computed by reference to the price
at which the common equity was last sold as of the last business
day of the registrant’s most recently completed second
quarter was approximately $10,683,141,499.
The number of shares outstanding of the registrant’s common
stock outstanding at February 21, 2011 was 586,207,919.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the Registrant’s Definitive Proxy Statement for
the Registrant’s 2011 Annual Meeting of Stockholders to be
held on May 19, 2011, are incorporated into Part III,
as specifically set forth in Part III.
THE
WILLIAMS COMPANIES, INC.
FORM 10-K
TABLE OF CONTENTS
FORM 10-K
TABLE OF CONTENTS
i
Table of Contents
DEFINITIONS
We use the following oil and gas measurements in this report:
Barrel
— means one barrel of petroleum products
that equals 42 U.S. gallons.
Bcfe
— means one billion cubic feet of gas
equivalent determined using the ratio of one barrel of oil or
condensate to six thousand cubic feet of natural gas.
Bcf/d
— means one billion cubic feet per day.
British Thermal Unit or BTU
— means a unit of
energy needed to raise the temperature of one pound of water by
one degree Fahrenheit.
BBtud
— means one billion BTUs per day.
Dekatherms or Dth or Dt
— means a unit of
energy equal to one million BTUs.
Mbbls/d
— means one thousand barrels per day.
Mcfe
— means one thousand cubic feet of gas
equivalent using the ratio of one barrel of oil or condensate to
six thousand cubic feet of natural gas.
Mdt/d
— means one thousand dekatherms per day.
MMboe
— means one million barrels of oil
equivalent.
MMBtu
— means one million Btus.
MMBtu/d
— means one million Btus per day.
MMcf
— means one million cubic feet.
MMcf/d
—
means one million cubic feet per day.
MMcfe
— means one million cubic feet of gas
equivalent using the ratio of one barrel of oil or condensate to
six thousand cubic feet of natural gas.
MMdt
— means one million dekatherms or
approximately one trillion BTUs.
MMdt/d
— means one million dekatherms per day.
TBtu
— means one trillion BTUs.
Other definitions:
FERC
— means Federal Energy Regulatory
Commission.
Fractionation
— means the process by which a
mixed stream of natural gas liquids is separated into its
constituent products, such as ethane, propane and butane.
LNG
— means liquefied natural gas; natural gas
which has been liquefied at cryogenic temperatures.
NGL
— means 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
— means NGL revenues less Btu
replacement cost, plant fuel, transportation and fractionation.
Throughput
— means the volume of product
transported or passing through a pipeline, plant, terminal or
other facility.
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Table of Contents
PART I
| Item 1. | Business |
In this report, Williams (which includes The Williams Companies,
Inc. and, unless the context otherwise requires, all of our
subsidiaries) is at times referred to in the first person as
“we,” “us” or “our.” We also
sometimes refer to Williams as the “Company.”
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,
proxy statements and other documents electronically with the
Securities and Exchange Commission (SEC) under the Securities
Exchange Act of 1934, as amended (Exchange Act). You may read
and copy any materials that we file with the SEC at the
SEC’s Public Reference Room at 100 F Street,
N.E., Washington, DC 20549. You may obtain information on the
operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330.
You may also obtain such reports from the SEC’s Internet
website at
http://www.sec.gov.
Our Internet website is
http://www.williams.com.
We make available free of charge through the Investor 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 Ethics for Senior Officers, Board
committee charters and the Williams Code of Business Conduct are
also available on our Internet website. We will also provide,
free of charge, a copy of any of our corporate documents listed
above upon written request to our Corporate Secretary, One
Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
GENERAL
We are primarily an integrated natural gas company originally
incorporated under the laws of the state of Nevada in 1949 and
reincorporated under the laws of the state of Delaware in 1987.
We were founded in 1908 when two Williams brothers began a
construction company in Fort Smith, Arkansas. Today, we
primarily find, produce, gather, process and transport natural
gas. Our operations are concentrated in the Pacific Northwest,
Rocky Mountains, Gulf Coast, Eastern Seaboard, and the province
of Alberta in Canada.
Our principal executive offices are located at One Williams
Center, Tulsa, Oklahoma 74172. Our telephone number is
918-573-2000.
CHANGE IN
STRUCTURE AND DIVIDEND INCREASE
On February 16, 2011, we announced that our Board of
Directors approved pursuing a plan to separate the company into
two standalone, publicly traded corporations. The plan calls for
the separation of our exploration and production business into a
publicly traded company via an initial public offering of up to
20 percent of our interest in the third quarter of 2011. We
intend to complete the offering so that it preserves our ability
to complete a tax-free spinoff of our remaining ownership in the
exploration and production business to Williams’
shareholders in 2012, after which Williams would continue as a
premier natural gas infrastructure company. We retain the
discretion to determine whether and when to execute the spinoff.
Additionally, we intend to increase the quarterly dividend paid
to our shareholders, with an initial increase of 60 percent
(to $0.20 per share), for the first quarter of 2011 payable in
June 2011.
Management believes these actions will serve to enhance the
growth potential and overall valuation of our assets.
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FINANCIAL
INFORMATION ABOUT SEGMENTS
See “
Item 8 — Financial Statements and
Supplementary Data — Notes to Consolidated Financial
Statements — Note 18
” for information
with respect to each segment’s revenues, profits or losses
and total assets.
BUSINESS
SEGMENTS
Substantially all our operations are conducted through our
subsidiaries. To achieve organizational and operating
efficiencies, our activities in 2010 were primarily operated
through the following business segments:
| • | Williams Partners — comprised of our master limited partnership Williams Partners L.P. (WPZ), which includes gas pipeline and domestic midstream businesses. The gas pipeline business includes interstate natural gas pipelines and pipeline joint venture investments, and the midstream business provides natural gas gathering, treating and processing services; NGL production, fractionation, storage, marketing and transportation; deepwater production handling and crude oil transportation services and is comprised of several wholly owned and partially owned subsidiaries and joint venture investments. | |
| • | Exploration & Production — produces, develops, and manages natural gas and oil primarily located in the Rocky Mountain, Northeast and Mid-Continent regions of the United States and is comprised of several wholly owned and partially owned subsidiaries including Williams Production Company, LLC and Williams Production RMT Company, LLC. This segment also includes our 69 percent equity interest in Apco Oil and Gas International Inc., as well as gas marketing services which manage our natural gas commodity risk through purchases, sales and other related transactions, under our wholly owned subsidiary Williams Gas Marketing, Inc. | |
| • | Other — includes other business activities that are not operating segments, primarily our Canadian midstream and domestic olefins operations and a 25.5 percent interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream), as well as corporate operations. |
This report is organized to reflect this structure.
Due to expected future growth in our Canadian midstream and
domestic olefins operations, we are considering reporting these
businesses as a separate segment beginning in the first quarter
of 2011.
Detailed discussion of each of our business segments follows.
Williams
Partners
Gas
Pipeline Business
Williams Partners owns and operates a combined total of
approximately 13,900 miles of pipelines with a total annual
throughput of approximately 2,800 TBtu of natural gas and
peak-day
delivery capacity of approximately 13 MMdt of natural gas.
Our gas pipeline businesses consist primarily of
Transcontinental Gas Pipe Line Company, LLC (Transco) and
Northwest Pipeline GP (Northwest Pipeline). Our gas pipeline
business also holds interests in joint venture interstate and
intrastate natural gas pipeline systems including a
24.5 percent interest in Gulfstream. The gas pipeline
businesses contributed revenues of approximately
28 percent, 35 percent and 28 percent of Williams
Partners’ revenues in 2010, 2009, and 2008, respectively.
During third quarter 2010, Williams Partners L.P. completed a
merger with Williams Pipeline Partners L.P. (WMZ). All of
WMZ’s common and subordinated units have been extinguished
and WMZ is wholly owned by Williams Partners. WMZ has been
delisted and is no longer publicly traded.
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.
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Pipeline
system and customers
At December 31, 2010, Transco’s system had a mainline
delivery capacity of approximately 4.9 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 8.8 MMdt of natural gas per day.
Transco’s 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.
Transco’s major natural gas transportation customers are
public utilities and municipalities that provide service to
residential, commercial, industrial and electric generation end
users. Shippers on Transco’s system include public
utilities, municipalities, intrastate pipelines, direct
industrial users, electrical generators, gas marketers and
producers. Transco’s firm transportation agreements are
generally long-term agreements with various expiration dates and
account for the major portion of Transco’s 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 it owns and
operates. 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 200 billion cubic feet of gas. At
December 31, 2010, our customers had stored in our
facilities approximately 154 Bcf of natural gas. In addition,
wholly owned subsidiaries of Transco operate and hold a
35 percent ownership interest in Pine Needle LNG Company,
LLC, a LNG storage facility with 4 billion cubic feet of
storage capacity. Storage capacity permits Transco’s
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 2010 or
are future significant pipeline projects for which Transco has
customer commitments.
Mobile
Bay South
The Mobile Bay South Expansion Project involved the addition of
compression at Transco’s 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
Federal Energy Regulatory Commission (FERC). The capital cost of
the project was $32 million. The project was placed into
service in May 2010 and increased capacity by 254 Mdt/d.
Mobile
Bay South II
The Mobile Bay South II Expansion Project involves the
addition of compression at Transco’s Station 85 in
Choctaw County, Alabama, and modifications to existing
facilities at Transco’s 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 July 2010 Transco
received approval from the FERC. The capital cost of the project
is estimated to be approximately $35 million, and it will
increase capacity by 380 Mdt/d. Transco plans to place the
project into service by May 2011.
85
North
The 85 North Expansion Project involves an expansion of
Transco’s 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 approximately $236 million, and
it will increase capacity by 309 Mdt/d. The first phase for 90
Mdt/d, was placed into service in July 2010, and the second
phase is expected to be placed into service in May 2011.
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Mid-South
The Mid-South Expansion Project involves an expansion of
Transco’s mainline from Station 85 in Choctaw County,
Alabama, to markets as far downstream as North Carolina. In
October 2010 Transco filed an application with the FERC. The
capital cost of the project is estimated to be approximately
$219 million. Transco plans to place the project into
service in phases in September 2012 and June 2013, and it will
increase capacity by 225 Mdt/d.
Mid-Atlantic
Connector Project
The Mid-Atlantic Connector Project involves an expansion of
Transco’s mainline from an existing interconnection in
North Carolina to markets as far downstream as Maryland. In
November 2010 Transco filed an application with the FERC. The
capital cost of the project is estimated to be approximately
$55 million. Transco plans to place the project into
service in November 2012, and it will increase capacity by 142
Mdt/d.
Rockaway
Delivery Lateral Project
The Rockaway Delivery Lateral Project involves the construction
of a
three-mile
offshore lateral to a distribution system in New York. Transco
anticipates filing an application with the FERC in the fourth
quarter of 2011. The capital cost of the project is estimated to
be approximately $159 million. Transco plans to place the
project into service as early as November 2013, and its capacity
will be 647 Mdt/d.
Northeast
Supply Link Project
The Northeast Supply Link Project involves an expansion of
Transco’s existing natural gas transmission system from the
Marcellus Shale production region on the Leidy Line to various
delivery points in New York and New Jersey. Transco anticipates
filing an application with the FERC in the fourth quarter of
2011. The capital cost of the project is estimated to be
approximately $341 million. Transco plans to place the
project into service in November 2013, and it will increase
capacity by 250 Mdt/d.
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.
Pipeline
system and customers
At December 31, 2010, Northwest Pipeline’s system,
having long-term firm transportation agreements including
peaking service of approximately 3.8 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 477,000 horsepower.
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. Northwest Pipeline’s firm transportation and
storage contracts are generally long-term contracts with various
expiration dates and account for the major portion of Northwest
Pipeline’s 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 have an aggregate working gas storage capacity of
13.2 Bcf of natural gas, which is substantially utilized
for third-party natural gas, and firm
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delivery capability of approximately
700 MMcf/d
enable Northwest Pipeline to provide storage services to its
customers and to balance daily receipts and deliveries.
Northwest
Pipeline expansion project
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 as
well as an upgrade to an existing Vernal, Utah compressor
station. The total estimated cost of the project is
approximately $50 million. We placed the project in service
in November 2010 with an increase in capacity of 150 Mdt/d.
Gulfstream
Gulfstream is a natural gas pipeline system extending from the
Mobile Bay area in Alabama to markets in Florida. Williams
Partners owns, through a subsidiary, a 24.5 percent
interest in Gulfstream while we own a 25.5 percent interest
through a subsidiary. Spectra Energy Corporation, through its
subsidiary, and Spectra Energy Partners, LP, own the additional
50 percent interest. Williams Partners shares operating
responsibilities for Gulfstream with Spectra Energy Corporation.
Gulfstream
expansion projects
The Gulfstream Phase V expansion involves the addition of
compression to provide 35 Mdt/d of firm capacity by April 2011.
The estimated capital cost of this expansion is approximately
$44 million with Williams Partners’ share being
24.5 percent of such cost.
Midstream
Business
Williams Partners’ midstream business, one of the
nation’s 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. The 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 this 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 core service areas and new step-out areas; | |
| • | Prices impacting commodity-based processing activities. |
The midstream business revenue contributed approximately
72 percent, 66 percent and 72 percent of Williams
Partners’ revenues in 2010, 2009 and 2008, respectively.
One of our midstream customers, ONEOK Hydrocarbon LP, accounted
for 10 percent of our consolidated revenues in 2010. These
revenues were generated by our NGL marketing business. There
were no customers for which our sales exceeded 10 percent of our
consolidated revenues in 2009 and 2008.
Gathering,
processing and treating
Williams Partners’ 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
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gas stream. Processing and treating plants remove water vapor,
carbon dioxide and other contaminants and 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 Williams Partners’ 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 we 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.
Williams Partners’ gas gathering and processing customers
are generally natural gas producers who have proved
and/or
producing natural gas fields in the areas surrounding its
infrastructure. During 2010, these operations gathered and
processed gas for approximately 215 gas gathering and processing
customers. Williams Partners’ top 6 gathering and
processing customers, one of which is an affiliate, accounted
for approximately 50 percent of our gathering and
processing revenue.
In addition to natural gas assets, Williams Partners owns and
operates four deepwater crude oil pipelines and owns two
production platforms serving the deepwater in the Gulf of
Mexico. The crude oil transportation revenues are typically
volumetric-based fee arrangements. However, a portion of its
marketing revenues are recognized from purchase and sale
arrangements whereby the oil that Williams Partners transports
is purchased and sold as a function of the same index-based
price. Williams Partners’ offshore floating production
platforms provide 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, the midstream natural gas assets are positioned
to maximize commercial and operational synergies with our other
assets. For example, most of the offshore gathering and
processing assets attach and process or condition natural gas
supplies delivered to the Transco pipeline. Also, the gathering
and processing facilities in the San Juan and Piceance
basins handle approximately 92 percent of our
Exploration & Production segment’s equity
production in these basins. The San Juan basin, southwest
Wyoming and Willow Creek systems deliver residue gas volumes
into Northwest Pipeline’s interstate system in addition to
third-party interstate systems.
Onshore
region gathering, processing and treating
Williams Partners owns
and/or
operates gas gathering, processing and treating assets within
the states of Wyoming, Colorado, New Mexico and Pennsylvania.
In the Rocky Mountain area, the assets include:
| • | Approximately 3,500 miles of gathering pipelines with a capacity of nearly 1 Bcf/d and over 4,000 receipt points serving the Wamsutter and southwest Wyoming areas in Wyoming; |
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| • | Opal and Echo Springs processing plants with a combined daily inlet capacity of over 2.2 Bcf/d and NGL processing capacity of nearly 125 Mbbls/d, including the addition of a fourth cryogenic processing train at the Echo Springs plant which began processing in the fourth quarter of 2010. |
In the Four Corners area, the assets include:
| • | Approximately 3,800 miles of gathering pipelines with a capacity of nearly 2 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 1 Mbbls/d of liquefied natural gas (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, the assets include:
| • | The Willow Creek processing plant, a 450 MMcf/d cryogenic natural gas processing plant in western Colorado’s Piceance basin, designed to recover 30 Mbbls/d of NGLs. The plant is currently operating at its designed inlet capacity. In the current processing arrangement with our Exploration & Production segment, Williams Partners receives a volumetric-based processing fee and a percent of the NGLs extracted. | |
| • | Approximately 150 miles of gathering pipeline and the Parachute Plant Complex along with three other treating facilities with a combined processing capacity of 1.2 Bcf/d, acquired in the fourth quarter of 2010 from Exploration & Production. | |
| • | 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. The Willow Creek plant processes gas flowing through the Parachute Lateral. | |
| • | PGX pipeline delivering NGLs from our Exploration & Production segment’s existing Parachute area processing plants to a major NGL transportation pipeline system. |
In the Appalachian basin in Pennsylvania, the assets include:
| • | Approximately 75 miles of gathering pipelines and two compressor stations in Susquehanna County, Pennsylvania in the Marcellus Shale, acquired in the fourth quarter of 2010. Williams Partners has agreed to a new long-term dedicated gathering agreement with the seller for its production in the northeast Pennsylvania area of the Marcellus Shale. The acquired system will connect into the Transco pipeline with our 33-mile, 24-inch diameter Springville gathering pipeline. Construction on the Springville pipeline is expected to begin in the first quarter of 2011 and be completed during 2011. |
Gulf
region gathering, processing and treating
Williams Partners’ owns
and/or
operates 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. This includes:
| • | Nearly 800 miles of onshore and offshore natural gas gathering pipelines with a combined capacity of approximately 3.7 Bcf/d, including: |
| • | The 115-mile deepwater Seahawk gas pipeline in the western Gulf of Mexico, flowing into the Markham processing plant and serving the Boomvang and Nansen field areas; |
7
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| • | The 105-mile deepwater Perdido Norte gas pipeline in the western Gulf of Mexico, which began transporting gas in the third quarter of 2010 from a third-party producers’ floating production facility in to the Seahawk gathering system, which flows into Williams Partners’ Markham processing plant; | |
| • | The 139-mile Canyon Chief gas pipeline, including the Blind Faith extension in the eastern Gulf of Mexico, flowing into the 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 1.2 Bcf/d and NGL handling capacity of 75 Mbbls/d, including the 2010 expansion of the Markham plant to accommodate production volumes from the Perdido Norte gas pipeline; | |
| • | 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; | |
| • | Four deepwater crude oil pipelines with a combined length of nearly 400 miles and capacity of 475 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 the shallow-water platform at Galveston Area Block A244 (GA-A244) and then onshore through the Hoover Offshore Oil Pipeline System (HOOPS); | |
| • | Perdido Norte pipeline running parallel to the Perdido Norte gas pipeline which began transporting oil in the third quarter of 2010 from a third-party producers’ floating production facility and then onshore through 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 pipeline, including the Blind Faith extension, which connects to similar production sources as our Canyon Chief pipeline, ultimately delivering production to a 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 world’s deepest dry tree spars. The platform, which is operated by another party, is capable of handling 210 MMcf/d of natural gas and 60 Mbbls/d of oil. |
NGL
marketing services
In addition to Williams Partners’ gathering and processing
operations, we market NGL 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 its processing plants, and also markets NGLs on behalf of
third-party NGL producers, including some of its fee-based
processing customers, and the NGL volumes owned by Discovery
Producer Services LLC (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, Williams Partners 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
Partially Owned Operations
Fractionation
and Storage
Williams Partners owns interests in
and/or
operates NGL fractionation and storage assets. These assets
include a 50 percent interest in an NGL fractionation
facility near Conway, Kansas with capacity of slightly more than
100 Mbbls/d and a 31.45 percent interest in another
fractionation facility in Baton Rouge, Louisiana with a capacity
8
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of 60 Mbbls/d. Williams Partners also fully owns
approximately 20 million barrels of NGL storage capacity in
central Kansas near Conway.
Overland
Pass Pipeline
In September 2010, Williams Partners completed the
$424 million acquisition of an additional 49 percent
ownership interest in Overland Pass Pipeline (OPPL), which
increased our ownership interest to 50 percent. As long as
we retain a 50 percent ownership interest in OPPL, we have
the right to become operator. We have notified our partner of
our intent to operate and are currently working on an early 2011
transition. OPPL includes a
760-mile
NGL
pipeline from Opal, Wyoming, to the Mid-Continent NGL market
center in Conway, Kansas, along with
150-
and
125-mile
extensions into the Piceance and Denver-Joules basins in
Colorado, respectively. Williams Partners’ equity NGL
volumes from our two Wyoming plants and our Willow Creek
facility in Colorado are dedicated for transport on OPPL under a
long-term shipping agreement.
Discovery
Williams Partners owns a 60 percent equity interest in and
operates the facilities of Discovery. Discovery’s 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.
Laurel
Mountain
Williams Partners owns a 51 percent interest in a joint
venture, Laurel Mountain Midstream LLC (Laurel Mountain), in the
Marcellus Shale located in western Pennsylvania. Laurel
Mountain’s assets, which we operate, include a gathering
system of approximately 1,000 miles of pipeline with a
fourth quarter 2010 average throughput of approximately
125 MMcf/d.
Laurel Mountain has a long-term, dedicated, volumetric-based fee
agreement, with some exposure to natural gas prices, to gather
the production of its joint venture partner’s production in
the northeast Pennsylvania area of the Marcellus Shale.
Construction began in 2010 on numerous new pipeline segments and
compressor stations, the largest of which is the Shamrock
compressor station. The Shamrock compressor station will have an
initial capacity of
60 MMcf/d,
expandable to
350 MMcf/d,
which will likely be the largest central delivery point out of
the Laurel Mountain system.
Aux
Sable
Williams Partners also owns a 14.6 percent 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 92 Mbbls/d of extracted liquids into NGL
products.
Operating
statistics
The following table summarizes our significant operating
statistics for Midstream:
| 2010 | 2009 | 2008 | ||||||||||
|
Volumes:(1)
|
||||||||||||
|
Gathering (Tbtu)(3)
|
1,262 | 1,370 | 1,361 | |||||||||
|
Plant inlet natural gas (Tbtu)
|
1,424 | 1,342 | 1,311 | |||||||||
|
NGL production (Mbbls/d)(2)
|
174 | 164 | 154 | |||||||||
|
NGL equity sales (Mbbls/d)(2)
|
80 | 80 | 80 | |||||||||
|
Crude oil gathering (Mbbls/d)(2)
|
94 | 109 | 70 | |||||||||
| (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. |
9
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| (3) | Amounts have been recast to reflect the November 2010 acquisition of certain gathering and processing assets in Colorado’s Piceance basin from Exploration & Production. |
Exploration &
Production
Our Exploration & Production segment includes natural
gas and oil development, production and gas marketing activities
primarily located in the Rocky Mountain (primarily Colorado,
North Dakota, New Mexico, and Wyoming), Northeast
(Pennsylvania), and Mid-Continent (Oklahoma and Texas) regions
of the United States. We specialize in production from
tight-sands and shale formations and coal bed methane (CBM)
reserves in the Piceance, Appalachian, Williston, San Juan,
Powder River, Fort Worth, Green River and Arkoma basins. Almost
97 percent of our domestic proved reserves are natural gas.
We also have international oil and gas interests, which include
a 69 percent equity interest in Apco Oil and Gas
International Inc., an oil and gas exploration and production
company with operations in South America. If combined with our
domestic proved reserves, our international interests would make
up approximately 5 percent of our total proved reserves.
Considering this, the reserves information included in this
section relates only to our domestic activity. The gas marketing
activities include transporting, scheduling, selling and hedging
equity natural gas production as well as managing various
natural gas related contracts such as transportation, storage
and related hedges not utilized for our equity production.
Additionally, Exploration & Production’s
marketing group procures all fuel and shrink requirements and
manages transportation and hedging activities in support of our
midstream business.
Our strategy is to continue to drill our existing proved
undeveloped reserves, which comprise approximately
42 percent of proved reserves, and to drill in areas of
probable and possible reserves in order to add to our proved
reserves. Our current proved, probable, and possible reserves
inventory provides us with strong capital investment
opportunities for many years into the future.
Oil
and Gas Reserves
The following table outlines our estimated net proved reserves
expressed on a gas equivalent basis for the reporting periods
December 31, 2010, 2009 and 2008. Proved reserves for 2010
and 2009 were prepared under rules issued by the SEC on January
14, 2009. We prepare our own reserves estimates and the majority
of our December 31, 2010 reserves were audited by
Netherland, Sewell & Associates (NSAI) or Miller and
Lents, Ltd (M&L). Proved reserves information is reported
as gas equivalents, since oil volumes are insignificant in the
three years shown below. Reserves for 2010 are approximately
97 percent natural gas. Reserves are more than
99 percent natural gas for 2009 and 2008. Oil reserves
increased to approximately 3 percent of total proved
reserves in 2010 as a result of a fourth quarter acquisition of
undeveloped acreage and producing properties located in the
Williston basin.
Summary of oil and gas reserves:
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Bcfe)(1) | ||||||||||||
|
Proved developed reserves
|
2,498 | 2,387 | 2,456 | |||||||||
|
Proved undeveloped reserves
|
1,774 | 1,868 | 1,883 | |||||||||
|
Total proved reserves
|
4,272 | 4,255 | 4,339 | |||||||||
| (1) | Gas equivalents are calculated using a ratio of 6 mcf of gas to 1 barrel of oil. |
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|
Proved Reserves
|
||||
| Basin | December 31, 2010 | |||
| (Bcfe) | ||||
|
Piceance
|
2,927 | |||
|
Powder River
|
348 | |||
|
San Juan
|
554 | |||
|
Fort Worth
|
196 | |||
|
Appalachian
|
28 | |||
|
Williston
|
136 | |||
|
Other
|
83 | |||
|
Total
|
4,272 | |||
We have not filed on a recurring basis estimates of our total
proved net oil and gas reserves with any U.S. regulatory
authority or agency other than with the Department of Energy
(DOE) and the SEC. The estimates furnished to the DOE have been
consistent with those furnished to the SEC.
The 2010 year-end proved reserves were derived using the
12-month
average,
first-of-the-month
Henry Hub spot price of $4.38 per MMbtu, adjusted for locational
price differentials. During 2010, we added 508 Bcfe of net
additions to our proved reserves through drilling
1,162 gross wells at a capital cost of approximately
$988 million.
Reserves
estimation process
Our reserves are estimated by deterministic methods by an
appropriate combination of production performance analysis and
volumetric techniques. The proved reserves for economic
undrilled locations are estimated by analogy or volumetrically
from offset developed locations. Reservoir continuity and
lateral persistence of our tight-sands, shale and CBM reservoirs
is established by combinations of subsurface analysis, 2D and 3D
seismic, and pressure data. Understanding reservoir quality may
be augmented by core samples analysis.
The engineering staff of each basin asset team provides the
reserves modeling and forecasts for their respective areas.
Various departments also participate in the preparation of the
year-end reserves estimate by providing supporting information
such as pricing, capital costs, expenses, ownership, gas
gathering and gas quality. The departments and their roles in
the year-end reserves process are coordinated by our reserves
analysis department. The reserves analysis department’s
responsibilities also include performing an internal review of
reserves data for reasonableness and accuracy, working with the
third-party consultants and the asset teams to successfully
complete the third-party reserves audit, finalizing the year-end
reserves report, and reporting reserves data to accounting.
The preparation of our year-end reserves report is a formal
process. Early in the year, we begin with a review of the
existing internal processes and controls to identify where
improvements can be made from the prior year’s reporting
cycle. Later in the year, the reserves staffs from the asset
teams submit their preliminary reserves data to the reserves
analysis department. After review by the reserves analysis
department, the data is submitted to our third party engineering
consultants, NSAI and M&L, to begin their audits. After
this point, reserves data, analysis and further review are
conducted and iterated between the asset teams, reserves
analysis department and our third party engineering consultants.
In early December, reserves are reviewed with senior management.
The process concludes when all parties agree upon the reserve
estimates and audit tolerance is achieved.
The reserves estimates resulting from our process are subjected
to both internal and external controls to promote transparency
and accuracy of the year-end reserves estimates. Our internal
reserves analysis team is independent and does not work within
an asset team or report directly to anyone on an asset team. The
reserves analysis department provides detailed independent
review and extensive documentation of the year-end process. Our
internal processes and controls, as they relate to the year-end
reserves, are reviewed and updated. The compensation of our
reserves analysis team is not linked to reserves additions or
revisions.
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Approximately 93 percent of our total year-end 2010
domestic proved reserves estimates were audited by NSAI. When
compared on a
well-by-well
basis, some of our estimates are greater and some are less than
the estimates of NSAI. However, in the opinion of NSAI, the
estimates of our proved reserves are in the aggregate reasonable
and have been prepared in accordance with principles set forth
in the Standards Pertaining to the Estimating and Auditing of
Oil and Gas Reserves Information promulgated by the Society of
Petroleum Engineers. NSAI is satisfied with our methods and
procedures in preparing the December 31, 2010 reserves
estimates and future revenue, and noted nothing of an unusual
nature that would cause NSAI to take exception with the
estimates, in the aggregate, as prepared by us. The report of
NSAI is included in Exhibit 99.1 to this
Form 10-K.
In addition, reserves estimates related to properties associated
with the former Williams Coal Seam Gas Royalty Trust were
audited by M&L. These properties represent approximately
1 percent of our total domestic proved reserves estimates.
The report of M&L is included in Exhibit 99.2 to this
Form 10-K.
The technical person primarily responsible for overseeing
preparation of the reserves estimates and the third- party
reserves audit is the Director of Reserves and Production
Services. The Director’s qualifications include
28 years of reserves evaluation experience, a B.S. in
geology from the University of Texas at Austin, an M.S. in
Physical Sciences from the University of Houston, and membership
in the American Association of Petroleum Geologists and The
Society of Petroleum Engineers.
Proved
undeveloped reserves (PUDs)
The majority of our reserves is concentrated in unconventional
tight-sands, shale and coal bed gas reservoirs. We use available
geoscience and engineering data to establish drainage areas and
reservoir continuity beyond one direct offset from a producing
well, which provides additional proved undeveloped reserves.
Inherent in the methodology is a requirement for significant
well density of economically producing wells to establish
reasonable certainty. In fields where producing wells are less
concentrated, only direct offsets from proved producing wells
were assigned the proved undeveloped reserves classification. No
new technologies were used to assign proved undeveloped reserves.
At December 31, 2010, our proved undeveloped reserves were
1,774 Bcfe — a decrease of 94 Bcfe over our
December 31, 2009 proved undeveloped reserves estimate of
1,868 Bcfe. During 2010, 280 Bcfe of our
December 31, 2009 proved undeveloped reserves were
converted to proved developed reserves. An additional
129 Bcfe was added due to the development of unproved
locations. We have reclassified a net 253 Bcfe from proved
to probable reserves attributable to locations not expected to
be developed within five years. This amount is predominantly in
the Piceance basin where the company has a large inventory of
drilling locations. The downward revision has been offset by the
addition of 342 Bcfe of new proved undeveloped drilling
locations.
All proved undeveloped locations are scheduled to be spud within
the next five years. Our five-year forecast indicates increasing
capital to allow for the addition of rigs in years
2013-2015
in
the Piceance basin. Our undeveloped estimate contains
91 Bcfe of aging PUDs. The majority of these are scheduled
to be spud by year-end 2011.
Oil
and Gas Properties and Production, Production Prices, and
Production Costs
The following table summarizes our domestic sales volumes for
the years indicated:
| 2010 | 2009 | 2008 | ||||||||||
| (Bcfe) | ||||||||||||
|
Piceance
|
245.9 | 254.6 | 237.7 | |||||||||
|
Powder River
|
83.8 | 88.9 | 83.6 | |||||||||
|
San Juan
|
51.5 | 53.1 | 52.8 | |||||||||
|
Fort Worth
|
21.5 | 25.2 | 16.6 | |||||||||
|
Appalachian
|
1.8 | 0.1 | — | |||||||||
|
Williston
|
0.1 | — | — | |||||||||
|
Other
|
8.5 | 9.6 | 9.7 | |||||||||
|
Total net production sold
|
413.1 | 431.5 | 400.4 | |||||||||
12
Table of Contents
The following table summarizes our domestic price and cost
information for the years indicated and has been recast for the
sale of certain of our gathering and processing assets in the
Piceance basin to Williams Partners in November 2010:
| 2010 | 2009 | 2008 | ||||||||||
| ($/Mcfe) | ||||||||||||
|
Average production costs excluding production taxes(1)
|
$ | 0.59 | $ | 0.50 | $ | 0.56 | ||||||
|
Average sales price(2)
|
$ | 4.42 | $ | 3.42 | $ | 6.95 | ||||||
|
Realized gain from hedging
|
$ | 0.81 | $ | 1.43 | $ | 0.09 | ||||||
|
Realized Average Price
|
$ | 5.23 | $ | 4.85 | $ | 7.04 | ||||||
| (1) | Includes lease and other operating expense and facility operating expense. | |
| (2) | Not reduced for gathering, processing, and transportation paid to affiliates and third parties of $1.02 in 2010, $0.79 in 2009, and $0.71 in 2008. |
Drilling
and Exploratory Activities
We focus on lower-risk development drilling. Our development
drilling success rate was approximately 99 percent in each
of 2010, 2009, and 2008.
The following table summarizes domestic drilling activity by
number and type of well for the periods indicated:*
| 2010 | 2009 | 2008 | ||||||||||||||||||||||
| Gross Wells | Net Wells | Gross Wells | Net Wells | Gross Wells | Net Wells | |||||||||||||||||||
|
Piceance
|
398 | 360 | 349 | 303 | 687 | 624 | ||||||||||||||||||
|
Powder River
|
531 | 242 | 233 | 95 | 702 | 324 | ||||||||||||||||||
|
San Juan
|
43 | 15 | 77 | 39 | 95 | 37 | ||||||||||||||||||
|
Fort Worth
|
39 | 36 | 43 | 41 | 58 | 51 | ||||||||||||||||||
|
Appalachian
|
8 | 3 | 8 | 4 | n/a | n/a | ||||||||||||||||||
|
Williston
|
— | — | n/a | n/a | n/a | n/a | ||||||||||||||||||
|
Other
|
138 | 2 | 165 | 4 | 240 | 14 | ||||||||||||||||||
|
Productive exploration
|
— | — | 3 | 1 | 4 | 2 | ||||||||||||||||||
|
Nonproductive, including exploration
|
5 | 3 | 4 | 1 | 1 | — | ||||||||||||||||||
|
Total
|
1,162 | 661 | 882 | 488 | 1,787 | 1,052 | ||||||||||||||||||
| * | We use the terms “gross” to refer to all wells or acreage in which we have at least a partial working interest and “net” to refer to our ownership represented by that working interest. All of the wells drilled were natural gas wells. |
In 2010, there were 5 gross nonproductive development wells
and 3 net nonproductive development wells. Total gross
operated wells drilled were 656 in 2010, 472 in 2009, and 1,125
in 2008.
Present
Activities
At December 31, 2010, we had 27 gross (16 net) wells
in the process of being drilled.
Delivery
Commitments
We hold a long-term obligation to deliver on a firm basis
200,000 MMBtu/d of gas to a buyer at the White River Hub
(Greasewood-Meeker, Colorado), which is the major market hub
exiting the Piceance basin. The Piceance, being our largest
producing basin, holds ample reserves to fulfill this obligation
without risk of nonperformance during periods of normal
infrastructure and market operations. While the daily volume of
gas
13
Table of Contents
is large and represents a significant percentage of our daily
production, this transaction does not represent a material
exposure.
Purchase
Commitments
In connection with a gathering agreement entered into by
Williams Partners with a third party in December 2010, we
concurrently agreed to buy up to 200,000 MMBtu/d of natural
gas priced at market prices from the same third party. Purchases
under the
12-year
contract are expected to begin in the third quarter of 2011. We
expect to sell this natural gas in the open market and may
utilize available transportation capacity to facilitate the
sales.
Oil
and Gas Properties, Wells, Operations, and Acreage
The table below summarizes 2010 productive wells by area:*
|
Gas Wells
|
Gas Wells
|
Oil Wells
|
Oil Wells
|
|||||||||||||
| (Gross) | (Net) | (Gross) | (Net) | |||||||||||||
|
Piceance
|
3,923 | 3,587 | — | — | ||||||||||||
|
Powder River
|
6,404 | 2,884 | — | — | ||||||||||||
|
San Juan
|
3,267 | 881 | — | — | ||||||||||||
|
Fort Worth
|
286 | 233 | — | — | ||||||||||||
|
Appalachian
|
14 | 6 | — | — | ||||||||||||
|
Williston
|
— | — | 19 | 13 | ||||||||||||
|
Other
|
1,340 | 299 | — | — | ||||||||||||
|
Total
|
15,234 | 7,890 | 19 | 13 | ||||||||||||
| * | We use the term “gross” to refer to all wells or acreage in which we have at least a partial working interest and “net” to refer to our ownership represented by that working interest. |
At December 31, 2010, there were 181 gross and
105 net producing wells with multiple completions.
The following table summarizes our leased acreage as of
December 31, 2010:
| Developed | Undeveloped | Total | ||||||||||||||||||||||
| Gross Acres | Net Acres | Gross Acres | Net Acres | Gross Acres | Net Acres | |||||||||||||||||||
|
Piceance
|
133,428 | 102,835 | 157,017 | 108,165 | 290,445 | 211,000 | ||||||||||||||||||
|
Powder River
|
551,113 | 250,179 | 399,869 | 175,371 | 950,982 | 425,550 | ||||||||||||||||||
|
San Juan
|
237,587 | 119,422 | 2,100 | 1,576 | 239,687 | 120,998 | ||||||||||||||||||
|
Fort Worth
|
28,876 | 21,173 | 12,306 | 8,309 | 41,182 | 29,482 | ||||||||||||||||||
|
Appalachian
|
1,828 | 914 | 108,023 | 98,387 | 109,851 | 99,301 | ||||||||||||||||||
|
Williston
|
16,178 | 13,483 | 229,640 | 190,148 | 245,818 | 203,631 | ||||||||||||||||||
|
Other
|
120,538 | 60,559 | 199,077 | 118,734 | 319,615 | 179,293 | ||||||||||||||||||
|
Total
|
1,089,548 | 568,565 | 1,108,032 | 700,690 | 2,197,580 | 1,269,255 | ||||||||||||||||||
Piceance
basin
The Piceance basin is located in northwestern Colorado and is
our largest area of concentrated development. During 2010, we
operated an average of 11 drilling rigs in the basin. This area
has 1,567 undrilled proved locations in inventory. During 2010,
an average of approximately 6.3 million gallons of NGLs
were recovered each month at plants now owned and operated
within Williams Partners, which were marketed separately from
the residue natural gas.
Powder
River basin
The Powder River basin is located in northeast Wyoming. The
Powder River basin includes large areas with multiple coal seam
potential, targeting thick coal bed methane formations at
shallow depths.
14
Table of Contents
San Juan
basin
The San Juan basin is located in northwest New Mexico and
southwest Colorado. We provide a significant amount of equity
production that is gathered
and/or
processed by Williams Partners’ facilities in the
San Juan basin.
Fort Worth
basin
The Fort Worth basin is located in north central Texas
where we drill horizontally into the Barnett Shale.
Appalachian
basin
The Appalachian basin acreage is primarily located in
northeastern Pennsylvania where we apply horizontal drilling in
the Marcellus Shale. We have continued to expand our position
since our entry into the basin in 2009.
Williston
basin
The Williston basin acreage is located in North Dakota and
Montana. Our focus in the basin is in North Dakota’s
Bakken/Three Forks oil play where we have a 89,420 net
acreage position, of which approximately 85,800 were acquired in
December 2010 and are on the Fort Berthold Indian
Reservation.
Other
properties
Other properties are primarily comprised of interests in the
Arkoma basin in southeastern Oklahoma. Also included are
exploration activity and other miscellaneous activity.
Hedging
Activity
To manage the commodity price risk and volatility of owning
producing gas properties, we enter into derivative contracts for
a portion of our expected future production. See further
discussion in
Management’s Discussion and Analysis of
Financial Condition and Results of Operations —
Exploration & Production
, included in Item 7
of this
Form 10-K
Acquisitions &
Divestitures
During the second quarter of 2010, we entered into an agreement
to acquire additional Appalachian leasehold acreage positions
and a 5 percent overriding royalty interest associated with
these acreage positions. These acquisitions nearly double our
acreage holdings in the Marcellus Shale and closed in July for
$599 million, including closing adjustments.
During 2010, we also spent a total of $164 million to
acquire additional unproved leasehold acreage positions in the
Marcellus Shale.
In October 2010, we exercised our right under the Williams Coal
Seam Gas Royalty Trust Agreement to acquire the royalty
interests for $22 million, including closing adjustments
upon termination of the the Trust. Prior to the purchase, the
Trust owned net profits interests in certain proved coal seam
gas properties owned by Williams Production Company, LLC (WPC)
and located in the San Juan basin.
In November 2010, we sold certain of our gathering and
processing assets in Colorado’s Piceance basin to Williams
Partners for $702 million in cash and approximately 1.8
million common units. The assets include the Parachute Plant
Complex, three other treating facilities with a combined
processing capacity of 1.2 Bcf/d, and a gathering system
with approximately 150 miles of pipeline. There are more
than 3,300 wells connected to the gathering system, which
includes pipelines ranging up to
30-inch
trunk lines. The transaction also includes a
life-of-lease
dedication from Exploration & Production.
In December 2010, we acquired a company that holds a major
acreage position (approximately 85,800 net acres and
includes 19 producing wells) in North Dakota’s Bakken Shale
oil play (Williston basin) that will diversify our interests
into light, sweet crude oil production. The purchase price was
approximately $949 million, including closing adjustments.
15
Table of Contents
Other
Domestic
olefins
In the Gulf of Mexico region, we own a 5/6 interest in and are
the operator of an NGL light-feed olefins cracker in Geismar,
Louisiana, with a total production capacity of 1.35 billion
pounds of ethylene and 90 million pounds of propylene per
year. Our feedstocks for the cracker are ethane and propane; as
a result, we are primarily exposed to the price spread between
ethane and propane, and ethylene and propylene, respectively.
Ethane and propane are available for purchase from third parties
and from affiliates. We own ethane and propane pipeline systems
in Louisiana that provide feedstock transportation to the
Geismar plant and other third-party crackers. Additionally, we
own a refinery grade propylene splitter and associated pipeline
with a production capacity of approximately 500 million
pounds per year of propylene. At our propylene splitter, we
purchase refinery grade propylene and fractionate it into
polymer grade propylene and propane; as a result we are exposed
to the price spread between those commodities. As a merchant
producer of ethylene and propylene, our product sales are to
customers for use in making plastics and other downstream
petrochemical products destined for both domestic and export
markets. Our olefins business also operates an ethylene storage
hub at Mont Belvieu using leased third-party underground storage
wells.
We also market olefin and NGL products to a wide range of users
in the energy and petrochemical industries. In order to meet
sales contract obligations, we may purchase products for resale.
Canadian
midstream
Our Canadian operations include an oil sands off-gas processing
plant located near Ft. McMurray, Alberta, and an olefin
fractionation facility and a butylene/butane splitter facility,
both of which are located at Redwater, Alberta, which is near
Edmonton, Alberta. We operate the Ft. McMurray area
processing plant, while another party operates the Redwater
facilities on our behalf. The butylene/butane splitter was
completed and placed into service in August 2010. Our
Ft. McMurray area facilities extract liquids from the
off-gas produced by a third-party oil sands bitumen upgrading
process. Our arrangement with the third-party upgrader is a
“keep-whole” type where we remove a mix of NGLs and
olefins from the off-gas and return the equivalent heating value
back in the form of natural gas. We fractionate, treat, store,
terminal and sell the propane, propylene, butane, butylene and
condensate recovered from this process. Our commodity price
exposure is the spread between the price for natural gas and the
NGL and olefin products we produce. We continue to be the only
NGL/olefins fractionator in western Canada and the only
treater/processor
of oil sands upgrader off-gas. Our extraction of liquids from
upgrader off-gas streams allows the upgraders to burn cleaner
natural gas streams and reduces their overall air emissions.
The Ft. McMurray extraction plant has processing capacity of
111 MMcf/d
with the ability to recover in excess of 17 Mbbls/d of
olefin and NGL products. Our Redwater fractionator has a liquids
handling capacity of
18 Mbbls/d.
The new butylene/butane splitter, which has a production
capacity of 3.7 Mbbls/d of butylene and 3.7 Mbbls/d of
normal butane, further fractionates the butylene/butane mix
product produced at our Redwater fractionators into separate
butylene and butane products, which receive higher values and
are in greater demand. Our products are sold within Canada and
the United States.
Canadian
expansion project
Construction began in 2010 on a
261-mile,
12-inch
diameter Canadian pipeline which will transport recovered NGLs
and olefins from our processing plant in Ft. McMurray to
our Redwater fractionation facility. The pipeline will have
sufficient capacity to transport additional NGLs and olefins
from our existing operations as well as from other NGLs and
olefins produced from oil sands off-gas. The project will be
constructed using cash previously generated from Canadian and
other international projects. We anticipate an in-service date
in 2012.
Other
Considering the deteriorating circumstances in Venezuela, in
2009 we fully impaired our $75 million investment in
Accroven SRL, a Venezuelan operation, which included two
400 MMcf/d
NGL extraction plants, a 50 Mbbls/d NGL fractionation plant
and associated storage and refrigeration facilities. (See
Note 2 of Notes to Consolidated Financial Statements.) In
June of 2010, we sold our 50 percent interest in Accroven
to the state-owned oil company, Petróleos de Venezuela S.A.
(PDVSA) for $107 million. Of this amount, $13 million
was received in cash at closing and another $30 million was
received in August 2010. The remainder is due in six quarterly
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payments beginning October 31, 2010. The first quarterly
payment of $11 million was received in January 2011 and
will be recognized as income in 2011. We will continue to
recognize the resulting gain as cash is received. Accroven was
not part of our operations that were expropriated by the
Venezuelan government in May 2009.
Operating
statistics
The following table summarizes our significant operating
statistics for Other:
| 2010 | 2009 | 2008 | ||||||||||
|
Volumes:
|
||||||||||||
|
Canadian NGL equity sales (Mbbls/d)
|
8 | 8 | 7 | |||||||||
|
Olefin (ethylene and propylene) sales (millions of pounds)
|
1,529 | 1,728 | 1,605 | |||||||||
Additional
Business Segment Information
Our ongoing business segments are accounted for as continuing
operations in the accompanying financial statements and notes to
financial statements included in Part II.
Operations related to certain assets in “Discontinued
Operations” have been reclassified from their traditional
business segment to “Discontinued Operations” in the
accompanying financial statements and notes to financial
statements included in Part II.
We perform certain management, legal, financial, tax,
consultation, information technology, administrative and other
services for our subsidiaries.
Our principal sources of cash are from dividends and advances
from our subsidiaries, investments, payments by subsidiaries for
services rendered, interest payments from subsidiaries on cash
advances and, if needed, external financings, sales of master
limited partnership units to the public, and net proceeds from
asset sales. The amount of dividends available to us from
subsidiaries largely depends upon each subsidiary’s
earnings and operating capital requirements. The terms of
certain of our subsidiaries’ borrowing arrangements may
limit the transfer of funds to us under certain conditions.
We believe that we have adequate sources and availability of raw
materials and commodities for existing and anticipated business
needs. In support of our energy commodity activities, primarily
conducted through gas marketing services which is included
within our Exploration & Production segment, our
counterparties require us to provide various forms of credit
support such as margin, adequate assurance amounts and
pre-payments for gas supplies. Our pipeline systems are all
regulated in various ways resulting in the financial return on
the investments made in the systems being limited to standards
permitted by the regulatory agencies. Each of the pipeline
systems has ongoing capital requirements for efficiency and
mandatory improvements, with expansion opportunities also
necessitating periodic capital outlays.
REGULATORY
MATTERS
Williams
Partners
Gas Pipeline Business.
Williams Partners gas
pipeline’s 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. Each gas pipeline company is also
subject to the Natural Gas Pipeline Safety Act of 1968, as
amended, and the Pipeline Safety Improvement Act of 2002, which
regulates safety requirements in the design, construction,
operation and maintenance of interstate natural gas transmission
facilities. 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.
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Each of our interstate natural gas pipeline companies
establishes its rates primarily through the FERC’s
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; | |
| • | Contract and volume throughput assumptions. |
The allowed rate of return is determined in each rate case. Rate
design and the allocation of costs between the reservation and
commodity rates also impact profitability. As a result of these
proceedings, certain revenues previously collected may be
subject to refund.
Pipeline
Integrity Regulations
For Williams Partners’ gas pipeline business, Transco and
Northwest Pipeline have developed an Integrity Management Plan
that we believe meets the United States Department of
Transportation Pipeline and Hazardous Materials Safety
Administration (PHMSA) final rule that was issued pursuant to
the requirements of the Pipeline Safety Improvement Act of 2002.
The rule requires gas pipeline operators to develop an integrity
management program for transmission pipelines that could affect
high consequence areas in the event of pipeline failure. The
Integrity Management Program includes a baseline assessment plan
along with periodic reassessments to be completed within
required timeframes. In meeting the integrity regulations,
Transco and Northwest Pipeline have identified high consequence
areas and developed baseline assessment plans. Transco and
Northwest Pipeline are on schedule to complete the required
assessments within required timeframes. Currently, Transco and
Northwest Pipeline estimate the cost to complete the required
initial assessments over the period from 2011 and 2012 and
associated remediation will be primarily capital in nature and
range between $80 million and $110 million for Transco
and between $50 million and $60 million for Northwest
Pipeline. Ongoing periodic reassessments and initial assessments
of any new high consequence areas will be completed within the
timeframes required by the rule. Management considers the costs
associated with compliance with the rule to be prudent costs
incurred in the ordinary course of business, and, therefore,
recoverable through Transco’s and Northwest Pipeline’s
rates.
Midstream Business.
For Williams
Partners’ midstream business, 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 the midstream business 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
offshore gathering facilities 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.”
The midstream business 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 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.
The midstream business owns an interest in, and is expected to
become the operator in 2011, of Overland Pass Pipeline, which is
an interstate natural gas liquids pipeline regulated by the FERC
pursuant to the Interstate Commerce Act. Overland Pass provides
transportation service pursuant to tariffs filed with the FERC.
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Exploration &
Production
Our Exploration & Production business is subject to
various federal, state and local laws and regulations on
taxation and payment of royalties, and the development,
production and marketing of oil and gas, and environmental and
safety matters. Many laws and regulations require drilling
permits and govern the spacing of wells, rates of production,
water discharge, prevention of waste and other matters. Such
laws and regulations have increased the costs of planning,
designing, drilling, installing, operating and abandoning our
oil and gas wells and other facilities. In addition, these laws
and regulations, and any others that are passed by the
jurisdictions where we have production, could limit the total
number of wells drilled or the allowable production from
successful wells, which could limit our reserves.
Our gas marketing business is subject to a variety of laws and
regulations at the local, state and federal levels, including
the FERC and the Commodity Futures Trading Commission
regulations. In addition, natural gas markets continue to be
subject to numerous and wide-ranging federal and state
regulatory proceedings and investigations.
Other
Our Canadian assets are regulated by the Energy Resources
Conservation Board (ERCB) and Alberta Environment. The
regulatory system for the Alberta oil and gas industry
incorporates a large measure of self-regulation, providing that
licensed operators are held responsible for ensuring that their
operations are conducted in accordance with all provincial
regulatory requirements. For situations in which noncompliance
with the applicable regulations is at issue, the ERCB and
Alberta Environment have implemented an enforcement process with
escalating consequences.
See Note 16 of our Notes to Consolidated Financial
Statements for further details on our regulatory matters.
ENVIRONMENTAL
MATTERS
Our operations are subject to federal environmental laws and
regulations as well as the state and tribal laws and regulations
adopted by the jurisdictions in which we operate. We could incur
liability to governments or third parties for any unlawful
discharge of pollutants into the air, soil, or water, as well as
liability for cleanup costs. Materials could be released into
the environment in several ways including, but not limited to:
| • | From a well or drilling equipment at a drill site; | |
| • | Leakage from gathering systems, pipelines, processing or treating facilities, transportation facilities and storage tanks; | |
| • | Damage to oil and gas wells resulting from accidents during normal operations; | |
| • | Blowouts, cratering and explosions. |
Because the requirements imposed by environmental laws and
regulations are frequently changed, we cannot assure you that
laws and regulations enacted in the future, including changes to
existing laws and regulations, will not adversely affect our
business. In addition, we may be liable for environmental damage
caused by former operators of our properties.
We believe compliance with environmental laws and regulations
will not have a material adverse effect on capital expenditures,
earnings or competitive position. However, environmental laws
and regulations could affect our business in various ways from
time to time, including incurring capital and maintenance
expenditures, fines and penalties, and creating the need to seek
relief from the FERC for rate increases to recover the costs of
certain capital expenditures and operation and maintenance
expenses.
For a discussion of specific environmental issues, see
“Environmental” under Management’s Discussion and
Analysis of Financial Condition and Results of Operations and
“Environmental Matters” in Note 16 of our Notes
to Consolidated Financial Statements.
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COMPETITION
Williams
Partners
For our gas pipeline business, 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.
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.
In our midstream business, 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 customer’s choice of a
gathering or processing services provider, including rate,
location, term, reliability, timeliness of services to be
provided, pressure obligations and contract structure. We also
compete in recruiting and retaining skilled employees. By virtue
of the master limited partnership structure, WPZ provides us
with an alternative source of capital, which helps us compete
against other master limited partnerships for capital projects.
Exploration &
Production
Our exploration and production business competes with other oil
and gas concerns, including major and independent oil and gas
companies in the development, production and marketing of
natural gas. We compete in areas such as acquisition of oil and
gas properties and obtaining necessary equipment, supplies and
services. We also compete in recruiting and retaining skilled
employees.
In our gas marketing services business, we compete directly with
large independent energy marketers, marketing affiliates of
regulated pipelines and utilities, and natural gas producers. We
also compete with brokerage houses, energy hedge funds and other
energy-based companies offering similar services.
Other
Ethylene and propylene markets, and therefore our olefins
business, compete in a worldwide marketplace. Due to our NGL
feedstock position at Geismar, we will benefit from the lower
cost position in North America versus other crude-based
feedstocks worldwide. The majority of North American olefins
producers have significant downstream petrochemical
manufacturing for plastics and other products. As such, they buy
or sell ethylene and propylene as required. We operate as a
merchant seller of olefins with no downstream manufacturing, and
therefore can be either a supplier or a competitor at any given
time to these other companies depending on their market
balances. Generally, we are viewed primarily as a supplier to
these companies and not as a direct competitor. We compete on
the basis of service, price and availability of the products we
produce.
Our Canadian midstream facilities continue to be the only
NGL/olefins fractionator in western Canada and the only
treater/processor of oil sands upgrader off-gas. Our extraction
of liquids from the upgrader off-gas stream allows the upgraders
to burn cleaner natural gas streams and reduce their overall air
emissions. Our Canadian
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midstream business competes for the sale of its products with
traditional Canadian midstream companies on the basis of
operational expertise, price, service offerings and availability
of the products we produce.
EMPLOYEES
At February 1, 2011, we had approximately
5,022 full-time employees. None of our employees are
represented by unions or covered by collective bargaining
agreements.
FINANCIAL
INFORMATION ABOUT GEOGRAPHIC AREAS
See Note 18 of our Notes to Consolidated Financial
Statements for amounts of revenues during the last three fiscal
years from external customers attributable to the United States
and all foreign countries. Also see Note 18 of our Notes to
Consolidated Financial Statements for information relating to
long-lived assets during the last three fiscal years, located in
the United States and all foreign countries.
| Item 1A. | Risk Factors |
FORWARD-LOOKING
STATEMENTS AND CAUTIONARY STATEMENT
FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Certain matters contained in this report include
“forward-looking statements” within the meaning of
Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as
amended. These forward-looking statements relate to anticipated
financial performance, management’s plans and objectives
for future operations, business prospects, outcome of regulatory
proceedings, market conditions and other matters. We make these
forward-looking statements in reliance on the safe harbor
protections provided under the Private Securities Litigation
Reform Act of 1995.
All statements, other than statements of historical facts,
included in this report 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 forward-looking statements are
based on management’s beliefs and assumptions and on
information currently available to management and include, among
others, statements regarding:
| • | Amounts and nature of future capital expenditures; | |
| • | Expansion and growth of our business and operations; | |
| • | Financial condition and liquidity; | |
| • | Business strategy; | |
| • | Estimates of proved gas and oil reserves; | |
| • | Reserve potential; | |
| • | Development drilling potential; | |
| • | Cash flow from operations or results of operations; | |
| • | Seasonality of certain business segments; | |
| • | Natural gas, natural gas liquids and crude oil 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. Many of the factors that
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will determine these results 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:
| • | Availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future natural gas and oil reserves), market demand, volatility of prices, and the availability and cost of capital; | |
| • | Inflation, interest rates, fluctuation in foreign exchange, 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); | |
| • | The strength and financial resources of our competitors; | |
| • | Development of alternative energy sources; | |
| • | The impact of operational and development hazards; | |
| • | Costs of, changes in, or the results of laws, government regulations (including climate change legislation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation, and rate proceedings; | |
| • | Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans; | |
| • | Changes in maintenance and construction costs; | |
| • | Changes in the current geopolitical situation; | |
| • | Our exposure to the credit risk of our customers; | |
| • | 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; | |
| • | Risks associated with future weather conditions; | |
| • | Acts of terrorism; | |
| • | Additional risks described in our filings with the Securities and Exchange Commission. |
Given the uncertainties and risk factors that could cause our
actual results to differ materially from those contained in any
forward-looking statement, we caution investors not to unduly
rely on our forward-looking statements. We disclaim any
obligations to and do not intend to update the above list or to
announce publicly the result of any revisions to any of the
forward-looking statements to reflect future events or
developments.
In addition to causing our actual results to differ, the factors
listed above and referred to below may cause our intentions to
change from those statements of intention set forth in this
report. Such changes in our intentions may also cause our
results to differ. We may change our intentions, at any time and
without notice, based upon changes in such factors, our
assumptions, or otherwise.
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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
Related to Separation Plan
If our
plan to separate our exploration and production business is
delayed or not completed, our stock price may decline and our
growth potential may not be enhanced.
On February 16, 2011, we announced that our Board of
Directors approved pursuing a plan to divide our businesses into
two separate, publicly traded corporations. The plan calls for a
separation of our exploration and production business through an
initial public offering of up to 20 percent of the
corporation holding that business in 2011 and a tax-free spinoff
of our remaining interest in that corporation to our
shareholders in 2012. The completion and timing of each of the
transactions is dependent on a number of factors including, but
not limited to, the macroeconomic environment, credit markets,
equity markets, energy prices, the receipt of a tax opinion from
counsel
and/or
Internal Revenue Service rulings, final approvals from our Board
of Directors and other customary matters. We may not complete
the transactions at all or complete the transactions on the
timeline or on the terms that we announced. If the transactions
are not completed or delayed, our stock price may decline and
our growth potential may not be enhanced.
Risks
Inherent in our Business
The
long-term financial condition of our gas pipeline 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 pipeline 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 systems 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 or gathered through our pipeline systems and cash
flows associated with the gathering and 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
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, if development in new supply basins
where we do not have significant gathering or pipeline systems
reduces demand for our services, or if environmental regulators
restrict new natural gas drilling, the overall volume of natural
gas transported, gathered and stored on our system would
decline, which could have a material
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adverse effect on our business, financial condition and results
of operations. In addition, new LNG import facilities built near
our markets could result in less demand for our gathering and
transportation facilities.
Significant
prolonged changes in natural gas prices could affect supply and
demand and cause a termination of our transportation and storage
contracts or a reduction in throughput on the gas pipeline
systems.
Higher natural gas prices over the long term could result in a
decline in the demand for natural gas and, therefore, in
long-term transportation and storage contracts or throughput on
our gas pipeline 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 the
gas pipeline systems. As a result, significant prolonged changes
in natural gas prices could have a material adverse effect on
our gas pipeline business, financial condition, results of
operations and cash flows.
Prices
for NGLs, natural gas and other commodities, including oil, 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, oil, 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, financial
condition and cash flows.
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:
| • | Worldwide and domestic supplies of and demand for natural gas, NGLs, oil, and related commodities; | |
| • | Turmoil in the Middle East and other producing regions; | |
| • | The activities of the Organization of Petroleum Exporting Countries; | |
| • | Terrorist attacks on production or transportation assets; | |
| • | Weather conditions; | |
| • | The level of consumer demand; | |
| • | The price and availability of other types of fuels; | |
| • | The availability of pipeline capacity; | |
| • | Supply disruptions, including plant outages and transportation disruptions; | |
| • | The price and level of foreign imports; | |
| • | Domestic and foreign governmental regulations and taxes; | |
| • | Volatility in the natural gas and oil markets; | |
| • | The overall economic environment; | |
| • | The credit of participants in the markets where products are bought and sold; | |
| • | The adoption of regulations or legislation relating to climate change. |
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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, oil 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 counterparty’s 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.
Significant
capital expenditures are required to replace our
reserves.
Our exploration, development and acquisition activities require
substantial capital expenditures. Historically, we have funded
our capital expenditures through a combination of cash flows
from operations and debt and equity issuances. Future cash flows
are subject to a number of variables, including the level of
production from existing wells, prices of natural gas and oil,
and our success in developing and producing new reserves. If our
cash flow from operations is not sufficient to fund our capital
expenditure budget, we may not be able to access additional bank
debt, issue debt or equity securities or access other methods of
financing on an economic basis to meet our capital expenditure
budget. As a result, our capital expenditure plans may have to
be adjusted.
Failure
to replace reserves may negatively affect our
business.
The growth of our Exploration & Production business
depends upon our ability to find, develop or acquire additional
natural gas and oil reserves that are economically recoverable.
Our proved reserves generally decline when reserves are
produced, unless we conduct successful exploration or
development activities or acquire properties containing proved
reserves, or both. We may not be able to find, develop or
acquire additional reserves on an economic basis. If natural gas
or oil prices increase, our costs for additional reserves would
also increase; conversely if natural gas or oil prices decrease,
it could make it more difficult to fund the replacement of our
reserves.
Exploration
and development drilling may not result in commercially
productive reserves.
Our past success rate for drilling projects should not be
considered a predictor of future commercial success. We do not
always encounter commercially productive reservoirs through our
drilling operations. The new wells we drill or participate in
may not be productive and we may not recover all or any portion
of our investment in wells we drill or participate in. The cost
of drilling, completing and operating a well is often uncertain,
and cost factors can adversely affect the economics of a
project. Our efforts will be unprofitable if we drill dry wells
or wells that are productive but do not produce enough reserves
to return a profit after drilling, operating and other costs.
Further, our drilling operations may be curtailed, delayed or
canceled as a result of a variety of factors, including:
| • | Increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment, skilled labor, capital or transportation; | |
| • | Unexpected drilling conditions or problems; | |
| • | Regulations and regulatory approvals; | |
| • | Changes or anticipated changes in energy prices; | |
| • | Compliance with environmental and other governmental requirements. |
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Estimating
reserves and future net revenues involves uncertainties.
Negative revisions to reserve estimates, oil and gas prices or
assumptions as to future natural gas prices may lead to
decreased earnings, losses, or impairment of oil and gas
assets.
Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured
in an exact manner. Reserves that are “proved
reserves” are those estimated quantities of crude oil,
natural gas, and natural gas liquids that geological and
engineering data demonstrate with reasonable certainty are
recoverable in future years from known reservoirs under existing
economic and operating conditions, but should not be considered
as a guarantee of results for future drilling projects.
The process relies on interpretations of available geological,
geophysical, engineering and production data. There are numerous
uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing
of developmental expenditures, including many factors beyond the
control of the producer. The reserve data included in this
report represent estimates. In addition, the estimates of future
net revenues from our proved reserves and the present value of
such estimates are based upon certain assumptions about future
production levels, prices and costs that may not prove to be
correct.
Quantities of proved reserves are estimated based on economic
conditions in existence during the period of assessment. Changes
to oil and gas prices in the markets for such commodities may
have the impact of shortening the economic lives of certain
fields because it becomes uneconomic to produce all recoverable
reserves on such fields, which reduces proved property reserve
estimates.
If negative revisions in the estimated quantities of proved
reserves were to occur, it would have the effect of increasing
the rates of depreciation, depletion and amortization on the
affected properties, which would decrease earnings or result in
losses through higher depreciation, depletion and amortization
expense. These revisions, as well as revisions in the
assumptions of future cash flows of these reserves, may also be
sufficient to trigger impairment losses on certain properties
which would result in a noncash charge to earnings.
Certain
of our gas pipeline 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.
Our gas pipelines 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.
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.
Our primary exposure to market risk for our gas pipelines occurs
at the time the terms of their existing transportation and
storage contracts expire and are subject to termination. 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:
| • | The level of existing and new competition to deliver natural gas to our markets; | |
| • | The growth in demand for natural gas in our markets; | |
| • | Whether the market will continue to support long-term firm contracts; | |
| • | Whether our business strategy continues to be successful; | |
| • | 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.
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 and may
in the future enter into contracts to hedge certain risks
associated with our assets and operations. In these hedging
activities, we have used and may in the future use 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 contract’s 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:
| • | Volumes are less than expected; | |
| • | The hedging instrument is not perfectly effective in mitigating the risk being hedged; | |
| • | The counterparties to our hedging arrangements fail to honor their financial commitments. |
The
adoption and implementation of new statutory and regulatory
requirements for derivative transactions could have an adverse
impact on our ability to hedge risks associated with our
business and increase the working capital requirements to
conduct these activities.
In July 2010, federal legislation known as the Dodd-Frank Wall
Street Reform and Consumer Protection Act (the Act) was enacted.
The Act provides for new statutory and regulatory requirements
for derivative transactions, including oil and gas hedging
transactions. Among other things, the Act provides for the
creation of position limits for certain derivatives
transactions, as well as requiring certain transactions to be
cleared on exchanges for which cash collateral will be required.
The final impact of the Act on our hedging activities is
uncertain at this time due to the requirement that the SEC and
the Commodities Futures Trading Commission (CFTC) promulgate
rules and regulations implementing the new legislation within
360 days from the date of enactment. These new rules and
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regulations could significantly increase the cost of derivative
contracts, materially alter the terms of derivative contracts or
reduce the availability of derivatives. Although we believe the
derivative contracts that we enter into should not be impacted
by position limits and should be exempt from the requirement to
clear transactions through a central exchange or to post
collateral, the impact upon our businesses will depend on the
outcome of the implementing regulations adopted by the CFTC.
Depending on the rules and definitions adopted by the CFTC, we
might in the future be required to provide cash collateral for
our commodities hedging transactions under circumstances in
which we do not currently post cash collateral. Posting of such
additional cash collateral could impact liquidity and reduce our
cash available for capital expenditures. A requirement to post
cash collateral could therefore reduce our ability to execute
hedges to reduce commodity price uncertainty and thus protect
cash flows. If we reduce our use of derivatives as a result of
the Act and regulations, our results of operations may become
more volatile and our cash flows may be less predictable.
We
depend on certain key customers for a significant portion of our
revenues. The loss of any of these key customers or the loss of
any contracted volumes could result in a decline in our
business.
Our gas pipeline and midstream businesses rely on a limited
number of customers for a significant portion of their revenues.
Although some of these customers are subject to long-term
contracts, extensions or replacements of these contracts may not
be renegotiated 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, financial
condition, results of operations, and cash flows, unless we are
able to acquire comparable volumes from other sources.
We are
exposed to the credit risk of our customers, and our credit risk
management may not be adequate to protect against such
risk.
We are subject to the risk of loss resulting from nonpayment
and/or
nonperformance by our customers in the ordinary course of our
business. 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.
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. 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.
Similarly, 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. We may not 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, financial
condition, results of operations, and cash flows.
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Our
operations are subject to operational hazards and unforeseen
interruptions for which they may not be adequately
insured.
There are operational risks associated with drilling for,
production, gathering, transporting, storage, processing and
treating of natural gas and the fractionation and storage of
NGLs, including:
| • | Hurricanes, tornadoes, floods, fires, extreme weather conditions, and other natural disasters; | |
| • | Aging infrastructure and mechanical problems; | |
| • | Damages to pipelines and pipeline blockages; | |
| • | Uncontrolled releases of natural gas (including sour gas), NGLs, brine or industrial chemicals; | |
| • | Collapse of storage caverns; | |
| • | Operator error; | |
| • | Damage inadvertently caused by third-party activity, such as operation of construction equipment; | |
| • | Pollution and environmental risks; | |
| • | Fires, explosions, craterings and blowouts; | |
| • | Risks related to truck and rail loading and unloading; | |
| • | Risks related to operating in a marine environment; | |
| • | 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.
Our
costs of maintaining or repairing our facilities may exceed our
expectations and the FERC or competition in our markets may not
allow us to recover such costs in the rates we charge for our
services.
We could experience unexpected leaks or ruptures on our gas
pipeline and midstream systems, or be required by regulatory
authorities to undertake modifications to our systems that could
result in a material adverse impact on our business, financial
condition and results of operations if the costs of maintaining
or repairing our facilities exceed current expectations and the
FERC or competition in our markets do not allow us to recover
such costs in the rates we charge for our service.
We do
not insure against all potential losses and could be seriously
harmed by unexpected liabilities or by the inability of our
insurers to satisfy our claims.
We are not fully insured against all risks inherent to our
business, including environmental accidents. We do not maintain
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 annual aggregate
with a $2 million per occurrence deductible. This insurance
covers us, our subsidiaries, and certain of our affiliates for
legal and contractual liabilities arising out of bodily 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.
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Although we maintain property insurance on property we own,
lease or are responsible to insure, the policy may not cover the
full replacement cost of all damaged assets or the entire amount
of business interruption loss we may experience. In addition,
certain perils may be excluded from coverage or
sub-limited.
We may not be able to maintain or obtain insurance of the type
and amount we desire at reasonable rates. We may elect to self
insure a portion of our risks. We do not insure our onshore
underground pipelines for physical damage, except at certain
locations such as river crossings and compressor stations. Only
certain offshore key-assets are covered for property damage and
the resulting business interruption when loss is due to a named
windstorm event and coverage for loss caused by a named
windstorm is significantly
sub-limited.
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.
In addition, any insurance company that provides coverage to us
may experience negative developments that could impair their
ability to pay any of our 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.
The occurrence of any 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 repay our debt.
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.
The growth in our gas pipeline and midstream businesses 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:
| • | The ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms; | |
| • | The availability of skilled labor, equipment, and materials to complete expansion projects; | |
| • | 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; | |
| • | Impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms; | |
| • | The ability to construct projects within estimated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials, labor, or other factors beyond our control, that may be material; | |
| • | 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.
Our
costs and funding obligations for our defined benefit pension
plans and costs for our other postretirement benefit plans are
affected by factors beyond our control.
We have defined benefit pension plans covering substantially all
of our U.S. employees and other post-retirement benefit
plans covering certain eligible participants. The timing and
amount of our funding requirements under the defined benefit
pension plans depend upon a number of factors we control,
including changes to pension plan benefits, as well as factors
outside of our control, such as asset returns, interest rates
and changes in pension laws. Changes to these and other factors
that can significantly increase our funding requirements could
have a significant adverse effect on our financial condition and
results of operations.
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One of
our subsidiaries acts as the general partner of a publicly
traded limited partnership, Williams Partners L.P. As such, this
subsidiary’s operations may involve a greater risk of
liability than ordinary business operations.
One of our subsidiaries acts as the general partner of WPZ, a
publicly-traded limited partnership. This subsidiary may be
deemed to have undertaken fiduciary obligations with respect to
WPZ as the general partner and to the limited partners of WPZ.
Activities determined to involve fiduciary obligations to other
persons or entities typically involve a higher standard of
conduct than ordinary business operations and therefore may
involve a greater risk of liability, particularly when a
conflict of interests is found to exist. Our control of the
general partner of WPZ may increase the possibility of
claims of breach of fiduciary duties, including claims brought
due to conflicts of interest (including conflicts of interest
that may arise between WPZ, on the one hand, and its general
partner and that general partner’s affiliates, including
us, on the other hand). Any liability resulting from such claims
could be material.
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, and companies’
relationships with their independent public accounting firms. It
remains unclear what new laws or regulations will be adopted,
and we cannot predict the ultimate impact of that any such new
laws or regulations could have. In addition, the Financial
Accounting Standards Board, the SEC or FERC could enact new
accounting standards or FERC orders that might impact how we are
required to record revenues, expenses, assets, liabilities and
equity. Any significant change in accounting standards or
disclosure requirements could have a material adverse effect on
our business, results of operations, and financial condition.
Our
investments and projects located outside of the United States
expose us to risks related to the laws of other countries, and
the taxes, economic conditions, fluctuations in currency rates,
political conditions and policies of foreign governments. These
risks might delay or reduce our realization of value from our
international projects.
We currently own and might acquire
and/or
dispose of material energy-related investments and projects
outside the United States. The economic and political conditions
in certain countries where we have interests or in which we
might explore development, acquisition or investment
opportunities present risks of delays in construction and
interruption of business, as well as risks of 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. The
uncertainty of the legal environment in certain foreign
countries in which we develop or acquire projects or make
investments could make it more difficult to obtain nonrecourse
project financing or other financing on suitable terms, could
adversely affect the ability of certain customers to honor their
obligations with respect to such projects or investments and
could impair our ability to enforce our rights under agreements
relating to such projects or investments.
Operations and investments in foreign countries also can present
currency exchange rate and convertibility, inflation and
repatriation risk. In certain situations under which we develop
or acquire projects or make investments, economic and monetary
conditions and other factors could affect our ability to convert
to U.S. dollars our earnings denominated in foreign
currencies. In addition, risk from fluctuations in currency
exchange rates can arise when our foreign subsidiaries expend or
borrow funds in one type of currency, but receive revenue in
another. In such cases, an adverse change in exchange rates can
reduce our ability to meet expenses, including debt service
obligations. We may or may not put contracts in place designed
to mitigate our foreign currency exchange risks. We have some
exposures that are not hedged and which could result in losses
or volatility in our results of operations.
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
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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. Additionally, changes in the price of
natural gas could benefit one of our businesses, but
disadvantage another. For example, our Exploration &
Production business may benefit from higher natural gas prices,
and our midstream business, which uses gas as a feedstock, may
not.
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. In
those instances in which we do not own the land on which our
facilities are located, 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. In addition, some of our facilities cross Native American
lands pursuant to
rights-of-way
of limited term. We may not have the right of eminent domain
over land owned by Native American tribes. Our loss of these
rights, through our inability to renew
right-of-way
contracts or otherwise, could have a material adverse effect on
our business, results of operations, and financial condition and
cash flows.
Risks
Related to Strategy and Financing
Our
debt agreements impose restrictions on us that may limit our
access to credit and adversely affect our ability to operate our
business.
Certain of our debt agreements contain various covenants that
restrict or limit, among other things, our ability to grant
liens to support indebtedness, merge or sell substantially all
of our assets, make certain distributions during an event of
default, and incur additional debt. In addition, our debt
agreements contain, and those we enter into in the future may
contain, financial covenants and other limitations with which we
will need to comply. 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.
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 one debt agreement could cause a
cross-default or cross-acceleration of another debt agreement.
Such a cross-default or cross-acceleration could have a wider
impact on our liquidity than might otherwise arise from a
default or acceleration of a single debt instrument. If an event
of default occurs, or if other debt agreements cross-default,
and the lenders under the affected debt agreements accelerate
the maturity of any loans or other debt outstanding to us, we
may not have sufficient liquidity to repay amounts outstanding
under such debt agreements. For more information regarding our
debt agreements, please read “Management’s Discussion
and Analysis of Financial Condition and Results of
Operations — Management’s Discussion and Analysis
of Financial Condition and Liquidity.”
Our ability to repay, extend or refinance our existing debt
obligations and to obtain future credit will depend primarily on
our operating performance, which will be affected by general
economic, financial, competitive, legislative, regulatory,
business and other factors, many of which are beyond our
control. Our ability to refinance existing debt obligations or
obtain future credit will also depend upon the current
conditions in the credit markets and the availability of credit
generally. If we are unable to meet our debt service obligations
or obtain future credit on favorable terms, if at all, we could
be forced to restructure or refinance our indebtedness, seek
additional equity capital or sell assets. We may be unable to
obtain financing or sell assets on satisfactory terms, or at all.
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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 existing bank credit facilities, but our
ability to borrow under those facilities could be impaired if
one or more of our lenders fails to honor its contractual
obligation to lend to us.
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.
A
downgrade of our credit ratings could impact our liquidity,
access to capital and our costs of doing business, and
independent third parties determine our credit ratings outside
of our control.
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:
| • | Economic downturns; | |
| • | Deteriorating capital market conditions; | |
| • | Declining market prices for natural gas, NGLs and other commodities; | |
| • | Terrorist attacks or threatened attacks on our facilities or those of other energy companies; | |
| • | 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. 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 or that our
senior unsecured debt rating will be raised to investment grade
by all of the credit rating agencies.
Risks
Related to Regulations that Affect our Industry
Our
gas pipelines could be subject to penalties and fines if they
fail to comply with FERC regulations.
Our gas pipeline’s transportation and storage operations
are regulated by FERC. Should our gas pipelines 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 Natural Gas Act (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 our gas pipeline
business, financial condition, results of operations and cash
flows.
The
natural gas sales, transportation and storage operations of our
gas pipelines are subject to regulation by the FERC, which could
have an adverse impact on their ability to establish
transportation and storage
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rates that would allow them to recover the full cost of
operating their respective pipelines, including a reasonable
rate of return.
The natural gas sales, transmission and storage operations of
the gas pipelines are subject to federal, state and local
regulatory authorities. Specifically, their interstate pipeline
transportation and storage service is subject to regulation by
the FERC. The federal regulation extends to such matters as:
| • | Transportation and sale for resale of natural gas in interstate commerce; | |
| • | Rates, operating terms, and conditions of service, including initiation and discontinuation of service; | |
| • | The types of services the gas pipelines may offer their customers; | |
| • | Certification and construction of new facilities; | |
| • | Acquisition, extension, disposition or abandonment of facilities; | |
| • | Accounts and records; | |
| • | Depreciation and amortization policies; | |
| • | Relationships with affiliated companies who are involved in marketing functions of the natural gas business; | |
| • | Market manipulation in connection with interstate sales, purchases or transportation of natural gas. |
Under the 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.
Unlike other interstate 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 is referred to as an “IT feeder”
charge. The “IT feeder” rate is charged only when gas
is actually transported on the facilities and typically it is
paid by producers or marketers. Because the “IT
feeder” rate 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. This rate design
disparity could result in producers bypassing Transco’s
offshore facilities in favor of alternative transportation
facilities.
The rates, terms and conditions for interstate gas pipeline
services are set forth in FERC-approved tariffs. Any successful
complaint or protest against the rates of the gas pipelines
could have an adverse impact on their revenues associated with
providing transportation services. In addition, there is a risk
that rates set by FERC in future rate cases filed by the gas
pipelines 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.
We are
subject to risks associated with climate change.
There is a growing belief that emissions of greenhouse gases
(GHGs) may be linked to climate change. Climate change and the
costs that may be associated with its impacts and the regulation
of GHGs 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. For further
information regarding risks to our business arising from climate
change related legislation, please read the discussion below
under “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.”
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Our
operations are subject to governmental laws and regulations
relating to the protection of the environment, which may expose
us to significant costs and liabilities and could exceed current
expectations.
The risk of substantial environmental costs and liabilities is
inherent in natural gas drilling and well completion, 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:
| • | Clean Air Act (CAA) and analogous state laws, which impose obligations related to air emissions; | |
| • | Clean Water Act (CWA), and analogous state laws, which regulate discharge of wastewaters from our facilities to state and federal waters; | |
| • | 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; | |
| • | Resource Conservation and Recovery Act (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 U.S. 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 or construction 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.
We are generally responsible for all liabilities associated with
the environmental condition of our facilities and assets,
whether acquired or developed, regardless of when the
liabilities arose and whether they are known or unknown. In
connection with certain acquisitions and divestitures, we could
acquire, or be required to provide indemnification against,
environmental liabilities that could expose us to material
losses, which may not be covered by insurance. In addition, the
steps we could be required to take to bring certain facilities
into compliance could be
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prohibitively expensive, and we might be required to shut down,
divest or alter the operation of those facilities, which might
cause us to incur losses.
In addition, legislative and regulatory responses related to
GHGs and climate change creates the potential for financial
risk. The U.S. 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.
Numerous states have 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 lead to the
direct regulation of GHG emissions in our industry under the
EPA’s interpretation of its authority and obligations under
the CAA. The recent actions of the EPA and the passage of any
federal or state climate change laws or regulations 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 financial condition. 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.
Certain environmental and other groups have suggested that
additional laws and regulations may be needed to more closely
regulate the hydraulic fracturing process commonly used in
natural gas production. Legislation to further regulate
hydraulic fracturing has been proposed in Congress and the
U.S. Department of Interior has announced plans to
formalize obligations for disclosure of chemicals associated
with hydraulic fracturing on federal lands. In addition, some
state and local authorities have considered or formalized new
rules related to hydraulic fracturing and enacted moratoria on
such activities. We cannot predict whether any federal, state or
local legislation or regulation will be enacted in this area and
if so, what its provisions would be. If additional levels of
reporting, regulation and permitting were required, our
operations and those of our customers could be adversely
affected.
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 drilling,
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.
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 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 other
facilities were to become temporarily or permanently unavailable
for any reason, or if throughput were reduced because of
testing, line repair, damage to the 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. 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, financial condition and cash flows.
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Our
businesses are subject to complex government regulations. The
operation of our businesses might be adversely affected by
changes in these regulations or in their interpretation or
implementation, or the introduction of new laws or regulations
applicable to our businesses or our customers.
Existing regulations might be revised or reinterpreted, new laws
and regulations might be adopted or become applicable to us, our
facilities or our customers, and future changes in laws and
regulations could have a material adverse effect on our
financial condition, results of operations and cash flows. For
example, several ruptures on third party pipelines have occurred
recently. In response, various legislative and regulatory
reforms associated with pipeline safety and integrity have been
proposed, including reforms that would require increased
periodic inspections, installation of additional valves and
other equipment on our gas pipelines and subjecting additional
pipelines (including gathering facilities) to more stringent
regulation. Such reforms, if adopted, could significantly
increase our costs.
Legal
and regulatory proceedings and investigations relating to the
energy industry have adversely affected our business and may
continue to do so.
Public and regulatory scrutiny of the energy industry has
resulted in increased regulation being either proposed or
implemented. Such scrutiny has also resulted in various
inquiries, investigations and court proceedings in which we are
a named defendant. Both the shippers on our pipelines and
regulators have rights to challenge the rates we charge under
certain circumstances. Any successful challenge could materially
affect our 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 us, civil or criminal fines or penalties, or other
regulatory action, including legislation, which might be
materially adverse to the operation of our business and our
revenues and net income or increase our 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 us.
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.
The
recently lifted drilling moratorium in the Gulf of Mexico and
potentially more stringent regulations and permitting
requirements on drilling in the Gulf of Mexico could adversely
affect our results of operations, financial condition and cash
flows.
The drilling moratorium in the Gulf of Mexico (in force from May
to October 2010) impacted our production handling,
gathering and transportation operations through production
delays which reduced volumes of natural gas and oil delivered to
our platform, pipeline and gathering facilities in 2010. In
addition, the Bureau of Ocean Energy Management, Regulation and
Enforcement continues to develop more stringent drilling and
permitting requirements for producers in the Gulf of Mexico
which could cause delays in production or new drilling. A
significant decline or delay in production volumes in the Gulf
of Mexico could adversely affect our operating results,
financial condition and cash flows through reduced production
handling activities, gathering and transportation volumes,
processing activities or other midstream services.
Risks
Related to Employees, Outsourcing of Noncore Support Activities,
and Technology
Institutional
knowledge residing with current employees nearing retirement
eligibility might not be adequately preserved.
In certain segments of 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.
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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 we have taken steps to build a
cooperative and mutually beneficial relationship with our
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 an
outsourcing provider from service centers outside of the United
States. The economic and political conditions in certain
countries from which our outsourcing providers may provide
services to us present similar risks of business operations
located outside of the United States previously discussed,
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.
Risks
Related to Weather, other Natural Phenomena and Business
Disruption
Our
assets and operations can be adversely affected by weather and
other natural phenomena.
Our assets and operations, including those located offshore, 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.
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.
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, NGLs 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.
| Item 1B. | Unresolved Staff Comments |
None.
| Item 2. | Properties |
We own property in 32 states plus the District of Columbia
in the United States and in Argentina, Canada, Venezuela, and
Colombia.
Williams Partners generally owns its facilities, although a
substantial portion of the pipeline and gathering facilities is
constructed and maintained pursuant to
rights-of-way,
easements, permits, licenses or consents on and across
properties owned by others. In our Exploration &
Production segment, the majority of our ownership interest is
held as working interests in oil and gas leaseholds. In the Gulf
of Mexico region, our Other segment owns a
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5/6 interest
in and is the operator of an ethane cracker at Geismar,
Louisiana. It also owns ethane and propane pipeline systems and
a refinery grade propylene splitter in Louisiana. Its Canadian
operations include an oil sands off-gas processing plant located
near Ft. McMurray, Alberta, an NGL/olefin fractionation
facility at Redwater, Alberta, which is near Edmonton, Alberta,
as well as a new butylene/butane splitter and hydro-treating
facility.
| Item 3. | Legal Proceedings |
The information called for by this item is provided in
Note 16 of the Notes to Consolidated Financial Statements
of this report, which information is incorporated by reference
into this item.
Executive
Officers of the Registrant
The name, age, period of service, and title of each of our
executive officers as of February 24, 2011, are listed
below.
| Alan S. Armstrong | Director, Chief Executive Officer, and President |
| Age: 48 | ||
| Position held since January 2011. | ||
| Mr. Armstrong became a director, Chief Executive Officer, and President effective January 3, 2011. From February 2002 until January 2011 he was Senior Vice President, Midstream and acted as President of our Midstream business. From 1999 to February 2002, Mr. Armstrong was Vice President, Gathering and Processing for Midstream. From 1998 to 1999 he was Vice President, Commercial Development for Midstream. Mr. Armstrong serves as Chairman of the Board and Chief Executive Officer of Williams Partners GP LLC, the general partner of WPZ, where he was formerly Senior Vice President and a director from February 2010 and February 2005, respectively. | ||
| Randall L. Barnard | Senior Vice President, Gas Pipeline | |
| Age: 52 | ||
| Position held since February 2011. | ||
| Mr. Barnard acts as President of our Gas Pipeline business. Mr. Barnard served as Vice President of Natural Gas Market Development from July 2010 to February 2011. From April 2002 to July 2010, Mr. Barnard was Senior Vice President of Operations and Technical Service for Williams Gas Pipeline. From September 2000 to April 2002, he served as President of Williams International and Vice President and General Manager of Williams, and was a director and CEO of Apco Oil and Gas International Inc., formerly Apco Argentina. From June 1997 to September 2000, Mr. Barnard was General Manager of Williams International in Venezuela. Mr. Barnard is a director and Senior Vice President, Gas Pipeline, of Williams Partners GP LLC, the general partner of WPZ, Chairman of the Board of the Gas Technology Institute and is Vice Chair of the Common Ground Alliance. | ||
| James J. Bender | Senior Vice President and General Counsel | |
| Age: 54 | ||
| Position held since December 2002. | ||
| Prior to joining us, Mr. Bender was Senior Vice President and General Counsel with NRG Energy, Inc., a position held since June 2000, prior to which he was Vice President, General Counsel and Secretary of NRG Energy Inc. NRG Energy, Inc. filed a voluntary bankruptcy |
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| petition during 2003 and its plan of reorganization was approved in December 2003. Mr. Bender has served as the General Counsel of Williams Partners GP LLC, the general partner of WPZ since February 2005 and was General Counsel of Williams Pipeline GP LLC, the general partner of WMZ from August 2007 until its merger with WPZ in August 2010. | ||
| Donald R. Chappel | Senior Vice President and Chief Financial Officer | |
| Age: 59 | ||
| Position held since April 2003. | ||
| Prior to joining us, Mr. Chappel held various financial, administrative and operational leadership positions. Mr. Chappel also serves as Chief Financial Officer and a director of Williams Partners GP LLC, the general partner of WPZ. He was Chief Financial Officer from August 2007 and a director from January 2008 of Williams Pipeline GP LLC, the general partner of WMZ until its merger with WPZ in August 2010. Mr. Chappel is a director of SUPERVALU, Inc., Energy Insurance Mutual Limited, the Children’s Hospital Foundation at St. Francis and the Family & Children Services of Oklahoma. | ||
| Robyn L. Ewing | Senior Vice President and Chief Administrative Officer | |
| Age: 55 | ||
| Position held since April 2008. | ||
| From 2004 to 2008 Ms. Ewing was Vice President of Human Resources. Prior to joining Williams, Ms. Ewing worked at MAPCO, which merged with Williams in April 1998. She began her career with Cities Service Company in 1976. | ||
| Ralph A. Hill | Senior Vice President, Exploration & Production | |
| Age: 51 | ||
| Position held since December 1998. | ||
| Mr. Hill acts as President of our Exploration & Production business unit. He was Vice President of the Exploration & Production business from 1993 to 1998 as well as Senior Vice President Petroleum Services from 1998 to 2003. Mr. Hill serves as a director of Apco Oil and Gas International Inc. and Petrolera Entre Lomas S.A. | ||
| Rory L. Miller | Senior Vice President, Midstream | |
| Age: 50 | ||
| Position held since January 2011. | ||
| Mr. Miller acts as President of the Williams Partners midstream business. He was a Vice President of the Williams Partners midstream business from May 2004 to December 2011. Mr. Miller also serves as a director and Senior Vice President, Midstream of Williams Partners GP LLC, the general partner of WPZ. | ||
| Ted T. Timmermans | Vice President, Controller, and Chief Accounting Officer | |
| Age: 54 | ||
| Position held since July 2005. | ||
| Mr. Timmermans has served as Vice President, Controller & Chief Accounting Officer of Williams since July 2005. He served as Assistant Controller of Williams from April 1998 to July 2005. Mr. Timmermans is also Vice President, Controller & Chief |
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| Accounting Officer of Williams Partners GP LLC, the general partner of WPZ and served as Chief Accounting Officer of Williams Pipeline Partners GP LLC, the general partner of WMZ from January 2008 until its merger with WPZ in August 2010. | ||
| Phillip D. Wright | Senior Vice President, Corporate Development | |
| Age: 55 | ||
| Position held since February 2011. | ||
| Mr. Wright has served as Senior Vice President, Corporate Development since February 2011. He served as Senior Vice President, Gas Pipeline and acted as President of our Gas Pipeline business from January 2005 to February 2011. From October 2002 to January 2005, he served as Chief Restructuring Officer. From September 2001 to October 2002, Mr. Wright served as President and Chief Executive Officer of our subsidiary, Williams Energy Services, LLC. From 1996 until September 2001, he was Senior Vice President, Enterprise Development and Planning for our energy services group. Mr. Wright served as a director and Chief Operating Officer of Williams Pipeline GP LLC, the general partner of WMZ until its merger with WPZ in August 2010 and was a director and Senior Vice President, Gas Pipeline, of Williams Partners GP LLC, the general partner of WPZ from January 2010 to February 2011. |
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PART II
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Our common stock is listed on the New York Stock Exchange under
the symbol “WMB.” At the close of business on
February 21, 2011, we had approximately 10,032 holders of
record of our common stock. The high and low sales price ranges
(New York Stock Exchange composite transactions) and dividends
declared by quarter for each of the past two years are as
follows:
| 2010 | 2009 | |||||||||||||||||||||||
| Quarter | High | Low | Dividend | High | Low | Dividend | ||||||||||||||||||
|
1st
|
$ | 23.76 | $ | 19.51 | $ | 0.11 | $ | 16.87 | $ | 9.52 | $ | 0.11 | ||||||||||||
|
2nd
|
$ | 24.66 | $ | 18.16 | $ | 0.125 | $ | 17.99 | $ | 11.30 | $ | 0.11 | ||||||||||||
|
3rd
|
$ | 21.00 | $ | 17.53 | $ | 0.125 | $ | 19.21 | $ | 13.59 | $ | 0.11 | ||||||||||||
|
4th
|
$ | 24.89 | $ | 18.88 | $ | 0.125 | $ | 21.54 | $ | 16.57 | $ | 0.11 | ||||||||||||
Some of our subsidiaries’ borrowing arrangements may limit
the transfer of funds to us. These terms have not impeded, nor
are they expected to impede, our ability to pay dividends.
Performance
Graph
Set forth below is a line graph comparing our cumulative total
stockholder return on our common stock (assuming reinvestment of
dividends) with the cumulative total return of the S&P 500
Stock Index and the Bloomberg U.S. Pipeline Index for the
period of five fiscal years commencing January 1, 2006. The
Bloomberg U.S. Pipeline Index is composed of El Paso,
Enbridge, Spectra Energy, TransCanada Corp. and Williams. The
graph below assumes an investment of $100 at the beginning of
the period.
Cumulative
Total Shareholder Return
| 2005 | 2006 | 2007 | 2008 | 2009 | 2010 | |||||||||||||||||||
|
The Williams Companies, Inc.
|
100.0 | 114.4 | 158.6 | 65.3 | 97.8 | 117.4 | ||||||||||||||||||
|
S&P 500 Index
|
100.0 | 115.8 | 122.1 | 77.0 | 97.3 | 112.0 | ||||||||||||||||||
|
Bloomberg U.S. Pipelines Index
|
100.0 | 115.9 | 137.4 | 84.0 | 119.0 | 146.3 | ||||||||||||||||||
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| Item 6. | Selected Financial Data |
The following financial data at December 31, 2010 and 2009,
and for each of the three years in the period ended
December 31, 2010, should be read in conjunction with the
other financial information included in Part II,
Item 7,
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
and
Part II, Item 8,
Financial Statements and
Supplementary Data
of this
Form 10-K.
All other financial data has been prepared from our accounting
records.
| 2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
| (Millions, except per-share amounts) | ||||||||||||||||||||
|
Revenues
|
$ | 9,616 | $ | 8,255 | $ | 11,890 | $ | 10,239 | $ | 9,144 | ||||||||||
|
Income (loss) from continuing operations(1)
|
(916 | ) | 584 | 1,467 | 910 | 366 | ||||||||||||||
|
Income (loss) from discontinued operations(2)
|
(6 | ) | (223 | ) | 125 | 170 | (17 | ) | ||||||||||||
|
Amounts attributable to The Williams Companies, Inc.:
|
||||||||||||||||||||
|
Income (loss) from continuing operations
|
(1,091 | ) | 438 | 1,306 | 829 | 332 | ||||||||||||||
|
Income (loss) from discontinued operations
|
(6 | ) | (153 | ) | 112 | 161 | (23 | ) | ||||||||||||
|
Diluted earnings (loss) per common share:
|
||||||||||||||||||||
|
Income (loss) from continuing operations
|
(1.87 | ) | .75 | 2.21 | 1.37 | .55 | ||||||||||||||
|
Income (loss) from discontinued operations
|
(0.01 | ) | (0.26 | ) | 0.19 | 0.26 | (0.04 | ) | ||||||||||||
|
Total assets at December 31
|
24,972 | 25,280 | 26,006 | 25,061 | 25,402 | |||||||||||||||
|
Short-term notes payable and long-term debt due within one year
at December 31
|
508 | 17 | 18 | 108 | 358 | |||||||||||||||
|
Long-term debt at December 31
|
8,600 | 8,259 | 7,683 | 7,580 | 7,410 | |||||||||||||||
|
Stockholders’ equity at December 31
|
7,288 | 8,447 | 8,440 | 6,375 | 6,073 | |||||||||||||||
|
Cash dividends declared per common share
|
0.485 | .44 | .43 | .39 | .345 | |||||||||||||||
| (1) | Loss from continuing operations for 2010 includes $648 million of pre-tax costs associated with our restructuring, as well as approximately $1.7 billion of impairment charges related to goodwill and certain properties at Exploration & Production. See Note 4 of Notes to Consolidated Financial Statements for further discussion of asset sales, impairments, and other accruals in 2010, 2009, and 2008. Income from continuing operations for 2006 includes a $73 million charge for a litigation contingency and a $167 million charge for a securities litigation settlement and related costs. | |
| (2) | See Note 2 of Notes to Consolidated Financial Statements for the analysis of the 2010, 2009, and 2008 income (loss) from discontinued operations. The discontinued operations results for 2007 includes our former power business and our discontinued Venezuela operations. The discontinued operations results for 2006 includes our former power business, discontinued Venezuela operations, as well as amounts associated with our former chemical fertilizer business, a former exploration business, our former Alaska refinery, and our former distributive power business. |
43
Table of Contents
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
General
We are primarily an integrated natural gas company engaged in
finding, producing, gathering, processing, and transporting
natural gas. Our operations are located principally in the
United States and are organized into the following segments as
of December 31, 2010: Williams Partners,
Exploration & Production, and Other. (See Note 1
of Notes to Consolidated Financial Statements and Part I,
Item 1 for further discussion of these segments.)
Unless indicated otherwise, the following discussion and
analysis of critical accounting estimates, results of
operations, and financial condition and liquidity relates to our
current continuing operations and should be read in conjunction
with the consolidated financial statements and notes thereto
included in Part II, Item 8 of this document.
Change in
Structure and Dividend Increase
On February 16, 2011, we announced that our Board of
Directors approved pursuing a plan to separate the company into
two standalone, publicly traded corporations. The plan calls for
the separation of our exploration and production business into a
publicly traded company via an initial public offering of up to
20 percent of our interest in the third quarter of 2011. We
intend to complete the offering so that it preserves our ability
to complete a tax-free spinoff of our remaining ownership in the
exploration and production business to Williams’
shareholders in 2012, after which Williams would continue as a
premier natural gas infrastructure company. We retain the
discretion to determine whether and when to execute the spinoff.
Additionally, we intend to increase the quarterly dividend paid
to our shareholders, with an initial increase of 60 percent
(to $0.20 per share), for the first quarter of 2011 payable in
June 2011.
Management believes these actions will serve to enhance the
growth potential and overall valuation of our assets.
Overview
of 2010
The effects of the severe economic recession during late 2008
and 2009 have eased during 2010. Crude oil and NGL prices have
returned to attractive levels, but natural gas prices have
remained low. Natural gas prices have remained low and forward
natural gas prices have declined, primarily as a result of
significant increases in near- and long-term supplies, which
have outpaced near-term demand growth. The decline in forward
natural gas prices contributed significantly to impairments
recorded by our Exploration & Production segment in
the third quarter of 2010. However, lower natural gas prices,
along with strong NGL prices and ethane demand, contributed to
improved results in our midstream businesses. Abundant and
low-cost natural gas reserves in the United States are
44
Table of Contents
driving strong demand for midstream and pipeline infrastructure.
Objectives and highlights of our plan for 2010 include:
| Objectives | Highlights | ||
| Continuing to invest in our gathering and processing and interstate natural gas pipeline systems. | We invested $1 billion in capital and investment expenditures in our midstream businesses and also invested $473 million in capital expenditures in our gas pipelines during 2010. | ||
| Continuing to invest in our natural gas production development. | We invested $2.8 billion in drilling activity and acquisitions in Exploration & Production, including $1.7 billion related to acquisitions in the Bakken and Marcellus Shale areas. | ||
| Retaining the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions, as well as seizing attractive opportunities. | During 2010, our Williams Partners and Exploration & Production segments seized growth opportunities to expand in the Marcellus Shale, while Exploration & Production further diversified into oil production with an acquisition in North Dakota’s Bakken Shale. (See further discussion in Other Significant 2010 Events.) These expenditures were funded through cash flow from operations, debt and equity offerings at WPZ, and cash on hand, while maintaining our desired level of liquidity of at least $1 billion from cash and cash equivalents and unused revolving credit facilities. | ||
Our 2010 income (loss) from continuing operations attributable
to The Williams Companies, Inc. changed unfavorably by
$1.5 billion compared to 2009. This decrease is primarily
reflective of a $1 billion full impairment charge related
to goodwill at Exploration & Production and
$678 million of pre-tax charges associated with impairments
of certain producing properties and acquired unproved reserves
at Exploration & Production during the third quarter
of 2010. Additionally, we had $648 million of pre-tax costs
associated with our 2010 restructuring, including
$606 million of early debt retirement costs. Partially
offsetting these costs is the impact of an improved energy
commodity price environment in 2010 compared to 2009. See
additional discussion in Results of Operations.
Our net cash provided by operating activities for 2010 increased
$79 million compared to 2009, primarily due to the
improvement in the energy commodity price environment during the
year. See additional discussion in Management’s Discussion
and Analysis of Financial Condition and Liquidity.
Other
Significant 2010 Events
On February 17, 2010, we completed a strategic
restructuring that involved contributing certain of our wholly
and partially owned subsidiaries to WPZ, our consolidated master
limited partnership, and restructuring our debt (see
Note 11 of Notes to Consolidated Financial Statements).
In May 2010, Exploration & Production announced a
major acreage acquisition in the Marcellus Shale located in
northeast Pennsylvania. In July 2010, the purchase was completed
for $599 million, including closing adjustments. (See
Results of Operations — Segments,
Exploration & Production.)
On May 24, 2010, WPZ and WMZ entered into a merger
agreement providing for the merger of WMZ and WPZ. On
August 31, 2010, the WMZ unitholders approved the proposed
merger between the two master limited partnerships and the
merger was completed.
In July 2010, we notified our partner in the Overland Pass
Pipeline Company LLC (OPPL) of our election to exercise our
option to purchase an additional ownership interest, which
provides us with a 50 percent ownership
45
Table of Contents
interest in OPPL, for approximately $424 million. This
transaction was completed on September 9, 2010, primarily
with proceeds from WPZ’s credit facility. (See Results of
Operations — Segments, Williams Partners.)
Additionally, WPZ completed an equity offering resulting in net
proceeds of $437 million, which were used to reduce the
borrowing under WPZ’s credit facility.
In October 2010, we filed an application with the Federal Energy
Regulatory Commission (FERC) to upgrade compressor facilities
and expand our existing natural gas transmission system from
Alabama to markets as far north as North Carolina. The cost of
the project is estimated to be $219 million. The project is
expected to be phased into service in September 2012 and June
2013, with an increase in capacity of 225 Mdt/d.
In November 2010, WPZ acquired a business from
Exploration & Production represented by certain
gathering and processing assets in Colorado’s Piceance
basin, for $702 million in cash, approximately
1.8 million of WPZ common units and an increase in the
capital account of its general partner to allow us to maintain
our 2 percent general partner interest. (See Note 1 of
Notes to Consolidated Financial Statements.)
In November 2010, WPZ completed a public offering of
$600 million of its 4.125 percent senior notes due
2020. WPZ used the net proceeds from the offering to fund a
portion of the cash consideration paid for the previously
described gathering and processing assets in the Piceance basin.
(See further discussion in Results of Operations —
Segments, Williams Partners.)
In December 2010, WPZ acquired a midstream business in
Pennsylvania’s Marcellus Shale for $150 million. (See
further discussion in Results of Operations —
Segments, Williams Partners.)
In December 2010, Exploration & Production acquired a
company that holds a major acreage position (approximately
85,800 net acres) in North Dakota’s Bakken Shale oil
play that will diversify our interests into light, sweet crude
oil production. The purchase price was approximately
$949 million, including closing adjustments.
In December 2010, WPZ completed a public offering of
8 million of its common units, representing limited-partner
interests. WPZ used the net proceeds from the common unit public
offering for repayment of a $200 million borrowing under
the partnership’s credit facility, as well as funding a
portion of the consideration for the acquisition of midstream
assets in Pennsylvania’s Marcellus Shale. We made a cash
contribution to WPZ in order to maintain our 2 percent
general partner interest in the partnership. As a result of the
offering, our limited partner interest in the partnership was
reduced to 73 percent. See additional discussion in
Management’s Discussion and Analysis of Financial Condition
and Liquidity.
Outlook
for 2011
We believe we are well positioned to execute on our 2011
business plan and to capture attractive growth opportunities.
Economic and commodity price indicators for 2011 and beyond
reflect continued improvement in the economic environment.
However, given the potential volatility of these measures, it is
reasonably possible that the economy could worsen
and/or
commodity prices could decline, negatively impacting future
operating results and increasing the risk of nonperformance of
counterparties or impairments of long-lived assets.
As a result of our 2010 restructuring, as previously discussed,
we are better positioned to drive additional organic growth and
aggressively pursue value-adding growth opportunities. Our
structure is designed to lower capital costs, enhance reliable
access to capital markets, and create a greater ability to
pursue development projects and acquisitions.
We continue to operate with a focus on increasing Economic Value
Added
®
(EVA
®
)
1
and invest in our businesses in a way that meets customer needs
and enhances our competitive position by:
| • | Continuing to invest in and grow our gathering and processing, interstate natural gas pipeline systems, and natural gas and oil drilling; |
1
Economic
Value
Added
®
(EVA
®
)
is a registered trademark of Stern, Stewart & Co. This
tool considers both financial earnings and a cost of capital in
measuring performance. We look for opportunities to improve
EVA
®
because we believe there is a strong correlation between
EVA
®
improvement and creation of shareholder value.
46
Table of Contents
| • | Retaining the flexibility to adjust somewhat our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities. |
Potential risks
and/or
obstacles that could impact the execution of our plan include:
| • | Lower than anticipated energy commodity prices; | |
| • | Lower than expected levels of cash flow from operations; | |
| • | Availability of capital; | |
| • | Counterparty credit and performance risk; | |
| • | Decreased drilling success at Exploration & Production; | |
| • | Decreased volumes from third parties served by our midstream businesses; | |
| • | General economic, financial markets, or industry downturn; | |
| • | Changes in the political and regulatory environments; | |
| • | Physical damages to facilities, especially damage to offshore facilities by named windstorms for which our aggregate insurance policy limit is $75 million in the event of a material loss. |
We continue to address these risks through utilization of
commodity hedging strategies, disciplined investment strategies,
and maintaining at least $1 billion in consolidated
liquidity from cash and cash equivalents and unused revolving
credit facilities. In addition, we utilize master netting
agreements and collateral requirements with our counterparties
to reduce credit risk and liquidity requirements.
Critical
Accounting Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions. We have reviewed the selection,
application, and disclosure of these critical accounting
estimates with our Audit Committee. We believe that the nature
of these estimates and assumptions is material due to the
subjectivity and judgment necessary, or the susceptibility of
such matters to change, and the impact of these on our financial
condition or results of operations.
Impairments
of Goodwill and Long-Lived Assets
We have assessed goodwill for impairment annually as of the end
of the year and we have performed interim assessments of
goodwill if impairment triggering events or circumstances were
present. One such triggering event is a significant decline in
forward natural gas prices. During the first and second quarter
of 2010, we evaluated the impact of declines in forward gas
prices across all future production periods and determined that
the impact was not significant enough to warrant a full
impairment review. Forward natural gas prices through 2025 used
in these prior analyses had declined less than 10 percent,
on average, from December 31, 2009 through March 31,
2010 and June 30, 2010. During the third quarter of 2010,
these forward natural gas prices through 2025 declined an
additional 19 percent for a total
year-to-date
decline of more than 22 percent on average through
September 30, 2010. Based on forward prices as of
September 30, 2010, we evaluated the impact of this decline
across all future production periods and determined that a full
impairment review was warranted.
As a result, we evaluated our goodwill of approximately
$1 billion resulting from a 2001 acquisition at
Exploration & Production related to its domestic
natural gas production operations (the reporting unit). Our
impairment evaluation of goodwill first considered our
management’s estimate of the fair value of the reporting
unit compared to its carrying value, including goodwill. If the
carrying value of the reporting unit exceeded its fair value, a
computation of the implied fair value of the goodwill was
compared with its related carrying value. If the carrying value
of the reporting unit goodwill exceeded the implied fair value
of that goodwill, an impairment loss was recognized in the
amount of the excess. Because quoted market prices were not
available for the reporting unit, management applied reasonable
judgments (including market supported assumptions when
available) in estimating the fair value for the reporting unit.
We estimated the fair value of the reporting unit on a
stand-alone basis and also
47
Table of Contents
considered our market capitalization and third party estimates
in corroborating our estimate of the fair value of the reporting
unit.
The fair value of the reporting unit was estimated primarily by
valuing proved and unproved reserves. We use an income approach
(discounted cash flows) for valuing reserves. The significant
inputs into the valuation of proved and unproved reserves
include reserve quantities, forward natural gas prices,
anticipated drilling and operating costs, anticipated production
curves, income taxes, and appropriate discount rates. To
estimate the fair value of the reporting unit and the implied
fair value of goodwill under a hypothetical acquisition of the
reporting unit, we assumed a tax structure where a buyer would
obtain a
step-up
in
the tax basis of the net assets acquired.
In our assessment as of September 30, 2010, the carrying
value of the reporting unit, including goodwill, exceeded its
fair value. We then determined that the implied fair value of
the goodwill was zero. As a result, we recognized a full
$1 billion impairment charge related to Exploration &
Production’s goodwill. See Note 4 and Note 14 of
Notes to Consolidated Financial Statements for additional
discussion and significant inputs into the fair value
determination.
We evaluate our long-lived assets for impairment when we believe
events or changes in circumstances indicate that we may not be
able to recover the carrying value. Our computations utilize
judgments and assumptions that include the estimated fair value
of the asset, undiscounted future cash flows, discounted future
cash flows, and the current and future economic environment in
which the asset is operated.
As a result of significant declines in forward natural gas
prices during the third quarter of 2010, we assessed
Exploration & Production’s natural gas producing
properties and acquired unproved reserve costs for impairment
using estimates of future cash flows. Significant judgments and
assumptions in these assessments include estimates of natural
gas reserves quantities, estimates of future natural gas prices
using a forward NYMEX curve adjusted for locational basis
differentials, drilling plans, expected capital costs, and our
estimate of an applicable discount rate commensurate with risk
of the underlying cash flow estimates. The assessment performed
at September 30, 2010 identified certain properties with a
carrying value in excess of their calculated fair values. As a
result, we recognized a $678 million impairment charge. See
Note 4 and Note 14 of Notes to Consolidated Financial
Statements for additional discussion and significant inputs into
the fair value determination.
In addition to those long-lived assets described above for which
impairment charges were recorded, certain others were reviewed
for which no impairment was required. These reviews included
Exploration & Production’s other domestic
producing properties and acquired unproved reserve costs, and
utilized inputs generally consistent with those described above.
Judgments and assumptions are inherent in our estimate of future
cash flows used to evaluate these assets. The use of alternate
judgments and assumptions could result in the recognition of
different levels of impairment charges in the consolidated
financial statements. For Exploration &
Production’s other producing assets reviewed, but for which
impairment charges were not recorded, we estimate that
approximately 10 percent could be at risk for impairment if
forward prices across all future periods decline by
approximately 8 to 11 percent, on average, as compared to
the forward prices at December 31, 2010. A substantial
portion of the remaining carrying value of these other assets
(primarily related to Exploration & Production’s
assets in the Piceance basin) could be at risk for impairment if
forward prices across all future periods decline by at least
30 percent, on average, as compared to the prices at
December 31, 2010.
Accounting
for Derivative Instruments and Hedging Activities
We review our energy contracts to determine whether they are
derivatives or contain derivatives. We further assess the
appropriate accounting method for any derivatives identified,
which could include:
| • | Qualifying for and electing cash flow hedge accounting, which recognizes changes in the fair value of the derivative in other comprehensive income (to the extent the hedge is effective) until the hedged item is recognized in earnings; | |
| • | Qualifying for and electing accrual accounting under the normal purchases and normal sales exception; or | |
| • | Applying mark-to-market accounting, which recognizes changes in the fair value of the derivative in earnings. |
48
Table of Contents
If cash flow hedge accounting or accrual accounting is not
applied, a derivative is subject to
mark-to-market
accounting. Determination of the accounting method involves
significant judgments and assumptions, which are further
described below.
The determination of whether a derivative contract qualifies as
a cash flow hedge includes an analysis of historical market
price information to assess whether the derivative is expected
to be highly effective in offsetting the cash flows attributed
to the hedged risk. We also assess whether the hedged forecasted
transaction is probable of occurring. This assessment requires
us to exercise judgment and consider a wide variety of factors
in addition to our intent, including internal and external
forecasts, historical experience, changing market and business
conditions, our financial and operational ability to carry out
the forecasted transaction, the length of time until the
forecasted transaction is projected to occur, and the quantity
of the forecasted transaction. In addition, we compare actual
cash flows to those that were expected from the underlying risk.
If a hedged forecasted transaction is not probable of occurring,
or if the derivative contract is not expected to be highly
effective, the derivative does not qualify for hedge accounting.
For derivatives designated as cash flow hedges, we must
periodically assess whether they continue to qualify for hedge
accounting. We prospectively discontinue hedge accounting and
recognize future changes in fair value directly in earnings if
we no longer expect the hedge to be highly effective, or if we
believe that the hedged forecasted transaction is no longer
probable of occurring. If the forecasted transaction becomes
probable of not occurring, we reclassify amounts previously
recorded in other comprehensive income into earnings in addition
to prospectively discontinuing hedge accounting. If the
effectiveness of the derivative improves and is again expected
to be highly effective in offsetting the cash flows attributed
to the hedged risk, or if the forecasted transaction again
becomes probable, we may prospectively re-designate the
derivative as a hedge of the underlying risk.
Derivatives for which the normal purchases and normal sales
exception has been elected are accounted for on an accrual
basis. In determining whether a derivative is eligible for this
exception, we assess whether the contract provides for the
purchase or sale of a commodity that will be physically
delivered in quantities expected to be used or sold over a
reasonable period in the normal course of business. In making
this assessment, we consider numerous factors, including the
quantities provided under the contract in relation to our
business needs, delivery locations per the contract in relation
to our operating locations, duration of time between entering
the contract and delivery, past trends and expected future
demand, and our past practices and customs with regard to such
contracts. Additionally, we assess whether it is probable that
the contract will result in physical delivery of the commodity
and not net financial settlement.
Since our energy derivative contracts could be accounted for in
three different ways, two of which are elective, our accounting
method could be different from that used by another party for a
similar transaction. Furthermore, the accounting method may
influence the level of volatility in the financial statements
associated with changes in the fair value of derivatives, as
generally depicted below:
| Consolidated Statement of Operations | Consolidated Balance Sheet | |||||||
| Accounting Method | Drivers | Impact | Drivers | Impact | ||||
|
Accrual Accounting
|
Realizations | Less Volatility | None | No Impact | ||||
|
Cash Flow Hedge Accounting
|
Realizations & Ineffectiveness | Less Volatility | Fair Value Changes | More Volatility | ||||
|
Mark-to-Market
Accounting
|
Fair Value Changes | More Volatility | Fair Value Changes | More Volatility | ||||
Our determination of the accounting method does not impact our
cash flows related to derivatives.
Additional discussion of the accounting for energy contracts at
fair value is included in Notes 1 and 15 of Notes to
Consolidated Financial Statements.
49
Table of Contents
Oil-
and Gas-Producing Activities
We use the successful efforts method of accounting for our oil-
and gas-producing activities. Estimated natural gas and oil
reserves and forward market prices for oil and gas are a
significant part of our financial calculations. Following are
examples of how these estimates affect financial results:
| • | An increase (decrease) in estimated proved oil and gas reserves can reduce (increase) our unit-of-production depreciation, depletion, and amortization rates. | |
| • | Changes in oil and gas reserves and forward market prices both impact projected future cash flows from our oil and gas properties. This, in turn, can impact our periodic impairment analyses. |
The process of estimating natural gas and oil reserves is very
complex, requiring significant judgment in the evaluation of all
available geological, geophysical, engineering, and economic
data. After being estimated internally, approximately
94 percent of our domestic reserve estimates are audited by
independent experts. (See Part I, Item 1 for further
discussion.) The data may change substantially over time as a
result of numerous factors, including additional development
cost and activity, evolving production history, and a continual
reassessment of the viability of production under changing
economic conditions. As a result, material revisions to existing
reserve estimates could occur from time to time. Such changes
could trigger an impairment of our oil and gas properties and
have an impact on our
depreciation, depletion, and
amortization
expense prospectively. For example, a change of
approximately 10 percent in our total oil and gas reserves could
change our annual
depreciation, depletion, and amortization
expense between approximately $77 million and
$94 million. The actual impact would depend on the specific
basins impacted and whether the change resulted from proved
developed, proved undeveloped, or a combination of these reserve
categories.
Forward market prices, which are utilized in our impairment
analyses, include estimates of prices for periods that extend
beyond those with quoted market prices. This forward market
price information is consistent with that generally used in
evaluating our drilling decisions and acquisition plans. These
market prices for future periods impact the production economics
underlying oil and gas reserve estimates. The prices of natural
gas and oil are volatile and change from period to period, thus
impacting our estimates. Significant unfavorable changes in the
forward price curve could result in an impairment of our oil and
gas properties.
Contingent
Liabilities
We record liabilities for estimated loss contingencies,
including environmental matters, when we assess that a loss is
probable and the amount of the loss can be reasonably estimated.
Revisions to contingent liabilities are generally reflected in
income when 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. Liabilities
for contingent losses are based upon our assumptions and
estimates and upon advice of legal counsel, engineers, or other
third parties regarding the probable outcomes of the matter.
Areas of significance include certain royalty-related and other
litigated matters, as well as environmental matters. As new
developments occur or more information becomes available, our
assumptions and estimates of these liabilities may 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 quarterly
or annual period. See Note 16 of Notes to Consolidated
Financial Statements.
Valuation
of Deferred Tax Assets and Tax Contingencies
We have deferred tax assets resulting from certain investments
and businesses that have a tax basis in excess of the book basis
and from tax carry-forwards generated in the current and prior
years. We must evaluate whether we will ultimately realize these
tax benefits and establish a valuation allowance for those that
may not be realizable. This evaluation considers tax planning
strategies, including assumptions about the availability and
character of future taxable income. When assessing the need for
a valuation allowance, we consider forecasts of future company
performance, the estimated impact of potential asset
dispositions, and our ability and intent to execute tax planning
strategies to utilize tax carryovers. The ultimate amount of
deferred tax assets realized could be materially different from
those recorded, as influenced by potential changes in
jurisdictional income tax laws and the circumstances surrounding
the actual realization of related tax assets, including the
impact of organizational or structural changes.
50
Table of Contents
We regularly face challenges from domestic and foreign tax
authorities regarding the amount of taxes due. These challenges
include questions regarding the timing and amount of deductions
and the allocation of income among various tax jurisdictions. We
evaluate the liability associated with our various filing
positions by applying the two step process of recognition and
measurement. The ultimate disposition of these contingencies
could have a significant impact on operating results and net
cash flows. To the extent we were to prevail in matters for
which accruals have been established or were required to pay
amounts in excess of our accrued liability, our effective tax
rate in a given financial statement period may be materially
impacted.
See Note 5 of Notes to Consolidated Financial Statements
for additional information.
Pension
and Postretirement Obligations
We have employee benefit plans that include pension and other
postretirement benefits. Net periodic benefit expense and
obligations for these plans are impacted by various estimates
and assumptions. These estimates and assumptions include the
expected long-term rates of return on plan assets, discount
rates, expected rate of compensation increase, health care cost
trend rates, and employee demographics, including retirement age
and mortality. These assumptions are reviewed annually and
adjustments are made as needed. The assumptions utilized to
compute expense and the benefit obligations are shown in
Note 7 of Notes to Consolidated Financial Statements.
The following table presents the estimated increase (decrease)
in net periodic benefit expense and obligations resulting from a
one-percentage-point change in the specified assumption.
| Benefit Expense | Benefit Obligation | |||||||||||||||
|
One-Percentage-
|
One-Percentage-
|
One-Percentage-
|
One-Percentage-
|
|||||||||||||
| Point Increase | Point Decrease | Point Increase | Point Decrease | |||||||||||||
| (Millions) | ||||||||||||||||
|
Pension benefits:
|
||||||||||||||||
|
Discount rate
|
$ | (10 | ) | $ | 11 | $ | (133 | ) | $ | 158 | ||||||
|
Expected long-term rate of return on plan assets
|
(10 | ) | 10 | — | — | |||||||||||
|
Rate of compensation increase
|
3 | (3 | ) | 14 | (12 | ) | ||||||||||
|
Other postretirement benefits:
|
||||||||||||||||
|
Discount rate
|
(3 | ) | 3 | (35 | ) | 43 | ||||||||||
|
Expected long-term rate of return on plan assets
|
(2 | ) | 2 | — | — | |||||||||||
|
Assumed health care cost trend rate
|
5 | (4 | ) | 39 | (32 | ) | ||||||||||
Our expected long-term rates of return on plan assets, as
determined at the beginning of each fiscal year, are based on
the average rate of return expected on the funds invested in the
plans. We determine our long-term expected rate of return on
plan assets using our expectations of capital market results,
which includes an analysis of historical results as well as
forward-looking projections. These capital market expectations
are based on a long-term period of at least ten years and
consider our investment strategy and mix of assets, which is
weighted toward domestic and international equity securities. We
develop our expectations using input from several external
sources, including consultation with our third-party independent
investment consultant. The forward-looking capital market
projections are developed using a consensus of economists’
expectations for inflation, GDP growth, and dividend yield along
with expected changes in risk premiums. The capital market
return projections for specific asset classes in the investment
portfolio are then applied to the relative weightings of the
asset classes in the investment portfolio. The resulting rate is
an estimate of future results and, thus, likely to be different
than actual results.
The capital markets continued to improve in 2010 and the benefit
plans’ assets reflect this improvement. While the 2010
investment performance was greater than our expected rates of
return, the expected rates of return on plan assets are
long-term in nature and are not significantly impacted by
short-term market performance. Changes to our asset allocation
would also impact these expected rates of return. Our expected
long-term rate of return on plan assets used for our pension
plans had been 7.75 percent since 2006. In 2010, we reduced
our expected long-term rate of return on pension plan assets to
7.5 percent. This reduction was implemented due to changes
in long-term capital market expectations and our intent to
slightly reduce the equity exposure and increase the fixed
income exposure in
51
Table of Contents
the investment portfolio. The 2010 actual return on plan assets
for our pension plans was a gain of approximately
12.9 percent. The ten-year average rate of return on
pension plan assets through December 2010 was approximately
3.3 percent and is largely affected by the approximately
34.1 percent loss experienced in 2008.
The discount rates are used to measure the benefit obligations
of our pension and other postretirement benefit plans. The
objective of the discount rates is to determine the amount, if
invested at the December 31 measurement date in a portfolio of
high-quality debt securities, that will provide the necessary
cash flows when benefit payments are due. Increases in the
discount rates decrease the obligation and, generally, decrease
the related expense. The discount rates for our pension and
other postretirement benefit plans are determined separately
based on an approach specific to our plans and their respective
expected benefit cash flows as described in Note 7 of Notes
to Consolidated Financial Statements. Our discount rate
assumptions are impacted by changes in general economic and
market conditions that affect interest rates on long-term
high-quality debt securities as well as by the duration of our
plans’ liabilities.
The expected rate of compensation increase represents average
long-term salary increases. An increase in this rate causes the
pension obligation and expense to increase.
The assumed health care cost trend rates are based on national
trend rates adjusted for our actual historical cost rates and
plan design. An increase in this rate causes the other
postretirement benefit obligation and expense to increase.
Fair
Value Measurements
A limited amount of our energy derivative assets and liabilities
trade in markets with lower availability of pricing information
requiring us to use unobservable inputs and are considered
Level 3 in the fair value hierarchy. At December 31,
2010, less than 1 percent of our energy derivative assets
and liabilities measured at fair value on a recurring basis are
included in Level 3. For Level 2 transactions, we do
not make significant adjustments to observable prices in
measuring fair value as we do not generally trade in inactive
markets.
The determination of fair value for our energy derivative 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 cash
collateral posted and letters of credit) and our nonperformance
risk on our energy derivative liabilities. The determination of
the fair value of our energy derivative liabilities does not
consider noncash collateral credit enhancements. For net
derivative assets, we apply a credit spread, based on the credit
rating of the counterparty, against the net derivative asset
with that counterparty. For net derivative liabilities we apply
our own credit rating. We derive the credit spreads by using the
corporate industrial credit curves for each rating category and
building a curve based on certain points in time for each rating
category. The spread comes from the discount factor of the
individual corporate curves versus the discount factor of the
LIBOR curve. At December 31, 2010, the credit reserve is
less than $1 million on both our net derivative assets and
net derivative liabilities. Considering these factors and that
we do not have significant risk from our net credit exposure to
derivative counterparties, the impact of credit risk is not
significant to the overall fair value of our derivatives
portfolio.
At December 31, 2010, 89 percent of the fair value of
our derivatives portfolio expires in the next 12 months and
more than 99 percent expires in the next 24 months.
Our derivatives portfolio is largely comprised of
exchange-traded products or like products where price
transparency has not historically been a concern. Due to the
nature of the markets in which we transact and the relatively
short tenure of our derivatives portfolio, we do not believe it
is necessary to make an adjustment for illiquidity. We regularly
analyze the liquidity of the markets based on the prevalence of
broker pricing and exchange pricing for products in our
derivatives portfolio.
The instruments included in Level 3 at December 31,
2010, consist of natural gas index transactions that are used to
manage the physical requirements of our Exploration &
Production segment. The change in the overall fair value of
instruments included in Level 3 primarily results from
changes in commodity prices.
Exploration & Production has an unsecured credit
agreement through December 2015 with certain banks that, so long
as certain conditions are met, serves to reduce our usage of
cash and other credit facilities for margin requirements related
to instruments included in the facility.
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Table of Contents
For the years ended December 31, 2010 and 2009, we
recognized impairments of certain assets that were measured at
fair value on a nonrecurring basis. These impairment
measurements are included in Level 3 as they include
significant unobservable inputs, such as our estimate of future
cash flows and the probabilities of alternative scenarios. (See
Note 14 of Notes to Consolidated Financial Statements.)
Results
of Operations
Consolidated
Overview
The following table and discussion is a summary of our
consolidated results of operations for the three years ended
December 31, 2010. The results of operations by segment are
discussed in further detail following this consolidated overview
discussion.
| Years Ended December 31, | ||||||||||||||||||||||||||||
|
$ Change
|
% Change
|
$ Change
|
% Change
|
|||||||||||||||||||||||||
|
from
|
from
|
from
|
from
|
|||||||||||||||||||||||||
| 2010 | 2009* | 2009* | 2009 | 2008* | 2008* | 2008 | ||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||
|
Revenues
|
$ | 9,616 | +1,361 | +16 | % | $ | 8,255 | − 3,635 | −31 | % | $ | 11,890 | ||||||||||||||||
|
Costs and expenses:
|
||||||||||||||||||||||||||||
|
Costs and operating expenses
|
7,185 | −1,104 | −18 | % | 6,081 | + 2,695 | +31 | % | 8,776 | |||||||||||||||||||
|
Selling, general and administrative expenses
|
498 | +14 | +3 | % | 512 | −8 | −2 | % | 504 | |||||||||||||||||||
|
Impairments of goodwill and long-lived assets
|
1,692 | −1,672 | NM | 20 | + 133 | +87 | % | 153 | ||||||||||||||||||||
|
Other (income) expense — net
|
(24 | ) | +21 | NM | (3 | ) | −222 | −99 | % | (225 | ) | |||||||||||||||||
|
General corporate expenses
|
221 | −57 | −35 | % | 164 | −15 | −10 | % | 149 | |||||||||||||||||||
|
Total costs and expenses
|
9,572 | 6,774 | 9,357 | |||||||||||||||||||||||||
|
Operating income (loss)
|
44 | 1,481 | 2,533 | |||||||||||||||||||||||||
|
Interest accrued — net
|
(581 | ) | +4 | +1 | % | (585 | ) | −8 | −1 | % | (577 | ) | ||||||||||||||||
|
Investing income — net
|
209 | +163 | NM | 46 | −143 | −76 | % | 189 | ||||||||||||||||||||
|
Early debt retirement costs
|
(606 | ) | −605 | NM | (1 | ) | — | — | (1 | ) | ||||||||||||||||||
|
Other income (expense) — net
|
(12 | ) | −14 | NM | 2 | + 2 | NM | — | ||||||||||||||||||||
|
Income (loss) from continuing operations before income taxes
|
(946 | ) | 943 | 2,144 | ||||||||||||||||||||||||
|
Provision (benefit) for income taxes
|
(30 | ) | +389 | NM | 359 | + 318 | +47 | % | 677 | |||||||||||||||||||
|
Income (loss) from continuing operations
|
(916 | ) | 584 | 1,467 | ||||||||||||||||||||||||
|
Income (loss) from discontinued operations
|
(6 | ) | +217 | +97 | % | (223 | ) | −348 | NM | 125 | ||||||||||||||||||
|
Net income (loss)
|
(922 | ) | 361 | 1,592 | ||||||||||||||||||||||||
|
Less: Net income attributable to noncontrolling interests
|
175 | −99 | −130 | % | 76 | + 98 | +56 | % | 174 | |||||||||||||||||||
|
Net income (loss) attributable to The Williams Companies,
Inc.
|
$ | (1,097 | ) | $ | 285 | $ | 1,418 | |||||||||||||||||||||
| * | + = Favorable change; − = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200. |
2010 vs.
2009
The increase in
revenues
is primarily due to higher
marketing and NGL production revenues due to higher average
energy commodity prices at Williams Partners. Additionally,
Exploration & Production gas management and production
revenues increased reflecting an increase in average natural gas
prices, partially offset by a decrease in production volumes
sold. NGL and olefin production revenues at Other also increased
due to higher average
per-unit
prices.
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The increase in
costs and operating expenses
is primarily
due to increased marketing purchases and NGL production
costs at Williams Partners, reflecting higher average energy
commodity prices. Exploration & Production costs
increased primarily due to increased average natural gas prices
associated with gas management activities. Additionally, NGL and
olefin production costs at Other increased due to higher average
per-unit
feedstock costs.
Impairments of goodwill and long-lived assets
in 2010
primarily includes a $1 billion impairment of goodwill and
$678 million of impairments of certain producing properties
and acquired unproved reserves at Exploration &
Production.
Impairments of goodwill and long-lived assets
in 2009
includes $20 million impairment of certain producing
properties and acquired unproved reserves at
Exploration & Production.
Other (income) expense — net
within
operating income (loss)
in 2010 includes:
| • | $18 million of involuntary conversion gains at Williams Partners due to insurance recoveries that are in excess of the carrying value of assets; | |
| • | A $12 million gain on the sale of certain assets at Williams Partners; | |
| • | A $10 million accrual of a regulatory liability related to overcollection of certain employee expenses at Williams Partners. |
Other (income) expense — net
within
operating income (loss)
in 2009 includes:
| • | A $40 million gain on the sale of our Cameron Meadows NGL processing plant at Williams Partners; | |
| • | $32 million of penalties from the early termination of certain drilling rig contracts at Exploration & Production. |
General corporate expenses
in 2010 includes
$45 million of transaction costs associated with our
strategic restructuring transaction.
The unfavorable change in
operating income (loss)
is
primarily due to $1.7 billion of impairment charges in 2010
at Exploration & Production and $45 million of
transaction costs in 2010 associated with our strategic
restructuring transaction. The unfavorable change is partially
offset by an improved energy commodity price environment in 2010
compared to 2009 and the favorable change in
other (income)
expense — net
.
The increase in
investing income — net
is
primarily due to the absence of a $75 million impairment
charge in 2009 and a $43 million gain in 2010 on the sale
of our 50 percent interest in Accroven at Other, a
$27 million increase in equity earnings, primarily at
Williams Partners, and the absence of an $11 million
impairment charge in 2009 of a cost-based investment at
Exploration & Production.
Early debt retirement costs
in 2010 reflect costs related
to corporate debt retirements associated with our first quarter
strategic restructuring transaction, including premiums of
$574 million.
Provision (benefit) for income taxes
changed favorably
primarily due to the pre-tax loss in 2010 compared to pre-tax
income in 2009. See Note 5 of Notes to Consolidated
Financial Statements for a reconciliation of the effective tax
rates compared to the federal statutory rate for both years.
See Note 2 of Notes to Consolidated Financial Statements
for a discussion of the items in
income (loss) from
discontinued operations
.
Net income attributable to noncontrolling interests
increased reflecting higher results, primarily at WPZ, due
to an improved energy commodity price environment in 2010
compared to 2009 as well as the impact of the first-quarter 2009
impairments and related charges associated with our discontinued
Venezuela operations.
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Table of Contents
2009 vs.
2008
Our consolidated results in 2009 declined significantly compared
to 2008. These results reflect a rapid decline in energy
commodity prices that began in the fourth quarter of 2008 as a
result of the weakened economy. Energy commodity prices
generally improved during 2009, but not to levels experienced
early in 2008.
The decrease in
revenues
is primarily due to decreased
gas management and production revenues at
Exploration & Production, reflecting a decrease in
average natural gas prices, partially offset by an increase in
production volumes sold. NGL production and marketing revenues
at Williams Partners, as well as NGL and olefin production
revenues at Other, also decreased reflecting lower average
prices.
The decrease in
costs and operating expenses
is primarily
due to decreased costs at Exploration & Production
reflecting a decrease in average natural gas prices associated
with gas management activities, as well as decreased marketing
purchases and decreased costs associated with our NGL production
businesses at Williams Partners. In addition, NGL and olefin
production costs at Other decreased primarily due to lower
average
per-unit
feedstock costs.
Impairments of goodwill and long-lived assets
in 2008
includes $143 million of impairments of certain producing
properties at Exploration & Production and
$10 million of impairments of certain gathering and
transportation assets at Williams Partners.
Other (income) expense — net
within
operating income (loss)
in 2008 includes:
| • | Gain of $148 million on the sale of our Peru interests at Exploration & Production; | |
| • | Net gains of $39 million on foreign currency exchanges at Other; | |
| • | Income of $32 million related to the partial settlement of our Gulf Liquids litigation at Other; | |
| • | Gain of $10 million on the sale of certain south Texas assets at Williams Partners; | |
| • | Income of $17 million resulting from involuntary conversion gains at Williams Partners; | |
| • | Expense of $23 million related to project development costs at Williams Partners. |
General corporate expenses
increased primarily due to an
increase in employee-related expenses, partially offset by a
decrease in outside services.
The decrease in
operating income (loss)
generally
reflects an overall unfavorable energy commodity price
environment in 2009 compared to 2008 and other changes as
previously discussed.
The decrease in
investing income — net
is
primarily due to a $75 million impairment charge in 2009 of
our 50 percent interest in Accroven at Other and an
$11 million impairment charge in 2009 of a cost-based
investment at Exploration & Production. (See
Note 3 of Notes to Consolidated Financial Statements.) A
decrease in interest income, primarily due to lower average
interest rates in 2009 compared to 2008, also contributed to the
decrease in
investing income — net.
Provision (benefit) for income taxes
changed favorably
primarily due to lower pre-tax income. See Note 5 of Notes
to Consolidated Financial Statements for a reconciliation of the
effective tax rates compared to the federal statutory rate for
both years.
See Note 2 of Notes to Consolidated Financial Statements
for a discussion of the items in
income (loss) from
discontinued operations
.
Net income attributable to noncontrolling interests
decreased reflecting the first-quarter 2009 impairments and
related charges associated with our discontinued Venezuela
operations (see Note 2 of Notes to Consolidated Financial
Statements) and the decline in WPZ’s operating results
primarily driven by lower NGL margins.
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Table of Contents
Results
of Operations — Segments
Williams
Partners
Our Williams Partners segment includes WPZ, our consolidated
master limited partnership, which includes two interstate
natural gas pipelines, as well as investments in natural gas
pipeline-related companies, which serve regions from the
San Juan basin in northwestern New Mexico and southwestern
Colorado to Oregon and Washington and from the Gulf of Mexico to
the northeastern United States. WPZ also includes natural gas
gathering and processing and treating facilities and oil
gathering and transportation facilities located primarily in the
Rocky Mountain and Gulf Coast regions of the United States. As
of December 31, 2010, we currently own approximately
75 percent of the interests in WPZ, including the interests
of the general partner, which is wholly owned by us, and
incentive distribution rights.
Williams Partners’ ongoing strategy is to safely and
reliably operate large-scale, interstate natural gas
transmission and midstream infrastructures 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 and utilizing
our low
cost-of-capital
to invest in growing markets, including the deepwater Gulf of
Mexico, the Marcellus Shale, the western United States, and
areas of increasing natural gas demand.
Williams Partners’ interstate transmission and related
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 FERC’s 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.
Overview
of 2010
Significant events during 2010 include the following:
Echo
Springs Plant Expansion
New capacity from our expansion of the Echo Springs facility
began service in the fourth quarter of 2010. The addition of the
fourth cryogenic processing train added approximately
350 MMcf/d
of processing capacity and 30 Mbbls/d of NGL production
capacity, nearly doubling Echo Spring’s capacities in both
cases. Approximately
70 MMcf/d
of production from Exploration & Production in the
Piceance basin is currently being processed at the Echo Springs
facility for a volumetric-based fee. While a slow-down in
Wamsutter area drilling has resulted in some unused capacity, we
are exploring ways to bring more natural gas to this facility in
the coming year.
Marcellus
Shale Gathering Asset Acquisition
In the fourth quarter of 2010 we acquired a gathering business
in Pennsylvania’s Marcellus Shale in the Appalachian basin
for $150 million. The business includes 75 miles of
gathering pipelines and two compressor stations which currently
gathers approximately
235 MMcf/d.
We have agreed to a new long-term dedicated gathering agreement
with the seller for its production in the northeast Pennsylvania
area of the Marcellus Shale. The acquired system will connect
into the Transco pipeline through our Springville gathering
pipeline, currently under construction in the Appalachian basin.
Piceance
Acquisition
During the fourth quarter of 2010, we completed the purchase of
certain gathering and processing assets in the Piceance basin
from Exploration & Production as discussed in
Note 1 of Notes to Consolidated Financial Statements. In
conjunction with this purchase, we entered into a gathering and
processing agreement with Exploration & Production,
such that future gathering and processing revenues will be at a
higher, market-based rate. Prior periods reflect gathering and
processing revenues at an internal cost of service rate.
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Table of Contents
Perdido
Norte
Our Perdido Norte project, in the western deepwater of the Gulf
of Mexico, began
start-up
of
operations late in the first quarter of 2010. The project
includes a
200 MMcf/d
expansion of our onshore Markham gas processing facility and a
total of 179 miles of deepwater oil and gas lines that
expand the scale of our existing infrastructure. Shortly after
an initial startup, during the second quarter, production was
suspended by the operator of the deepwater producing platforms
to address facility issues and the third quarter was impacted by
further delays. While these issues have been resolved and both
oil and gas production is currently flowing, production has been
impacted in part by the drilling moratorium and the
producer’s technical issues, and has not increased as
quickly as expected. We anticipate volumes to increase
significantly, however, during 2011.
Impact of
Gulf Oil Spill
Our transportation and processing assets in the Gulf of Mexico
were not physically impacted by the Deepwater Horizon oil spill.
Operations are normal at all facilities, and we did not
experience any operational or logistical issues that hindered
the safety of our employees or facilities. The drilling
moratorium, in force from May to October, in the Gulf of Mexico
impacted the financial performance of our operations through
production delays which reduced natural gas and oil growth
volumes in 2010. Protracted delays in permitting and drilling
could continue to impact our future growth volumes. While we
continue to carefully monitor the events and business
environment in the Gulf of Mexico for potential negative
impacts, we also continue to pursue major expansion and growth
opportunities in that region.
Overland
Pass Pipeline
In September 2010, we completed the $424 million
acquisition of an additional 49 percent ownership interest
in OPPL, which increased our ownership interest to
50 percent. In 2006, we entered into an agreement to
develop new pipeline capacity for transporting NGLs from
production areas in the Rocky Mountain area to central Kansas.
Our partner reimbursed us for the development costs we had
incurred for the proposed pipeline and acquired 99 percent
of the pipeline. We retained a 1 percent interest and the
option to increase our ownership to 50 percent within two
years of the pipeline becoming operational in November of 2008.
As long as we retain a 50 percent ownership interest in
OPPL, we have the right to become operator. We have notified our
partner of our intent to operate and are currently working on an
early 2011 transition. Work is also under way to determine
optimal expansions to serve producers in the OPPL corridor. OPPL
includes a
760-mile
NGL
pipeline from Opal, Wyoming, to the Mid-Continent NGL market
center in Conway, Kansas, along with 150- and
125-mile
extensions into the Piceance and Denver-Joules basins in
Colorado, respectively. Our equity NGL volumes from our two
Wyoming plants and our Willow Creek facility in Colorado are
dedicated for transport on OPPL under a long-term shipping
agreement.
Volatile
commodity prices
Average
per-unit
NGL
margins in 2010 are significantly higher than in 2009,
benefiting from a period of increasing average NGL prices while
abundant natural gas supplies limited the increase in natural
gas prices. Benefits from favorable natural gas price
differentials in the Rocky Mountain area have narrowed since the
second quarter of 2009 such that our realized
per-unit
margins are only slightly greater than that of the industry
benchmarks for natural gas processed in the Henry Hub area and
for liquids fractionated and sold at Mont Belvieu, Texas.
NGL margins are defined as NGL revenues less any applicable BTU
replacement cost, plant fuel, and third-party transportation and
fractionation.
Per-unit
NGL
margins are calculated based on sales of our own equity volumes
at the processing plants.
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Table of Contents
Gathering
and Processing Per Unit NGL Margin
with Production and Sales Volumes by Quarter
(excludes partially owned plants)
with Production and Sales Volumes by Quarter
(excludes partially owned plants)
Williams
Pipeline Partners L.P.
During the third quarter, WPZ consummated its merger with WMZ.
As a result, WMZ is wholly owned by WPZ and is no longer
publicly traded.
Mobile
Bay South project
In May 2010, a compression facility in Alabama allowing natural
gas pipeline transportation service to various southbound
delivery points was placed into service. The cost of the project
was $32 million and increased capacity by 254 thousand
dekatherms per day (Mdt/d).
Sundance
Trail project
In November 2009, approval was received from the FERC to
construct approximately 16 miles of
30-inch
pipeline between existing compressor stations in Wyoming. The
project also includes an upgrade to the existing compressor
station. The total estimated cost of the project is
approximately $50 million. The project was placed in
service in November 2010 with an increase in capacity of 150
Mdt/d.
Outlook
for 2011
The following factors could impact our business in 2011.
Commodity
price changes
| • | We expect our average per-unit NGL margins in 2011 to be higher than our rolling five-year average per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil, although NGL, crude and natural gas prices are highly volatile and difficult to predict. NGL margins are highly dependent upon continued demand within the global economy. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets. |
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Table of Contents
Gathering,
processing, and NGL sales volumes
| • | The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities. | |
| • | We anticipate growth in our onshore businesses’ gas gathering and processing volumes as our infrastructure grows to support drilling activities in the Piceance and Appalachian basins. However, we anticipate no change or slight declines in basins in the Rocky Mountain and Four Corners areas due to reduced drilling activity. Due to the high proportion of fee-based processing agreements in the Piceance basin, we anticipate only a slight increase in NGL equity sales volumes. | |
| • | In our Gulf Coast businesses, we expect higher gas gathering, processing and crude transportation volumes as our Perdido Norte pipelines move into a full year of operation and other in-process drilling is completed. However, permitting and production delays related to the drilling moratorium which was in force from May to October, 2010 continue to hamper growth. While we expect an overall increase in processed gas volumes in 2011, NGL equity volumes are expected to be lower as we anticipate a major contract to change from keep-whole to fee-based processing. |
Expansion
projects
We have planned capital and investment expenditures of
$1,090 million to $1,370 million in 2011 including
expenditures related to our newly acquired gathering system in
the Marcellus Shale as well as our Laurel Mountain Midstream,
LLC (Laurel Mountain) equity investment. We also plan to pursue
major expansion and growth opportunities in the Gulf of Mexico,
as well as in the Piceance basin in conjunction with both
Exploration & Production’s and third-party
drilling programs. The ongoing major expansion projects include:
85
North
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
approximately $236 million. Phase I service was placed into
service in July 2010 and increased capacity by 90 Mdt/d.
Phase II service is anticipated to begin in May 2011 and
will increase capacity by 219 Mdt/d.
Mobile
Bay South II
Additional compression facilities and modifications to existing
facilities in Alabama allowing natural gas transportation
service to various southbound delivery points. In July 2010, we
received approval from the U.S. Federal Energy Regulatory
Commission. Construction began in October 2010 and is estimated
to cost $35 million. The estimated project in-service date
is May 2011 and will increase capacity by 380 Mdt/d.
Mid-South
In October 2010, we filed an application with the FERC to
upgrade compressor facilities and expand our existing natural
gas transmission system from Alabama to markets as far north as
North Carolina. The cost of the project is estimated to be
$219 million. The project is expected to be phased into
service in September 2012 and June 2013, with an increase in
capacity of 225 Mdt/d.
Mid-Atlantic
Connector
In November 2010, we filed an application with the FERC to
expand our existing natural gas transmission system from North
Carolina to markets as far downstream as Maryland. The cost of
the project is estimated to be $55 million and will
increase capacity by 142 Mdt/d. We plan to place the project
into service in November 2012.
Marcellus
Shale
In the Appalachian basin, $150 million was added to our
planned expansion capital to fund the 2011 construction phase of
additional gathering assets, including compression and
dehydration. In conjunction with a
59
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long-term agreement with a significant producer, we will
construct and operate a
33-mile
natural gas gathering pipeline in the Marcellus Shale region
which will connect our recently acquired gathering assets in
Pennsylvania’s Marcellus Shale into the Transco pipeline.
In order to pursue future opportunities, the project has been
increased from a
20-inch
diameter to a
24-inch
diameter pipeline. Construction on the pipeline is expected to
begin in the first quarter of 2011 and be completed during 2011.
Laurel
Mountain
Capital to be invested within our Laurel Mountain Midstream, LLC
(Laurel Mountain) equity investment to enable the rapid
expansion of our gathering system including the initial stages
of projects that are planned to provide approximately
1.5 Bcf/d of gathering capacity and 1,400 miles of
gathering lines, including 400 new miles of
6-inch
to
24-inch
diameter pipeline. Construction has begun on our Shamrock
compressor station with an initial capacity of
60 MMcf/d,
expandable to
350 MMcf/d,
which will likely be the largest central delivery point out of
the Laurel Mountain system.
We have several other proposed projects to meet customer demands
in addition to the various in-progress expansion projects
previously discussed. Subject to regulatory approvals,
construction of some of these projects could begin in 2011.
Year-Over-Year
Operating Results
| Year Ended December 31, | ||||||||||||
| 2010 | 2009* | 2008* | ||||||||||
| (Millions) | ||||||||||||
|
Segment revenues
|
$ | 5,715 | $ | 4,602 | $ | 5,847 | ||||||
|
Segment profit
|
$ | 1,574 | $ | 1,317 | $ | 1,425 | ||||||
| * | Recast as discussed in Note 1 of Notes to Consolidated Financial Statements |
2010 vs.
2009
The increase in
segment revenues
includes:
| • | A $699 million increase in marketing revenues primarily due to higher average NGL and crude prices. These changes are more than offset by similar changes in marketing purchases. | |
| • | A $330 million increase in revenues associated with the production of NGLs reflecting an increase of $335 million associated with a 41 percent increase in average NGL per-unit sales prices. | |
| • | A $56 million increase in fee revenues primarily due to higher gathering revenue in the Piceance basin as a result of permitted increases in the cost-of-service gathering rate in 2010. |
The increase in s
egment costs and expenses
of
$884 million includes:
| • | A $721 million increase in marketing purchases primarily due to higher average NGL and crude prices. These changes are substantially offset by similar changes in marketing revenues. | |
| • | A $107 million increase in costs associated with the production of NGLs reflecting an increase of $101 million associated with a 30 percent increase in average natural gas prices. | |
| • | A $19 million increase in operating costs including $12 million higher depreciation primarily due to the new Perdido Norte pipelines and a full year of depreciation on our Willow Creek facility which was placed into service in the latter part of 2009. | |
| • | A $14 million unfavorable change related to the disposal of assets reflecting the absence of a $40 million gain on the sale of our Cameron Meadows processing plant in 2009, partially offset by smaller gains in 2010. Gains recognized in 2010 include involuntary conversion gains due to insurance recoveries in excess of the carrying value of our Gulf assets which were damaged by Hurricane Ike in 2008 and our |
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| Ignacio plant, which was damaged by a fire in 2007, as well as gains associated with sales of certain assets in Colorado’s Piceance basin. |
The increase in William Partners’
segment profit
includes:
| • | $223 million of higher NGL production margins reflecting higher NGL prices, partially offset by increased production costs associated with higher natural gas prices. NGL equity volumes were slightly higher due primarily to new production at Willow Creek, partially offset by the absence of favorable customer contractual changes and decreasing inventory levels in 2009. | |
| • | $28 million increase in equity earnings, including a $10 million increase from Discovery primarily due to higher processing margins and new volumes from the Tahiti pipeline lateral expansion completed in 2009. In addition, equity earnings from Aux Sable Liquid Products LP (Aux Sable) are $10 million higher primarily due to higher processing margins, and equity earnings from our increased investment in OPPL were $5 million. | |
| • | A $56 million increase in fee revenues as previously discussed. | |
| • | A $22 million decrease in margins related to the marketing of NGLs and crude primarily due to lower favorable changes in pricing while product was in transit in 2010 as compared to 2009. | |
| • | A $19 million increase in operating costs as previously discussed. | |
| • | A $14 million unfavorable change related to the disposal of assets as previously discussed. |
2009 vs.
2008
The decrease in segment revenues includes:
| • | A $716 million decrease in revenues associated with the production of NGLs primarily due to lower average NGL prices. | |
| • | A $513 million decrease in marketing revenues primarily due to lower average NGL and crude prices, partially offset by higher NGL volumes. | |
| • | A $53 million decrease in revenues from lower transportation imbalance settlements in 2009 compared to 2008 ( offset in costs and operating expenses ). | |
| • | A $65 million increase in fee revenues primarily due to higher volumes resulting from connecting new supplies in the deepwater Gulf of Mexico in the latter part of 2008 and new fees for processing the Exploration & Production segment’s natural gas production at Willow Creek. | |
| • | A $17 million increase in transportation revenues associated with expansion projects placed into service in 2009. |
The decrease in s
egment costs and expenses
of
$1,132 million includes:
| • | A $643 million decrease in marketing purchases primarily due to lower average NGL and crude prices, including the absence of a $9 million charge in 2008 to write down the value of NGL inventories, partially offset by higher NGL volumes. | |
| • | A $435 million decrease in costs associated with the production of NGLs primarily due to lower average natural gas prices. | |
| • | A $53 million decrease in costs associated with lower transportation imbalance settlements in 2009 compared to 2008 ( offset in segment revenues ). | |
| • | A $40 million gain on the 2009 sale of our Cameron Meadows processing plant. | |
| • | The absence of $17 million of charges in 2008 related to an impairment, asset abandonments, and asset retirement obligations. |
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The decrease in William Partners’ segment profit includes:
| • | $281 million of lower NGL production margins reflecting a decrease in energy commodity prices in 2009 compared to 2008. | |
| • | $124 million in higher margins related to the marketing of NGLs primarily due to favorable changes in pricing while product was in transit during 2009 as compared to significant unfavorable changes in pricing while product was in transit in 2008 and the absence of a $9 million charge in 2008 to write down the value of NGL inventories. | |
| • | A $40 million gain in 2009 on the sale of our Cameron Meadows processing plant, partially offset by the absence of a $5 million involuntary conversion gain in 2008 related to our Cameron Meadows plant. |
Exploration &
Production
Exploration & Production includes the natural gas
development, production and gas management activities primarily
in the Rocky Mountain and Mid-Continent regions of the United
States, natural gas development activities in the northeastern
portion of the United States, oil and natural gas interests in
South America, and more recently, oil development activities in
the northern United States. The gas management activities
include procuring fuel and shrink gas for our midstream
businesses and providing marketing services to third parties,
such as producers. Additionally, gas management activities
include the managing of various natural gas related contracts
such as transportation, storage and related hedges.
Overview
of 2010
Domestic production revenues for 2010 were higher than 2009
primarily due to higher realized average prices on our natural
gas production, partially offset by lower production volumes.
Segment profit (loss)
for 2010 includes approximately
$1.7 billion in impairments of natural gas properties and
goodwill (see further discussion below), while 2009 included
expense of $32 million associated with contractual
penalties from the early termination of drilling rig contracts.
Highlights of the comparative periods, primarily related to our
production activities, include:
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | % Change | ||||||||||
|
Average daily domestic production (MMcfe)
|
1,132 | 1,182 | −4 | % | ||||||||
|
Average daily total production (MMcfe)
|
1,185 | 1,236 | −4 | % | ||||||||
|
Domestic production realized average price ($/Mcfe)(1)
|
$ | 5.23 | $ | 4.85 | +8 | % | ||||||
|
Capital expenditures and acquisitions($ millions)
|
$ | 2,823 | $ | 1,291 | +119 | % | ||||||
|
Domestic production revenues ($ millions)
|
$ | 2,160 | $ | 2,093 | +3 | % | ||||||
|
Segment revenues ($ millions)
|
$ | 4,042 | $ | 3,684 | +10 | % | ||||||
|
Segment profit (loss) ($ millions)
|
$ | (1,343 | ) | $ | 391 | NM | ||||||
| (1) | Realized average prices include market prices, net of fuel and shrink and hedge gains and losses. The realized hedge gain per Mcfe was $0.81 and $1.43 for 2010 and 2009, respectively. |
During the second quarter of 2010, we entered into an agreement
to acquire additional leasehold acreage positions and a
5 percent overriding royalty interest associated with these
acreage positions. These acquisitions nearly double our acreage
holdings in the Marcellus Shale and closed in July for
$599 million, including closing adjustments. During 2010,
we also spent a total of $164 million to acquire additional
unproved leasehold acreage in the Marcellus Shale.
During the fourth quarter of 2010, we acquired a company that
holds a major acreage position (approximately 85,800 net
acres, most of which is undeveloped) in North Dakota’s
Bakken Shale oil play (Williston basin) that will diversify our
interests into light, sweet crude oil production. The purchase
price was approximately $949 million, including closing
adjustments.
During the fourth quarter of 2010, we completed the sale of
certain gathering and processing assets in the Piceance basin to
WPZ for consideration of $702 million in cash and
approximately 1.8 million common units. See
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Note 1 in Notes to Consolidated Financial Statements. In
conjunction with this sale, we entered into a gathering and
processing agreement with WPZ. Gathering and processing costs
prior to the sale reflect an internal
cost-of-service
rate. Subsequent to the closing date of the sale, gathering and
processing costs will be at a higher, market-based rate.
As a result of significant declines in forward natural gas
prices during third quarter 2010, we performed an interim
assessment of our capitalized costs related to property and
goodwill. As a result of these assessments, we recorded a
$503 million impairment charge related to the capitalized
costs of our Barnett Shale properties and a $175 million
impairment charge related to capitalized costs of acquired
unproved reserves in the Piceance Highlands, which were acquired
in 2008. Additionally, we fully impaired our goodwill in the
amount of $1 billion. These impairments were based on our
assessment of estimated future discounted cash flows and other
information. See Notes 4 and 14 of Notes to Consolidated
Financial Statements for a further discussion of the impairments.
Outlook
for 2011
We have the following expectations for 2011:
| • | Natural gas prices to remain at levels similar to 2010. | |
| • | Increase capital expenditures in 2011 over levels (before acquisitions) in 2010 to develop positions that were acquired in the Appalachian and Williston basins in 2010. | |
| • | Continuation of our development drilling program in the Appalachian, Piceance, Fort Worth, Powder River, and San Juan basins. Our total capital expenditures for 2011 are projected to be between $1.15 billion and $1.75 billion. We expect to maintain three to five drilling rigs in our newly acquired Williston basin properties with related capital expenditures expected to be between $200 million and $300 million. | |
| • | Annual average daily domestic production expected to increase approximately 9 percent over 2010. |
Risks to achieving our expectations include unfavorable energy
commodity price movements which are impacted by numerous
factors, including weather conditions, domestic natural gas, oil
and NGL production levels and demand. A significant decline in
natural gas, oil and NGL prices would impact these expectations
for 2011, although the impact would be somewhat mitigated by our
hedging program, which hedges a significant portion of our
expected production. In addition, changes in laws and
regulations may impact our development drilling program.
Purchase
Commitments
In connection with a gathering agreement entered into by
Williams Partners with a third party in December 2010, we
concurrently agreed to buy up to 200,000 MMBtu/d of natural
gas priced at market prices from the same third party. Purchases
under the
12-year
contract are expected to begin in the third quarter of 2011. We
expect to sell this natural gas in the open market and may
utilize available transportation capacity to facilitate the
sales.
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Commodity
Price Risk Strategy
To manage the commodity price risk and volatility of owning
producing gas and oil properties, we enter into derivative
contracts for a portion of our future production. For 2011, we
have the following contracts for our daily domestic production,
shown at weighted average volumes and basin-level weighted
average prices:
| 2011 Natural Gas | ||||||||
|
Price ($/Mcf)
|
||||||||
|
Volume
|
Floor-Ceiling for
|
|||||||
| (MMcf/d) | Collars | |||||||
|
Collar agreements — Rockies
|
45 | $5.30 - $7.10 | ||||||
|
Collar agreements — San Juan
|
90 | $5.27 - $7.06 | ||||||
|
Collar agreements — Mid-Continent
|
80 | $5.10 - $7.00 | ||||||
|
Collar agreements — Southern California
|
30 | $5.83 - $7.56 | ||||||
|
Collar agreements — Appalachia
|
30 | $6.50 - $8.14 | ||||||
|
Fixed price at basin swaps
|
368 | $5.21 | ||||||
| 2011 Crude Oil | ||||||||
|
Volume
|
||||||||
|
(Bbls/d)
|
||||||||
| (Feb-Dec) | Price ($/Bbl) | |||||||
|
WTI Crude Oil fixed-price (entered into first-quarter 2011)
|
3,073 | 95.13 | ||||||
The following is a summary of our agreements and contracts for
daily domestic production shown at weighted average volumes and
basin-level weighted average prices for the years ended
December 31, 2010, 2009 and 2008:
| 2010 | 2009 | 2008 | ||||||||||||
|
Price ($/Mcf)
|
Price ($/Mcf)
|
Price ($/Mcf)
|
||||||||||||
|
Volume
|
Floor-Ceiling
|
Volume
|
Floor-Ceiling
|
Volume
|
Floor-Ceiling
|
|||||||||
| (MMcf/d) | for Collars | (MMcf/d) | for Collars | (MMcf/d) | for Collars | |||||||||
|
Collars — Rockies
|
100 | $6.53 - $8.94 | 150 | $6.11 -$9.04 | 170 | $6.16 - $9.14 | ||||||||
|
Collars — San Juan
|
233 | $5.75 - $7.82 | 245 | $6.58 - $9.62 | 202 | $6.35 - $8.96 | ||||||||
|
Collars — Mid-Continent
|
105 | $5.37 - $7.41 | 95 | $7.08 -$9.73 | 63 | $7.02 - $9.72 | ||||||||
|
Collars — Southern California
|
45 | $4.80 - $6.43 | — | — | — | — | ||||||||
|
Collars — Other
|
28 | $5.63 - $6.87 | — | — | — | — | ||||||||
|
NYMEX and basis fixed-price
|
120 | $4.40 | 106 | $3.67 | 70 | $3.97 | ||||||||
Additionally, we utilize contracted pipeline capacity to move
our production from the Rockies to other locations when pricing
differentials are favorable to Rockies pricing. We hold a
long-term obligation to deliver on a firm basis
200,000 MMbtu per day of gas to a buyer at the White River
Hub (Greasewood-Meeker, CO), which is the major market hub
exiting the Piceance basin. Our interests in the Piceance basin
hold sufficient reserves to meet this obligation.
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Year-Over-Year
Operating Results
| Years Ended December 31, | ||||||||||||
| 2010 | 2009* | 2008* | ||||||||||
| (Millions) | ||||||||||||
|
Segment revenues:
|
||||||||||||
|
Domestic production revenues
|
$ | 2,160 | $ | 2,093 | $ | 2,819 | ||||||
|
Gas management revenues
|
1,743 | 1,456 | 3,244 | |||||||||
|
Net forward unrealized
mark-to-market
gains and ineffectiveness
|
27 | 18 | 29 | |||||||||
|
Other revenues
|
112 | 117 | 103 | |||||||||
|
Total segment revenues
|
$ | 4,042 | $ | 3,684 | $ | 6,195 | ||||||
|
Segment profit (loss)
|
$ | (1,343 | ) | $ | 391 | $ | 1,253 | |||||
| * | Recast as discussed in Note 1 of Notes to Consolidated Financial Statements. |
2010 vs.
2009
The increase in total
segment revenues
is primarily due
to the following:
| • | The increase in domestic production revenues reflects an increase of $156 million associated with an 8 percent increase in realized average prices including the effect of hedges, partially offset by a decrease of $89 million associated with a 4 percent decrease in production volumes sold. Production revenues in 2010 and 2009 include approximately $202 million and $93 million, respectively, related to NGLs and approximately $57 million and $38 million, respectively, related to condensate. The increase related to NGLs is primarily due to higher volumes in the Piceance basin processed by Williams Partners’ Willow Creek facility, which was placed into service in the latter part of 2009; | |
| • | The increase in gas management revenues is primarily due to an increase in physical natural gas revenue as a result of a 21 percent increase in average prices on physical natural gas sales. This is primarily related to gas sales associated with our transportation and storage contracts and is offset by a similar increase in segment costs and expenses ; |
Total
segment costs and expenses
increased
$2,094 million, primarily due to the following:
| • | $1,684 million due to 2010 impairments of property and goodwill as previously discussed. In 2009, $20 million of impairments were recorded in the Fort Worth and Arkoma basins; | |
| • | $278 million increase in gas management expenses, primarily due to an 19 percent increase in average prices on physical natural gas purchases. This increase is primarily related to the gas purchases associated with our previously discussed transportation and storage contracts and is more than offset by a similar increase in segment revenues . Gas management expenses in 2010 and 2009 include $48 million and $21 million, respectively, related to charges for unutilized pipeline capacity; | |
| • | $76 million higher gathering, processing, and transportation expenses primarily as a result of processing natural gas liquids at Williams Partners’ Willow Creek plant, which began processing in August 2009, and higher rates charged on gathering and processing associated with certain gathering and processing assets in the Piceance basin that were sold to WPZ in the fourth quarter of 2010; | |
| • | $44 million higher severance and ad valorem taxes primarily due to higher average market prices, excluding the impact of hedges; | |
| • | $30 million higher lease and other operating expenses primarily due to increased workover and maintenance activity; | |
| • | $27 million higher depreciation, depletion, and amortization expenses primarily due to a change in prior production volumes and higher depreciable costs used in the calculation of depreciation, depletion, and amortization expenses. |
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Partially offsetting the increased costs is a decrease due to
the absence of $32 million of expenses in 2009 related to
penalties from the early release of drilling rigs as previously
discussed.
The $1,734 million decrease in s
egment profit (loss)
is primarily due to the impairments, partially offset by an
8 percent increase in realized average domestic prices on
production and the other previously discussed changes in
segment revenues
and
segment costs and expenses.
2009 vs.
2008
The decrease in total
segment revenues
is primarily due
to the following:
| • | $726 million, or 26 percent, decrease in domestic production revenues reflecting $946 million associated with a 31 percent decrease in realized average prices, partially offset by an increase of $220 million associated with an 8 percent increase in production volumes sold. Production revenues in 2009 and 2008 include approximately $93 million and $85 million, respectively, related to NGLs and approximately $38 million and $62 million, respectively, related to condensate. While NGL volumes were significantly higher than the prior year, NGL prices were significantly lower; | |
| • | $1,788 million, or 55 percent, decrease in gas management revenues primarily due to a decrease in physical natural gas revenue as a result of a 56 percent decrease in average prices on physical natural gas sales, slightly offset by a 2 percent increase in natural gas sales volumes. This is primarily related to gas sales associated with our transportation and storage contracts and is substantially offset by a similar decrease in segment costs and expenses . |
The decrease in
net forward unrealized
mark-to-market
gains (losses) and ineffectiveness
is primarily related to
the absence of a $10 million favorable impact in 2008 for
the initial consideration of our own nonperformance risk in
estimating the fair value of our derivative liabilities.
Total
segment costs and expenses
decreased
$1,651 million, primarily due to the following:
| • | $1,752 million decrease in gas management expenses, primarily due to a 55 percent decrease in average prices on physical natural gas purchases, slightly offset by a 2 percent increase in natural gas purchase volumes. This decrease is primarily related to the gas purchases associated with our previously discussed transportation and storage contracts and is more than offset by a similar decrease in segment revenues . Gas management expenses in 2009 and 2008 include $21 million and $8 million, respectively, related to charges for unutilized pipeline capacity. Gas management expenses in 2009 and 2008 also include $7 million and $35 million, respectively, related to adjustments to the carrying value of natural gas inventories in storage; | |
| • | $166 million lower operating taxes due primarily to 56 percent lower average market prices (excluding the impact of hedges), partially offset by higher production volumes sold. The lower operating taxes include a net decrease of $39 million reflecting a $34 million charge in 2008 and $5 million of favorable revisions in 2009 relating to Wyoming severance and ad valorem tax issues; | |
| • | $143 million due to the absence of property impairments recorded in 2008 in the Arkoma basin; | |
| • | $6 million lower SG&A expenses, which include lower bad debt expense related to the partial recovery of certain receivables previously reserved for in 2008 resulting from a bankrupt counterparty. |
Partially offsetting the decreased costs are increases due to
the following:
| • | The absence of a $148 million gain recorded in 2008 associated with the sale of our Peru interests; | |
| • | $145 million higher depreciation, depletion, and amortization expense primarily due to the impact of higher capitalized drilling costs from prior years and higher production volumes compared to the prior year. Also, we recorded an additional $17 million of depreciation, depletion, and amortization in the |
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| fourth quarter of 2009 primarily due to new SEC reserves reporting rules. Our proved reserves decreased primarily due to the new SEC reserves reporting rules and the related price impact; |
| • | $57 million higher gathering, processing and transportation expense primarily due to higher production volumes and the processing fees for natural gas liquids at Williams Partners’ Willow Creek plant, which began processing in August 2009; | |
| • | $32 million of expense related to penalties from the early release of drilling rigs as previously discussed; | |
| • | $31 million higher exploratory expense in 2009, primarily related to $20 million of increased seismic costs and $12 million related to higher amortization and the write-off of lease acquisition costs. Dry hole costs for 2009 and 2008 were $11 million and $12 million, respectively. As of December 31, 2009, we have approximately $14 million of capitalized drilling costs and $24 million of undeveloped leasehold costs related to continuing exploratory activities in the Paradox basin; | |
| • | $20 million of impairment costs in the Fort Worth and Arkoma basins. We recorded a $15 million impairment in 2009 related to costs of acquired unproved reserves resulting from a 2008 acquisition in the Fort Worth basin. This impairment was based on our assessment of estimated future discounted cash flows and additional information obtained from drilling and other activities in 2009. We also recorded a $5 million impairment in the Arkoma basin in 2009 related to facilities. |
The $862 million decrease in segment profit is primarily
due to the 31 percent decrease in realized average domestic
prices and the other previously discussed changes in segment
revenues and segment costs and expenses.
Other
Other includes other business activities that are not operating
segments, primarily our Canadian midstream and domestic olefins
operations and a 25.5 percent interest in Gulfstream, as
well as corporate operations.
Segment profit (loss)
for
the year ended December 31, 2010, has improved compared to
the prior year primarily due to $139 million higher NGL and
olefins production margins resulting from significantly higher
average
per-unit
margins on lower volumes and the net impact of recognizing
$43 million in gains on the Accroven investment in 2010
while recording a $75 million impairment charge on that
investment in 2009.
Significant events for 2010 include the following:
Sale of
Accroven
Considering the deteriorating circumstances in Venezuela, in
2009 we fully impaired our $75 million investment in
Accroven SRL, a Venezuelan operation. (See Note 2 of Notes
to Consolidated Financial Statements.) In June of 2010, we sold
our 50 percent interest in Accroven to the state-owned oil
company, Petróleos de Venezuela S.A. (PDVSA) for
$107 million. Of this amount, $13 million was received
in cash at closing and another $30 million was received in
August 2010. The remainder is due in six quarterly payments
beginning October 31, 2010. The first quarterly payment of
$11 million was received in January 2011 and will be
recognized as income in 2011. We will continue to recognize the
resulting gain as cash is received. Accroven was not part of our
operations that were expropriated by the Venezuelan government
in May 2009.
Completion
of the butylene/butane splitter facility in Canada
The new butylene/butane splitter and hydro-treating facility was
placed into service in August 2010. The butylene/butane splitter
further fractionates the butylene/butane mix product produced at
our Redwater fractionators near Edmonton, Alberta, into separate
butylene and butane products, which receive higher values and
are in greater demand. The source of the product fractionated at
Redwater is our oil sands off-gas extraction facility near
Ft. McMurray, Alberta.
Outlook
for 2011
The following factors could impact our business in 2011.
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Commodity
price changes
We anticipate average
per-unit
margins in 2011 will be consistent with the 2010 levels. Margins
in our Canadian midstream and domestic olefins business are
highly dependent upon continued demand within the global
economy. NGL products are currently the preferred feedstock for
ethylene and propylene production which has been shifting away
from the more expensive crude-based feedstocks. Bolstered by
abundant long-term domestic natural gas supplies, we expect to
benefit from these dynamics in the broader global petrochemical
markets because of our NGL-based olefins production.
Allocation
of capital to projects
We expect to spend $380 million to $480 million in
2011 on capital projects. The major expansion projects include a
12-inch
diameter pipeline in Canada, which will transport recovered NGLs
and olefins from our extraction plant in Ft. McMurray to
our Redwater fractionation facility. The pipeline will have
sufficient capacity to transport additional recovered liquids in
excess of those from our current agreements. Construction has
begun and we anticipate an in-service date in 2012.
Year-Over-Year
Operating Results
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
Segment revenues
|
$ | 1,057 | $ | 780 | $ | 1,257 | ||||||
|
Segment profit (loss)
|
$ | 240 | $ | (2 | ) | $ | 142 | |||||
2010 vs.
2009
Segment revenues
increased primarily due to:
| • | $307 million higher NGL and olefins production revenues resulting from higher average per-unit prices. The new butylene/butane splitter began producing and selling both butylene and butane in August 2010 and resulted in $22 million additional sales revenues over the 2009 butylene/butane mix product sold. | |
| • | $27 million higher marketing revenues due to general increases in energy commodity prices on slightly higher volumes. The higher marketing revenues were more than offset by similar changes in marketing purchases described below. |
Partially offsetting the increased revenue was a
$57 million decrease from lower sales volumes primarily due
to:
| • | 11 percent lower Gulf ethylene sales volumes, including the impact of a four-week plant maintenance outage at our Geismar plant during the fourth quarter of 2010. | |
| • | 12 percent lower propylene volumes sold primarily due to the absence of certain large 2009 propylene inventory sales and lower volumes available for processing at our Gulf propylene splitter. |
Segment costs and expenses
increased $150 million
primarily as a result of:
| • | $156 million higher NGL and olefins production product costs resulting from higher average per-unit feedstock costs. | |
| • | $29 million increased marketing purchases due to general increases in energy commodity prices on slightly higher volumes. The increased marketing purchases more than offset similar changes in marketing revenues. | |
| • | $7 million higher operating and general and administrative costs in our Canadian midstream and domestic olefins operations. |
Partially offsetting the increased costs are decreases due to:
| • | $45 million of reduced product costs resulting from the lower sales volumes described above. |
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| • | $6 million favorable customer settlement in 2010. |
The favorable change in
segment profit (loss)
is
primarily due to $139 million higher NGL and olefins
production margins resulting from significantly higher average
per-unit
margins on lower volumes and the net impact of recognizing
$43 million in gains on the Accroven investment in 2010
while recording a $75 million impairment charge on that
investment in 2009.
2009 vs.
2008
Segment revenues
decreased primarily due to:
| • | A $457 million decrease in NGL and olefins production revenues resulting from lower average product prices, partially offset by higher volumes. | |
| • | A $19 million decrease in marketing revenues primarily due to lower average NGL and olefin prices, partially offset by higher NGL and olefin volumes. |
Segment costs and expenses
decreased $413 million
primarily as a result of:
| • | A $445 million decrease in costs in our NGL and olefins production business primarily due to lower per-unit feedstock costs, including the absence of an $11 million charge in 2008 to write-down the value of olefin inventories, partially offset by higher volumes. | |
| • | A $34 million decrease in marketing purchases primarily due to lower average NGL and olefin prices, including the absence of an $11 million charge in 2008 to write-down the value of our NGL inventories, partially offset by higher volumes. |
These decreases were partially offset by:
| • | A $39 million unfavorable change primarily due to foreign currency exchange gains in 2008 related to the revaluation of current assets held in U.S. dollars within our Canadian operations. | |
| • | The absence of $32 million of income in 2008 related to the partial settlement of our Gulf Liquids litigation (see Note 16 of Notes to Consolidated Financial Statements). |
The unfavorable change in segment profit (loss) was primarily
due to:
| • | A $75 million loss from investment related to the 2009 impairment of our investment in Accroven. | |
| • | A $39 million unfavorable change primarily due to foreign currency exchange gains in 2008 related to the revaluation of current assets held in U.S. dollars within our Canadian operations. | |
| • | The absence of $32 million of income in 2008 related to the partial settlement of our Gulf Liquids litigation. | |
| • | A $12 million decrease in NGL and olefins production margins primarily due to lower average prices, partially offset by lower per-unit feedstock costs, including the absence of an $11 million charge in 2008 to write-down the value of olefin production inventories, and higher volumes in 2009 related to the impact of third-party operational issues in 2008 that reduced off-gas supplies to our plant in Canada. | |
| • | The absence of an $8 million gain recognized in 2008 related to a final earn-out payment on a 2005 asset sale. |
These decreases were partially offset by $15 million higher
marketing margins in our NGL and olefins production business
primarily due to the absence of an $11 million charge in
2008 to write-down the value of NGL inventories.
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Table of Contents
Management’s
Discussion and Analysis of Financial Condition and
Liquidity
Overview
In 2010, we continued to focus upon growth through disciplined
investments in our businesses. Examples of this growth included:
| • | Continued investment in Exploration & Production’s development drilling programs, as well as acquisitions that expanded our presence in the Marcellus Shale and provided our initial entry into the Bakken Shale areas. | |
| • | Expansion of Williams Partners’ interstate natural gas pipeline system to meet the demand of growth markets. | |
| • | Continued investment in Williams Partners’ deepwater Gulf expansion projects, gas processing capacity in the western United States, infrastructure in the Marcellus Shale area and increased ownership in OPPL. |
These investments were funded through cash flow from operations,
debt and equity offerings at WPZ and cash on hand.
During 2010, the overall economic recession has impacted us. In
consideration of our liquidity under these conditions, we note
the following:
| • | As of December 31, 2010, we have approximately $800 million of cash and cash equivalents and approximately $2.7 billion of available credit capacity under our credit facilities. Our $900 million credit facility does not expire until May 2012, and WPZ’s $1.75 billion credit facility does not expire until February 2013. Additionally, Exploration & Production has an unsecured credit agreement that serves to reduce our margin requirements related to our hedging activities. (See additional discussion in the following Available Liquidity section.) | |
| • | Our credit exposure to derivative counterparties is partially mitigated by master netting agreements and collateral support. (See Note 15 of Notes to Consolidated Financial Statements.) |
Outlook
For 2011, we expect operating cash flows to be stronger than
2010 levels.
Lower-than-expected
energy commodity prices would be somewhat mitigated by certain
of our cash flow streams that are substantially insulated from
short-term changes in commodity prices as follows:
| • | Firm demand and capacity reservation transportation revenues under long-term contracts from our gas pipelines; | |
| • | Hedged natural gas sales at Exploration & Production related to a significant portion of its production; | |
| • | Fee-based revenues from certain gathering and processing services in our midstream businesses. |
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 tax and debt
payments while maintaining a sufficient level of liquidity. In
particular, we note the following assumptions for the year:
| • | We expect to maintain consolidated liquidity (which includes liquidity at WPZ) of at least $1 billion from cash and cash equivalents and unused revolving credit facilities; | |
| • | We expect to fund capital and investment expenditures, debt payments, dividends, and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, utilization of our revolving credit facilities, and proceeds from debt issuances and sales of equity securities as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $2.5 billion and $3.3 billion in 2011; | |
| • | We expect capital and investment expenditures to total between $3.125 billion and $4.125 billion in 2011. Of this total, a significant portion of Williams Partners’ expected expenditures of $1.58 billion to |
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| $1.905 billion are considered nondiscretionary to meet legal, regulatory, and/or contractual requirements or to fund committed growth projects. Exploration & Production’s expected expenditures of $1.15 billion to $1.75 billion are considered primarily discretionary. See Results of Operations — Segments, Williams Partners and Exploration & Production for discussions describing the general nature of these expenditures. |
Potential risks associated with our planned levels of liquidity
and the planned capital and investment expenditures discussed
above include:
| • | Sustained reductions in energy commodity prices from the range of current expectations; | |
| • | Lower than expected distributions, including incentive distribution rights, from WPZ. WPZ’s liquidity could also be impacted by a lack of adequate access to capital markets to fund its growth; | |
| • | Lower than expected levels of cash flow from operations from Exploration & Production and our other businesses. |
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 2011. Our internal and
external sources of consolidated liquidity include cash
generated from our operations, cash and cash equivalents on
hand, and our credit facilities. Additional sources of
liquidity, if needed, include bank financings, proceeds from the
issuance of long-term debt and equity securities, and proceeds
from asset sales. These sources are available to us at the
parent level and are expected to be available to certain of our
subsidiaries, particularly equity and debt issuances from WPZ.
WPZ is expected to be self-funding through its cash flows from
operations, use of its credit facility, and its access to
capital markets. Cash held by WPZ is available to us through
distributions in accordance with the partnership agreement,
which considers our level of ownership and incentive
distribution rights. Our ability to raise funds in the capital
markets will be impacted by our financial condition, interest
rates, market conditions, and industry conditions.
Available
Liquidity
| December 31, 2010 | ||||||||||||||||
| Expiration | WPZ | WMB | Total | |||||||||||||
| (Millions) | ||||||||||||||||
|
Cash and cash equivalents
|
$ | 187 | $ | 608 | (1) | $ | 795 | |||||||||
|
Available capacity under our $900 million unsecured
revolving and letter of credit facility(2)
|
May 1, 2012 | 900 | 900 | |||||||||||||
|
Capacity available to Williams Partners L.P. under its
$1.75 billion senior unsecured credit facility(2)
|
February 17, 2013 | 1,750 | 1,750 | |||||||||||||
| $ | 1,937 | $ | 1,508 | $ | 3,445 | |||||||||||
| (1) | Cash and cash equivalents includes $25 million of funds received from third parties as collateral. The obligation for these amounts is reported as accrued liabilities on the Consolidated Balance Sheet. Also included is $518 million of cash and cash equivalents that is being utilized by certain subsidiary and international operations. The remainder of our cash and cash equivalents is primarily held in government-backed instruments. | |
| (2) | At December 31, 2010, we are in compliance with the financial covenants associated with these credit facilities. See Note 11 of Notes to Consolidated Financial Statements. |
In addition to the credit facilities listed above, we have
issued letters of credit totaling $90 million as of
December 31, 2010, under certain bilateral bank agreements.
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WPZ filed a shelf registration statement as a well-known,
seasoned issuer in October 2009 that allows it to issue an
unlimited amount of registered debt and limited partnership unit
securities.
At the parent-company level, we filed a shelf registration
statement as a well-known, seasoned issuer in May 2009 that
allows us to issue an unlimited amount of registered debt and
equity securities.
Exploration & Production has an unsecured credit
agreement with certain banks that, so long as certain conditions
are met, serves to reduce our use of cash and other credit
facilities for margin requirements related to our hedging
activities as well as lower transaction fees. In July 2010, the
agreement term was extended from December 2013 to December 2015.
The impairments of goodwill, natural gas producing properties
and acquired unproved reserves recorded by our
Exploration & Production segment in the third quarter
of 2010 (see Notes 4 and 14 of Notes to Consolidated
Financial Statements) did not impact our ability to utilize
Exploration & Production’s credit agreement to
facilitate hedging our future natural gas production.
Credit
Ratings
Our ability to borrow money is impacted by our credit ratings
and the credit ratings of WPZ. The current ratings are as
follows:
| WMB | WPZ | |||
|
Standard and Poor’s(1)
|
||||
|
Corporate Credit Rating
|
BBB− | BBB− | ||
|
Senior Unsecured Debt Rating
|
BB+ | BBB− | ||
|
Outlook
|
Positive | Positive | ||
|
Moody’s Investors Service(2)
|
||||
|
Senior Unsecured Debt Rating
|
Baa3 | Baa3 | ||
|
Outlook
|
Stable | Stable | ||
|
Fitch Ratings(3)
|
||||
|
Senior Unsecured Debt Rating
|
BBB− | BBB− | ||
|
Outlook
|
Stable | Stable |
| (1) | 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 & Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard & Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category. | |
| (2) | A rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. 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 the lower end of the category. | |
| (3) | A rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category. |
Credit rating agencies perform independent analyses when
assigning credit ratings. No assurance can be given that the
credit rating agencies will continue to assign us investment
grade ratings even if we meet or exceed their current criteria
for investment grade ratios. A downgrade of our credit rating
might increase our future cost of borrowing and would require us
to post additional collateral with third parties, negatively
impacting our available liquidity. As of December 31, 2010,
we estimate that a downgrade to a rating below investment grade
for WMB or WPZ would require us to post up to $453 million
or $53 million, respectively, in additional collateral with
third parties.
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Sources
(Uses) of Cash
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
Net cash provided (used) by:
|
||||||||||||
|
Operating activities
|
$ | 2,651 | $ | 2,572 | $ | 3,355 | ||||||
|
Financing activities
|
573 | 166 | (432 | ) | ||||||||
|
Investing activities
|
(4,296 | ) | (2,310 | ) | (3,183 | ) | ||||||
|
Increase (decrease) in cash and cash equivalents
|
$ | (1,072 | ) | $ | 428 | $ | (260 | ) | ||||
Operating
activities
Our
net cash provided by operating activities
in 2010
increased slightly from 2009 primarily due to the improvement in
the energy commodity price environment during the year.
The decrease in
net cash provided by operating activities
from 2009 to 2008 was primarily due to the decrease in our
operating results.
Financing
activities
Significant transactions include:
2010
| • | $369 million received from WPZ’s December 2010 equity offering used primarily to reduce revolver borrowings mentioned below and to fund a portion of WPZ’s acquisition of a midstream business in Pennsylvania’s Marcellus Shale in December 2010; | |
| • | $200 million received in revolver borrowings from WPZ’s $1.75 billion unsecured credit facility primarily used for WPZ’s general partnership purposes and to fund a portion of the cash consideration paid for WPZ’s acquisition of certain gathering and processing assets in Colorado’s Piceance basin in November 2010; | |
| • | $600 million received from WPZ’s public offering of 4.125 percent senior unsecured notes in November 2010 primarily used to fund a portion of the cash consideration paid to Exploration & Production for WPZ’s Piceance acquisition (see Note 1 of Notes to Consolidated Financial Statements); | |
| • | $430 million received in revolver borrowings from WPZ’s $1.75 billion unsecured credit facility primarily used to fund our increased ownership in OPPL, a transaction that closed in September 2010; | |
| • | $437 million received from a WPZ equity offering used to reduce WPZ’s revolver borrowings mentioned above; | |
| • | $3.491 billion received by WPZ in February 2010 from the issuance of $3.5 billion of senior unsecured notes related to our previously discussed restructuring (see Note 11 of Notes to Consolidated Financial Statements); | |
| • | $3 billion of senior unsecured notes retired in February 2010 and $574 million paid in associated premiums utilizing proceeds from the $3.5 billion debt issuance (see Note 11 of Notes to Consolidated Financial Statements); | |
| • | $250 million received from revolver borrowings on WPZ’s $1.75 billion unsecured credit facility in February 2010 to repay a term loan; | |
| • | We paid $284 million of quarterly dividends on common stock for the year ended December 31, 2010. |
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2009
| • | We received $595 million net cash from the issuance of $600 million aggregate principal amount of 8.75 percent senior unsecured notes due 2020 to fund general corporate expenses and capital expenditures. (See Note 11 of Notes to Consolidated Financial Statements.); | |
| • | We paid $256 million of quarterly dividends on common stock for the year ended December 31, 2009. |
2008
| • | We received $362 million from the completion of the WMZ initial public offering; | |
| • | We paid $474 million for the repurchase of our common stock. (See Note 12 of Notes to Consolidated Financial Statements.); | |
| • | WPZ received $75 million net proceeds from debt transactions; | |
| • | We paid $250 million of quarterly dividends on common stock for the year ended December 31, 2008. |
Investing
activities
Significant transactions include:
2010
| • | Capital expenditures totaled $2.8 billion in 2010. Included is approximately $599 million, including closing adjustments, related to Exploration & Production’s acquisition in the Marcellus Shale in July 2010 (see Results of Operations — Segments, Exploration & Production); | |
| • | We paid approximately $949 million, including closing adjustments, for Exploration & Production’s December 2010 business purchase, consisting primarily of oil and gas properties in the Bakken Shale (see Results of Operations — Segments, Exploration & Production); | |
| • | We contributed $488 million to our investments, including a $424 million cash payment for WPZ’s September 2010 acquisition of an increased interest in OPPL (see Results of Operations — Segments, Williams Partners); | |
| • | We paid $150 million for WPZ’s December 2010 business purchase, consisting primarily of certain midstream assets in the Marcellus Shale. |
2009
| • | Capital expenditures totaled $2.4 billion, more than half of which related to Exploration & Production. Included was a $253 million payment by Exploration & Production for the purchase of additional properties in the Piceance basin. (See Results of Operations — Segments, Exploration & Production.); | |
| • | We received $148 million as a distribution from Gulfstream following its debt offering; | |
| • | We contributed $142 million to our investments, including $106 million related to our Laurel Mountain equity investment and $20 million related to our Gulfstream equity investment. |
2008
| • | Capital expenditures totaled $3.4 billion and were primarily related to Exploration & Production’s drilling activity. This total includes Exploration & Production’s acquisitions of certain interests in the Piceance and Fort Worth basins; | |
| • | We received $148 million of cash from Exploration & Production’s sale of a contractual right to a production payment; |
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| • | We contributed $111 million to our investments, including $90 million related to our Gulfstream equity investment. |
Off-Balance
Sheet Financing Arrangements and Guarantees of Debt or Other
Commitments
We have various other guarantees and commitments which are
disclosed in Notes 9, 11, 15 and 16 of Notes to
Consolidated Financial Statements. We do not believe these
guarantees or the possible fulfillment of them will prevent us
from meeting our liquidity needs.
Contractual
Obligations
The table below summarizes the maturity dates of our contractual
obligations at December 31, 2010, including obligations
related to discontinued operations.
|
2012-
|
2014-
|
|||||||||||||||||||
| 2011 | 2013 | 2015 | Thereafter | Total | ||||||||||||||||
| (Millions) | ||||||||||||||||||||
|
Long-term debt, including current portion:
|
||||||||||||||||||||
|
Principal
|
$ | 507 | $ | 352 | $ | 750 | $ | 7,532 | $ | 9,141 | ||||||||||
|
Interest
|
580 | 1,071 | 1,017 | 5,046 | 7,714 | |||||||||||||||
|
Capital leases
|
1 | 3 | — | — | 4 | |||||||||||||||
|
Operating leases
|
89 | 84 | 59 | 182 | 414 | |||||||||||||||
|
Purchase obligations(1)
|
1,068 | 1,446 | 1,233 | 2,674 | 6,421 | |||||||||||||||
|
Other long-term liabilities, including current portion:
|
||||||||||||||||||||
|
Physical and financial derivatives(2)(3)
|
489 | 1,058 | 870 | 3,634 | 6,051 | |||||||||||||||
|
Other(4)(5)
|
165 | — | — | — | 165 | |||||||||||||||
|
Total
|
$ | 2,899 | $ | 4,014 | $ | 3,929 | $ | 19,068 | $ | 29,910 | ||||||||||
| (1) | Includes $2.3 billion of natural gas purchase obligations at market prices at our Exploration & Production segment. The purchased natural gas can be sold at market prices. | |
| (2) | Includes $5.4 billion of physical natural gas derivatives related to purchases at market prices in our Exploration & Production segment. The natural gas expected to be purchased under these contracts can be sold at market prices. The obligations for physical and financial derivatives are based on market information as of December 31, 2010, and assumes contracts remain outstanding for their full contractual duration. Because market information changes daily and has the potential to be volatile, significant changes to the values in this category may occur. | |
| (3) | Expected offsetting cash inflows of $2.1 billion at December 31, 2010, resulting from product sales or net positive settlements, are not reflected in these amounts. In addition, product sales may require additional purchase obligations to fulfill sales obligations that are not reflected in these amounts. | |
| (4) | Does not include estimated contributions to our pension and other postretirement benefit plans. We made contributions to our pension and other postretirement benefit plans of $76 million in 2010 and $77 million in 2009. In 2011, we expect to contribute approximately $83 million to these plans (see Note 7 of Notes to Consolidated Financial Statements). During 2010, we contributed $60 million to our tax-qualified pension plans which was greater than the minimum required contributions. We expect to contribute approximately $60 million to these pension plans again in 2011, which is expected to be greater than the minimum required contributions. In the past, we have contributed amounts in excess of the minimum required contribution. These excess amounts can be used to offset future minimum contribution requirements. In the future, we may elect to use some of these excess amounts to satisfy the minimum contribution requirement in order to maintain cash contributions at the current level. Additionally, estimated future minimum funding requirements may vary significantly from historical requirements if actual results differ significantly from estimated results for |
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| assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant assumptions or by changes to current legislation and regulations. | ||
| (5) | Includes $165 million reflecting our estimate of an income tax settlement to be paid in 2011. We have not included other income tax liabilities in the table above. See Note 5 of Notes to Consolidated Financial Statements for a discussion of income taxes, including our unrecognized tax benefits. |
Effects
of Inflation
Our operations have benefited from relatively low inflation
rates. Approximately 35 percent of our gross property,
plant, and equipment is comprised of our interstate gas
pipelines. These assets are 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 regulation, along with competition
and other market factors, may limit our ability to recover such
increased costs. For the remainder of our business, operating
costs are influenced to a greater extent by both competition for
specialized services and specific price changes in crude oil and
natural gas and related commodities than by changes in general
inflation. Crude oil, natural gas, and NGL 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 certain of 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, some of which we currently
do not own (see Note 16 of Notes to Consolidated Financial
Statements). 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
$49 million, all of which are included in
accrued
liabilities
and
other liabilities and deferred income
on the Consolidated Balance Sheet at December 31, 2010. We
will seek recovery of approximately $12 million of these
accrued costs through future natural gas transmission rates. The
remainder of these costs will be funded from operations. During
2010, we paid approximately $8 million for cleanup
and/or
remediation and monitoring activities. We expect to pay
approximately $11 million in 2011 for these activities.
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, 2010, 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 also subject to the Federal Clean Air Act (Act) and to
the Federal Clean Air Act Amendments of 1990 (1990 Amendments),
which added significantly to the existing requirements
established by the Act. Pursuant to requirements of the 1990
Amendments and EPA rules designed to mitigate the migration of
ground-level ozone (NOx), we are planning installation of air
pollution controls on existing sources at certain facilities in
order to reduce NOx emissions. For many of these facilities, we
are developing more cost effective and innovative compressor
engine control designs.
In March 2008, the EPA promulgated a new, lower National Ambient
Air Quality Standard (NAAQS) for ground-level ozone. Within two
years, the EPA was expected to designate new
eight-hour
ozone non-attainment areas. However, in September 2009, the EPA
announced it would reconsider the 2008 NAAQS for ground level
ozone to ensure that the standards were clearly grounded in
science and were protective of both public health and the
environment. As a result, the EPA delayed designation of new
eight-hour
ozone non-attainment areas under the 2008 standards until the
reconsideration is complete. In January 2010, the EPA proposed
to further reduce the ground-level ozone NAAQS from the March
2008 levels. The EPA currently anticipates finalization of the
new ground-level ozone standard in the third quarter of 2011.
Designation of new
eight-hour
ozone non-attainment areas
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are expected to result in additional federal and state
regulatory actions that will likely impact our operations and
increase the cost of additions to
property, plant and
equipment-net
on the Consolidated Balance Sheet. We are
unable at this time to estimate the cost of additions that may
be required to meet this new regulation.
Additionally, in August 2010, the EPA promulgated National
Emission Standards for Hazardous Air Pollutants (NESHAP)
regulations that will impact our operations. The emission
control additions required to comply with the NESHAP regulations
are estimated to include costs in the range of $31 million
to $39 million through 2013, the compliance date.
Furthermore, the EPA promulgated the Greenhouse Gas (GHG)
Mandatory Reporting Rule on October 30, 2009, which
requires facilities that emit 25,000 metric tons or more carbon
dioxide
(CO
2
)
equivalent per year from stationary fossil fuel combustion
sources to report GHG emissions to the EPA annually beginning
March 31, 2011 for calendar year 2010. On November 30,
2010, the EPA issued additional regulations that expand the
scope of the Mandatory Reporting Rule to include fugitive and
vented greenhouse gas emissions effective January 1, 2011.
Facilities that emit 25,000 metric tons or more
CO
2
equivalent per year from stationary fossil-fuel combustion and
fugitive/vented sources combined will be required to report GHG
combustion and fugitive/vented emissions to the EPA annually
beginning March 31, 2012, for calendar year 2011.
Compliance with this reporting obligation is estimated to cost a
total of $10 million to $14 million over the next four
to five years.
In February 2010, the EPA promulgated a final rule establishing
a new
one-hour
nitrogen dioxide
(NO
2
)
NAAQS. The effective date of the new
NO
2
standard was April 12, 2010. This new standard is subject
to numerous challenges in the federal court. We are unable at
this time to estimate the cost of additions that may be required
to meet this new regulation.
Our interstate natural gas pipelines consider prudently incurred
environmental assessment and remediation costs and the costs
associated with compliance with environmental standards to be
recoverable through rates.
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Table of Contents
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
Interest
Rate Risk
Our current interest rate risk exposure is related primarily to
our debt portfolio. The majority of our debt portfolio is
comprised of fixed rate debt in order to mitigate the impact of
fluctuations in interest rates. Any borrowings under our credit
facilities could be at a variable interest rate and could expose
us to the risk of increasing interest rates. The maturity of our
long-term debt portfolio is partially influenced by the expected
lives of our operating assets.
The tables below provide information by maturity date about our
interest rate risk-sensitive instruments as of December 31,
2010 and 2009. Long-term debt in the tables represents principal
cash flows, net of (discount) premium, and weighted-average
interest rates by expected maturity dates. The fair value of our
publicly traded long-term debt is valued using indicative
year-end traded bond market prices. Private debt is valued based
on market rates and the prices of similar securities with
similar terms and credit ratings.
|
Fair Value
|
||||||||||||||||||||||||||||||||
|
December 31,
|
||||||||||||||||||||||||||||||||
| 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter(1) | Total | 2010 | |||||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||||||
|
Long-term debt, including
|
||||||||||||||||||||||||||||||||
|
current portion(2):
|
||||||||||||||||||||||||||||||||
|
Fixed rate
|
$ | 507 | $ | 352 | $ | — | $ | — | $ | 750 | $ | 7,495 | $ | 9,104 | $ | 9,990 | ||||||||||||||||
|
Interest rate
|
6.4 | % | 6.4 | % | 6.3 | % | 6.3 | % | 6.4 | % | 6.9 | % | ||||||||||||||||||||
|
Fair Value
|
||||||||||||||||||||||||||||||||
|
December 31,
|
||||||||||||||||||||||||||||||||
| 2010 | 2011 | 2012 | 2013 | 2014 | Thereafter(1) | Total | 2009 | |||||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||||||
|
Long-term debt, including
|
||||||||||||||||||||||||||||||||
|
current portion(2):
|
||||||||||||||||||||||||||||||||
|
Fixed rate
|
$ | 15 | $ | 936 | $ | 953 | $ | — | $ | — | $ | 6,119 | $ | 8,023 | $ | 8,905 | ||||||||||||||||
|
Interest rate
|
7.7 | % | 7.7 | % | 7.7 | % | 7.7 | % | 7.7 | % | 8.0 | % | ||||||||||||||||||||
|
Variable rate
|
$ | — | $ | — | $ | 250 | $ | — | $ | — | $ | — | $ | 250 | $ | 237 | ||||||||||||||||
|
Interest rate(3)
|
||||||||||||||||||||||||||||||||
| (1) | Includes unamortized discount and premium. | |
| (2) | Excludes capital leases. | |
| (3) | The interest rate at December 31, 2009 was LIBOR plus 1 percent. |
Commodity
Price Risk
We are exposed to the impact of fluctuations in the market price
of natural gas, NGL and crude, as well as other market factors,
such as market volatility and energy commodity price
correlations. We are exposed to these risks in connection with
our owned energy-related assets, our long-term energy-related
contracts and our proprietary trading activities. We manage the
risks associated with these market fluctuations using various
derivatives and nonderivative energy-related contracts. The fair
value of derivative contracts is subject to many factors,
including changes in energy commodity market prices, the
liquidity and volatility of the markets in which the contracts
are transacted, and changes in interest rates. (See Note 15
of Notes to Consolidated Financial Statements.)
We measure the risk in our portfolios using a
value-at-risk
methodology to estimate the potential
one-day
loss
from adverse changes in the fair value of the portfolios. 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 portfolios. 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 percent
probability that the
one-day
loss
in fair value of the portfolios will not exceed the value at
risk. The simulation method uses historical correlations and
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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
portfolios 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.
We segregate our derivative contracts into trading and
nontrading contracts, as defined in the following paragraphs. We
calculate value at risk separately for these two categories.
Contracts designated as normal purchases or sales and
nonderivative energy contracts have been excluded from our
estimation of value at risk.
Trading
Our trading portfolio consists of derivative contracts entered
into for purposes other than economically hedging our commodity
price-risk exposure. The fair value of our trading derivatives
was a net asset of $2 million at December 31, 2010.
The value at risk for contracts held for trading purposes was
less than $1 million at December 31, 2010 and
December 31, 2009.
Nontrading
Our nontrading portfolio consists of derivative contracts that
hedge or could potentially hedge the price risk exposure from
the following activities:
| Segment | Commodity Price Risk Exposure | |
|
Williams Partners
|
• Natural gas purchases
|
|
|
• NGL sales
|
||
|
Exploration & Production
|
• Natural gas purchases and sales
|
|
|
Other
|
• NGL purchases
|
The fair value of our nontrading derivatives was a net asset of
$282 million at December 31, 2010.
The value at risk for derivative contracts held for nontrading
purposes was $24 million at December 31, 2010, and
$34 million at December 31, 2009. During the year
ended December 31, 2010, our value at risk for these
contracts ranged from a high of $33 million to a low of
$21 million. The decrease in value at risk primarily
reflects the realization of certain derivative positions and the
market price impact, partially offset by new derivative
contracts.
Certain of the derivative contracts held for nontrading purposes
are accounted for as cash flow hedges. Of the total fair value
of nontrading derivatives, cash flow hedges had a net asset
value of $266 million as of December 31, 2010. Though
these contracts are included in our
value-at-risk
calculation, any changes in the fair value of the effective
portion of these hedge contracts would generally not be
reflected in earnings until the associated hedged item affects
earnings.
Trading
Policy
We have policies and procedures that govern our trading and risk
management activities. These policies cover authority and
delegation thereof in addition to control requirements,
authorized commodities and term and exposure limitations.
Value-at-risk
is limited in aggregate and calculated at a 95 percent
confidence level.
Foreign
Currency Risk
Net assets of our consolidated foreign operations, whose
functional currency is the local currency, are located primarily
in Canada and approximate 8 percent and 6 percent of
our net assets at December 31, 2010 and 2009, respectively.
These foreign operations do not have significant transactions or
financial instruments denominated in currencies other than their
functional currency. However, these investments do have the
potential to impact our financial position, due to fluctuations
in these local currencies arising from the process of
translating the local functional currency into the
U.S. dollar. As an example, a 20 percent change in the
respective functional currencies against the U.S. dollar
would have changed
stockholders’ equity
by
approximately $117 million at December 31, 2010.
79
Table of Contents
| Item 8. | Financial Statements and Supplementary Data |
MANAGEMENT’S
ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
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 Chief Executive Officer and Chief
Financial Officer, we assessed the effectiveness of our internal
control over financial reporting as of December 31, 2010,
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, 2010, 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.
80
Table of Contents
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON INTERNAL CONTROL OVER FINANCIAL REPORTING
ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors and Stockholders of
The Williams Companies, Inc.
We have audited The Williams Companies, Inc.’s internal
control over financial reporting as of December 31, 2010,
based on criteria established in Internal Control —
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria).
The Williams Companies, Inc.’s management is responsible
for maintaining effective internal control over financial
reporting, and for its assessment of the effectiveness of
internal control over financial reporting included in the
accompanying Management’s Annual Report on Internal Control
Over Financial Reporting. Our responsibility is to express an
opinion on the Company’s internal control over financial
reporting based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, The Williams Companies, Inc. maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2010, based on the COSO
criteria.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheet of The Williams Companies, Inc. as of
December 31, 2010 and 2009, and the related consolidated
statements of operations, changes in equity, and cash flows for
each of the three years in the period ended December 31,
2010 of The Williams Companies, Inc. and our report dated
February 24, 2011 expressed an unqualified opinion thereon.
/s/ Ernst &
Young LLP
Tulsa, Oklahoma
February 24, 2011
81
Table of Contents
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of
The Williams Companies, Inc.
We have audited the accompanying consolidated balance sheet of
The Williams Companies, Inc. as of December 31, 2010 and
2009, and the related consolidated statements of operations,
changes in equity, and cash flows for each of the three years in
the period ended December 31, 2010. Our audits also
included the financial statement schedule listed in the index at
Item 15(a). These financial statements and schedule are the
responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial
statements and schedule based on our audits. The 2010 financial
statements of Gulfstream Natural Gas System, L.L.C.
(“Gulfstream”) (a limited liability corporation in
which the Company has a 50% interest), have been audited by
other auditors whose report has been furnished to us, and our
opinion on the 2010 consolidated financial statements, insofar
as it relates to the amounts included for Gulfstream, is based
solely on the report of the other auditors. In the consolidated
financial statements, the Company’s investment in
Gulfstream is stated at $378 million at December 31,
2010 and the Company’s equity earnings in the net income of
Gulfstream is stated at $66 million for the year then ended.
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 and the
report of other auditors provide a reasonable basis for our
opinion.
In our opinion, based on our audits and the report of other
auditors, the financial statements referred to above present
fairly, in all material respects, the consolidated financial
position of The Williams Companies, Inc. at December 31,
2010 and 2009, and the consolidated results of its operations
and its cash flows for each of the three years in the period
ended December 31, 2010, in conformity with
U.S. generally accepted accounting principles. Also, in our
opinion, the related financial statement schedule, when
considered in relation to the basic financial statements taken
as a whole, presents fairly in all material respects the
information set forth therein.
As discussed in Note 9 to the consolidated financial
statements, beginning in the fourth quarter of 2009, the Company
changed its reserve estimates and related disclosures as a
result of adopting new oil and gas reserve estimation and
disclosure requirements.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), The
Williams Companies, Inc.’s internal control over financial
reporting as of December 31, 2010, 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 24, 2011
expressed an unqualified opinion thereon.
/s/ Ernst &
Young LLP
Tulsa, Oklahoma
February 24, 2011
82
Table of Contents
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Members of Gulfstream Natural Gas System, L.L.C.
Houston, Texas
Houston, Texas
We have audited the balance sheet of Gulfstream Natural Gas
System, L.L.C., (the “Company”), as of
December 31, 2010, and the related statements of
operations, cash flows, and members’ equity and
comprehensive income for the period ended December 31,
2010. These financial statements are the responsibility of the
Company’s management. Our responsibility is to express an
opinion on these financial statements based on our audit.
We conducted our audit in accordance with the auditing 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. The Company is not
required to have, nor were we engaged to perform, an audit of
its internal control over financial reporting. Our audit
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 Company’s
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, as well as
evaluating the overall financial statement presentation. We
believe that our audit provides a reasonable basis for our
opinion.
In our opinion, such financial statements present fairly, in all
material respects, the financial position of Gulfstream Natural
Gas System, L.L.C. as of December 31, 2010, and the results
of its operations and its cash flows for the period ended
December 31, 2010 in conformity with accounting principles
generally accepted in the United States of America.
/s/ Deloitte &
Touche LLP
Houston, Texas
February 23, 2011
83
Table of Contents
THE
WILLIAMS COMPANIES, INC.
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions, except per-share amounts) | ||||||||||||
|
Revenues:
|
||||||||||||
|
Williams Partners*
|
$ | 5,715 | $ | 4,602 | $ | 5,847 | ||||||
|
Exploration & Production*
|
4,042 | 3,684 | 6,195 | |||||||||
|
Other
|
1,057 | 780 | 1,257 | |||||||||
|
Intercompany eliminations*
|
(1,198 | ) | (811 | ) | (1,409 | ) | ||||||
|
Total revenues
|
9,616 | 8,255 | 11,890 | |||||||||
|
Segment costs and expenses:
|
||||||||||||
|
Costs and operating expenses
|
7,185 | 6,081 | 8,776 | |||||||||
|
Selling, general, and administrative expenses
|
498 | 512 | 504 | |||||||||
|
Impairments of goodwill and long-lived assets
|
1,692 | 20 | 153 | |||||||||
|
Other (income) expense — net
|
(24 | ) | (3 | ) | (225 | ) | ||||||
|
Total segment costs and expenses
|
9,351 | 6,610 | 9,208 | |||||||||
|
General corporate expenses
|
221 | 164 | 149 | |||||||||
|
Operating income (loss):
|
||||||||||||
|
Williams Partners*
|
1,465 | 1,236 | 1,349 | |||||||||
|
Exploration & Production*
|
(1,363 | ) | 373 | 1,233 | ||||||||
|
Other
|
163 | 36 | 100 | |||||||||
|
General corporate expenses
|
(221 | ) | (164 | ) | (149 | ) | ||||||
|
Total operating income (loss)
|
44 | 1,481 | 2,533 | |||||||||
|
Interest accrued
|
(632 | ) | (661 | ) | (636 | ) | ||||||
|
Interest capitalized
|
51 | 76 | 59 | |||||||||
|
Investing income — net
|
209 | 46 | 189 | |||||||||
|
Early debt retirement costs
|
(606 | ) | (1 | ) | (1 | ) | ||||||
|
Other income (expense) — net
|
(12 | ) | 2 | — | ||||||||
|
Income (loss) from continuing operations before income taxes
|
(946 | ) | 943 | 2,144 | ||||||||
|
Provision (benefit) for income taxes
|
(30 | ) | 359 | 677 | ||||||||
|
Income (loss) from continuing operations
|
(916 | ) | 584 | 1,467 | ||||||||
|
Income (loss) from discontinued operations
|
(6 | ) | (223 | ) | 125 | |||||||
|
Net income (loss)
|
(922 | ) | 361 | 1,592 | ||||||||
|
Less: Net income attributable to noncontrolling interests
|
175 | 76 | 174 | |||||||||
|
Net income (loss) attributable to The Williams Companies,
Inc.
|
$ | (1,097 | ) | $ | 285 | $ | 1,418 | |||||
|
Amounts attributable to The Williams Companies, Inc.:
|
||||||||||||
|
Income (loss) from continuing operations
|
$ | (1,091 | ) | $ | 438 | $ | 1,306 | |||||
|
Income (loss) from discontinued operations
|
(6 | ) | (153 | ) | 112 | |||||||
|
Net income (loss)
|
$ | (1,097 | ) | $ | 285 | $ | 1,418 | |||||
|
Basic earnings (loss) per common share:
|
||||||||||||
|
Income (loss) from continuing operations
|
$ | (1.87 | ) | $ | .75 | $ | 2.25 | |||||
|
Income (loss) from discontinued operations
|
(.01 | ) | (.26 | ) | .19 | |||||||
|
Net income (loss)
|
$ | (1.88 | ) | $ | .49 | $ | 2.44 | |||||
|
Weighted-average shares (thousands)
|
584,552 | 581,674 | 581,342 | |||||||||
|
Diluted earnings (loss) per common share:
|
||||||||||||
|
Income (loss) from continuing operations
|
$ | (1.87 | ) | $ | .75 | $ | 2.21 | |||||
|
Income (loss) from discontinued operations
|
(.01 | ) | (.26 | ) | .19 | |||||||
|
Net income (loss)
|
$ | (1.88 | ) | $ | .49 | $ | 2.40 | |||||
|
Weighted-average shares (thousands)
|
584,552 | 589,385 | 592,719 | |||||||||
| * | 2009 and 2008 recast as discussed in Note 1. |
See accompanying notes.
84
Table of Contents
THE
WILLIAMS COMPANIES, INC.
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions, except per-share amounts) | ||||||||
|
ASSETS
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 795 | $ | 1,867 | ||||
|
Accounts and notes receivable (net of allowance of $15 at
December 31, 2010 and $22 at December 31, 2009)
|
859 | 816 | ||||||
|
Inventories
|
303 | 222 | ||||||
|
Derivative assets
|
400 | 650 | ||||||
|
Other current assets and deferred charges
|
173 | 238 | ||||||
|
Total current assets
|
2,530 | 3,793 | ||||||
|
Investments
|
1,344 | 886 | ||||||
|
Property, plant, and equipment — net
|
20,272 | 18,644 | ||||||
|
Derivative assets
|
173 | 444 | ||||||
|
Goodwill
|
8 | 1,011 | ||||||
|
Other assets and deferred charges
|
645 | 502 | ||||||
|
Total assets
|
$ | 24,972 | $ | 25,280 | ||||
| LIABILITIES AND EQUITY | ||||||||
|
Current liabilities:
|
||||||||
|
Accounts payable
|
$ | 918 | $ | 934 | ||||
|
Accrued liabilities
|
1,002 | 948 | ||||||
|
Derivative liabilities
|
146 | 578 | ||||||
|
Long-term debt due within one year
|
508 | 17 | ||||||
|
Total current liabilities
|
2,574 | 2,477 | ||||||
|
Long-term debt
|
8,600 | 8,259 | ||||||
|
Deferred income taxes
|
3,448 | 3,656 | ||||||
|
Derivative liabilities
|
143 | 428 | ||||||
|
Other liabilities and deferred income
|
1,588 | 1,441 | ||||||
|
Contingent liabilities and commitments (Note 16)
|
||||||||
|
Equity:
|
||||||||
|
Stockholders’ equity:
|
||||||||
|
Common stock (960 million shares authorized at $1 par
value; 620 million shares issued at December 31, 2010
and 618 million shares issued at December 31, 2009)
|
620 | 618 | ||||||
|
Capital in excess of par value
|
8,269 | 8,135 | ||||||
|
Retained earnings (deficit)
|
(478 | ) | 903 | |||||
|
Accumulated other comprehensive income (loss)
|
(82 | ) | (168 | ) | ||||
|
Treasury stock, at cost (35 million shares of common stock)
|
(1,041 | ) | (1,041 | ) | ||||
|
Total stockholders’ equity
|
7,288 | 8,447 | ||||||
|
Noncontrolling interests in consolidated subsidiaries
|
1,331 | 572 | ||||||
|
Total equity
|
8,619 | 9,019 | ||||||
|
Total liabilities and equity
|
$ | 24,972 | $ | 25,280 | ||||
See accompanying notes.
85
Table of Contents
THE
WILLIAMS COMPANIES, INC.
| The Williams Companies, Inc., Stockholders | ||||||||||||||||||||||||||||||||
|
Accumulated
|
||||||||||||||||||||||||||||||||
|
Capital in
|
Retained
|
Other
|
Total
|
|||||||||||||||||||||||||||||
|
Common
|
Excess of
|
Earnings
|
Comprehensive
|
Treasury
|
Stockholders’
|
Noncontrolling
|
||||||||||||||||||||||||||
| Stock | Par Value | (Deficit) | Loss | Stock | Equity | Interest | Total | |||||||||||||||||||||||||
| (Millions, except per-share amounts) | ||||||||||||||||||||||||||||||||
|
Balance, December 31, 2007
|
$ | 608 | $ | 6,748 | $ | (293 | ) | $ | (121 | ) | $ | (567 | ) | $ | 6,375 | $ | 1,430 | $ | 7,805 | |||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||||||||||
|
Net income
|
— | — | 1,418 | — | — | 1,418 | 174 | 1,592 | ||||||||||||||||||||||||
|
Other comprehensive income:
|
||||||||||||||||||||||||||||||||
|
Net change in cash flow hedges (Note 17)
|
— | — | — | 453 | — | 453 | 2 | 455 | ||||||||||||||||||||||||
|
Foreign currency translation adjustments
|
— | — | — | (76 | ) | — | (76 | ) | — | (76 | ) | |||||||||||||||||||||
|
Pension benefits:
|
||||||||||||||||||||||||||||||||
|
Prior service cost
|
— | — | — | 1 | — | 1 | — | 1 | ||||||||||||||||||||||||
|
Net actuarial loss
|
— | — | — | (337 | ) | — | (337 | ) | (7 | ) | (344 | ) | ||||||||||||||||||||
|
Other postretirement benefits:
|
||||||||||||||||||||||||||||||||
|
Prior service cost
|
— | — | — | 9 | — | 9 | — | 9 | ||||||||||||||||||||||||
|
Net actuarial loss
|
— | — | — | (9 | ) | — | (9 | ) | — | (9 | ) | |||||||||||||||||||||
|
Total other comprehensive income
|
41 | (5 | ) | 36 | ||||||||||||||||||||||||||||
|
Total comprehensive income
|
1,459 | 169 | 1,628 | |||||||||||||||||||||||||||||
|
Cash dividends — common stock (Note 12)
|
— | — | (250 | ) | — | — | (250 | ) | — | (250 | ) | |||||||||||||||||||||
|
Sale of limited partner units of consolidated partnership
|
— | — | — | — | — | — | 362 | 362 | ||||||||||||||||||||||||
|
Dividends and distributions to noncontrolling interests
|
— | — | — | — | — | — | (122 | ) | (122 | ) | ||||||||||||||||||||||
|
Issuance of common stock from 5.5% debentures conversion
(Note 12)
|
2 | 25 | — | — | — | 27 | — | 27 | ||||||||||||||||||||||||
|
Conversion of Williams Partners L.P. subordinated units to
common units (Note 12)
|
— | 1,225 | — | — | — | 1,225 | (1,225 | ) | — | |||||||||||||||||||||||
|
Purchase of treasury stock (Note 12)
|
— | — | — | — | (474 | ) | (474 | ) | — | (474 | ) | |||||||||||||||||||||
|
Stock-based compensation, net of tax benefit
|
3 | 67 | — | — | — | 70 | — | 70 | ||||||||||||||||||||||||
|
Other
|
— | 9 | (1 | ) | — | — | 8 | — | 8 | |||||||||||||||||||||||
|
Balance, December 31, 2008
|
613 | 8,074 | 874 | (80 | ) | (1,041 | ) | 8,440 | 614 | 9,054 | ||||||||||||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||||||||||
|
Net income
|
— | — | 285 | — | — | 285 | 76 | 361 | ||||||||||||||||||||||||
|
Other comprehensive loss:
|
||||||||||||||||||||||||||||||||
|
Net change in cash flow hedges (Note 17)
|
— | — | — | (221 | ) | — | (221 | ) | — | (221 | ) | |||||||||||||||||||||
|
Foreign currency translation adjustments
|
— | — | — | 83 | — | 83 | — | 83 | ||||||||||||||||||||||||
|
Pension benefits:
|
||||||||||||||||||||||||||||||||
|
Net actuarial gain
|
— | — | — | 46 | — | 46 | 7 | 53 | ||||||||||||||||||||||||
|
Other postretirement benefits:
|
||||||||||||||||||||||||||||||||
|
Prior service cost
|
— | — | — | 4 | — | 4 | — | 4 | ||||||||||||||||||||||||
|
Total other comprehensive loss
|
(88 | ) | 7 | (81 | ) | |||||||||||||||||||||||||||
|
Total comprehensive income
|
197 | 83 | 280 | |||||||||||||||||||||||||||||
|
Cash dividends — common stock (Note 12)
|
— | — | (256 | ) | — | — | (256 | ) | — | (256 | ) | |||||||||||||||||||||
|
Dividends and distributions to noncontrolling interests
|
— | — | — | — | — | — | (129 | ) | (129 | ) | ||||||||||||||||||||||
|
Issuance of common stock from 5.5% debentures conversion
(Note 12)
|
3 | 25 | — | — | — | 28 | — | 28 | ||||||||||||||||||||||||
|
Stock-based compensation, net of tax benefit
|
2 | 36 | — | — | — | 38 | — | 38 | ||||||||||||||||||||||||
|
Other
|
— | — | — | — | — | — | 4 | 4 | ||||||||||||||||||||||||
|
Balance, December 31, 2009
|
618 | 8,135 | 903 | (168 | ) | (1,041 | ) | 8,447 | 572 | 9,019 | ||||||||||||||||||||||
|
Comprehensive income (loss):
|
||||||||||||||||||||||||||||||||
|
Net income (loss)
|
— | — | (1,097 | ) | — | — | (1,097 | ) | 175 | (922 | ) | |||||||||||||||||||||
|
Other comprehensive income:
|
||||||||||||||||||||||||||||||||
|
Net change in cash flow hedges (Note 17)
|
— | — | — | 92 | — | 92 | — | 92 | ||||||||||||||||||||||||
|
Foreign currency translation adjustments
|
— | — | — | 29 | — | 29 | — | 29 | ||||||||||||||||||||||||
|
Pension benefits:
|
||||||||||||||||||||||||||||||||
|
Prior service cost
|
— | — | — | 1 | — | 1 | — | 1 | ||||||||||||||||||||||||
|
Net actuarial loss
|
— | — | — | (25 | ) | — | (25 | ) | — | (25 | ) | |||||||||||||||||||||
|
Other postretirement benefits:
|
||||||||||||||||||||||||||||||||
|
Prior service cost
|
— | — | — | (3 | ) | — | (3 | ) | — | (3 | ) | |||||||||||||||||||||
|
Net actuarial loss
|
— | — | — | (8 | ) | — | (8 | ) | — | (8 | ) | |||||||||||||||||||||
|
Total other comprehensive income
|
— | — | — | — | — | 86 | — | 86 | ||||||||||||||||||||||||
|
Total comprehensive income (loss)
|
— | — | — | — | — | (1,011 | ) | 175 | (836 | ) | ||||||||||||||||||||||
|
Cash dividends — common stock (Note 12)
|
— | — | (284 | ) | — | — | (284 | ) | — | (284 | ) | |||||||||||||||||||||
|
Dividends and distributions to noncontrolling interests
|
— | — | — | — | — | — | (145 | ) | (145 | ) | ||||||||||||||||||||||
|
Issuance of common stock from 5.5% debentures conversion
(Note 12)
|
— | 2 | — | — | — | 2 | — | 2 | ||||||||||||||||||||||||
|
Sale of limited partner units of consolidated partnership
|
— | — | — | — | — | — | 806 | 806 | ||||||||||||||||||||||||
|
Stock-based compensation, net of tax benefit
|
2 | 55 | — | — | — | 57 | — | 57 | ||||||||||||||||||||||||
|
Changes in Williams Partners L.P. ownership interest, net
|
— | 77 | — | — | — | 77 | (77 | ) | — | |||||||||||||||||||||||
|
Other
|
— | — | — | — | — | — | — | — | ||||||||||||||||||||||||
|
Balance, December 31, 2010
|
$ | 620 | $ | 8,269 | $ | (478 | ) | $ | (82 | ) | $ | (1,041 | ) | $ | 7,288 | $ | 1,331 | $ | 8,619 | |||||||||||||
See accompanying notes.
86
Table of Contents
THE
WILLIAMS COMPANIES, INC.
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
OPERATING ACTIVITIES:
|
||||||||||||
|
Net income (loss)
|
$ | (922 | ) | $ | 361 | $ | 1,592 | |||||
|
Adjustments to reconcile to net cash provided by operating
activities:
|
||||||||||||
|
Depreciation, depletion, and amortization
|
1,507 | 1,469 | 1,310 | |||||||||
|
Provision (benefit) for deferred income taxes
|
(155 | ) | 249 | 611 | ||||||||
|
Provision for loss on goodwill, investments, property and other
assets
|
1,735 | 386 | 166 | |||||||||
|
Gain on sale of contractual production rights
|
— | — | (148 | ) | ||||||||
|
Provision for doubtful accounts and notes
|
(6 | ) | 48 | 15 | ||||||||
|
Amortization of stock-based awards
|
48 | 43 | 31 | |||||||||
|
Early debt retirement costs
|
606 | 1 | 1 | |||||||||
|
Cash provided (used) by changes in current assets and
liabilities:
|
||||||||||||
|
Accounts and notes receivable
|
(36 | ) | 52 | 335 | ||||||||
|
Inventories
|
(81 | ) | 33 | (48 | ) | |||||||
|
Margin deposits and customer margin deposits payable
|
(1 | ) | 4 | 88 | ||||||||
|
Other current assets and deferred charges
|
43 | 7 | (82 | ) | ||||||||
|
Accounts payable
|
(14 | ) | 5 | (343 | ) | |||||||
|
Accrued liabilities
|
(29 | ) | (170 | ) | 7 | |||||||
|
Changes in current and noncurrent derivative assets and
liabilities
|
(42 | ) | 36 | (121 | ) | |||||||
|
Other, including changes in noncurrent assets and liabilities
|
(2 | ) | 48 | (59 | ) | |||||||
|
Net cash provided by operating activities
|
2,651 | 2,572 | 3,355 | |||||||||
|
FINANCING ACTIVITIES:
|
||||||||||||
|
Proceeds from long-term debt
|
5,129 | 595 | 674 | |||||||||
|
Payments of long-term debt
|
(4,305 | ) | (33 | ) | (665 | ) | ||||||
|
Proceeds from sale of limited partner units of consolidated
partnerships
|
806 | — | 362 | |||||||||
|
Dividends paid
|
(284 | ) | (256 | ) | (250 | ) | ||||||
|
Purchase of treasury stock
|
— | — | (474 | ) | ||||||||
|
Dividends and distributions paid to noncontrolling interests
|
(145 | ) | (129 | ) | (122 | ) | ||||||
|
Payments for debt issuance costs
|
(71 | ) | (7 | ) | (4 | ) | ||||||
|
Premiums paid on early debt retirements
|
(574 | ) | — | — | ||||||||
|
Changes in restricted cash
|
— | 40 | (5 | ) | ||||||||
|
Changes in cash overdrafts
|
14 | (51 | ) | — | ||||||||
|
Other — net
|
3 | 7 | 52 | |||||||||
|
Net cash provided (used) by financing activities
|
573 | 166 | (432 | ) | ||||||||
|
INVESTING ACTIVITIES:
|
||||||||||||
|
Capital expenditures*
|
(2,788 | ) | (2,387 | ) | (3,394 | ) | ||||||
|
Purchases of investments/advances to affiliates
|
(488 | ) | (142 | ) | (111 | ) | ||||||
|
Purchase of businesses
|
(1,099 | ) | — | — | ||||||||
|
Proceeds from sale of contractual production rights
|
— | — | 148 | |||||||||
|
Distribution from Gulfstream Natural Gas System, L.L.C.
|
— | 148 | — | |||||||||
|
Other — net
|
79 | 71 | 174 | |||||||||
|
Net cash used by investing activities
|
(4,296 | ) | (2,310 | ) | (3,183 | ) | ||||||
|
Increase (decrease) in cash and cash equivalents
|
(1,072 | ) | 428 | (260 | ) | |||||||
|
Cash and cash equivalents at beginning of year
|
1,867 | 1,439 | 1,699 | |||||||||
|
Cash and cash equivalents at end of year
|
$ | 795 | $ | 1,867 | $ | 1,439 | ||||||
|
|
||||||||||||
|
* Increases to property, plant, and equipment
|
$ | (2,755 | ) | $ | (2,314 | ) | $ | (3,475 | ) | |||
|
Changes in related accounts payable and accrued liabilities
|
(33 | ) | (73 | ) | 81 | |||||||
|
Capital expenditures
|
$ | (2,788 | ) | $ | (2,387 | ) | $ | (3,394 | ) | |||
See accompanying notes.
87
Table of Contents
THE
WILLIAMS COMPANIES, INC.
| Note 1. | Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies |
Description
of Business
Operations of our company are located principally in the United
States and are organized into the following reporting segments:
Williams Partners, Exploration & Production, and Other.
Williams Partners consists of our consolidated master limited
partnership, Williams Partners L.P. (WPZ) and includes the gas
pipeline and midstream businesses that were contributed as part
of our first quarter 2010 restructuring. The contributed gas
pipeline businesses include 100 percent of Transcontinental
Gas Pipe Line Company, LLC (Transco), 65 percent of
Northwest Pipeline GP (Northwest Pipeline), and
24.5 percent of Gulfstream Natural Gas System, L.L.C.
(Gulfstream). The remaining 35 percent of Northwest
Pipeline is directly owned by WPZ following the third quarter
2010 merger of WPZ and Williams Pipeline Partners L.P. (WMZ).
WPZ’s midstream operations are composed of significant,
large-scale operations in the Rocky Mountain and Gulf Coast
regions, operations in Pennsylvania’s Marcellus Shale
region, and various equity investments in domestic processing
and fractionation assets. WPZ’s midstream assets also
include substantial operations and investments in the Four
Corners and Gulf Coast regions, as well as a NGLs fractionator
and storage facilities near Conway, Kansas.
Exploration & Production includes the natural gas
development, production and gas management activities primarily
in the Rocky Mountain and Mid-Continent regions of the United
States, natural gas development activities in the northeastern
portion of the United States, oil and natural gas interests in
South America, and more recently, oil development activities in
the northern United States. The gas management activities
include procuring fuel and shrink gas for our midstream
businesses and providing marketing to third parties, such as
producers. Additionally, gas management activities include
managing various natural gas related contracts such as
transportation, storage, and related hedges.
Other includes other business activities that are not operating
segments, primarily our Canadian midstream and domestic olefins
operations, a 25.5 percent interest in Gulfstream, as well
as corporate operations.
Basis
of Presentation
During fourth-quarter 2010, we contributed a business
represented by certain gathering and processing assets in
Colorado’s Piceance basin to WPZ. The transaction has been
accounted for as a combination of entities under common control
whereby the assets and liabilities sold were recorded by WPZ at
their historical amounts. The operations of this business and
the related assets and liabilities were previously reported
through our Exploration & Production segment, however
they are now reported in our Williams Partners segment. Prior
period segment disclosures have been adjusted for this
transaction.
Master
limited partnerships
At December 31, 2010, we own approximately 75 percent
of the interests in WPZ, including the interests of the general
partner, which is wholly owned by us, and incentive distribution
rights. At December 31, 2009, we owned approximately
24 percent of WPZ. Changes in our ownership of WPZ
occurring during the past year include:
| • | In conjunction with our first quarter 2010 restructuring, we ultimately received 203,000,000 common units from WPZ. Following this transaction, we owned approximately 84 percent of WPZ. | |
| • | On August 31, 2010, WMZ unitholders approved the merger between WMZ and WPZ. As a result of the merger, effective September 1, 2010, WMZ unitholders, other than its general partner, received 0.7584 WPZ common units for each WMZ common unit they owned at the effective time of the merger, for a total issuance of 13,580,485 common units. Upon completing this merger, WMZ is wholly owned by WPZ and is no longer publicly traded. |
88
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| • | On September 28, 2010, WPZ completed an equity issuance of common units resulting in proceeds of $380 million, net of the underwriters’ discount and fees. | |
| • | On October 8, 2010, WPZ sold additional common units to the underwriters upon the underwriters’ exercise of their option to purchase additional common units pursuant to WPZ’s common unit offering in September 2010. The offering resulted in proceeds of $57 million, net of the underwriters’ discount and fees. | |
| • | On December 17, 2010, WPZ completed an equity issuance of common units resulting in proceeds of approximately $369 million, net of the underwriters’ discount and fees. |
These transactions resulted in changes in ownership between us
and the noncontrolling interest that have been accounted for as
equity transactions, resulting in an aggregate $77 million
increase in capital in excess of par and a corresponding
decrease in noncontrolling interest in consolidated subsidiaries.
WPZ is self funding and maintains separate lines of bank credit
and cash management accounts. Cash distributions from WPZ to us,
including any associated with our incentive distribution rights,
occur through the normal partnership distributions from WPZ to
all partners.
Discontinued
operations
The accompanying consolidated financial statements and notes
reflect the results of operations and financial position of
certain of our Venezuela operations and other former businesses
as discontinued operations. (See Note 2).
Unless indicated otherwise, the information in the Notes to the
Consolidated Financial Statements relates to our continuing
operations.
Summary
of Significant Accounting Policies
Principles
of consolidation
The consolidated financial statements include the accounts of
our corporate parent and our majority-owned or controlled
subsidiaries and investments. We apply the equity method of
accounting for investments in unconsolidated companies in which
we and our subsidiaries own 20 to 50 percent of the voting
interest, otherwise exercise significant influence over
operating and financial policies of the company, or where
majority ownership does not provide us with control due to
significant participatory rights of other owners.
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.
Significant estimates and assumptions include:
| • | Impairment assessments of investments, long-lived assets and goodwill; | |
| • | Litigation-related contingencies; | |
| • | Valuations of derivatives; | |
| • | Hedge accounting correlations and probability; | |
| • | Environmental remediation obligations; | |
| • | Realization of deferred income tax assets; |
89
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| • | Valuation of Exploration & Production’s reserves; | |
| • | Asset retirement obligations; | |
| • | Pension and postretirement valuation variables. |
These estimates are discussed further throughout these notes.
Regulatory
accounting
Transco and Northwest Pipeline are regulated by the Federal
Energy Regulatory Commission (FERC). Their rates established by
the FERC are designed to recover the costs of providing the
regulated services, and their competitive environment makes it
probable that such rates can be charged and collected.
Therefore, our management has determined that it is appropriate
to account for and report regulatory assets and liabilities
related to these operations consistent with the economic effect
of the way in which their rates are established. Accounting for
these businesses that are regulated can differ from the
accounting requirements for non-regulated businesses. These
differences are discussed further throughout these notes.
Cash and
cash equivalents
Our
cash and cash equivalents
balance includes 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 maturity dates of three months
or less when acquired.
Accounts
receivable
Accounts receivable
are carried on a gross basis, with no
discounting, less the allowance for doubtful accounts. We
estimate the allowance for doubtful accounts based on existing
economic conditions, the financial conditions 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. Interest income related to past due
accounts receivable is generally recognized at the time full
payment is received or collectability is assured. Past due
accounts are generally written off against the allowance for
doubtful accounts only after all collection attempts have been
exhausted.
Inventory
valuation
All
inventories
are stated at the lower of cost or
market. The cost of inventories is primarily determined using
the average-cost method. We determine the cost of certain
natural gas inventories held by Transco using the
last-in,
first-out (LIFO) cost method. LIFO inventory at
December 31, 2010 and 2009 is $9 million and
$7 million, respectively.
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.
As regulated entities, Northwest Pipeline and Transco provide
for depreciation using the straight-line method at
FERC-prescribed rates. See Note 9 for depreciation rates
used for major regulated gas plant facilities.
Depreciation for nonregulated entities is provided primarily on
the straight-line method over estimated useful lives, except as
noted below for oil and gas exploration and production
activities. See Note 9 for the estimated useful lives
associated with our nonregulated assets.
Gains or losses from the ordinary sale or retirement of
property, plant, and equipment for regulated pipelines are
credited or charged to accumulated depreciation; other gains or
losses are recorded in
other (income) expense — net
included in
operating income
.
90
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Ordinary maintenance and repair costs are generally expensed as
incurred. Costs of major renewals and replacements are
capitalized as
property, plant, and equipment —
net
.
Oil and gas exploration and production activities are accounted
for under the successful efforts method. Costs incurred in
connection with the drilling and equipping of exploratory wells,
as applicable, are capitalized as incurred. If proved reserves
are not found, such costs are charged to expense. Other
exploration costs, including lease rentals, are expensed as
incurred. All costs related to development wells, including
related production equipment and lease acquisition costs, are
capitalized when incurred.
Depreciation, depletion and
amortization
is provided under the
units-of-production
method on a field basis.
We record an asset and a liability upon incurrence equal to the
present value of each expected future asset retirement
obligation (ARO). The ARO asset is depreciated in a manner
consistent with the depreciation of the underlying physical
asset. We measure changes in the liability due to passage of
time by applying an interest method of allocation. This amount
is recognized as an increase in the carrying amount of the
liability and as a corresponding accretion expense included in
other (income) expense — net
included in
operating income
, except for regulated entities, for
which the liability is offset by a regulatory asset as
management expects to recover amounts in future rates. The
regulatory asset is amortized commensurate with our collection
of those costs in rates.
Measurements of AROs include, as a component of future expected
costs, an estimate of the price that a third party would demand,
and could expect to receive, for bearing the uncertainties
inherent in the obligations, sometimes referred to as a
market-risk premium.
Goodwill
Goodwill
represents the excess of cost over fair value of
the assets of businesses acquired. It is evaluated at least
annually for impairment by first comparing our management’s
estimate of the fair value of a reporting unit with its carrying
value, including goodwill. If the carrying value of the
reporting unit exceeds its fair value, a computation of the
implied fair value of the goodwill is compared with its related
carrying value. If the carrying value of the reporting unit
goodwill exceeds the implied fair value of that goodwill, an
impairment loss is recognized in the amount of the excess.
As a result of significant declines in forward natural gas
prices during the third quarter of 2010, we performed an interim
impairment assessment of our goodwill. As a result of that
assessment, we recorded an impairment of goodwill of
approximately $1 billion. See Note 4.
Cash
flows from revolving credit facilities
Proceeds and payments related to borrowings under our credit
facilities are reflected in the
financing activities
of
the Consolidated Statement of Cash Flows on a gross basis.
Treasury
stock
Treasury stock
purchases are accounted for under the cost
method whereby the entire cost of the acquired stock is recorded
as treasury stock. Gains and losses on the subsequent reissuance
of shares are credited or charged to
capital in excess of par
value
using the average-cost method.
Derivative
instruments and hedging activities
We utilize derivatives to manage our commodity price risk. These
instruments consist primarily of futures contracts, swap
agreements, option contracts, and forward contracts involving
short- and long-term purchases and sales of a physical energy
commodity.
We report the fair value of derivatives, except for those for
which the normal purchases and normal sales exception has been
elected, on the Consolidated Balance Sheet in
derivative
assets
and
derivative liabilities
as
91
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
either current or noncurrent. We determine the current and
noncurrent classification based on the timing of expected future
cash flows of individual trades. We report these amounts on a
gross basis. Additionally, we report cash collateral receivables
and payables with our counterparties on a gross basis.
The accounting for the changes in fair value of a commodity
derivative can be summarized as follows:
| Derivative Treatment | Accounting Method | |
|
Normal purchases and normal sales exception
|
Accrual accounting | |
|
Designated in a qualifying hedging relationship
|
Hedge accounting | |
|
All other derivatives
|
Mark-to-market accounting |
We may elect the normal purchases and normal sales exception for
certain short- and long-term purchases and sales of a physical
energy commodity. Under accrual accounting, any change in the
fair value of these derivatives is not reflected on the balance
sheet after the initial election of the exception.
We have also designated a hedging relationship for certain
commodity derivatives. 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
revenues
or
costs and operating expenses
dependent upon the
underlying hedge transaction.
For commodity derivatives designated as a cash flow hedge, the
effective portion of the change in fair value of the derivative
is reported in
accumulated other comprehensive income (loss)
(AOCI) and reclassified into earnings in the period in which
the hedged item affects earnings. Any ineffective portion of the
derivative’s change in fair value is recognized currently
in
revenues
or
costs and operating expenses
. Gains
or losses deferred in AOCI 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
AOCI 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 AOCI is recognized in
revenues
or
costs and operating expenses
at that time. The change in
likelihood is a judgmental decision that includes qualitative
assessments made by management.
For commodity derivatives that are not designated in a hedging
relationship, and for which we have not elected the normal
purchases and normal sales exception, we report changes in fair
value currently in
revenues
or
costs and operating
expenses
dependent upon the underlying hedge transaction.
Certain gains and losses on derivative instruments included in
the Consolidated Statement of Operations are netted together to
a single net gain or loss, while other gains and losses are
reported on a gross basis. Gains and losses recorded on a net
basis include:
| • | Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception; | |
| • | The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges; | |
| • | Realized gains and losses on all derivatives that settle financially other than natural gas derivatives for NGL processing activities; | |
| • | Realized gains and losses on derivatives held for trading purposes; |
92
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| • | Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement. |
Realized gains and losses on derivatives that require physical
delivery, as well as natural gas derivatives for NGL processing
activities and which are not held for trading purposes nor were
entered into as a pre-contemplated buy/sell arrangement, are
recorded on a gross basis. In reaching our conclusions on this
presentation, we considered whether we act as principal in the
transaction; whether we have the risks and rewards of ownership,
including credit risk; and whether we have latitude in
establishing prices.
Revenues
Revenues from our gas pipeline businesses are primarily from
services pursuant to long-term firm transportation and storage
agreements. These agreements provide for a reservation charge
based on the volume of contracted capacity and a commodity
charge based on the volume of gas delivered, both at rates
specified in our FERC tariffs. We recognize revenues for
reservation charges ratably over the contract period regardless
of the volume of natural gas that is transported or stored.
Revenues for commodity charges, from both firm and interruptible
transportation services, and storage injection and withdrawal
services, are recognized when natural gas is delivered at the
agreed upon delivery point or when natural gas is injected or
withdrawn from the storage facility.
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. The
resulting imbalances are primarily settled through the purchase
and sale of gas with our customers under terms provided for in
our FERC tariffs. Revenue is recognized from the sale of gas
upon settlement of the transportation and exchange imbalances.
As a result of the ratemaking process, certain revenues
collected by us may be subject to refunds upon the issuance of
final orders by the FERC in pending rate proceedings. We record
estimates of rate refund liabilities considering our and other
third-party regulatory proceedings, advice of counsel and other
risks.
Revenues from our midstream operations include those derived
from natural gas gathering and processing services and are
performed under volumetric-based fee contracts, keep-whole
agreements and
percent-of-liquids
arrangements. Revenues under volumetric-based fee contracts are
recorded when services have been performed. Under keep-whole and
percent-of-liquids
processing contracts, we retain the rights to all or a portion
of the NGLs extracted from the producers’ natural gas
stream and recognize revenues when the extracted NGLs are sold
and delivered.
Oil gathering and transportation revenues and offshore
production handling fees of our midstream operations are
recognized when the services have been performed. Certain
offshore production handling contracts contain fixed payment
terms that result in the deferral of revenues until such
services have been performed.
We market NGLs that we purchase from our producer customers.
Revenues from marketing NGLs are recognized when the products
have been sold and delivered.
Storage revenues under prepaid contracted storage capacity
contracts are recognized evenly over the life of the contract as
services are provided.
Revenues for sales of natural gas are recognized when the
product is sold and delivered. Revenues from the domestic
production of natural gas in properties for which
Exploration & Production has an interest with other
producers are recognized based on the actual volumes sold during
the period. Any differences between volumes sold and entitlement
volumes, based on Exploration & Production’s net
working interest, that are determined to be nonrecoverable
through remaining production are recognized as accounts
receivable or accounts payable, as appropriate. Cumulative
differences between volumes sold and entitlement volumes are not
significant.
We have NGLs and olefins extraction operations where we retain
certain products extracted from the producers’ off-gas
stream and we recognize revenues when the extracted products are
sold and delivered to
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
our purchasers. We also produce olefins from purchased
feed-stock, and we recognize revenues when the olefins are sold
and delivered.
Impairment
of long-lived assets and investments
We evaluate the long-lived assets of identifiable business
activities for impairment when events or changes in
circumstances indicate, in our management’s judgment, that
the carrying value of such assets may not be recoverable. Except
for proved and unproved properties discussed below, when an
indicator of impairment has occurred, we compare our
management’s estimate of undiscounted future cash flows
attributable to the assets to the carrying value of the assets
to determine whether an impairment has occurred and we apply a
probability-weighted approach to consider the likelihood of
different cash flow assumptions and possible outcomes including
selling in the near term or holding for the remaining estimated
useful life. If an impairment of the carrying value has
occurred, we determine the amount of the impairment recognized
in the financial statements by estimating the fair value of the
assets and recording a loss for the amount that the carrying
value exceeds the estimated fair value.
For assets identified to be disposed of in the future and
considered held for sale, we compare the carrying value to the
estimated fair value less the cost to sell to determine if
recognition of an impairment is required. Until the assets are
disposed of, the estimated fair value, which includes estimated
cash flows from operations until the assumed date of sale, is
recalculated when related events or circumstances change.
Proved properties, including developed and undeveloped, are
assessed for impairment using estimated future undiscounted cash
flows on a field basis. If the undiscounted cash flows are less
than the carrying value of the assets, then a subsequent
analysis to estimate fair value is performed using discounted
cash flows. Estimating future cash flows involves the use of
complex judgments such as estimation of the oil and gas reserve
quantities, risk associated with the different categories of oil
and gas reserves, timing of development and production, expected
future commodity prices, capital expenditures, and production
costs.
Unproved properties include lease acquisition costs and costs of
acquired unproved reserves. Individually significant lease
acquisition costs are assessed annually, or as conditions
warrant, for impairment considering our future drilling plans,
the remaining lease term and recent drilling results. Lease
acquisition costs that are not individually significant are
aggregated, and the portion of such costs estimated to be
nonproductive is amortized over the average holding period. The
estimate of what could be nonproductive is based on our
historical experience or other information, including current
drilling plans and existing geological data. A majority of the
costs of acquired unproved reserves are associated with areas to
which proved developed producing reserves are also attributed.
Generally, economic recovery of unproved reserves in such areas
is not yet supported by actual production or conclusive
formation tests, but may be confirmed by our continuing
development program. Ultimate recovery of potentially
recoverable reserves in areas with established production
generally has greater probability than in areas with limited or
no prior drilling activity. Costs of acquired unproved reserves
are assessed annually, or as conditions warrant, for impairment
using estimated future discounted cash flows on a field basis
and considering our future drilling plans. If the unproved
properties are determined to be productive, the appropriate
related costs are transferred to proved oil and gas properties.
We evaluate our investments for impairment when events or
changes in circumstances indicate, in our management’s
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 fair value is
recognized in the consolidated financial statements as an
impairment charge.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Judgments and assumptions are inherent in our management’s
estimate of undiscounted future cash flows and an asset’s
fair value. Additionally, judgment is used to determine the
probability of sale with respect to assets considered for
disposal.
Capitalization
of 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 million. Interest is
capitalized on borrowed funds and, where regulation by the FERC
exists, on internally generated funds as a component of
other
income (expense) — net
. The rates used by
regulated companies are calculated in accordance with FERC
rules. Rates used by nonregulated companies are based on the
average interest rate on debt.
Employee
stock-based awards
Stock options are valued at the date of award, which does not
precede the approval date, and compensation cost is recognized
on a straight-line basis, net of estimated forfeitures, over the
requisite service period. The purchase price per share for stock
options may not be less than the market price of the underlying
stock on the date of grant. Stock options generally become
exercisable over a three-year period from the date of grant and
can be subject to accelerated vesting if certain future stock
prices or specific financial performance targets are achieved.
Stock options generally expire ten years after the grant.
Restricted stock units are generally valued at market value on
the grant date and generally vest over three years. Restricted
stock unit compensation cost, net of estimated forfeitures, is
generally recognized over the vesting period on a straight-line
basis.
Income
taxes
We include the operations of our subsidiaries in our
consolidated tax return. Deferred income taxes are computed
using the liability method and are provided on all temporary
differences between the financial basis and the tax basis of our
assets and liabilities. Our management’s judgment and
income tax assumptions are used to determine the levels, if any,
of valuation allowances associated with deferred tax assets.
Earnings
(loss) per common share
Basic earnings (loss) per common share
is based on the
sum of the weighted-average number of common shares outstanding
and vested restricted stock units.
Diluted earnings (loss)
per common share
includes any dilutive effect of stock
options, nonvested restricted stock units and, for applicable
periods presented, convertible debt, unless otherwise noted.
Foreign
currency translation
Certain of our foreign subsidiaries use the Canadian dollar as
their functional currency. Assets and liabilities of such
foreign subsidiaries are translated at the spot rate in effect
at the applicable reporting date, and the combined statements of
operations are translated into the U.S. dollar at the
average exchange rates in effect during the applicable period.
The resulting cumulative translation adjustment is recorded as a
separate component of AOCI.
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 and losses which are reflected in the
Consolidated Statement of Operations.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Issuance
of equity of consolidated subsidiary
Sales of residual equity interests in a consolidated subsidiary
are accounted for as capital transactions. No adjustments to
capital are made for sales of preferential interests in a
subsidiary. No gain or loss is recognized on these transactions.
| Note 2. | Discontinued Operations |
Summarized
Results of Discontinued Operations
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
Revenues
|
$ | — | $ | — | $ | 172 | ||||||
|
Income (loss) from discontinued operations before (impairments)
and gain
|
||||||||||||
|
on sale, gain on deconsolidation and income taxes
|
$ | (2 | ) | $ | (87 | ) | $ | 241 | ||||
|
(Impairments) and gain on sale
|
— | (211 | ) | 8 | ||||||||
|
Gain on deconsolidation
|
— | 9 | — | |||||||||
|
(Provision) benefit for income taxes
|
(4 | ) | 66 | (124 | ) | |||||||
|
Income (loss) from discontinued operations
|
$ | (6 | ) | $ | (223 | ) | $ | 125 | ||||
|
Income (loss) from discontinued operations:
|
||||||||||||
|
Attributable to noncontrolling interests
|
$ | — | $ | (70 | ) | $ | 13 | |||||
|
Attributable to The Williams Companies, Inc.
|
$ | (6 | ) | $ | (153 | ) | $ | 112 | ||||
The decrease in
revenues
reflects the cessation of
revenue recognition of our discontinued Venezuela operations in
2009.
Income (loss) from discontinued operations before
(impairments) and gain on sale, gain on deconsolidation, and
income taxes
for 2009 primarily includes losses from our
discontinued Venezuela operations, including $48 million of
bad debt expense and a $30 million net charge related to
the write-off of certain deferred charges and credits.
Offsetting these losses is a $15 million gain related to
our former coal operations.
Income (loss) from discontinued operations before
(impairments) and gain on sale, gain on deconsolidation, and
income taxes
for 2008 includes:
| • | $140 million of gains related to the favorable resolution of matters involving pipeline transportation rates associated with our former Alaska operations; | |
| • | $77 million of income related to our discontinued Venezuela operations; | |
| • | $54 million of income related to a reduction of remaining amounts accrued in excess of our obligation associated with the Trans-Alaska Pipeline System Quality Bank; | |
| • | An $11 million charge associated with an oil purchase contract related to our former Alaska refinery; | |
| • | A $10 million charge associated with a settlement primarily related to the sale of NGL pipeline systems in 2002. |
(Impairments) and gain on sale
for 2009 reflects an
impairment of our Venezuela property, plant, and equipment. (See
Note 14.)
(Impairments) and gain on sale
for 2008 includes the
final proceeds from the 2007 sale of our former power business.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Gain on deconsolidation
reflects the gain recognized when
we deconsolidated the entities that owned and operated our
Venezuela gas compression facilities prior to their
expropriation by the Venezuelan government in 2009.
(Provision) benefit for income taxes
for 2009 includes a
$76 million benefit from the reversal of deferred tax
balances related to our discontinued Venezuela operations.
| Note 3. | Investing Activities |
Investing
Income
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
Equity earnings*
|
$ | 163 | $ | 136 | $ | 137 | ||||||
|
Income (loss) from investments*
|
43 | (75 | ) | 1 | ||||||||
|
Impairment of cost-based investments
|
— | (22 | ) | (4 | ) | |||||||
|
Interest income and other
|
3 | 7 | 55 | |||||||||
|
Total investing income
|
$ | 209 | $ | 46 | $ | 189 | ||||||
| * | Items also included in segment profit (loss) . (See Note 18.) |
Income (loss) from investments
in 2009 reflects a
$75 million impairment charge related to an
other-than-temporary
loss in value associated with our Venezuelan investment in
Accroven SRL (Accroven). Accroven owns and operates gas
processing facilities and a NGL fractionation plant for the
exclusive benefit of Petróleos de Venezuela S.A. (PDVSA).
The deteriorating circumstances in the first quarter of 2009 for
our Venezuelan operations caused us to review our investment in
Accroven. We utilized a probability-weighted discounted cash
flow analysis, which included an after-tax discount rate of
20 percent to reflect the risk associated with operating in
Venezuela. Accroven was not part of the operations that were
expropriated by the Venezuelan government in May 2009.
In June 2010, we sold our 50 percent interest in Accroven
to the state-owned oil company, PDVSA for $107 million. Of
this amount, $13 million was received in cash at closing
and another $30 million was received in August 2010. The
remainder is due in six quarterly payments beginning
October 31, 2010. The first quarterly payment of
$11 million was received in January 2011 and will be
recognized as income in 2011. We will continue to recognize the
resulting gain as cash is received. Accroven was not part of our
operations that were expropriated by the Venezuelan government
in May 2009.
Impairment of cost-based investments
in 2009 includes an
$11 million impairment related to our 4 percent
interest in a Venezuelan corporation that owns and operates oil
and gas activities. This investment resulted from our previous
10 percent direct working interest in a concession that was
converted to a reduced interest in a mixed company at the
direction of the Venezuelan government in 2006. Considering our
evaluation of the deteriorating financial condition of this
corporation, we recorded an
other-than-temporary
decline in value of our remaining investment balance.
The unfavorable change in
interest income and other
in
2009 is primarily due to lower average interest rates which
continued in 2010.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Investments
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Equity method:
|
||||||||
|
Overland Pass Pipeline Company LLC — 50%
|
$ | 429 | $ | — | ||||
|
Gulfstream — 50%(1)
|
378 | 383 | ||||||
|
Discovery Producer Services LLC — 60%(2)
|
181 | 189 | ||||||
|
Laurel Mountain Midstream, LLC — 51%(2)
|
170 | 133 | ||||||
|
Petrolera Entre Lomas S.A. — 40.8%
|
81 | 81 | ||||||
|
Other
|
103 | 98 | ||||||
| 1,342 | 884 | |||||||
|
Cost method
|
2 | 2 | ||||||
| $ | 1,344 | $ | 886 | |||||
| (1) | As of December 31, 2010, 24.5 percent interest is held within Williams Partners, with the remaining 25.5 percent held within Other. | |
| (2) | We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control the investments. |
Differences between the carrying value of our equity investments
and the underlying equity in the net assets of the investees are
primarily related to impairments we previously recognized. These
differences are amortized over the expected remaining life of
the investees’ underlying assets.
In September 2010, we purchased an additional 49 percent
ownership interest in Overland Pass Pipeline Company LLC (OPPL)
for $424 million. In addition, we invested $43 million
and $133 million in Laurel Mountain Midstream, LLC in 2010
and 2009, respectively.
Dividends and distributions, including those presented below,
received from companies accounted for by the equity method were
$193 million, $291 million, and $167 million in
2010, 2009, and 2008, respectively. These transactions reduced
the carrying value of our investments. These dividends and
distributions primarily included:
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
Gulfstream
|
$ | 81 | $ | 223 | $ | 58 | ||||||
|
Discovery Producer Services LLC
|
44 | 32 | 56 | |||||||||
|
Aux Sable Liquid Products LP
|
28 | 15 | 28 | |||||||||
In 2009, we received a $148 million distribution from
Gulfstream following its debt offering.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Summarized
Financial Position and Results of Operations of Equity Method
Investments (Unaudited)
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Current assets
|
$ | 321 | $ | 383 | ||||
|
Noncurrent assets
|
4,421 | 3,723 | ||||||
|
Current liabilities
|
229 | 266 | ||||||
|
Noncurrent liabilities
|
1,409 | 1,511 | ||||||
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
Gross revenue
|
$ | 1,362 | $ | 1,115 | $ | 1,246 | ||||||
|
Operating income
|
699 | 516 | 521 | |||||||||
|
Net income
|
508 | 396 | 405 | |||||||||
| Note 4. | Asset Sales, Impairments and Other Accruals |
The following table presents significant gains or losses
reflected in
impairments of goodwill and long-lived assets
and
other (income) expense
—
net
within
segment costs and expenses
:
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
Williams Partners
|
||||||||||||
|
Involuntary conversion gains
|
$ | (18 | ) | $ | (4 | ) | $ | (17 | ) | |||
|
Gains on sales of certain assets
|
(12 | ) | (40 | ) | (10 | ) | ||||||
|
Accrual of regulatory liability related to overcollection of
certain employee expenses
|
10 | — | — | |||||||||
|
Impairments of certain gathering and transportation assets
|
9 | — | 6 | |||||||||
|
Exploration & Production
|
||||||||||||
|
Gain on sale of contractual right to an international production
payment
|
— | — | (148 | ) | ||||||||
|
Impairment of goodwill
|
1,003 | — | — | |||||||||
|
Impairments of producing properties and acquired unproved
reserves
|
678 | 20 | 143 | |||||||||
|
Penalties from early release of drilling rigs
|
— | 32 | — | |||||||||
|
Other
|
||||||||||||
|
Gulf Liquids litigation contingency accrual reversal (see
Note 16)
|
— | — | (32 | ) | ||||||||
Other (income) expense — net
within
segment
costs and expenses
also includes net foreign currency
exchange gains of $38 million in 2008, which primarily
relates to the remeasurement of current assets held in
U.S. dollars within our Canadian operations in the Other
segment.
Impairments
of goodwill and certain Exploration & Production
properties
As a result of significant declines in forward natural gas
prices during the third quarter of 2010, we performed an interim
impairment assessment of our capitalized costs related to
goodwill and domestic properties at Exploration &
Production. As a result of these assessments,
Exploration & Production recorded an impairment of
goodwill, as noted above, and impairments of capitalized costs
of certain natural gas producing properties in the
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Barnett Shale of $503 million and capitalized costs of
certain acquired unproved reserves in the Piceance Highlands
acquired in 2008 of $175 million.
Based on a comparison of the estimated fair value to the
carrying value, Exploration & Production recorded a
$15 million impairment in 2009 related to costs of acquired
unproved reserves resulting from a 2008 acquisition in the
Fort Worth basin. Additionally, Exploration &
Production recorded impairment charges of $5 million and
$143 million in 2009 and 2008, respectively, related to
properties in the Arkoma basin.
Our impairment analyses included assessments of undiscounted
(except for the unproved reserves) and discounted future cash
flows, which considered information obtained from drilling,
other activities, and year-end natural gas reserve quantities.
See Note 14 for a further discussion of the impairments.
Additional
Items
We completed a strategic restructuring transaction in 2010 that
involved significant debt issuances, retirements and amendments
(see Note 11). We incurred significant costs related to
these transactions, as follows:
| • | $606 million of early debt retirement costs consisting primarily of cash premiums; | |
| • | $45 million of other transaction costs reflected in general corporate expenses, of which $7 million is attributable to noncontrolling interests; | |
| • | $4 million of accelerated amortization of debt costs related to the amendments of credit facilities, reflected in other income (expense) — net below operating income (loss) . |
Exploration & Production recorded a $19 million
unfavorable adjustment to depletion expense in 2010 related to a
correction of prior years’ production volumes used in the
calculation of depletion expense, which is reflected in
costs
and operating expenses
.
Exploration & Production recorded $16 million of
exploratory dry hole costs in 2010, which is included within
costs and operating expenses
.
Exploration & Production recorded a $34 million
accrual for Wyoming severance taxes in 2008, which is reflected
in
costs and operating expenses
.
| Note 5. | Provision (Benefit) for Income Taxes |
The
provision (benefit) for income taxes
from continuing
operations includes:
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | 81 | $ | 10 | $ | 179 | ||||||
|
State
|
2 | 12 | 24 | |||||||||
|
Foreign
|
40 | 21 | 8 | |||||||||
| 123 | 43 | 211 | ||||||||||
|
Deferred:
|
||||||||||||
|
Federal
|
(61 | ) | 271 | 466 | ||||||||
|
State
|
(104 | ) | 42 | (11 | ) | |||||||
|
Foreign
|
12 | 3 | 11 | |||||||||
| (153 | ) | 316 | 466 | |||||||||
|
Total provision (benefit)
|
$ | (30 | ) | $ | 359 | $ | 677 | |||||
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Reconciliations from the
provision (benefit) for income taxes
from continuing operations at the federal statutory rate to
the realized
provision (benefit) for income taxes
are as
follows:
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
Provision (benefit) at statutory rate
|
$ | (331 | ) | $ | 330 | $ | 750 | |||||
|
Increases (decreases) in taxes resulting from:
|
||||||||||||
|
State income taxes (net of federal benefit)
|
(70 | ) | 35 | 8 | ||||||||
|
Foreign operations — net
|
(17 | ) | 25 | (16 | ) | |||||||
|
Impact of nontaxable noncontrolling interests
|
(58 | ) | (49 | ) | (54 | ) | ||||||
|
Goodwill impairment
|
351 | — | — | |||||||||
|
Taxes on undistributed earnings of certain foreign operations
|
66 | — | — | |||||||||
|
Reduction of tax benefits on Medicare Part D federal subsidy
|
11 | — | — | |||||||||
|
Other — net
|
18 | 18 | (11 | ) | ||||||||
|
Provision (benefit) for income taxes
|
$ | (30 | ) | $ | 359 | $ | 677 | |||||
State income taxes (net of federal benefit) were reduced by
$65 million in 2010 and $46 million in 2008 due to
reductions in our estimate of the effective deferred state rate,
including state income tax carryovers, reflective of a change in
the mix of jurisdictional attribution of taxable income.
Income (loss) from continuing operations before income taxes
includes $173 million of foreign income,
$36 million of foreign loss, and $139 million of
foreign income in 2010, 2009, and 2008, respectively.
During the course of audits of our business by domestic and
foreign tax authorities, we frequently face challenges regarding
the amount of taxes due. These challenges include questions
regarding the timing and amount of deductions and the allocation
of income among various tax jurisdictions. In evaluating the
liability associated with our various filing positions, we apply
the two step process of recognition and measurement. In
association with this liability, we record an estimate of
related interest and tax exposure as a component of our tax
provision. The impact of this accrual is included within
other-net
in our reconciliation of the tax provision to the federal
statutory rate.
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Significant components of
deferred tax liabilities
and
deferred tax assets
are as follows:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Deferred tax liabilities:
|
||||||||
|
Property, plant, and equipment
|
$ | 1,784 | $ | 3,658 | ||||
|
Derivatives — net
|
111 | 66 | ||||||
|
Investments
|
2,125 | 491 | ||||||
|
Other
|
100 | 108 | ||||||
|
Total deferred tax liabilities
|
4,120 | 4,323 | ||||||
|
Deferred tax assets:
|
||||||||
|
Accrued liabilities
|
369 | 557 | ||||||
|
Minimum tax credits
|
120 | 62 | ||||||
|
State loss and credit carryovers
|
278 | 289 | ||||||
|
Other
|
70 | 58 | ||||||
|
Total deferred tax assets
|
837 | 966 | ||||||
|
Less valuation allowance
|
249 | 289 | ||||||
|
Net deferred tax assets
|
588 | 677 | ||||||
|
Overall net deferred tax liabilities
|
$ | 3,532 | $ | 3,646 | ||||
The valuation allowance at December 31, 2010 and 2009
serves to reduce the recognized tax assets associated with state
loss and credit carryovers to an amount that will more likely
than not be realized. These amounts are presented in the table
above before any federal benefit.
As a result of the plan approved by our Board of Directors to
pursue separation of the company into two standalone publicly
traded corporations (see Note 19), we provided
$66 million of deferred taxes in 2010 on undistributed
earnings of certain foreign operations that we no longer
consider permanently reinvested. As of December 31, 2010,
we still consider $277 million of undistributed earnings of
other consolidated foreign subsidiaries to be permanently
reinvested and have not provided deferred income taxes on that
amount.
Cash payments for income taxes (net of refunds and including
discontinued operations) were $40 million,
$14 million, and $155 million in 2010, 2009, and 2008,
respectively.
As of December 31, 2010, we had approximately
$91 million of unrecognized tax benefits. If recognized,
approximately $74 million, net of federal tax expense,
would be recorded as a reduction of income tax expense.
A
reconciliation of the beginning and ending amount of
unrecognized tax benefits is as follows:
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Balance at beginning of period
|
$ | 89 | $ | 79 | ||||
|
Additions based on tax positions related to the current year
|
11 | 17 | ||||||
|
Additions for tax positions for prior years
|
3 | 4 | ||||||
|
Reductions for tax positions of prior years
|
(12 | ) | (7 | ) | ||||
|
Settlement with taxing authorities
|
— | (4 | ) | |||||
|
Balance at end of period
|
$ | 91 | $ | 89 | ||||
We recognize related interest and penalties as a component of
income tax expense. Total interest and penalties recognized as
part of income tax expense were $11 million,
$17 million, and $2 million for 2010, 2009, and 2008,
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
respectively. Approximately $104 million and
$93 million of interest and penalties primarily relating to
uncertain tax positions have been accrued as of
December 31, 2010 and 2009, respectively.
As of December 31, 2010, the Internal Revenue Service (IRS)
examination of our consolidated U.S. income tax return for
2008 is in process. During the first quarter of 2011, we
finalized a settlement for 1997 through 2007 on certain
contested matters with the IRS Appeals Division which we
anticipate will result in a net reduction to our 2011 provision
for income taxes of approximately $90 million to
$100 million. This reduction is primarily driven by a
deferred tax asset created as a result of our settlement. We
anticipate making approximately $160 million to
$170 million of cash payments to the IRS and various states
related to this settlement in 2011. During the first quarter of
2011, we expect this settlement to reduce the balance of our
unrecognized tax benefits by approximately $40 million. The
statute of limitations for most states expires one year after
expiration of the IRS statute.
Generally, tax returns for our Venezuelan, Argentine and
Canadian entities are open to audit from 2003 through 2010.
Certain Canadian entities are currently under examination. We
believe there is a high degree of probability of an adjustment
related to an international matter that could result in a
decrease of approximately $17 million in our unrecognized
tax benefits during the next twelve months.
| Note 6. | Earnings (Loss) Per Common Share from Continuing Operations |
| Years Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions, except per-share amounts; shares in thousands) | ||||||||||||
|
Income (loss) from continuing operations attributable to The
Williams Companies, Inc. available to common stockholders for
basic and diluted earnings (loss) per common share(1)
|
$ | (1,091 | ) | $ | 438 | $ | 1,306 | |||||
|
Basic weighted-average shares(2)
|
584,552 | 581,674 | 581,342 | |||||||||
|
Effect of dilutive securities:
|
||||||||||||
|
Nonvested restricted stock units
|
— | 2,216 | 1,334 | |||||||||
|
Stock options
|
— | 2,065 | 3,439 | |||||||||
|
Convertible debentures(2)
|
— | 3,430 | 6,604 | |||||||||
|
Diluted weighted-average shares
|
584,552 | 589,385 | 592,719 | |||||||||
|
Earnings (loss) per common share from continuing operations:
|
||||||||||||
|
Basic
|
$ | (1.87 | ) | $ | .75 | $ | 2.25 | |||||
|
Diluted
|
$ | (1.87 | ) | $ | .75 | $ | 2.21 | |||||
| (1) | The years of 2009 and 2008 include $1.2 million and $2.4 million, respectively, of interest expense, net of tax, associated with our convertible debentures. (See Note 12.) These amounts have been added back to income (loss) from continuing operations attributable to The Williams Companies, Inc. available to common stockholders to calculate diluted earnings per common share. | |
| (2) | During 2009, we issued shares of our common stock in exchange for a portion of our convertible debentures. (See Note 12.) |
For 2010, 3.2 million weighted-average nonvested restricted
stock units and 3.0 million weighted-average stock options
have been excluded from the computation of diluted earnings per
common share as their inclusion would be antidilutive due to our
loss from continuing operations attributable to The Williams
Companies, Inc.
Additionally, for 2010, 2.2 million weighted-average shares
related to the assumed conversion of our convertible debentures,
as well as the related interest, net of tax, have been excluded
from the computation of
103
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
diluted earnings per common share. Inclusion of these shares
would have an antidilutive effect on the diluted earnings per
common share. We estimate that if 2010
income (loss) from
continuing operations attributable to The Williams Companies,
Inc. available to common stockholders
was $219 million
of income, then these shares would become dilutive.
The table below includes information related to stock options
that were outstanding at December 31 of each respective year but
have been excluded from the computation of weighted-average
stock options due to the option exercise price exceeding the
fourth quarter weighted-average market price of our common
shares.
| 2010 | 2009 | 2008 | ||||||||||
|
Options excluded (millions)
|
2.4 | 3.7 | 6.4 | |||||||||
|
Weighted-average exercise price of options excluded
|
$32.41 | $30.21 | $26.41 | |||||||||
|
Exercise price range of options excluded
|
$22.68 - $40.51 | $20.28 - $42.29 | $16.40 - $42.29 | |||||||||
|
Fourth quarter weighted-average market price
|
$22.47 | $19.81 | $16.37 | |||||||||
| Note 7. | Employee Benefit Plans |
We have noncontributory defined benefit pension plans in which
all eligible employees participate. Currently, eligible
employees earn benefits primarily based on a cash balance
formula. Various other formulas, as defined in the plan
documents, are utilized to calculate the retirement benefits for
plan participants not covered by the cash balance formula. At
the time of retirement, participants may elect, to the extent
they are eligible for the various options, to receive annuity
payments, a lump sum payment, or a combination of a lump sum and
annuity payments. In addition to our pension plans, we currently
provide subsidized retiree medical and life insurance benefits
(other postretirement benefits) to certain eligible
participants. Generally, employees hired after December 31,
1991, are not eligible for the subsidized retiree medical
benefits, except for participants that were employees or
retirees of Transco Energy Company on December 31, 1995,
and other miscellaneous defined participant groups. Certain of
these other postretirement benefit plans, particularly the
subsidized retiree medical benefit plans, provide for retiree
contributions and contain other cost-sharing features such as
deductibles, co-payments, and co-insurance. The accounting for
these plans anticipates future cost-sharing that is consistent
with our expressed intent to increase the retiree contribution
level generally in line with health care cost increases.
104
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Benefit
Obligations
The following table presents the changes in benefit obligations
and plan assets for pension benefits and other postretirement
benefits for the years indicated. The annual measurement date
for our plans is December 31.
|
Other
|
||||||||||||||||
|
Postretirement
|
||||||||||||||||
| Pension Benefits | Benefits | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| (Millions) | ||||||||||||||||
|
Change in benefit obligation:
|
||||||||||||||||
|
Benefit obligation at beginning of year
|
$ | 1,118 | $ | 1,035 | $ | 259 | $ | 273 | ||||||||
|
Service cost
|
35 | 32 | 2 | 2 | ||||||||||||
|
Interest cost
|
64 | 62 | 15 | 16 | ||||||||||||
|
Plan participants’ contributions
|
— | — | 6 | 5 | ||||||||||||
|
Benefits paid
|
(58 | ) | (59 | ) | (24 | ) | (24 | ) | ||||||||
|
Medicare Part D subsidy
|
— | — | 2 | 2 | ||||||||||||
|
Plan amendment
|
— | — | (1 | ) | (18 | ) | ||||||||||
|
Actuarial loss
|
108 | 48 | 30 | 3 | ||||||||||||
|
Benefit obligation at end of year
|
1,267 | 1,118 | 289 | 259 | ||||||||||||
|
Change in plan assets:
|
||||||||||||||||
|
Fair value of plan assets at beginning of year
|
860 | 705 | 148 | 126 | ||||||||||||
|
Actual return on plan assets
|
108 | 153 | 17 | 25 | ||||||||||||
|
Employer contributions
|
61 | 61 | 15 | 16 | ||||||||||||
|
Plan participants’ contributions
|
— | — | 6 | 5 | ||||||||||||
|
Benefits paid
|
(58 | ) | (59 | ) | (24 | ) | (24 | ) | ||||||||
|
Fair value of plan assets at end of year
|
971 | 860 | 162 | 148 | ||||||||||||
|
Funded status — underfunded
|
$ | (296 | ) | $ | (258 | ) | $ | (127 | ) | $ | (111 | ) | ||||
|
Accumulated benefit obligation
|
$ | 1,224 | $ | 1,075 | ||||||||||||
The underfunded status of our pension plans and other
postretirement benefit plans presented in the previous table are
recognized in the Consolidated Balance Sheet within the
following accounts:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Underfunded pension plans:
|
||||||||
|
Current liabilities
|
$ | 7 | $ | 1 | ||||
|
Noncurrent liabilities
|
289 | 257 | ||||||
|
Underfunded other postretirement benefit plans:
|
||||||||
|
Current liabilities
|
8 | 8 | ||||||
|
Noncurrent liabilities
|
119 | 103 | ||||||
The plan assets within our other postretirement benefit plans
are intended to be used for the payment of benefits for certain
groups of participants. The
current liabilities
for the
other postretirement benefit plans represent the current portion
of benefits expected to be payable in the subsequent year for
the groups of participants whose benefits are not expected to be
paid from plan assets.
105
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The pension plans’ benefit obligation
actuarial loss
of $108 million in 2010 and $48 million in 2009 is
primarily due to the impact of decreases in the discount rates
utilized to calculate the benefit obligation. The 2010 benefit
obligation
actuarial loss
of $30 million for our
other postretirement benefit plans is primarily due to the
impact of decreases in the discount rates utilized to calculate
the benefit obligation and changes to medical claims experience.
The impact of the provisions of the federal healthcare reform
legislation has been included in the December 31, 2010
other postretirement benefit plans’ obligation and is not
significant. The other postretirement benefits
plan
amendment
of $18 million in 2009 is due to an increase
in the retirees’ cost-sharing percentage within our
subsidized retiree medical benefit plans.
At December 31, 2010 and 2009, all of our pension plans had
a projected benefit obligation and accumulated benefit
obligation in excess of plan assets.
The determination of
net periodic benefit expense
allows
for the delayed recognition of gains and losses caused by
differences between actual and assumed outcomes for items such
as estimated return on plan assets, or caused by changes in
assumptions for items such as discount rates or estimated future
compensation levels. The
net actuarial loss
presented in
the following table and recorded in
accumulated other
comprehensive loss
and
net regulatory assets
represents the cumulative net deferred loss from these types
of differences or changes which have not yet been recognized in
the Consolidated Statement of Income. A portion of the
net
actuarial loss
is amortized over the participants’
average remaining future years of service, which is
approximately 13 years for our pension plans and
approximately 11 years for our other postretirement benefit
plans.
Pre-tax amounts not yet recognized in
net periodic benefit
expense
at December 31 are as follows:
|
Other
|
||||||||||||||||
|
Postretirement
|
||||||||||||||||
| Pension Benefits | Benefits | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| (Millions) | ||||||||||||||||
|
Amounts included in accumulated other comprehensive loss:
|
||||||||||||||||
|
Prior service (cost) credit
|
$ | (3 | ) | $ | (4 | ) | $ | 10 | $ | 15 | ||||||
|
Net actuarial loss
|
(657 | ) | (621 | ) | (20 | ) | (9 | ) | ||||||||
|
Amounts included in net regulatory assets associated with our
FERC-regulated gas pipelines:
|
||||||||||||||||
|
Prior service credit
|
N/A | N/A | $ | 20 | $ | 28 | ||||||||||
|
Net actuarial loss
|
N/A | N/A | (48 | ) | (40 | ) | ||||||||||
In addition to the net regulatory assets included in the
previous table, differences in the amount of actuarially
determined
net periodic benefit expense
for our other
postretirement benefit plans and the other postretirement
benefit costs recovered in rates for our FERC-regulated gas
pipelines are deferred as a regulatory asset or liability. We
have
net regulatory liabilities
of $23 million at
December 31, 2010 and $15 million at December 31,
2009 related to these deferrals. These amounts will be reflected
in future rates based on the gas pipelines’ rate structures.
106
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Net
Periodic Benefit Expense and Items Recognized in Other
Comprehensive Income (Loss)
Net periodic benefit expense
and other changes in plan
assets and benefit obligations recognized in
other
comprehensive income (loss)
before taxes for the years ended
December 31 consist of the following:
|
Other
|
||||||||||||||||||||||||
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||
|
Components of net periodic benefits expense:
|
||||||||||||||||||||||||
|
Service cost
|
$ | 35 | $ | 32 | $ | 23 | $ | 2 | $ | 2 | $ | 2 | ||||||||||||
|
Interest cost
|
64 | 62 | 60 | 15 | 16 | 18 | ||||||||||||||||||
|
Expected return on plan assets
|
(71 | ) | (61 | ) | (79 | ) | (9 | ) | (9 | ) | (13 | ) | ||||||||||||
|
Amortization of prior service cost (credit)
|
1 | 1 | 1 | (14 | ) | (11 | ) | — | ||||||||||||||||
|
Amortization of net actuarial loss
|
35 | 43 | 13 | 3 | 3 | — | ||||||||||||||||||
|
Amortization of regulatory asset
|
— | 1 | — | 1 | 5 | 5 | ||||||||||||||||||
|
Net periodic benefit expense
|
$ | 64 | $ | 78 | $ | 18 | $ | (2 | ) | $ | 6 | $ | 12 | |||||||||||
|
Other changes in plan assets and benefit obligations recognized
in other comprehensive income (loss):
|
||||||||||||||||||||||||
|
Net actuarial (gain) loss
|
$ | 71 | $ | (44 | ) | $ | 565 | $ | 12 | $ | 1 | $ | 15 | |||||||||||
|
Prior service credit
|
— | — | — | — | (7 | ) | (16 | ) | ||||||||||||||||
|
Amortization of prior service (cost) credit
|
(1 | ) | (1 | ) | (1 | ) | 5 | 4 | (1 | ) | ||||||||||||||
|
Amortization of net actuarial loss
|
(35 | ) | (43 | ) | (13 | ) | (1 | ) | — | — | ||||||||||||||
|
Other changes in plan assets and benefit obligations recognized
in other comprehensive income (loss)
|
35 | (88 | ) | 551 | 16 | (2 | ) | (2 | ) | |||||||||||||||
|
Total recognized in net periodic benefit expense and other
comprehensive income (loss)
|
$ | 99 | $ | (10 | ) | $ | 569 | $ | 14 | $ | 4 | $ | 10 | |||||||||||
Other changes in plan assets and benefit obligations for our
other postretirement benefit plans associated with our
FERC-regulated gas pipelines are recognized in
net regulatory
assets
at December 31, 2010, and include a
net
actuarial loss
of $10 million,
prior service credit
of $1 million,
amortization of prior service credit
of $9 million, and
amortization of net actuarial
loss
of $2 million. At December 31, 2009, amounts
recognized in
net regulatory assets
included a
net
actuarial gain
of $14 million,
prior service credit
of $11 million,
amortization of prior service credit
of $7 million, and
amortization of net actuarial
loss
of $3 million. At December 31, 2008, amounts
recognized in
net regulatory assets
included a
net
actuarial loss
of $83 million,
prior service credit
of $22 million, and
amortization of prior service
credit
of $1 million.
107
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Pre-tax amounts expected to be amortized in
net periodic
benefit expense
in 2011 are as follows:
|
Other
|
||||||||
|
Pension
|
Postretirement
|
|||||||
| Benefits | Benefits | |||||||
| (Millions) | ||||||||
|
Amounts included in accumulated other comprehensive loss:
|
||||||||
|
Prior service cost (credit)
|
$ | 1 | $ | (4 | ) | |||
|
Net actuarial loss
|
37 | 1 | ||||||
|
Amounts included in net regulatory assets associated with our
FERC- regulated gas pipelines:
|
||||||||
|
Prior service credit
|
N/A | $ | (7 | ) | ||||
|
Net actuarial loss
|
N/A | 3 | ||||||
Key
Assumptions
The weighted-average assumptions utilized to determine benefit
obligations as of December 31 are as follows:
|
Other
|
||||||||||||||||
|
Postretirement
|
||||||||||||||||
| Pension Benefits | Benefits | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
|
Discount rate
|
5.20 | % | 5.78 | % | 5.35 | % | 5.80 | % | ||||||||
|
Rate of compensation increase
|
5.00 | 5.00 | N/A | N/A | ||||||||||||
The weighted-average assumptions utilized to determine
net
periodic benefit expense
for the years ended December 31 are
as follows:
|
Other
|
||||||||||||||||||||||||
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||||||||||||||
|
Discount rate
|
5.78 | % | 6.08 | % | 6.41 | % | 5.80 | % | 6.00 | % | 6.40 | % | ||||||||||||
|
Expected long-term rate of return on plan assets
|
7.50 | 7.75 | 7.75 | 6.51 | 7.00 | 7.00 | ||||||||||||||||||
|
Rate of compensation increase
|
5.00 | 5.00 | 5.00 | N/A | N/A | N/A | ||||||||||||||||||
The discount rates for our pension and other postretirement
benefit plans were determined separately based on an approach
specific to our plans. The year-end discount rates were
determined considering a yield curve comprised of high-quality
corporate bonds published by a large securities firm and the
timing of the expected benefit cash flows of each plan.
The expected long-term rates of return on plan assets were
determined by combining a review of the historical returns
realized within the portfolio, the investment strategy included
in the plans’ Investment Policy Statement, and capital
market projections for the asset classes in which the portfolio
is invested and the target weightings of each asset class.
The expected return on plan assets component of
net periodic
benefit expense
is calculated using the market-related value
of plan assets. For assets held in our pension plans, the
market-related value of plan assets is equal to the fair value
of plan assets adjusted to reflect amortization of gains or
losses associated with the difference between the expected
return on plan assets and the actual return on plan assets over
a five-year period. Additionally, the market-related value of
plan assets may be no more than 110 percent or less than
90 percent of the fair value of plan assets at the
beginning of the year. The market-related value of plan assets
for our other postretirement benefit plans is equal to the
unadjusted fair value of plan assets at the beginning of the
year.
The mortality assumptions used to determine the obligations for
our pension and other postretirement benefit plans are the best
estimate of expected mortality rates for the participants in
these plans. The selected mortality
108
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
tables are among the most recent tables available and mortality
improvements are projected to the measurement date.
The assumed health care cost trend rate for 2011 is
7.0 percent, increases slightly in 2012 and 2013, and then
decreases to 5.0 percent by 2021. The health care cost
trend rate assumption has a significant effect on the amounts
reported. A one-percentage-point change in assumed health care
cost trend rates would have the following effects:
| Point increase | Point decrease | |||||||
| (Millions) | ||||||||
|
Effect on total of service and interest cost components
|
$ | 2 | $ | (2 | ) | |||
|
Effect on other postretirement benefit obligation
|
39 | (32 | ) | |||||
Plan
Assets
The investment policy for our pension and other postretirement
benefit plans provides for an investment strategy in accordance
with ERISA, which governs the investment of the assets in a
diversified portfolio. The plans follow a policy of diversifying
the investments across various asset classes and investment
managers. Additionally, the investment returns on approximately
40 percent of the other postretirement benefit plan assets
are subject to income tax; therefore, certain investments are
managed in a tax efficient manner.
During 2010, the pension plans’ target asset allocation
ranges were adjusted resulting in a slightly larger allocation
to fixed income securities. The updated pension plans’
target asset allocation range at December 31, 2010 was
54 percent to 66 percent equity securities, which
includes commingled investment funds, and 36 percent to
44 percent fixed income securities and cash management
funds. Within equity securities, the target range for
U.S. equity securities is 37 percent to
45 percent and international equity securities is
17 percent to 21 percent. The asset allocation
continues to be weighted toward equity securities since the
obligations of the pension and other postretirement benefit
plans are long-term in nature and historically equity securities
have outperformed other asset classes over long periods of time.
The rebalancing to the higher fixed income securities asset
allocation is expected to occur during 2011.
Equity security investments are restricted to high-quality,
readily marketable securities that are actively traded on the
major U.S. and foreign national exchanges. Investment in
Williams’ securities or an entity in which Williams has a
majority ownership is prohibited in the pension plans except
where these securities may be owned in a commingled investment
fund in which the plans’ trusts invest. No more than
5 percent of the total stock portfolio valued at market may
be invested in the common stock of any one corporation.
The following securities and transactions are not authorized:
unregistered securities, commodities or commodity contracts,
short sales or margin transactions, or other leveraging
strategies. Investment strategies using the direct holding of
options or futures require approval and, historically, have not
been used; however, these instruments may be used in commingled
investment funds. Additionally, real estate equity and natural
resource property investments are generally restricted.
Fixed income securities are restricted to high-quality,
marketable securities that may include, but are not necessarily
limited to, U.S. Treasury securities, U.S. government
guaranteed and nonguaranteed mortgage-backed securities,
government and municipal bonds, and investment grade corporate
securities. The overall rating of the fixed income security
assets is generally required to be at least “A,”
according to the Moody’s or Standard &
Poor’s rating systems. No more than 5 percent of the
total portfolio may be invested in the fixed income securities
of any one issuer with the exception of bond index funds and
U.S. government guaranteed and agency securities.
During 2010, nine active investment managers and one passive
investment manager managed substantially all of the pension
plans’ funds and five active investment managers managed
the other postretirement benefit plans’ funds. Each of the
managers had responsibility for managing a specific portion of
these assets and each investment manager was responsible for
2 percent to 17 percent of the assets.
109
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The pension and other postretirement benefit plans’ assets
are held primarily in equity securities, including commingled
investment funds invested in equity securities, and fixed income
securities. Within the plans’ investment securities, there
are no significant concentrations of risk because of the
diversity of the types of investments, diversity of the various
industries, and the diversity of the fund managers and
investment strategies. Generally, the investments held in the
plans are publicly traded, therefore, minimizing liquidity risk
in the portfolio.
The pension and other postretirement benefit plans participate
in securities lending programs under which securities are loaned
to selected securities brokerage firms. The title of the
securities is transferred to the borrower, but the plans are
entitled to all distributions made by the issuer of the
securities during the term of the loan and retain the right to
redeem the securities on short notice. All loans require
collateralization by U.S. government securities, cash, or
letters of credit that equal at least 102 percent of the
fair value of the loaned securities plus accrued interest. There
are limitations on the aggregate fair value of securities that
may be loaned to any one broker and to all brokers as a group.
The collateral is invested in repurchase agreements,
asset-backed securities, bank notes, corporate floating rate
notes, and certificates of deposit. At December 31, 2010,
the fair values of the loaned securities are $116 million
for the pension plans and $17 million for the other
postretirement benefit plans and are included in the following
tables. At December 31, 2010, the fair values of securities
held as collateral, and the obligation to return the collateral,
are $120 million for the pension plans and $17 million
for the other postretirement benefit plans and are not included
in the following tables. At December 31, 2009, the fair
values of the loaned securities are $63 million for the
pension plans and $9 million for the other postretirement
benefit plans and are included in the following tables. At
December 31, 2009, the fair values of securities held as
collateral, and the obligation to return the collateral, are
$66 million for the pension plans and $9 million for
the other postretirement benefit plans and are not included in
the following tables. The pension and other postretirement
benefit plans are exiting the securities lending programs under
a plan designed to be orderly and minimize potential losses. The
exit from the securities lending programs is expected to be
completed during 2011 and no significant losses are expected to
be realized.
The fair values (see Note 14) of our pension plan
assets at December 31, 2010 and 2009, by asset class are as
follows:
| 2010 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Millions) | ||||||||||||||||
|
Pension assets:
|
||||||||||||||||
|
Cash management fund(1)
|
$ | 30 | $ | — | $ | — | $ | 30 | ||||||||
|
Equity securities:
|
||||||||||||||||
|
U.S. large cap
|
192 | — | — | 192 | ||||||||||||
|
U.S. small cap
|
137 | — | — | 137 | ||||||||||||
|
International developed markets large cap growth
|
4 | 68 | — | 72 | ||||||||||||
|
Emerging markets growth
|
4 | 12 | — | 16 | ||||||||||||
|
Commingled investment funds:
|
||||||||||||||||
|
U.S. large cap(2)
|
— | 168 | — | 168 | ||||||||||||
|
Emerging markets value(3)
|
— | 35 | — | 35 | ||||||||||||
|
International developed markets large cap value(4)
|
— | 80 | — | 80 | ||||||||||||
|
Fixed income securities(5):
|
||||||||||||||||
|
U.S. Treasury securities
|
17 | 3 | — | 20 | ||||||||||||
|
Mortgage-backed securities
|
— | 64 | — | 64 | ||||||||||||
|
Corporate bonds
|
— | 150 | — | 150 | ||||||||||||
|
Insurance company investment contracts and other
|
— | 7 | — | 7 | ||||||||||||
|
Total assets at fair value at December 31, 2010
|
$ | 384 | $ | 587 | $ | — | $ | 971 | ||||||||
110
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 2009 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Millions) | ||||||||||||||||
|
Pension assets:
|
||||||||||||||||
|
Cash management fund(1)
|
$ | 23 | $ | — | $ | — | $ | 23 | ||||||||
|
Equity securities:
|
||||||||||||||||
|
U.S. large cap
|
244 | — | — | 244 | ||||||||||||
|
U.S. small cap
|
103 | — | — | 103 | ||||||||||||
|
International developed markets large cap growth
|
2 | 58 | — | 60 | ||||||||||||
|
Emerging markets growth
|
10 | 9 | — | 19 | ||||||||||||
|
Commingled investment funds:
|
||||||||||||||||
|
U.S. large cap(2)
|
— | 84 | — | 84 | ||||||||||||
|
Emerging markets value(3)
|
— | 29 | — | 29 | ||||||||||||
|
International developed markets large cap value(4)
|
— | 74 | — | 74 | ||||||||||||
|
Fixed income securities(5):
|
||||||||||||||||
|
U.S. Treasury securities
|
11 | 3 | — | 14 | ||||||||||||
|
Mortgage-backed securities
|
— | 53 | — | 53 | ||||||||||||
|
Corporate bonds
|
— | 149 | — | 149 | ||||||||||||
|
Insurance company investment contracts and other
|
— | 8 | — | 8 | ||||||||||||
|
Total assets at fair value at December 31, 2009
|
$ | 393 | $ | 467 | $ | — | $ | 860 | ||||||||
The fair values of our other postretirement benefits plan assets
at December 31, 2010 and 2009, by asset class are as
follows:
| 2010 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Millions) | ||||||||||||||||
|
Other postretirement benefit assets:
|
||||||||||||||||
|
Cash management funds(1)
|
$ | 15 | $ | — | $ | — | $ | 15 | ||||||||
|
Equity securities:
|
||||||||||||||||
|
U.S. large cap
|
44 | — | — | 44 | ||||||||||||
|
U.S. small cap
|
24 | — | — | 24 | ||||||||||||
|
International developed markets large cap growth
|
1 | 14 | — | 15 | ||||||||||||
|
Emerging markets growth
|
1 | 2 | — | 3 | ||||||||||||
|
Commingled investment funds:
|
||||||||||||||||
|
U.S. large cap(2)
|
— | 17 | — | 17 | ||||||||||||
|
Emerging markets value(3)
|
— | 3 | — | 3 | ||||||||||||
|
International developed markets large cap value(4)
|
— | 8 | — | 8 | ||||||||||||
|
Fixed income securities(6):
|
||||||||||||||||
|
U.S. Treasury securities
|
2 | — | — | 2 | ||||||||||||
|
Government and municipal bonds
|
— | 10 | — | 10 | ||||||||||||
|
Mortgage-backed securities
|
— | 6 | — | 6 | ||||||||||||
|
Corporate bonds
|
— | 15 | — | 15 | ||||||||||||
|
Total assets at fair value at December 31, 2010
|
$ | 87 | $ | 75 | $ | — | $ | 162 | ||||||||
111
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 2009 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Millions) | ||||||||||||||||
|
Other postretirement benefit assets:
|
||||||||||||||||
|
Cash management funds(1)
|
$ | 15 | $ | — | $ | — | $ | 15 | ||||||||
|
Equity securities:
|
||||||||||||||||
|
U.S. large cap
|
49 | — | — | 49 | ||||||||||||
|
U.S. small cap
|
19 | — | — | 19 | ||||||||||||
|
International developed markets large cap growth
|
— | 13 | — | 13 | ||||||||||||
|
Emerging markets growth
|
2 | 2 | — | 4 | ||||||||||||
|
Commingled investment funds:
|
||||||||||||||||
|
U.S. large cap(2)
|
— | 8 | — | 8 | ||||||||||||
|
Emerging markets value(3)
|
— | 3 | — | 3 | ||||||||||||
|
International developed markets large cap value(4)
|
— | 7 | — | 7 | ||||||||||||
|
Fixed income securities(6):
|
||||||||||||||||
|
U.S. Treasury securities
|
1 | — | — | 1 | ||||||||||||
|
Government and municipal bonds
|
— | 8 | — | 8 | ||||||||||||
|
Mortgage-backed securities
|
— | 6 | — | 6 | ||||||||||||
|
Corporate bonds
|
— | 15 | — | 15 | ||||||||||||
|
Total assets at fair value at December 31, 2009
|
$ | 86 | $ | 62 | $ | — | $ | 148 | ||||||||
| (1) | These funds invest in high credit-quality, short-term corporate, and government money market debt securities that have remaining maturities of approximately one year or less, and are deemed to have minimal credit risk. | |
| (2) | This fund invests primarily in equity securities comprising the Standard & Poor’s 500 Index. The investment objective of the fund is to match the return of the Standard & Poor’s 500 Index. During 2009, certain restrictions were put into place that limited the amount that could be withdrawn. As of December 31, 2009, 37 percent was eligible for withdrawal. Effective August 2010, the withdrawal restrictions were terminated by the fund. The fund manager retains the right to restrict withdrawals from the fund as not to disadvantage other investors in the fund. | |
| (3) | This fund invests in equity securities of international emerging markets for the purpose of capital appreciation. The fund invests primarily in common stocks of the financial, telecommunications, information technology, consumer goods, energy, industrial, materials, and utilities sectors, as well as forward foreign currency exchange contracts. The plans’ trustee is required to notify the fund manager ten days prior to a withdrawal from the fund. The fund manager retains the right to restrict withdrawals from the fund as not to disadvantage other investors in the fund. | |
| (4) | This fund invests in a diversified portfolio of international equity securities for the purpose of capital appreciation. The fund invests primarily in common stocks in the consumer goods, materials, financial, energy, information technology, telecommunications, industrial, utilities, and health care sectors, as well as forward foreign currency exchange contracts. The plans’ trustee is required to notify the fund manager ten days prior to a withdrawal from the fund. The fund manager retains the right to restrict withdrawals from the fund as not to disadvantage other investors in the fund. | |
| (5) | The weighted-average credit quality rating of the pension assets’ fixed income security portfolio is investment grade with a weighted-average duration of 5.6 years for 2010 and 5.1 years for 2009. | |
| (6) | The weighted-average credit quality rating of the other postretirement benefit assets’ fixed income security portfolio is investment grade with a weighted-average duration of 4.8 years for 2010 and 4.5 years for 2009. |
112
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The asset’s fair value measurement level within the fair
value hierarchy is based on the lowest level of any input that
is significant to the fair value measurement.
Shares of the cash management funds are valued at fair value
based on published market prices as of the close of business on
the last business day of the year, which represents the net
asset values of the shares held.
The fair values of equity securities traded on
U.S. exchanges are derived from quoted market prices as of
the close of business on the last business day of the year. The
fair values of equity securities traded on foreign exchanges are
also derived from quoted market prices as of the close of
business on an active foreign exchange on the last business day
of the year. However, the valuation requires translation of the
foreign currency to U.S. dollars and this translation is
considered an observable input to the valuation.
The fair value of all commingled investment funds has been
estimated based on the net asset values per unit of each of the
funds. The net asset values per unit of the fund represent the
aggregate value of the fund’s assets less liabilities,
divided by the number of units outstanding. Common stocks traded
in active markets comprise the majority of each commingled
investment fund’s assets. The fair value of these common
stocks is derived from quoted market prices as of the close of
business on the last business day of the year.
The fair value of fixed income securities, except
U.S. Treasury notes and bonds, are determined using pricing
models. These pricing models incorporate observable inputs such
as benchmark yields, reported trades, broker/dealer quotes, and
issuer spreads for similar securities to determine fair value.
The U.S. Treasury notes and bonds are valued at fair value
based on closing prices on the last business day of the year
reported in the active market in which the security is traded.
The investment contracts with insurance companies are valued at
fair value by discounting the cash flow of a bond using a yield
to maturity based on an investment grade index or comparable
index with a similar maturity value, maturity period, and
nominal coupon rate.
Plan
Benefit Payments and Employer Contributions
Following are the expected benefits to be paid by the plans and
the expected federal prescription drug subsidy to be received in
the next ten years. These estimates are based on the same
assumptions previously discussed and reflect future service as
appropriate. The actuarial assumptions are based on long-term
expectations and include, but are not limited to, assumptions as
to average expected retirement age and form of benefit payment.
Actual benefit payments could differ significantly from expected
benefit payments if near-term participant behaviors differ
significantly from the actuarial assumptions.
|
Federal
|
||||||||||||
|
Other
|
Prescription
|
|||||||||||
|
Pension
|
Postretirement
|
Drug
|
||||||||||
| Benefits | Benefits | Subsidy | ||||||||||
| (Millions) | ||||||||||||
|
2011
|
$ | 51 | $ | 18 | $ | (2 | ) | |||||
|
2012
|
51 | 18 | (3 | ) | ||||||||
|
2013
|
54 | 18 | (3 | ) | ||||||||
|
2014
|
68 | 18 | (3 | ) | ||||||||
|
2015
|
75 | 19 | (3 | ) | ||||||||
|
2016-2020
|
536 | 107 | (20 | ) | ||||||||
In 2011, we expect to contribute approximately $60 million
to our tax-qualified pension plans and approximately
$7 million to our nonqualified pension plans, for a total
of approximately $67 million, and approximately
$16 million to our other postretirement benefit plans.
113
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Defined
Contribution Plans
We also maintain defined contribution plans for the benefit of
substantially all of our employees. Generally, plan participants
may contribute a portion of their compensation on a pre-tax and
after-tax basis in accordance with the plans’ guidelines.
We match employees’ contributions up to certain limits. Our
matching contributions charged to expense were $26 million
in 2010, $25 million in 2009, and $24 million in 2008.
Certain accounts within one of our defined contribution plans
have a nonleveraged employee stock ownership plan (ESOP)
component. The shares held by the ESOP are treated as
outstanding when computing earnings per share and the dividends
on the shares held by the ESOP are recorded as a component of
retained earnings. There were no contributions in 2010, 2009,
and 2008 to this ESOP, other than dividend reinvestment, as
contributions for purchase of our stock are no longer allowed
within this defined contribution plan.
| Note 8. | Inventories |
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Natural gas liquids and olefins
|
$ | 87 | $ | 70 | ||||
|
Natural gas in underground storage
|
93 | 47 | ||||||
|
Materials, supplies, and other
|
123 | 105 | ||||||
| $ | 303 | $ | 222 | |||||
| Note 9. | Property, Plant, and Equipment |
|
Estimated
|
Depreciation
|
|||||||||||
|
Useful Life (a)
|
Rates (a)
|
December 31, | ||||||||||
| (Years) | (%) | 2010 | 2009 | |||||||||
| (Millions) | ||||||||||||
|
Nonregulated:
|
||||||||||||
|
Oil and gas properties
|
(b) | $ | 11,741 | $ | 9,854 | |||||||
|
Natural gas gathering and processing facilities
|
5 - 40 | 6,224 | 5,461 | |||||||||
|
Construction in progress
|
(c) | 865 | 1,227 | |||||||||
|
Other
|
3 - 45 | 940 | 816 | |||||||||
|
Regulated:
|
||||||||||||
|
Natural gas transmission facilities
|
.01 - 7.25 | 9,066 | 8,814 | |||||||||
|
Construction in progress
|
(c) | 240 | 152 | |||||||||
|
Other
|
.01 - 33.33 | 1,359 | 1,301 | |||||||||
|
Total property, plant, and equipment, at cost
|
30,435 | 27,625 | ||||||||||
|
Accumulated depreciation, depletion & amortization
|
(10,163 | ) | (8,981 | ) | ||||||||
|
Property, plant, and equipment — net
|
$ | 20,272 | $ | 18,644 | ||||||||
| (a) | Estimated useful life and depreciation rates are presented as of December 31, 2010. Depreciation rates for regulated assets are prescribed by the FERC. | |
| (b) | Oil and gas properties are depleted using the units-of-production method (see Note 1). Balances include $1.9 billion at December 31, 2010, and $864 million at December 31, 2009, of capitalized costs related to properties with unproved reserves or leasehold not yet subject to depletion at Exploration & Production. | |
| (c) | Construction in progress balances not yet subject to depreciation and depletion. |
114
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
On December 21, 2010, we completed the acquisition of
100 percent of the equity of Dakota-3 E&P Company LLC
for $949 million, including closing adjustments. This
company holds approximately 85,800 net acres on the
Fort Berthold Indian Reservation in the Williston basin of
North Dakota. Approximately 85 percent of this acreage is
undeveloped. This acquisition establishes us in the Bakken Shale
oil play and further diversifies our commodity profile.
Substantially all of the purchase price was recorded as oil and
gas properties within property, plant and equipment by
Exploration & Production. Revenues and earnings for
the acquired company are insignificant for the three years ended
December 31, 2010, 2009 and 2008.
Depreciation, depletion and amortization
expense for
property, plant, and equipment — net
was
$1.5 billion in 2010, $1.5 billion in 2009, and
$1.3 billion in 2008. Oil and gas accounting guidance
requires we value our reserves using an average price. This
price is calculated using prices at the beginning of the month
for the preceding 12 months. This accounting guidance was
adopted on a prospective basis in fourth quarter 2009.
Adjustments resulting from the implementation of this guidance
have not had a material impact on our financial statements.
Regulated
property, plant, and equipment — net
includes $906 million and $946 million at
December 31, 2010 and 2009, respectively, related to
amounts in excess of the original cost of the regulated
facilities within our gas pipeline businesses as a result of our
prior acquisitions. This amount is being amortized over
40 years using the straight-line amortization method.
Current FERC policy does not permit recovery through rates for
amounts in excess of original cost of construction.
Asset
Retirement Obligations
Our accrued obligations relate to producing wells, underground
storage caverns, offshore platforms, fractionation facilities,
gas gathering well connections and pipelines, and gas
transmission facilities. At the end of the useful life of each
respective asset, we are legally obligated to plug both
producing wells and storage caverns and remove any related
surface equipment, to restore land and remove surface equipment
at fractionation facilities, to dismantle offshore platforms, to
cap certain gathering pipelines at the wellhead connection and
remove any related surface equipment, and to remove certain
components of gas transmission facilities from the ground.
The following table presents the significant changes to our
AROs, of which $750 million and $716 million are
included in
other liabilities and deferred income
, with
the remaining current portion in
accrued liabilities
at
December 31, 2010 and 2009, respectively.
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Beginning balance
|
$ | 728 | $ | 644 | ||||
|
Liabilities settled
|
(18 | ) | (13 | ) | ||||
|
Additions
|
39 | 32 | ||||||
|
Accretion expense
|
56 | 51 | ||||||
|
Revisions(1)
|
(16 | ) | 14 | |||||
|
Ending balance
|
$ | 789 | $ | 728 | ||||
| (1) | Change in revisions primarily due to the annual review process which considers various factors including inflation rates, current estimates for removal cost, discount rates and the estimated remaining life of the assets. The net downward revision in 2010 includes an offsetting increase of $31 million related to changes in the timing and method of abandonment on certain of Transco’s natural gas storage caverns that were associated with a recent leak. |
115
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Pursuant to its 2008 rate case settlement, Transco deposits a
portion of its collected rates into an external trust (ARO
Trust) that is specifically designated to fund future AROs.
Transco is also required to make annual deposits into the trust
through 2012. (See Note 15).
Property
Insurance
The current availability of named windstorm insurance has been
significantly reduced from historical levels. Additionally,
named windstorm insurance coverage that is available for
offshore assets comes at significantly higher premium amounts,
higher deductibles and lower coverage limits. Our existing
coverage for physical damage to facilities, especially damage to
offshore facilities by named windstorms, is limited to
$75 million for each occurrence and on an annual aggregate
basis in the event of material loss.
| Note 10. | Accounts Payable and Accrued Liabilities |
Under our cash-management system, certain cash accounts
reflected negative balances to the extent checks written have
not been presented for payment. These negative balances
represent obligations and have been reclassified to
accounts
payable. Accounts payable
includes $58 million of these
negative balances at December 31, 2010 and $44 million
at December 31, 2009.
Accrued
Liabilities
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Income taxes
|
$ | 275 | $ | 112 | ||||
|
Interest on debt
|
162 | 199 | ||||||
|
Employee costs
|
146 | 158 | ||||||
|
Taxes other than income taxes
|
110 | 176 | ||||||
|
Other, including other loss contingencies
|
309 | 303 | ||||||
| $ | 1,002 | $ | 948 | |||||
| Note 11. | Debt, Leases, and Banking Arrangements |
Long-Term
Debt
|
Weighted-
|
||||||||||||
|
Average
|
||||||||||||
|
Interest
|
December 31, | |||||||||||
| Rate(1) | 2010(2) | 2009(2) | ||||||||||
| (Millions) | ||||||||||||
|
Secured
|
||||||||||||
|
Capital lease obligations
|
12.0 | % | $ | 4 | $ | 3 | ||||||
|
Unsecured
|
||||||||||||
|
3.8% to 10.25%, payable through 2040
|
6.4 | % | 9,104 | 8,023 | ||||||||
|
Adjustable rate
|
— | 250 | ||||||||||
|
Total long-term debt, including current portion
|
9,108 | 8,276 | ||||||||||
|
Long-term debt due within one year
|
(508 | ) | (17 | ) | ||||||||
|
Long-term debt
|
$ | 8,600 | $ | 8,259 | ||||||||
| (1) | At December 31, 2010. |
116
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (2) | Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, and incur additional debt. Default of these agreements could also restrict our ability to make certain distributions or repurchase equity. |
Credit
Facilities
In conjunction with our restructuring in the first quarter of
2010, we reduced our $1.5 billion unsecured revolving
credit facility that expires May 2012 to $900 million and
removed Transco and Northwest Pipeline as borrowers. Interest is
calculated based on a choice of two methods: a fluctuating rate
equal to the lender’s base rate plus an applicable margin,
or a periodic fixed rate equal to LIBOR plus an applicable
margin. We are required to pay a commitment fee (currently
0.125 percent) based on the unused portion of the credit
facility. The margins and commitment fee are generally based on
our senior unsecured long-term debt ratings. Significant
financial covenants under the credit agreement include the
following:
| • | Our consolidated ratio of debt to capitalization must be no greater than 65 percent. At December 31, 2010, we are in compliance with this covenant. |
In October 2010, unsecured credit facilities totaling
$700 million expired and were not renewed. These facilities
were originated primarily in support of our former power
business.
As part of our strategic restructuring, WPZ entered into a new
$1.75 billion three-year senior unsecured revolving credit
facility with Transco and Northwest Pipeline as co-borrowers.
This credit facility replaced an unsecured $450 million
credit facility, comprised of a $200 million revolving
credit facility and a $250 million term loan which was
terminated as part of the restructuring. At the closing, WPZ
utilized $250 million of the credit facility to repay the
outstanding term loan. During 2010, WPZ had a maximum of
$430 million outstanding under this credit facility, which
was primarily used to purchase an additional ownership interest
in Overland Pass Pipeline Company LLC (OPPL). At
December 31, 2010, the outstanding balance under the credit
facility was reduced to zero.
The credit facility may, under certain conditions, be increased
by up to an additional $250 million. The full amount of the
credit facility is available to WPZ to the extent not otherwise
utilized by Transco and Northwest Pipeline. Transco and
Northwest Pipeline each have access to borrow up to
$400 million under the credit facility to the extent not
otherwise utilized by other co-borrowers. Each time funds are
borrowed, the borrower may choose from two methods of
calculating interest: a fluctuating base rate equal to Citibank
N.A’s adjusted base rate plus an applicable margin, or a
periodic fixed rate equal to LIBOR plus an applicable margin.
WPZ is required to pay a commitment fee (currently
0.5 percent) based on the unused portion of the credit
facility. The applicable margin and the commitment fee are based
on the specific borrower’s senior unsecured long-term debt
ratings. The credit facility contains various covenants that
limit, among other things, a borrower’s 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. Significant financial covenants under the credit
facility include:
| • | WPZ ratio of debt to EBITDA (each as defined in the credit facility, with EBITDA measured on a rolling four-quarter basis) must be no greater than 5 to 1. | |
| • | The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 55 percent for Transco and Northwest Pipeline. |
Each of the above ratios are tested at the end of each fiscal
quarter (with the first full year measured on an annualized
basis). At December 31, 2010, we are in compliance with
these financial covenants.
The credit facility includes customary events of default. If an
event of default with respect to a borrower occurs under the
credit facility, the lenders will be able to terminate the
commitments for all borrowers and accelerate the maturity of any
loans of the defaulting borrower under the credit facility and
exercise other rights and remedies.
117
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
At December 31, 2010, no loans are outstanding under our
credit facilities. Letters of credit issued under our credit
facilities are:
|
Letters of Credit at
|
||||||
| Expiration | December 31, 2010 | |||||
| (Millions) | ||||||
|
$900 million unsecured credit facility
|
May 1, 2012 | $ | — | |||
|
$1.75 billion Williams Partners L.P. unsecured credit
facility
|
February 17, 2013 | — | ||||
|
Bilateral bank agreements
|
90 | |||||
| $ | 90 | |||||
Exploration &
Production’s Credit Agreement
Exploration & Production has an unsecured credit
agreement with certain banks in order to reduce margin
requirements related to our hedging activities as well as lower
transaction fees. In July 2010, the term of this facility
expiring in December 2013 was extended to December 2015. Under
the credit agreement, Exploration & Production is not
required to post collateral as long as the value of its domestic
natural gas reserves, as determined under the provisions of the
agreement, exceeds by a specified amount certain of its
obligations including any outstanding debt and the aggregate
out-of-the-money
positions on hedges entered into under the credit agreement.
Exploration & Production is subject to additional
covenants under the credit agreement including restrictions on
hedge limits, the creation of liens, the incurrence of debt, the
sale of assets and properties, and making certain payments
during an event of default, such as dividends. In December 2010,
a waiver with the same terms and restrictions as the original
agreement, was executed that will allow us to also hedge up to a
certain volume of oil.
Issuances
and Retirements
In connection with the restructuring, WPZ issued
$3.5 billion face value of senior unsecured notes as
follows:
| (Millions) | ||||
|
3.80% Senior Notes due 2015
|
$ | 750 | ||
|
5.25% Senior Notes due 2020
|
1,500 | |||
|
6.30% Senior Notes due 2040
|
1,250 | |||
|
Total
|
$ | 3,500 | ||
As part of the issuance of the $3.5 billion unsecured
notes, WPZ entered into registration rights agreements with the
initial purchasers of the notes. An offer to exchange these
unregistered notes for substantially identical new notes that
are registered under the Securities Act of 1933, as amended, was
commenced in June 2010 and completed in July 2010.
118
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
With the debt proceeds discussed above, we retired
$3 billion of debt and paid $574 million in related
premiums. The $3 billion of aggregate principal corporate
debt retired includes:
| (Millions) | ||||
|
7.125% Notes due 2011
|
$ | 429 | ||
|
8.125% Notes due 2012
|
602 | |||
|
7.625% Notes due 2019
|
668 | |||
|
8.75% Senior Notes due 2020
|
586 | |||
|
7.875% Notes due 2021
|
179 | |||
|
7.70% Debentures due 2027
|
98 | |||
|
7.50% Debentures due 2031
|
163 | |||
|
7.75% Notes due 2031
|
111 | |||
|
8.75% Notes due 2032
|
164 | |||
|
Total
|
$ | 3,000 | ||
On November 9, 2010, WPZ completed a public offering of
$600 million of 4.125 percent senior notes due 2020.
WPZ used the net proceeds to fund part of its acquisition from
Exploration & Production of certain gathering and
processing assets in the Piceance basin. (See Note 1.)
Aggregate minimum maturities of
long-term debt
(excluding
capital leases and unamortized discount and premium) for each of
the next five years are as follows:
| (Millions) | ||||
|
2011
|
$ | 507 | ||
|
2012
|
352 | |||
|
2013
|
— | |||
|
2014
|
— | |||
|
2015
|
750 | |||
Cash payments for interest (net of amounts capitalized),
including amounts related to discontinued operations, were as
follows: 2010 — $614 million; 2009 —
$592 million; and 2008 — $592 million.
Leases-Lessee
Future minimum annual rentals under noncancelable operating
leases as of December 31, 2010, are payable as follows:
| (Millions) | ||||
|
2011
|
$ | 55 | ||
|
2012
|
44 | |||
|
2013
|
40 | |||
|
2014
|
32 | |||
|
2015
|
27 | |||
|
Thereafter
|
181 | |||
|
Total
|
$ | 379 | ||
Total rent expense was $61 million in 2010,
$70 million in 2009, and $87 million in 2008.
119
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 12. | Stockholders’ Equity |
Cash dividends declared per our common share were $.485, $.44
and $.43 for 2010, 2009, and 2008, respectively.
In July 2007, our Board of Directors authorized the repurchase
of up to $1 billion of our common stock. During 2007, we
purchased 16 million shares for $526 million
(including transaction costs) at an average cost of $33.08 per
share. During 2008, we purchased 13 million shares of our
common stock for $474 million (including transaction costs)
at an average cost of $36.76 per share. We completed our
$1 billion stock repurchase program in July 2008. Our
overall average cost per share was $34.74. This stock repurchase
is recorded in
treasury stock
on our Consolidated Balance
Sheet.
At December 31, 2010, approximately $22 million of our
original $300 million, 5.5 percent junior subordinated
convertible debentures, convertible into approximately two
million shares of common stock, remain outstanding. In 2009 and
2008, we converted $28 million and $27 million,
respectively, of the debentures in exchange for three million
and two million shares, respectively, of common stock.
At December 31, 2007, we held all of WPZ’s seven
million subordinated units outstanding. In February 2008, these
subordinated units were converted into common units of WPZ due
to the achievement of certain financial targets that resulted in
the early termination of the subordination period. While these
subordinated units were outstanding, other issuances of
partnership units by WPZ had preferential rights and the
proceeds from these issuances in excess of the book basis of
assets acquired by WPZ were therefore reflected as
noncontrolling interests in consolidated subsidiaries
on
our Consolidated Balance Sheet. Due to the conversion of the
subordinated units, these original issuances of partnership
units no longer have preferential rights and now represent the
lowest level of equity securities issued by WPZ. In accordance
with our policy in effect at that time regarding the issuance of
equity of a consolidated subsidiary, such issuances of
nonpreferential equity are accounted for as capital transactions
and no gain or loss is recognized. Therefore, as a result of the
2008 conversion, we recognized a decrease to
noncontrolling
interests in consolidated subsidiaries
and a corresponding
increase to
capital in excess of par value
of
approximately $1.2 billion.
We maintain a Stockholder Rights Plan, as amended and restated
on September 21, 2004, and further amended May 18,
2007, and October 12, 2007, under which each outstanding
share of our common stock has a right (as defined in the plan)
attached. Under certain conditions, each right may be exercised
to purchase, at an exercise price of $50 (subject to
adjustment), one two-hundredth of a share of Series A
Junior Participating Preferred Stock. The rights may be
exercised only if an Acquiring Person acquires (or obtains the
right to acquire) 15 percent or more of our common stock or
commences an offer for 15 percent or more of our common
stock. The plan contains a mechanism to divest of shares of
common stock if such stock in excess of 14.9 percent was
acquired inadvertently or without knowledge of the terms of the
rights. The rights, which until exercised do not have voting
rights, expire in 2014 and may be redeemed at a price of $.01
per right prior to their expiration, or within a specified
period of time after the occurrence of certain events. In the
event a person becomes the owner of more than 15 percent of
our common stock, each holder of a right (except an Acquiring
Person) shall have the right to receive, upon exercise, our
common stock having a value equal to two times the exercise
price of the right. In the event we are engaged in a merger,
business combination, or 50 percent or more of our assets,
cash flow or earnings power is sold or transferred, each holder
of a right (except an Acquiring Person) shall have the right to
receive, upon exercise, common stock of the acquiring company
having a value equal to two times the exercise price of the
right.
| Note 13. | Stock-Based Compensation |
Plan
Information
On May 17, 2007, our stockholders approved a plan that
provides common-stock-based awards to both employees and
nonmanagement directors and reserved 19 million new shares
for issuance. On May 20, 2010, our stockholders approved an
amendment and restatement of the 2007 plan to increase by
11 million the number of new
120
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
shares authorized for making awards under the plan, among other
changes. The plan permits the granting of various types of
awards including, but not limited to, restricted stock units and
stock options. At December 31, 2010, 39 million shares
of our common stock were reserved for issuance pursuant to
existing and future stock awards, of which 19 million
shares were available for future grants. At December 31,
2009, 30 million shares of our common stock were reserved
for issuance pursuant to existing and future stock awards, of
which 11 million shares were available for future grants.
Additionally, on May 17, 2007, our stockholders approved an
Employee Stock Purchase Plan (ESPP) which authorizes up to
2 million new shares of our common stock to be available
for sale under the plan. The ESPP enables eligible participants
to purchase our common stock through payroll deductions not
exceeding an annual amount of $15,000 per participant. The ESPP
provides for offering periods during which shares may be
purchased and continues until the earliest of: (1) the
Board of Directors terminates the ESPP, (2) the sale of all
shares available under the ESPP, or (3) the tenth
anniversary of the date the Plan was approved by the
stockholders. The first offering under the ESPP commenced on
October 1, 2007 and ended on December 31, 2007.
Subsequent offering periods are from January through June and
from July through December. Generally, all employees are
eligible to participate in the ESPP, with the exception of
executives and international employees. The number of shares
eligible for an employee to purchase during each offering period
is limited to 750 shares. The purchase price of the stock
is 85 percent of the lower closing price of either the
first or the last day of the offering period. The ESPP requires
a one-year holding period before the stock can be sold.
Employees purchased 301 thousand shares at an average price of
$15.36 per share during 2010. Approximately 1.0 million and
1.3 million shares were available for purchase under the
ESPP at December 31, 2010 and 2009, respectively.
Total stock-based compensation expense for the years ended
December 31, 2010, 2009 and 2008 was $48 million,
$43 million, and $31 million, respectively. Measured
but unrecognized stock-based compensation expense at
December 31, 2010, was $46 million, which does not
include the effect of estimated forfeitures of $2 million.
This amount is comprised of $5 million related to stock
options and $41 million related to restricted stock units.
These amounts are expected to be recognized over a
weighted-average period of 1.8 years.
Stock
Options
The following summary reflects stock option activity and related
information for the year ended December 31, 2010.
|
Weighted-
|
||||||||||||
|
Average
|
Aggregate
|
|||||||||||
|
Exercise
|
Intrinsic
|
|||||||||||
| Stock Options | Options | Price | Value | |||||||||
| (Millions) | (Millions) | |||||||||||
|
Outstanding at December 31, 2009
|
13.0 | $ | 16.73 | |||||||||
|
Granted
|
1.3 | $ | 21.20 | |||||||||
|
Exercised
|
(1.2 | ) | $ | 6.11 | $ | 20 | ||||||
|
Expired
|
(0.3 | ) | $ | 40.89 | ||||||||
|
Forfeited
|
(0.1 | ) | $ | 17.71 | ||||||||
|
Outstanding at December 31, 2010
|
12.7 | $ | 17.59 | $ | 109 | |||||||
|
Exercisable at December 31, 2010
|
9.8 | $ | 17.44 | $ | 86 | |||||||
The total intrinsic value of options exercised during the years
ended December 31, 2010, 2009, and 2008 was
$20 million, $2 million, and $49 million,
respectively; and the tax benefit realized was $7 million,
$1 million, and $17 million, respectively. Cash
received from stock option exercises was $7 million,
$2 million, and $32 million during 2010, 2009, and
2008, respectively.
121
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following summary provides additional information about
stock options that are outstanding and exercisable at
December 31, 2010.
| Stock Options Outstanding | Stock Options Exercisable | |||||||||||||||||||||||
|
Weighted-
|
Weighted-
|
|||||||||||||||||||||||
|
Weighted-
|
Average
|
Weighted-
|
Average
|
|||||||||||||||||||||
|
Average
|
Remaining
|
Average
|
Remaining
|
|||||||||||||||||||||
|
Exercise
|
Contractual
|
Exercise
|
Contractual
|
|||||||||||||||||||||
| Range of Exercise Prices | Options | Price | Life | Options | Price | Life | ||||||||||||||||||
| (Millions) | (Years) | (Millions) | (Years) | |||||||||||||||||||||
|
$2.27 to $11.82
|
5.4 | $ | 8.85 | 4.6 | 4.0 | $ | 8.18 | 3.4 | ||||||||||||||||
|
$11.83 to 21.38
|
4.0 | $ | 19.53 | 5.4 | 2.8 | $ | 18.75 | 3.6 | ||||||||||||||||
|
$21.39 to $30.94
|
2.0 | $ | 25.14 | 5.3 | 2.0 | $ | 25.14 | 5.3 | ||||||||||||||||
|
$30.95 to $40.51
|
1.3 | $ | 36.17 | 5.3 | 1.0 | $ | 36.06 | 4.7 | ||||||||||||||||
|
Total
|
12.7 | $ | 17.59 | 5.0 | 9.8 | $ | 17.44 | 4.0 | ||||||||||||||||
The estimated fair value at date of grant of options for our
common stock granted in each respective year, using the
Black-Scholes option pricing model, is as follows:
| 2010 | 2009 | 2008 | ||||||||||
|
Weighted-average grant date fair value of options for our common
stock granted during the year
|
$ | 7.02 | $ | 5.60 | $ | 12.83 | ||||||
|
Weighted-average assumptions:
|
||||||||||||
|
Dividend yield
|
2.6 | % | 1.6 | % | 1.2 | % | ||||||
|
Volatility
|
39.0 | % | 60.8 | % | 33.4 | % | ||||||
|
Risk-free interest rate
|
3.0 | % | 2.3 | % | 3.5 | % | ||||||
|
Expected life (years)
|
6.5 | 6.5 | 6.5 | |||||||||
The expected dividend yield is based on the average annual
dividend yield as of the grant date. Expected volatility is
based on the historical volatility of our stock and the implied
volatility of our stock based on traded options. In calculating
historical volatility, returns during calendar year 2002 were
excluded as the extreme volatility during that time is not
reasonably expected to be repeated in the future. The risk-free
interest rate is based on the U.S. Treasury Constant
Maturity rates as of the grant date. The expected life of the
option is based on historical exercise behavior and expected
future experience.
Nonvested
Restricted Stock Units
The following summary reflects nonvested restricted stock unit
activity and related information for the year ended
December 31, 2010.
|
Weighted-
|
||||||||
|
Average
|
||||||||
| Restricted Stock Units | Shares | Fair Value* | ||||||
| (Millions) | ||||||||
|
Nonvested at December 31, 2009
|
6.1 | $ | 16.24 | |||||
|
Granted
|
2.1 | $ | 21.05 | |||||
|
Forfeited
|
(0.1 | ) | $ | 19.87 | ||||
|
Cancelled
|
(0.5 | ) | $ | 0.00 | ||||
|
Vested
|
(1.0 | ) | $ | 28.67 | ||||
|
Nonvested at December 31, 2010
|
6.6 | $ | 16.97 | |||||
122
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| * | Performance-based shares are primarily valued using the end-of-period market price until certification that the performance objectives have been completed, a value of zero once it has been determined that it is unlikely that performance objectives will be met, or a valuation pricing model. All other shares are valued at the grant-date market price. |
Other
restricted stock unit information
| 2010 | 2009 | 2008 | ||||||||||
|
Weighted-average grant date fair value of restricted stock units
granted during the year, per share
|
$ | 21.05 | $ | 10.23 | $ | 30.13 | ||||||
|
Total fair value of restricted stock units vested during the
year ($’s in millions)
|
$ | 29 | $ | 28 | $ | 48 | ||||||
Performance-based shares granted under the Plan represent
26 percent of nonvested restricted stock units outstanding
at December 31, 2010. These grants may be earned at the end
of a three-year period based on actual performance against a
performance target. Expense associated with these
performance-based grants is recognized in periods after
performance targets are established. Based on the extent to
which certain financial targets are achieved, vested shares may
range from zero percent to 200 percent of the original
grant amount.
| Note 14. | 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 considered from the
perspective of a market participant. We use market data or
assumptions that we believe 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.
The fair value hierarchy prioritizes the inputs used to measure
fair value, giving 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 for identical assets or liabilities in active markets 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. Our Level 1 measurements primarily consist of financial instruments that are exchange traded. | |
| • | 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. Our Level 2 measurements primarily consist of over-the-counter (OTC) instruments such as forwards, swaps, and options. | |
| • | Level 3 — Inputs that are not observable or for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments that are valued utilizing unobservable pricing inputs that are significant to the overall fair value. |
123
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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.
| December 31, 2010 | December 31, 2009 | |||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
| (Millions) | (Millions) | |||||||||||||||||||||||||||||||
|
Assets:
|
||||||||||||||||||||||||||||||||
|
Energy derivatives
|
$ | 96 | $ | 475 | $ | 2 | $ | 573 | $ | 178 | $ | 911 | $ | 5 | $ | 1,094 | ||||||||||||||||
|
ARO Trust Investments (see Note 15)
|
40 | — | — | 40 | 22 | — | — | 22 | ||||||||||||||||||||||||
|
Total assets
|
$ | 136 | $ | 475 | $ | 2 | $ | 613 | $ | 200 | $ | 911 | $ | 5 | $ | 1,116 | ||||||||||||||||
|
Liabilities:
|
||||||||||||||||||||||||||||||||
|
Energy derivatives
|
$ | 78 | $ | 210 | $ | 1 | $ | 289 | $ | 177 | $ | 826 | $ | 3 | $ | 1,006 | ||||||||||||||||
|
Total liabilities
|
$ | 78 | $ | 210 | $ | 1 | $ | 289 | $ | 177 | $ | 826 | $ | 3 | $ | 1,006 | ||||||||||||||||
Energy derivatives include commodity based exchange-traded
contracts and OTC contracts. Exchange-traded contracts include
futures, swaps, and options. OTC contracts include forwards,
swaps and options.
Many contracts have bid and ask prices that can be observed in
the market. Our policy is to use a mid-market pricing (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.
The determination of fair value for our energy derivative 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 cash
collateral posted and letters of credit) and our nonperformance
risk on our liabilities. The determination of the fair value of
our liabilities does not consider noncash collateral credit
enhancements.
Exchange-traded contracts include New York Mercantile Exchange
and Intercontinental Exchange contracts and are valued based on
quoted prices in these active markets and are classified within
Level 1.
Forward, swap, and option contracts included in Level 2 are
valued using an income approach including present value
techniques and option pricing models. Option contracts, which
hedge future sales of production from our
Exploration & Production segment, are structured as
costless collars and are financially settled. They are valued
using an industry standard Black-Scholes option pricing model.
Significant inputs into our Level 2 valuations include
commodity prices, implied volatility by location, and interest
rates, as well as considering executed transactions or broker
quotes corroborated by other market data. These broker quotes
are based on observable market prices at which transactions
could currently be executed. In certain instances where these
inputs are not observable for all periods, relationships of
observable market data and historical observations are used as a
means to estimate fair value. Where observable inputs are
available for substantially the full term of the asset or
liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of
exchange-traded products or like products and the tenure of our
derivatives portfolio is relatively short with more than
99 percent of the value of our derivatives
124
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
portfolio expiring in the next 24 months. Due to the nature
of the products and tenure, we are consistently able to obtain
market pricing. All pricing is reviewed on a daily basis and is
formally validated with broker quotes and documented on a
monthly basis.
Certain instruments trade with lower availability of pricing
information. These instruments are valued with a present value
technique 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. The
instruments included in Level 3 at December 31, 2010,
consist primarily of natural gas index transactions that are
used to manage the physical requirements of our
Exploration & Production segment.
Reclassifications of fair value between Level 1,
Level 2, and Level 3 of the fair value hierarchy, if
applicable, are made at the end of each quarter. No significant
transfers in or out of Level 1 and Level 2 occurred
during the year ended December 31, 2010. In 2009, certain
Exploration & Production options which hedge future
sales of production were transferred from Level 3 to
Level 2. These options were originally included in
Level 3 because a significant input to the model, implied
volatility by location, was considered unobservable. Due to
increased transparency, this input was considered observable,
and we transferred these options to Level 2.
The following tables present a reconciliation of changes in the
fair value of our net energy derivatives and other assets
classified as Level 3 in the fair value hierarchy.
Level 3
Fair Value Measurements Using Significant Unobservable
Inputs
| Years Ended December 31, | ||||||||||||||||||||
| 2010 | 2009 | 2008 | ||||||||||||||||||
|
Net Energy
|
Net Energy
|
Other
|
Net Energy
|
Other
|
||||||||||||||||
| Derivatives | Derivatives | Assets | Derivatives | Assets | ||||||||||||||||
| (Millions) | ||||||||||||||||||||
|
Beginning balance
|
$ | 2 | $ | 507 | $ | 7 | $ | (14 | ) | $ | 10 | |||||||||
|
Realized and unrealized gains (losses):
|
||||||||||||||||||||
|
Included in income (loss) from continuing operations
|
3 | 476 | — | 88 | (3 | ) | ||||||||||||||
|
Included in other comprehensive income (loss)
|
2 | (331 | ) | — | 486 | — | ||||||||||||||
|
Purchases, issuances, and settlements
|
(6 | ) | (477 | ) | (7 | ) | (51 | ) | — | |||||||||||
|
Transfers into Level 3
|
— | — | — | 3 | — | |||||||||||||||
|
Transfers out of Level 3
|
— | (173 | ) | — | (5 | ) | — | |||||||||||||
|
Ending balance
|
$ | 1 | $ | 2 | $ | — | $ | 507 | $ | 7 | ||||||||||
|
Unrealized gains (losses) included in income (loss) from
continuing operations relating to instruments still held at
December 31
|
$ | — | $ | 2 | $ | — | $ | — | $ | — | ||||||||||
Realized and unrealized gains (losses) included in
income
(loss) from continuing operations
for the above periods are
reported in
revenues
in our Consolidated Statement of
Operations.
125
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table presents impairments associated with certain
assets that have been measured at fair value on a nonrecurring
basis within Level 3 of the fair value hierarchy.
|
Total
|
||||||||
|
Losses For The
|
||||||||
|
Years Ended
|
||||||||
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Impairments:
|
||||||||
|
Goodwill — Exploration & Production (see
Note 4)
|
$ | 1,003 | (a) | $ | — | |||
|
Producing properties and acquired unproved reserves —
|
||||||||
|
Exploration & Production (see Note 4)
|
678 | (b) | 15 | (c) | ||||
|
Certain gathering assets — Williams Partners (see
Note 4)
|
9 | (d) | — | |||||
|
Venezuelan property — Discontinued Operations (see
Note 2)
|
— | 211 | (e) | |||||
|
Investment in Accroven — Other (see Note 3)
|
— | 75 | (f) | |||||
|
Cost-based investment — Exploration &
Production (see Note 3)
|
— | 11 | (g) | |||||
| $ | 1,690 | $ | 312 | |||||
| (a) | Due to a significant decline in forward natural gas prices across all future production periods as of September 30, 2010, we performed an interim impairment assessment of the approximate $1 billion of goodwill at Exploration & Production related to its domestic natural gas production operations (the reporting unit). Forward natural gas prices through 2025 as of September 30, 2010, used in our analysis declined more than 22 percent on average compared to the forward prices as of December 31, 2009. We estimated the fair value of the reporting unit on a stand-alone basis by valuing proved and unproved reserves, as well as estimating the fair values of other assets and liabilities which are identified to the reporting unit. We used an income approach (discounted cash flow) for valuing reserves. The significant inputs into the valuation of proved and unproved reserves included reserve quantities, forward natural gas prices, anticipated drilling and operating costs, anticipated production curves, income taxes, and appropriate discount rates. To estimate the fair value of the reporting unit and the implied fair value of goodwill under a hypothetical acquisition of the reporting unit, we assumed a tax structure where a buyer would obtain a step-up in the tax basis of the net assets acquired. Significant assumptions in valuing proved reserves included reserves quantities of more than 4.4 trillion cubic feet of gas equivalent; forward prices averaging approximately $4.65 per thousand cubic feet of gas equivalent (Mcfe) for natural gas (adjusted for locational differences), natural gas liquids and oil; and an after-tax discount rate of 11 percent. Unproved reserves (probable and possible) were valued using similar assumptions adjusted further for the uncertainty associated with these reserves by using after- tax discount rates of 13 percent and 15 percent, respectively, commensurate with our estimate of the risk of those reserves. In our assessment as of September 30, 2010, the carrying value of the reporting unit, including goodwill, exceeded its estimated fair value. We then determined that the implied fair value of the goodwill was zero. As a result of our analysis, we recognized a full $1 billion impairment charge related to this goodwill. | |
| (b) | As of September 30, 2010, we assessed the carrying value of Exploration & Production’s natural gas-producing properties and costs of acquired unproved reserves, for impairments as a result of recent significant declines in forward natural gas prices. Our assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments are similar to those used in the goodwill evaluation and include estimates of natural gas reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates. The assessment performed at September 30, 2010, identified certain properties with a carrying value in excess of their calculated fair values. As a result, we |
126
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STATEMENTS — (Continued)
| recorded a $678 million impairment charge in third-quarter 2010 as further described below. Fair value measured for these properties at September 30, 2010, was estimated to be approximately $320 million. | ||
|
• $503 million of the impairment charge related
to natural gas-producing properties in the Barnett Shale.
Significant assumptions in valuing these properties included
proved reserves quantities of more than 227 billion cubic
feet of gas equivalent, forward weighted average prices
averaging approximately $4.67 per Mcfe for natural gas (adjusted
for locational differences), natural gas liquids and oil, and an
after-tax discount rate of 11 percent.
|
||
|
• $175 million of the impairment charge related
to acquired unproved reserves in the Piceance Highlands acquired
in 2008. Significant assumptions in valuing these unproved
reserves included evaluation of probable and possible reserves
quantities, drilling plans, forward natural gas (adjusted for
locational differences) and natural gas liquids prices, and an
after-tax discount rate of 13 percent.
|
||
| (c) | Fair value measured at December 31, 2009, was $22 million. | |
| (d) | Fair value measured at December 31, 2010, was $3 million. | |
| (e) | Fair value measured at March 31, 2009, was $106 million. This value was based on our estimates of probability-weighted discounted cash flows that considered (1) the continued operation of the assets considering different scenarios of outcome, (2) the purchase of the assets by PDVSA, (3) the results of arbitration with varying degrees of award and collection, and (4) an after-tax discount rate of 20 percent. | |
| (f) | Fair value measured at March 31, 2009, was zero. This value was determined based on a probability-weighted discounted cash flow analysis that considered the deteriorating circumstances in Venezuela. | |
| (g) | Fair value measured at March 31, 2009, was zero. This value was based on an other-than-temporary decline in the value of our investment considering the deteriorating financial condition of a Venezuelan corporation in which Exploration & Production has a 4 percent interest. |
| Note 15. | Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk |
Financial
Instruments
Fair-value
methods
We use the following methods and assumptions in estimating our
fair-value disclosures for financial instruments:
Cash and cash equivalents and restricted
cash
: The carrying amounts reported in the
Consolidated Balance Sheet approximate fair value due to the
short-term maturity of these instruments. Current and noncurrent
restricted cash is included in
other current assets and
deferred charges
and
other assets and deferred
charges
, respectively, in the Consolidated Balance Sheet.
ARO Trust Investments:
Transco deposits a
portion of its collected rates, pursuant to its 2008 rate case
settlement, into an external trust specifically designated to
fund future asset retirement obligations (ARO Trust). The ARO
Trust invests in a portfolio of mutual funds that are reported
at fair value in
other assets and deferred charges
in the
Consolidated Balance Sheet and are classified as
available-for-sale.
However, both realized and unrealized gains and losses are
ultimately recorded as regulatory assets or liabilities.
Long-term debt
: The fair value of our publicly
traded long-term debt is determined using indicative year-end
traded bond market prices. Private debt is valued based on
market rates and the prices of similar securities with similar
terms and credit ratings. At December 31, 2010 and 2009,
approximately 100 percent and 97 percent,
respectively, of our long-term debt was publicly traded. (See
Note 11.)
Guarantees
: The
guarantees
represented
in the following table consist of a guarantee we have provided
in the event of nonpayment by our previously owned
communications subsidiary, Williams Communications Group
(WilTel), on a certain lease performance obligation. To estimate
the fair value of the guarantee, the estimated default
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WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
rate is determined by obtaining the average cumulative
issuer-weighted corporate default rate for each guarantee based
on the credit rating of WilTel’s current owner and the term
of the underlying obligation. The default rates are published by
Moody’s Investors Service. Guarantees, if recognized, are
included in
accrued liabilities
in the Consolidated
Balance Sheet.
Other
: Includes current and noncurrent notes
receivable, margin deposits, customer margin deposits payable,
and cost-based investments.
Energy derivatives
: Energy derivatives include
futures, forwards, swaps, and options. These are carried at fair
value in the Consolidated Balance Sheet. See Note 14 for
discussion of valuation of our energy derivatives.
Carrying
amounts and fair values of our financial instruments
| December 31, | ||||||||||||||||
| 2010 | 2009 | |||||||||||||||
|
Carrying
|
Carrying
|
|||||||||||||||
| Asset (Liability) | Amount | Fair Value | Amount | Fair Value | ||||||||||||
| (Millions) | ||||||||||||||||
|
Cash and cash equivalents
|
$ | 795 | $ | 795 | $ | 1,867 | $ | 1,867 | ||||||||
|
Restricted cash (current and noncurrent)
|
$ | 28 | $ | 28 | $ | 28 | $ | 28 | ||||||||
|
ARO Trust Investments
|
$ | 40 | $ | 40 | $ | 22 | $ | 22 | ||||||||
|
Long-term debt, including current portion(a)
|
$ | (9,104 | ) | $ | (9,990 | ) | $ | (8,273 | ) | $ | (9,142 | ) | ||||
|
Guarantees
|
$ | (35 | ) | $ | (34 | ) | $ | (36 | ) | $ | (33 | ) | ||||
|
Other
|
$ | (23 | ) | $ | (25 | )(b) | $ | (23 | ) | $ | (25 | )(b) | ||||
|
Net energy derivatives:
|
||||||||||||||||
|
Energy commodity cash flow hedges
|
$ | 266 | $ | 266 | $ | 178 | $ | 178 | ||||||||
|
Other energy derivatives
|
$ | 18 | $ | 18 | $ | (90 | ) | $ | (90 | ) | ||||||
| (a) | Excludes capital leases. (See Note 11.) | |
| (b) | Excludes certain cost-based investments in companies that are not publicly traded and therefore it is not practicable to estimate fair value. The carrying value of these investments was $2 million at December 31, 2010 and December 31, 2009. |
Energy
Commodity Derivatives
Risk
management activities
We are exposed to market risk from changes in energy commodity
prices within our operations. We manage this risk on an
enterprise basis and may utilize derivatives to manage our
exposure to the variability in expected future cash flows from
forecasted purchases and sales of natural gas and NGLs
attributable to commodity price risk. Certain of these
derivatives utilized for risk management purposes have been
designated as cash flow hedges, while other derivatives have not
been designated as cash flow hedges or do not qualify for hedge
accounting despite hedging our future cash flows on an economic
basis.
We produce, buy, and sell natural gas at different locations
throughout the United States. We also enter into forward
contracts to buy and sell natural gas to maximize the economic
value of transportation agreements and storage capacity
agreements. To reduce exposure to a decrease in revenues or
margins from fluctuations in natural gas market prices, we enter
into natural gas futures contracts, swap agreements, and
financial option contracts to mitigate the price risk on
forecasted sales of natural gas. We have also entered into basis
swap agreements to reduce the locational price risk associated
with our producing basins. These 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
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NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
hedged item. Our financial option contracts are either purchased
options or a combination of options that comprise a net
purchased option or a zero-cost collar. Our designation of the
hedging relationship and method of assessing effectiveness for
these option contracts are generally such that the hedging
relationship is considered perfectly effective and no
ineffectiveness is recognized in earnings. Hedges for storage
contracts have not been designated as cash flow hedges, despite
economically hedging the expected cash flows generated by those
agreements.
We produce and sell NGLs and olefins at different locations
throughout North America. We also buy natural gas to satisfy the
required fuel and shrink needed to generate NGLs and olefins. 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 and NGL market prices, we may
enter into NGL or natural gas swap agreements, financial forward
contracts, and financial option contracts to mitigate the price
risk on forecasted sales of NGLs and purchases of natural gas
and NGLs. These 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.
Other
activities
We also enter into energy commodity derivatives for other than
risk management purposes, including managing certain remaining
legacy natural gas contracts and positions from our former power
business and providing services to third parties. These legacy
natural gas contracts include substantially offsetting positions
and have an insignificant net impact on earnings.
Volumes
Our energy commodity derivatives are comprised of both contracts
to purchase the commodity (long positions) and contracts to sell
the commodity (short positions). Derivative transactions are
categorized into four types:
| • | Central hub risk: Includes physical and financial derivative exposures to Henry Hub for natural gas, West Texas Intermediate for crude oil, and Mont Belvieu for NGLs; | |
| • | Basis risk: Includes physical and financial derivative exposures to the difference in value between the central hub and another specific delivery point; | |
| • | Index risk: Includes physical derivative exposure at an unknown future price; | |
| • | Options: Includes all fixed price options or combination of options (collars) that set a floor and/or ceiling for the transaction price of a commodity. |
Fixed price swaps at locations other than the central hub are
classified as both central hub risk and basis risk instruments
to represent their exposure to overall market conditions
(central hub risk) and specific location risk (basis risk).
The following table depicts the notional quantities of the net
long (short) positions in our commodity derivatives portfolio as
of December 31, 2010. Natural gas is presented in millions
of British Thermal Units (MMBtu), and NGLs are presented in
gallons. The volumes for options represent at location zero-cost
collars and present one side of the short position. The net
index position for Exploration & Production includes
certain positions on behalf of other segments.
|
Unit of
|
Central Hub
|
Basis
|
Index
|
|||||||||||||||||||
| Derivative Notional Volumes | Measure | Risk | Risk | Risk | Options | |||||||||||||||||
|
Designated as Hedging Instruments
|
||||||||||||||||||||||
|
Exploration & Production
|
Risk Management | MMBtu | (200,100,000 | ) | (200,100,000 | ) | (100,375,000 | ) | ||||||||||||||
|
Not Designated as Hedging Instruments
|
||||||||||||||||||||||
|
Exploration & Production
|
Risk Management | MMBtu | (9,077,499 | ) | (20,195,000 | ) | 16,586,059 | |||||||||||||||
|
Williams Partners
|
Risk Management | Gallons | (3,990,000 | ) | ||||||||||||||||||
|
Exploration & Production
|
Other | MMBtu | 150,400 | (14,766,500 | ) | |||||||||||||||||
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NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Fair
values and gains (losses)
The following table presents the fair value of energy commodity
derivatives. Our derivatives are presented as separate line
items in our Consolidated Balance Sheet as
current
and
noncurrent derivative assets
and
liabilities
.
Derivatives are classified as current or noncurrent based on the
contractual timing of expected future net cash flows of
individual contracts. The expected future net cash flows for
derivatives classified as current are expected to occur within
the next 12 months. 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. Further, the amounts below do not include
cash held on deposit in margin accounts that we have received or
remitted to collateralize certain derivative positions.
| December 31, | ||||||||||||||||
| 2010 | 2009 | |||||||||||||||
| Assets | Liabilities | Assets | Liabilities | |||||||||||||
| (Millions) | ||||||||||||||||
|
Designated as hedging instruments
|
$ | 288 | $ | 22 | $ | 352 | $ | 174 | ||||||||
|
Not designated as hedging instruments:
|
||||||||||||||||
|
Legacy natural gas contracts from former power business
|
186 | 187 | 505 | 526 | ||||||||||||
|
All other
|
99 | 80 | 237 | 306 | ||||||||||||
|
Total derivatives not designated as hedging instruments
|
285 | 267 | 742 | 832 | ||||||||||||
|
Total derivatives
|
$ | 573 | $ | 289 | $ | 1,094 | $ | 1,006 | ||||||||
The following table presents pre-tax gains and losses for our
energy commodity derivatives designated as cash flow hedges, as
recognized in
AOCI
,
revenues
or
costs and
operating expenses
.
| Years Ended December 31, | ||||||||||
| 2010 | 2009 | Classification | ||||||||
| (Millions) | ||||||||||
|
Net gain recognized in other comprehensive income (loss)
(effective portion)
|
$ | 495 | $ | 262 | AOCI | |||||
|
Net gain reclassified from accumulated other comprehensive
income (loss) into income (effective portion)
|
$ | 342 | $ | 618 |
Revenues or Costs and
Operating Expenses |
|||||
|
Gain recognized in income (ineffective portion)
|
$ | 9 | $ | 4 |
Revenues or Costs and
Operating Expenses |
|||||
There were no gains or losses recognized in income as a result
of excluding amounts from the assessment of hedge effectiveness
or as a result of reclassifications to earnings following the
discontinuance of any cash flow hedges.
The following table presents pre-tax gains and losses for our
energy commodity derivatives not designated as hedging
instruments.
|
Years Ended
|
||||||||
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Revenues
|
$ | 46 | $ | 37 | ||||
|
Costs and operating expenses
|
28 | 33 | ||||||
|
Net gain
|
$ | 18 | $ | 4 | ||||
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The cash flow impact of our derivative activities is presented
in the Consolidated Statement of Cash Flows as
changes in
current and noncurrent derivative assets and liabilities
.
Credit-risk-related
features
Certain of our derivative contracts contain credit-risk-related
provisions that would require us, in certain circumstances, to
post additional collateral in support of our net derivative
liability positions. These credit-risk-related provisions
require us to post collateral in the form of cash or letters of
credit when our net liability positions exceed an established
credit threshold. The credit thresholds are typically based on
our senior unsecured debt ratings from Standard and Poor’s
and/or
Moody’s Investors Service. Under these contracts, a credit
ratings decline would lower our credit thresholds, thus
requiring us to post additional collateral. We also have
contracts that contain adequate assurance provisions giving the
counterparty the right to request collateral in an amount that
corresponds to the outstanding net liability. Additionally,
Exploration & Production has an unsecured credit
agreement with certain banks related to hedging activities. We
are not required to provide collateral support for net
derivative liability positions under the credit agreement as
long as the value of Exploration & Production’s
domestic natural gas reserves, as determined under the
provisions of the agreement, exceeds by a specified amount
certain of its obligations including any outstanding debt and
the aggregate
out-of-the-money
position on hedges entered into under the credit agreement.
As of December 31, 2010, we have collateral totaling
$8 million, all of which is in the form of letters of
credit, posted to derivative counterparties to support the
aggregate fair value of our net derivative liability position
(reflecting master netting arrangements in place with certain
counterparties) of $36 million, which includes a reduction
of less than $1 million to our liability balance for our
own nonperformance risk. At December 31, 2009, we had
collateral totaling $96 million posted to derivative
counterparties, all of which was in the form of letters of
credit, to support the aggregate fair value of our net
derivative liability position (reflecting master netting
arrangements in place with certain counterparties) of
$167 million, which included a reduction of $3 million
to our liability balance for our own nonperformance risk. The
additional collateral that we would have been required to post,
assuming our credit thresholds were eliminated and a call for
adequate assurance under the credit risk provisions in our
derivative contracts was triggered, was $29 million and
$74 million at December 31, 2010 and December 31,
2009, respectively.
Cash flow
hedges
Changes in the fair value of our cash flow hedges, to the extent
effective, are deferred in AOCI and 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. As of December 31,
2010, we have hedged portions of future cash flows associated
with anticipated energy commodity purchases and sales for up to
two years. Based on recorded values at December 31, 2010,
$148 million of net gains (net of income tax provision of
$88 million) will be reclassified into earnings within the
next year. These recorded values are based on market prices of
the commodities as of December 31, 2010. Due to the
volatile nature of commodity prices and changes in the
creditworthiness of counterparties, actual gains or losses
realized within the next year 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
associated with underlying hedged transactions.
Guarantees
In addition to the guarantees and payment obligations discussed
in Note 16, we have issued guarantees and other similar
arrangements as discussed below.
We are required by our revolving credit agreements to indemnify
lenders for any taxes required to be withheld from payments due
to the lenders and for any tax payments made by the lenders. The
maximum potential amount of
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
future payments under these indemnifications is based on the
related borrowings and such future payments cannot currently be
determined. These indemnifications generally continue
indefinitely unless limited by the underlying tax regulations
and have no carrying value. We have never been called upon to
perform under these indemnifications and have no current
expectation of a future claim.
We have provided a guarantee in the event of nonpayment by our
previously owned communications subsidiary, WilTel, on a certain
lease performance obligation that extends through 2042. The
maximum potential exposure is approximately $39 million at
December 31, 2010 and $40 million at December 31,
2009. Our exposure declines systematically throughout the
remaining term of WilTel’s obligation. The carrying value
of the guarantee included in
accrued liabilities
on the
Consolidated Balance Sheet is $35 million at
December 31, 2010 and $36 million at December 31,
2009.
At December 31, 2010, we do not expect these guarantees to
have a material impact on our future liquidity or financial
position. However, if we are required to perform on these
guarantees in the future, it may have a material adverse effect
on our results of operations.
Concentration
of Credit Risk
Cash
equivalents
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.
Accounts
and notes receivable
The following table summarizes concentration of receivables, net
of allowances, by product or service:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Receivables by product or service:
|
||||||||
|
Sale of natural gas and related products and services
|
$ | 635 | $ | 599 | ||||
|
Transportation of natural gas and related products
|
149 | 160 | ||||||
|
Joint interest
|
71 | 56 | ||||||
|
Other
|
4 | 1 | ||||||
|
Total
|
$ | 859 | $ | 816 | ||||
Natural gas customers include pipelines, distribution companies,
producers, gas marketers and industrial users primarily located
in the eastern and northwestern United States, Rocky Mountains,
Gulf Coast, and Canada. As a general policy, collateral is not
required for receivables, but customers’ financial
condition and credit worthiness are evaluated regularly.
Derivative
assets and liabilities
We have a risk of loss from counterparties not performing
pursuant to the terms of their contractual obligations.
Counterparty performance can be influenced by changes in the
economy and regulatory issues, among other factors. Risk of loss
is impacted by several factors, including credit considerations
and the regulatory environment in which a counterparty
transacts. We attempt to minimize credit-risk exposure to
derivative counterparties and brokers through formal credit
policies, consideration of credit ratings from public ratings
agencies, monitoring procedures, master netting agreements and
collateral support under certain circumstances. Collateral
support could include
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
letters of credit, payment under margin agreements, and
guarantees of payment by credit worthy parties. The gross credit
exposure from our derivative contracts as of December 31,
2010, is summarized as follows:
|
Investment
|
||||||||
| Counterparty Type | Grade(a) | Total | ||||||
| (Millions) | ||||||||
|
Gas and electric utilities
|
$ | 7 | $ | 8 | ||||
|
Energy marketers and traders
|
— | 133 | ||||||
|
Financial institutions
|
432 | 432 | ||||||
| $ | 439 | 573 | ||||||
|
Credit reserves
|
— | |||||||
|
Gross credit exposure from derivatives
|
$ | 573 | ||||||
We assess our credit exposure on a net basis to reflect master
netting agreements in place with certain counterparties. We
offset our credit exposure to each counterparty with amounts we
owe the counterparty under derivative contracts. The net credit
exposure from our derivatives as of December 31, 2010,
excluding collateral support discussed below, is summarized as
follows:
|
Investment
|
||||||||
| Counterparty Type | Grade(a) | Total | ||||||
| (Millions) | ||||||||
|
Gas and electric utilities
|
$ | 3 | $ | 3 | ||||
|
Financial institutions
|
317 | 317 | ||||||
| $ | 320 | 320 | ||||||
|
Credit reserves
|
— | |||||||
|
Net credit exposure from derivatives
|
$ | 320 | ||||||
| (a) | We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade. |
Our nine largest net counterparty positions represent
approximately 99 percent of our net credit exposure from
derivatives and are all with investment grade counterparties.
Included within this group are eight counterparty positions,
representing 81 percent of our net credit exposure from
derivatives, associated with Exploration &
Production’s hedging facility. Under certain conditions,
the terms of this credit agreement may require the participating
financial institutions to deliver collateral support to a
designated collateral agent (which is another participating
financial institution in the agreement). The level of collateral
support required is dependent on whether the net position of the
counterparty financial institution exceeds specified thresholds.
The thresholds may be subject to prescribed reductions based on
changes in the credit rating of the counterparty financial
institution.
At December 31, 2010, the designated collateral agent holds
$19 million of collateral support on our behalf under
Exploration & Production’s hedging facility. In
addition, we hold collateral support, which may include cash or
letters of credit, of $15 million related to our other
derivative positions.
Revenues
In 2010 we had one customer in our Williams Partners segment
that accounted for 10 percent of our consolidated revenues.
In 2009, and 2008, there were no customers for which our sales
exceeded 10 percent of our consolidated revenues.
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NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Note 16. | Contingent Liabilities and Commitments |
Issues
Resulting from California Energy Crisis
Our former power business was engaged in power marketing in
various geographic areas, including California. Prices charged
for power by us and other traders and generators in California
and other western states in 2000 and 2001 were challenged in
various proceedings, including those before the FERC. We have
entered into settlements with the State of California (State
Settlement), major California utilities (Utilities Settlement),
and others that substantially resolved each of these issues with
these parties.
Although the State Settlement and Utilities Settlement resolved
a significant portion of the refund issues among the settling
parties, we continue to have potential refund exposure to
nonsettling parties, including various California end users that
did not participate in the Utilities Settlement. We are
currently in settlement negotiations with certain California
utilities aimed at eliminating or substantially reducing this
exposure. If successful, and subject to a final
“true-up”
mechanism, the settlement agreement would also resolve our
collection of accrued interest from counterparties as well as
our payment of accrued interest on refund amounts. Thus, as
currently contemplated by the parties, the settlement agreement
would resolve most, if not all, of our legal issues arising from
the
2000-2001
California Energy Crisis.
As a result of a 2008 U.S. Supreme Court decision, certain
contracts that we entered into during 2000 and 2001 might have
been subject to partial refunds depending on the results of
further proceedings at the FERC. These contracts, under which we
sold electricity, totaled approximately $89 million in
revenue. While we were not a party to the cases involved in the
U.S. Supreme Court decision, the buyer of electricity from
us is a party to the cases and claimed that we must refund to
the buyer any loss it suffers due to the FERC’s
reconsideration of the contract terms at issue in the decision.
In August 2010, the FERC ruled that settlement of the separate
claims against the buyer required the dismissal of the
buyer’s claims against us.
Certain other issues also remain open at the FERC and for other
nonsettling parties.
Reporting
of Natural Gas-Related Information to Trade
Publications
Civil suits based on allegations of manipulating published gas
price indices have been brought against us and others, in each
case seeking an unspecified amount of damages. We are currently
a defendant in class action litigation and other litigation
originally filed in state court in Colorado, Kansas, Missouri
and Wisconsin brought on behalf of direct and indirect
purchasers of gas in those states.
| • | The federal court in Nevada currently presides over cases that were transferred to it from state courts in Colorado, Kansas, Missouri, and Wisconsin. In 2008, the federal court in Nevada granted summary judgment in the Colorado case in favor of us and most of the other defendants, and on January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal. We expect that the Colorado plaintiffs will appeal, but the appeal cannot occur until the case against the remaining defendant is concluded. In the other cases, our joint motions for summary judgment to preclude the plaintiffs’ state law claims based upon federal preemption have been pending since late 2009. If the motions are granted, we expect a final judgment in our favor which the plaintiffs could appeal. If the motions are denied, the current stay of activity would be lifted, class certification would be addressed, and discovery would be completed as the cases proceeded towards trial. Additionally, we would be unable to estimate a revised range of exposure until certain of these matters were resolved. However, it would be reasonably possible that such a range could include levels that would be material to our results of operations. | |
| • | On April 23, 2010, the Tennessee Supreme Court reversed the state appellate court and dismissed the plaintiffs’ claims against us on federal preemption grounds. The plaintiffs did not appeal this ruling to the United States Supreme Court. This case is now concluded in our favor. |
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NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| • | On September 24, 2010, the Missouri Supreme Court declined to hear the plaintiff’s appeal of the trial court’s dismissal of a case for lack of standing. The case is now concluded in our favor. |
Environmental
Matters
Continuing
operations
Our interstate gas pipelines are involved in remediation
activities related to certain facilities and locations for
polychlorinated biphenyl, mercury contamination, and other
hazardous substances. These activities have involved the
U.S. Environmental Protection Agency (EPA) and various
state environmental authorities. At December 31, 2010 we
have accrued liabilities of $12 million for these costs. We
expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas
underground storage facilities, primarily related to soil and
groundwater contamination. At December 31, 2010, we have
accrued liabilities totaling $6 million for these costs.
In March 2008, the 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.
In September 2007, the EPA requested, and our Transco subsidiary
later provided, information regarding natural gas compressor
stations in the states of Mississippi and Alabama as part of the
EPA’s investigation of our compliance with the Clean Air
Act. On March 28, 2008, the EPA issued notices of violation
alleging violations of Clean Air Act requirements at these
compressor stations. We met with the EPA in May 2008 and
submitted our response denying the allegations in June 2008. In
July 2009, the EPA requested additional information pertaining
to these compressor stations and in August 2009, we submitted
the requested information. On August 20, 2010, the EPA
requested and our Transco subsidiary provided, similar
information for a compressor station in Maryland.
Former
operations, including operations classified as
discontinued
We have potential obligations in connection with assets and
businesses we no longer operate. These potential obligations
include the indemnification of the purchasers of certain of
these assets and businesses for environmental and other
liabilities existing at the time the sale was consummated. Our
responsibilities include those described below.
| • | Potential indemnification obligations to purchasers of our former agricultural fertilizer and chemical operations and former retail petroleum and refining operations; | |
| • | Former petroleum products and natural gas pipelines; | |
| • | Discontinued petroleum refining facilities; | |
| • | Former exploration and production and mining operations. |
At December 31, 2010, we have accrued environmental
liabilities of $31 million related to these matters.
Actual costs for these matters could be substantially greater
than amounts accrued depending on the actual number of
contaminated sites identified, the actual amount and extent of
contamination discovered, the final cleanup standards mandated
by the EPA and other governmental authorities. Any incremental
amount cannot be reasonably estimated at this time.
Certain of our subsidiaries have been identified as potentially
responsible parties at various Superfund and state waste
disposal sites. In addition, these subsidiaries have incurred,
or are alleged to have incurred, various other hazardous
materials removal or remediation obligations under environmental
laws.
135
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Environmental
matters — general
The EPA and various state regulatory agencies routinely
promulgate and propose new rules, and issue updated guidance to
existing rules. These new rules and rulemakings include, but are
not limited to, rules for reciprocating internal combustion
engine maximum achievable control technology, new air quality
standards for ground level ozone, and one hour nitrogen dioxide
emission limits. We are unable to estimate the costs of asset
additions or modifications necessary to comply with these new
regulations due to uncertainty created by the various legal
challenges to these regulations and the need for further
specific regulatory guidance.
Other
Legal Matters
Gulf
Liquids litigation
Gulf Liquids contracted with Gulsby Engineering Inc. (Gulsby)
and Gulsby-Bay (a joint venture between Gulsby and Bay Ltd.) for
the construction of certain gas processing plants in Louisiana.
National American Insurance Company (NAICO) and American Home
Assurance Company provided payment and performance bonds for the
projects. In 2001, the contractors and sureties filed multiple
cases in Louisiana and Texas against Gulf Liquids and us.
In 2006, at the conclusion of the consolidated trial of the
asserted contract and tort claims, the jury returned its actual
and punitive damages verdict against us and Gulf Liquids. Based
on our interpretation of the jury verdicts, we recorded a charge
based on our estimated exposure for actual damages of
approximately $68 million plus potential interest of
approximately $20 million. In addition, we concluded that
it was reasonably possible that any ultimate judgment might have
included additional amounts of approximately $199 million
in excess of our accrual, which primarily represented our
estimate of potential punitive damage exposure under Texas law.
From May through October 2007, the court entered seven
post-trial orders in the case (interlocutory orders) which,
among other things, overruled the verdict award of tort and
punitive damages as well as any damages against us. The court
also denied the plaintiffs’ claims for attorneys’
fees. On January 28, 2008, the court issued its judgment
awarding damages against Gulf Liquids of approximately
$11 million in favor of Gulsby and approximately
$4 million in favor of Gulsby-Bay. Gulf Liquids, Gulsby,
Gulsby-Bay, Bay Ltd., and NAICO appealed the judgment. In
February 2009, we settled with certain of these parties and
reduced our liability as of December 31, 2008, by
$43 million, including $11 million of interest. On
February 17, 2011, the Texas Court of Appeals upheld the
dismissals of the tort and punitive damages claims and reversed
and remanded the contract claim and attorney fee claims for
further proceedings. The appellate court ruling is subject to a
potential appeal to the Texas Supreme Court. If the appellate
court judgment is upheld, our remaining liability will be
substantially less than the amount of our accrual for these
matters.
Royalty
litigation
In September 2006, royalty interest owners in Garfield County,
Colorado, filed a class action suit in Colorado state court
alleging that we improperly calculated oil and gas royalty
payments, failed to account for the proceeds that we received
from the sale of gas and extracted products, improperly charged
certain expenses, and failed to refund amounts withheld in
excess of ad valorem tax obligations. We reached a final partial
settlement agreement for an amount that was previously accrued.
We received a favorable ruling on our motion for summary
judgment on one claim now on appeal by plaintiffs. We anticipate
trial on the other remaining issue related to royalty payment
calculation and obligations under specific lease provisions in
2011. While we are not able to estimate the amount of any
additional exposure at this time, it is reasonably possible that
plaintiff’s claims could reach a material amount.
Other producers have been in litigation or discussions with a
federal regulatory agency and a state agency in New Mexico
regarding certain deductions used in the calculation of
royalties. Although we are not a party to these matters, we have
monitored them to evaluate whether their resolution might have
the potential for unfavorable impact on our results of
operations. One of these matters involving federal litigation
was decided on October 5,
136
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
2009. The resolution of this specific matter is not material to
us. However, other related issues in these matters that could be
material to us remain outstanding. We received notice from the
U.S. Department of Interior Office of Natural Resources Revenue
(ONRR) in the fourth quarter of 2010, intending to clarify the
guidelines for calculating federal royalties on conventional gas
production applicable to our federal leases in New Mexico. The
ONRR’s guidance provides its view as to how much of a
producer’s bundled fees for transportation and processing
can be deducted from the royalty payment. Using these guidelines
would not result in a material difference in determining our
historical federal royalty payments for our leases in New
Mexico. No similar specific guidance has been issued by ONRR for
leases in other states, but such guidelines are expected in the
future. The issuance of similar guidelines in Colorado and other
states could affect our previous royalty payments and the effect
could be material to our results of operations.
Other
In 2003, we entered into an agreement to sublease certain
underground storage facilities to Liberty Gas Storage (Liberty).
We have asserted claims against Liberty for prematurely
terminating the sublease, and for damage caused to the
facilities. In February 2010, Liberty subsequently indicated
that they intend to assert a counterclaim for costs in excess of
$200 million associated with its use of the facilities. Due
to the lack of information currently available, we are unable to
evaluate the merits of the potential counterclaim and determine
the amount of any possible liability.
Other
Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to
divested businesses and assets, we have indemnified certain
purchasers against liabilities that they may incur with respect
to the businesses and assets acquired from us. The indemnities
provided to the purchasers are customary in sale transactions
and are contingent upon the purchasers incurring liabilities
that are not otherwise recoverable from third parties. The
indemnities generally relate to breach of warranties, tax,
historic litigation, personal injury, property damage,
environmental matters, right of way and other representations
that we have provided.
At December 31, 2010, we do not expect any of the
indemnities provided pursuant to the sales agreements to have a
material impact on our future financial position. However, if a
claim for indemnity is brought against us in the future, it may
have a material adverse effect on our results of operations in
the period in which the claim is made.
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.
Commitments
Commitments for construction and acquisition of property, plant
and equipment are approximately $226 million at
December 31, 2010.
137
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
As part of managing our commodity price risk, we utilize
contracted pipeline capacity primarily to move our natural gas
production to other locations with more favorable pricing
differentials. Our commitments under these contracts are as
follows:
| (Millions) | ||||
|
2011
|
$ | 143 | ||
|
2012
|
137 | |||
|
2013
|
125 | |||
|
2014
|
127 | |||
|
2015
|
120 | |||
|
Thereafter
|
404 | |||
|
Total
|
$ | 1,056 | ||
We also have certain commitments to an equity investee for
natural gas gathering and treating services which total
$181 million over approximately seven years.
| Note 17. | Accumulated Other Comprehensive Loss |
The table below presents changes in the components of
accumulated other comprehensive income (loss)
.
| Income (Loss) | ||||||||||||||||||||||||||||
|
Other
|
||||||||||||||||||||||||||||
|
Postretirement
|
||||||||||||||||||||||||||||
| Pension Benefits | Benefits | |||||||||||||||||||||||||||
|
Foreign
|
Prior
|
Net
|
Prior
|
Net
|
||||||||||||||||||||||||
|
Cash Flow
|
Currency
|
Service
|
Actuarial
|
Service
|
Actuarial
|
|||||||||||||||||||||||
| Hedges | Translation | Cost | Gain (Loss) | Cost | Gain (Loss) | Total | ||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||
|
Balance at December 31, 2007
|
$ | (157 | ) | $ | 129 | $ | (4 | ) | $ | (97 | ) | $ | (3 | ) | $ | 11 | $ | (121 | ) | |||||||||
|
2008 Change:
|
||||||||||||||||||||||||||||
|
Pre-income tax amount
|
714 | (76 | ) | — | (565 | ) | 16 | (15 | ) | 74 | ||||||||||||||||||
|
Income tax (provision) benefit
|
(270 | ) | — | — | 213 | (8 | ) | 6 | (59 | ) | ||||||||||||||||||
|
Net reclassification into earnings of derivative instrument
losses (net of a $7 million income tax benefit)
|
11 | — | — | — | — | — | 11 | |||||||||||||||||||||
|
Amortization included in net periodic benefit expense
|
— | — | 1 | 13 | 1 | — | 15 | |||||||||||||||||||||
|
Income tax provision on amortization
|
— | — | — | (5 | ) | — | — | (5 | ) | |||||||||||||||||||
| 455 | (76 | ) | 1 | (344 | ) | 9 | (9 | ) | 36 | |||||||||||||||||||
|
Allocation of other comprehensive income (loss) to
noncontrolling interests
|
(2 | ) | — | — | 7 | — | — | 5 | ||||||||||||||||||||
|
Balance at December 31, 2008
|
296 | 53 | (3 | ) | (434 | ) | 6 | 2 | (80 | ) | ||||||||||||||||||
|
2009 Change:
|
||||||||||||||||||||||||||||
|
Pre-income tax amount
|
262 | 83 | — | 44 | 7 | (1 | ) | 395 | ||||||||||||||||||||
|
Income tax (provision) benefit
|
(99 | ) | — | — | (17 | ) | — | 1 | (115 | ) | ||||||||||||||||||
|
Net reclassification into earnings of derivative instrument
gains (net of a $234 million income tax provision)
|
(384 | ) | — | — | — | — | — | (384 | ) | |||||||||||||||||||
|
Amortization included in net periodic benefit expense
|
— | — | 1 | 42 | (4 | ) | — | 39 | ||||||||||||||||||||
|
Income tax (provision) benefit on amortization
|
— | — | (1 | ) | (16 | ) | 1 | — | (16 | ) | ||||||||||||||||||
| (221 | ) | 83 | — | 53 | 4 | — | (81 | ) | ||||||||||||||||||||
|
Allocation of other comprehensive income to noncontrolling
interests
|
— | — | — | (7 | ) | — | — | (7 | ) | |||||||||||||||||||
|
Balance at December 31, 2009
|
75 | 136 | (3 | ) | (388 | ) | 10 | 2 | (168 | ) | ||||||||||||||||||
138
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Income (Loss) | ||||||||||||||||||||||||||||
|
Other
|
||||||||||||||||||||||||||||
|
Postretirement
|
||||||||||||||||||||||||||||
| Pension Benefits | Benefits | |||||||||||||||||||||||||||
|
Foreign
|
Prior
|
Net
|
Prior
|
Net
|
||||||||||||||||||||||||
|
Cash Flow
|
Currency
|
Service
|
Actuarial
|
Service
|
Actuarial
|
|||||||||||||||||||||||
| Hedges | Translation | Cost | Gain (Loss) | Cost | Gain (Loss) | Total | ||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||
|
2010 Change:
|
||||||||||||||||||||||||||||
|
Pre-income tax amount
|
488 | 29 | — | (71 | ) | — | (12 | ) | 434 | |||||||||||||||||||
|
Income tax (provision) benefit
|
(185 | ) | — | — | 24 | — | 3 | (158 | ) | |||||||||||||||||||
|
Net reclassification into earnings of derivative instrument
gains (net of a $131 million income tax provision)
|
(211 | ) | — | — | — | — | — | (211 | ) | |||||||||||||||||||
|
Amortization included in net periodic benefit expense
|
— | — | 1 | 35 | (5 | ) | 1 | 32 | ||||||||||||||||||||
|
Income tax (provision) benefit on amortization
|
— | — | — | (13 | ) | 2 | — | (11 | ) | |||||||||||||||||||
| 92 | 29 | 1 | (25 | ) | (3 | ) | (8 | ) | 86 | |||||||||||||||||||
|
Allocation of other comprehensive income to noncontrolling
interests
|
— | — | — | — | — | — | — | |||||||||||||||||||||
|
Balance at December 31, 2010
|
$ | 167 | $ | 165 | $ | (2 | ) | $ | (413 | ) | $ | 7 | $ | (6 | ) | $ | (82 | ) | ||||||||||
| Note 18. | Segment Disclosures |
Our reporting segments are Williams Partners,
Exploration & Production, and Other. (See Note 1.)
Our segment presentation of Williams Partners is reflective of
the parent-level focus by our chief operating decision-maker,
considering the resource allocation and governance provisions
associated with this master limited partnership structure. WPZ
maintains a capital and cash management structure that is
separate from ours. WPZ is expected to be self-funding and
maintains its own lines of bank credit and cash management
accounts. These factors, coupled with a different cost of
capital from our other businesses, serve to differentiate the
management of this entity as a whole.
Due to expected future growth in our Canadian midstream and
domestic olefins operations, we are considering reporting these
businesses as a separate segment in the first quarter of 2011.
Performance
Measurement
We currently evaluate performance based upon
segment profit
(loss)
from operations, which includes
segment revenues
from external and internal customers,
segment costs and
expenses
,
equity earnings (losses)
and
income
(loss) from investments
. The accounting policies of the
segments are the same as those described in Note 1.
Intersegment sales are generally accounted for at current market
prices as if the sales were to unaffiliated third parties.
The primary types of costs and operating expenses by segment can
be generally summarized as follows:
| • | Williams Partners — commodity purchases (primarily for NGL and crude marketing, shrink and fuel), depreciation and operation and maintenance expenses; | |
| • | Exploration & Production — commodity purchases (primarily in support of commodity marketing and risk management activities), depletion, depreciation and amortization, lease and facility operating expenses and operating taxes; | |
| • | Other — commodity purchases (primarily for shrink, feedstock and NGL and olefin marketing activities), depreciation and operation and maintenance expenses. |
Energy commodity hedging by our business units may be done
through intercompany derivatives with our
Exploration & Production segment which, in turn,
enters into offsetting derivative contracts with unrelated third
parties. Additionally, Exploration & Production may
enter into transactions directly with third parties under their
139
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
credit agreement. (See Note 11.) Exploration &
Production bears the counterparty performance risks associated
with the unrelated third parties in these transactions.
The following geographic area data includes
revenues from
external customers
based on product shipment origin and
long-lived assets
based upon physical location.
| United States | Other | Total | ||||||||||
| (Millions) | ||||||||||||
|
Revenues from external customers:
|
||||||||||||
|
2010
|
$ | 9,359 | $ | 257 | $ | 9,616 | ||||||
|
2009
|
8,065 | 190 | 8,255 | |||||||||
|
2008
|
11,629 | 261 | 11,890 | |||||||||
|
Long-lived assets:
|
||||||||||||
|
2010
|
$ | 19,791 | $ | 527 | $ | 20,318 | ||||||
|
2009
|
19,247 | 410 | 19,657 | |||||||||
|
2008
|
18,419 | 335 | 18,754 | |||||||||
Our foreign operations are primarily located in Canada and South
America.
Long-lived assets
are comprised of property,
plant, and equipment, goodwill, and other intangible assets.
140
Table of Contents
THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table reflects the reconciliation of
segment
revenues
and
segment profit (loss)
to
revenues
and
operating income (loss)
as reported in the
Consolidated Statement of Operations and
other financial
information
related to
long-lived assets
.
|
Williams
|
Exploration &
|
|||||||||||||||||||
| Partners* | Production* | Other | Eliminations* | Total | ||||||||||||||||
| (Millions) | ||||||||||||||||||||
|
2010
|
||||||||||||||||||||
|
Segment revenues:
|
||||||||||||||||||||
|
External
|
$ | 5,344 | $ | 3,245 | $ | 1,027 | $ | — | $ | 9,616 | ||||||||||
|
Internal
|
371 | 797 | 30 | (1,198 | ) | — | ||||||||||||||
|
Total revenues
|
$ | 5,715 | $ | 4,042 | $ | 1,057 | $ | (1,198 | ) | $ | 9,616 | |||||||||
|
Segment profit (loss)
|
$ | 1,574 | $ | (1,343 | ) | $ | 240 | $ | — | $ | 471 | |||||||||
|
Less:
|
||||||||||||||||||||
|
Equity earnings (losses)
|
109 | 20 | 34 | — | 163 | |||||||||||||||
|
Income (loss) from investments
|
— | — | 43 | — | 43 | |||||||||||||||
|
Segment operating income (loss)
|
$ | 1,465 | $ | (1,363 | ) | $ | 163 | $ | — | 265 | ||||||||||
|
General corporate expenses
|
(221 | ) | ||||||||||||||||||
|
Total operating income (loss)
|
$ | 44 | ||||||||||||||||||
|
Other financial information:
|
||||||||||||||||||||
|
Additions to long-lived assets **
|
$ | 904 | $ | 2,859 | $ | 129 | $ | — | $ | 3,892 | ||||||||||
|
Depreciation, depletion & amortization
|
$ | 568 | $ | 895 | $ | 44 | $ | — | $ | 1,507 | ||||||||||
|
2009
|
||||||||||||||||||||
|
Segment revenues:
|
||||||||||||||||||||
|
External
|
$ | 4,359 | $ | 3,143 | $ | 753 | $ | — | $ | 8,255 | ||||||||||
|
Internal
|
243 | 541 | 27 | (811 | ) | — | ||||||||||||||
|
Total revenues
|
$ | 4,602 | $ | 3,684 | $ | 780 | $ | (811 | ) | $ | 8,255 | |||||||||
|
Segment profit (loss)
|
$ | 1,317 | $ | 391 | $ | (2 | ) | $ | — | $ | 1,706 | |||||||||
|
Less:
|
||||||||||||||||||||
|
Equity earnings (losses)
|
81 | 18 | 37 | — | 136 | |||||||||||||||
|
Income (loss) from investments
|
— | — | (75 | ) | — | (75 | ) | |||||||||||||
|
Segment operating income (loss)
|
$ | 1,236 | $ | 373 | $ | 36 | $ | — | 1,645 | |||||||||||
|
General corporate expenses
|
(164 | ) | ||||||||||||||||||
|
Total operating income (loss)
|
$ | 1,481 | ||||||||||||||||||
|
Other financial information:
|
||||||||||||||||||||
|
Additions to long-lived assets
|
$ | 1,023 | $ | 1,304 | $ | 70 | $ | — | $ | 2,397 | ||||||||||
|
Depreciation, depletion & amortization
|
$ | 553 | $ | 868 | $ | 40 | $ | — | $ | 1,461 | ||||||||||
|
2008
|
||||||||||||||||||||
|
Segment revenues:
|
||||||||||||||||||||
|
External
|
$ | 5,545 | $ | 5,130 | $ | 1,215 | $ | — | $ | 11,890 | ||||||||||
|
Internal
|
302 | 1,065 | 42 | (1,409 | ) | — | ||||||||||||||
|
Total revenues
|
$ | 5,847 | $ | 6,195 | $ | 1,257 | $ | (1,409 | ) | $ | 11,890 | |||||||||
|
Segment profit (loss)
|
$ | 1,425 | $ | 1,253 | $ | 142 | $ | — | $ | 2,820 | ||||||||||
|
Less:
|
||||||||||||||||||||
|
Equity earnings (losses)
|
76 | 20 | 41 | — | 137 | |||||||||||||||
|
Income (loss) from investments
|
— | — | 1 | — | 1 | |||||||||||||||
|
Segment operating income (loss)
|
$ | 1,349 | $ | 1,233 | $ | 100 | $ | — | 2,682 | |||||||||||
|
General corporate expenses
|
(149 | ) | ||||||||||||||||||
|
Total operating income (loss)
|
$ | 2,533 | ||||||||||||||||||
|
Other financial information:
|
||||||||||||||||||||
|
Additions to long-lived assets
|
$ | 1,212 | $ | 2,418 | $ | 64 | $ | — | $ | 3,694 | ||||||||||
|
Depreciation, depletion & amortization
|
$ | 518 | $ | 723 | $ | 39 | $ | — | $ | 1,280 | ||||||||||
| * | 2009 and 2008 recast as discussed in Note 1. | |
| ** | Does not include WPZ’s purchase of a business represented by certain gathering and processing assets in Colorado’s Piceance basin from Exploration & Production. (See Note 1.) |
141
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THE
WILLIAMS COMPANIES, INC.
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Total segment revenues for Exploration & Production
include $1,743 million, $1,456 million and
$3,244 million of gas management revenues for the years
ended December 31, 2010, 2009 and 2008, respectively. Gas
management revenues include sales of natural gas in conjunction
with marketing services provided to third parties and
intercompany sales of fuel and shrink gas to the midstream
businesses in Williams Partners. These revenues are
substantially offset by similar amounts of gas management costs.
The following table reflects
total assets
and
equity
method investments
by reporting segment.
| Total Assets | Equity Method Investments | |||||||||||||||||||||||
|
December 31,
|
December 31,
|
December 31,
|
December 31,
|
December 31,
|
December 31,
|
|||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | |||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||
|
Williams Partners*
|
$ | 13,396 | $ | 12,472 | $ | 12,167 | $ | 1,045 | $ | 593 | $ | 524 | ||||||||||||
|
Exploration & Production*
|
9,827 | 10,084 | 11,155 | 104 | 95 | 87 | ||||||||||||||||||
|
Other
|
4,178 | 4,192 | 3,696 | 193 | 196 | 336 | ||||||||||||||||||
|
Eliminations
|
(2,429 | ) | (1,469 | ) | (1,541 | ) | — | — | — | |||||||||||||||
|
Discontinued Operations
|
— | 1 | 529 | — | — | — | ||||||||||||||||||
|
Total
|
$ | 24,972 | $ | 25,280 | $ | 26,006 | $ | 1,342 | $ | 884 | $ | 947 | ||||||||||||
| * | 2009 and 2008 Total Assets recast as discussed in Note 1. |
| Note 19. | Subsequent Events |
On February 16, 2011, we announced that our Board of
Directors approved pursuing a plan to separate the company into
two standalone, publicly traded corporations. The plan calls for
the separation of our exploration and production business into a
publicly traded company via an initial public offering of up to
20 percent of our interest in the third quarter of 2011. We
intend to complete the offering so that it preserves our ability
to complete a tax-free spinoff of our remaining ownership in the
exploration and production business to Williams’
shareholders in 2012, after which Williams would continue as a
premier natural gas infrastructure company. We retain the
discretion to determine whether and when to execute the spinoff.
142
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THE
WILLIAMS COMPANIES, INC.
(Unaudited)
Summarized quarterly financial data are as follows:
|
First
|
Second
|
Third
|
Fourth
|
|||||||||||||
| Quarter | Quarter | Quarter | Quarter | |||||||||||||
| (Millions, except per-share amounts) | ||||||||||||||||
|
2010
|
||||||||||||||||
|
Revenues
|
$ | 2,596 | $ | 2,292 | $ | 2,304 | $ | 2,424 | ||||||||
|
Costs and operating expenses
|
1,922 | 1,723 | 1,752 | 1,788 | ||||||||||||
|
Income (loss) from continuing operations
|
(148 | ) | 224 | (1,221 | ) | 229 | ||||||||||
|
Net income (loss)
|
(146 | ) | 222 | (1,226 | ) | 228 | ||||||||||
|
Amounts attributable to The Williams Companies, Inc.:
|
||||||||||||||||
|
Income (loss) from continuing operations
|
(195 | ) | 187 | (1,258 | ) | 175 | ||||||||||
|
Net income (loss)
|
(193 | ) | 185 | (1,263 | ) | 174 | ||||||||||
|
Basic earnings (loss) per common share:
|
||||||||||||||||
|
Income (loss) from continuing operations
|
(0.33 | ) | 0.32 | (2.15 | ) | 0.30 | ||||||||||
|
Diluted earnings (loss) per common share:
|
||||||||||||||||
|
Income (loss) from continuing operations
|
(0.33 | ) | 0.31 | (2.15 | ) | 0.29 | ||||||||||
|
2009
|
||||||||||||||||
|
Revenues
|
$ | 1,922 | $ | 1,909 | $ | 2,098 | $ | 2,326 | ||||||||
|
Costs and operating expenses
|
1,444 | 1,392 | 1,537 | 1,708 | ||||||||||||
|
Income from continuing operations
|
19 | 151 | 192 | 222 | ||||||||||||
|
Net income (loss)
|
(224 | ) | 169 | 194 | 222 | |||||||||||
|
Amounts attributable to The Williams Companies, Inc.:
|
||||||||||||||||
|
Income from continuing operations
|
2 | 123 | 141 | 172 | ||||||||||||
|
Net income (loss)
|
(172 | ) | 142 | 143 | 172 | |||||||||||
|
Basic earnings per common share:
|
||||||||||||||||
|
Income from continuing operations
|
— | 0.21 | 0.24 | 0.30 | ||||||||||||
|
Diluted earnings per common share:
|
||||||||||||||||
|
Income from continuing operations
|
— | 0.21 | 0.24 | 0.29 | ||||||||||||
The sum of earnings per share for the four quarters may not
equal the total earnings per share for the year due to changes
in the average number of common shares outstanding and
rounding.
Net income
for fourth-quarter 2010 includes the following
pre-tax items:
| • | $19 million unfavorable adjustment to depletion expense related to a correction of prior years’ production volumes used in the calculation of depletion expense at Exploration & Production (see Note 4 of Notes to Consolidated Financial Statements); | |
| • | $11 million unfavorable adjustment to depreciation, depletion and amortization expense related to a correction of prior years’ costs used in the calculation of depreciation, depletion, and amortization expenses at Exploration & Production. |
Net income
for fourth-quarter 2010 also includes the
following tax adjustments:
| • | $66 million provision to reflect taxes on undistributed earnings of certain foreign operations that are no longer consider permanently reinvested (see Note 5); | |
| • | $65 million benefit to decrease state income taxes (net of federal benefit) due to a reduction in our estimate of the effective deferred state rate, including state income tax carryovers (see Note 5). |
Net loss
for third-quarter 2010 includes the following
pre-tax items:
| • | $1,003 million impairment of goodwill at Exploration & Production (see Notes 4 and 14); |
143
Table of Contents
| • | $678 million of impairments of certain producing properties and acquired unproved reserves at Exploration & Production (see Note 4); | |
| • | $30 million gain related to the sale of our 50 percent interest in Accroven at Other (see Note 3); | |
| • | $15 million of exploratory dry hole costs at Exploration & Production (see Note 4); | |
| • | $12 million gain on the sale of certain assets at Williams Partners (see Note 4). |
Net income
for second-quarter 2010 includes the following
pre-tax items:
| • | $13 million gain related to the sale of our 50 percent interest in Accroven at Other (see Note 3); | |
| • | $11 million of involuntary conversion gains due to insurance recoveries that are in excess of the carrying value of assets at Williams Partners (see Note 4). |
Net loss
for first-quarter 2010 includes the following
pre-tax items:
| • | $606 million of early debt retirement costs consisting primarily of cash premiums of $574 million (see Note 4); | |
| • | $39 million of other transaction costs associated with our strategic restructuring transaction, of which $4 million are attributable to noncontrolling interests (see Note 4); | |
| • | $4 million of accelerated amortization of debt costs related to amendments of credit facilities (see Note 4). |
Net income
for fourth-quarter 2009 includes the following
pre-tax items:
| • | $40 million gain related to the sale of our Cameron Meadows processing plant at Williams Partners (see Note 4); | |
| • | $17 million unfavorable depletion adjustment at Exploration & Production primarily as the result of new oil and gas accounting guidance that requires we value our reserves using an average price; | |
| • | $15 million impairment of certain natural gas properties at Exploration & Production (see Note 4). |
Net income
for second-quarter 2009 includes the following
pre-tax items:
| • | $15 million gain related to our former coal operations (see summarized results of discontinued operations at Note 2); | |
| • | $11 million of income related to the recovery of certain royalty overpayments from prior periods at Exploration & Production. |
Net loss
for first-quarter 2009 includes the following
pre-tax items:
| • | $211 million impairment of Venezuela property, plant, and equipment (see summarized results of discontinued operations at Note 2); | |
| • | $75 million impairment of a Venezuelan investment in Accroven at Other (see Note 3); | |
| • | $48 million of bad debt expense related to our discontinued Venezuela operations (see summarized results of discontinued operations at Note 2); | |
| • | $30 million net charge related to the write-off of certain deferred charges related to our discontinued Venezuela operations (see summarized results of discontinued operations at Note 2); | |
| • | $34 million of penalties from early release of drilling rigs at Exploration & Production (see Note 4); | |
| • | $11 million impairment of a Venezuelan cost-based investment at Exploration & Production (see Note 3). |
Net loss
for first-quarter 2009 also includes a
$76 million benefit from the reversal of deferred tax
balances related to our discontinued Venezuela operations (see
summarized results of discontinued operations at Note 2).
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THE
WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(Unaudited)
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(Unaudited)
We have significant oil and gas producing activities primarily
in the Rocky Mountain, Northeast and Mid-continent areas of the
United States. Additionally, we have international oil and gas
producing activities, primarily in Argentina. Proved reserves
and revenues related to international activities are
approximately five percent and three percent, respectively, of
our total international and domestic proved reserves and
revenues from producing activities. Accordingly, the following
information relates only to the oil and gas activities in the
United States. This information also excludes our gas management
activities.
Capitalized
Costs
| As of December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Proved Properties
|
$ | 9,780 | $ | 9,165 | ||||
|
Unproved properties
|
2,170 | 953 | ||||||
| 11,950 | 10,118 | |||||||
|
Accumulated depreciation, depletion and amortization and
valuation provisions
|
(3,864 | ) | (3,212 | ) | ||||
|
Net capitalized costs
|
$ | 8,086 | $ | 6,906 | ||||
| • | Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $320 million and $272 million, net, for 2010 and 2009, respectively. | |
| • | Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs, and successful exploratory wells. | |
| • | Unproved properties consist primarily of unproved leasehold costs and costs for acquired unproven reserves. |
Cost
Incurred
|
For The Year Ended
|
||||||||||||
| December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
Acquisition
|
$ | 1,731 | $ | 305 | $ | 543 | ||||||
|
Exploration
|
22 | 51 | 38 | |||||||||
|
Development
|
988 | 878 | 1,699 | |||||||||
| $ | 2,741 | $ | 1,234 | $ | 2,280 | |||||||
| • | Costs incurred include capitalized and expensed items. | |
| • | Acquisition costs are as follows: The 2010 costs are primarily for additional leasehold in the Williston and Marcellus basins and include approximately $355 million of proved property values. The 2009 costs are primarily for additional leasehold and reserve acquisitions in the Piceance basin, and include $85 million of proved property values. The 2008 costs are primarily for additional leasehold and reserve acquisitions in the Piceance and Fort Worth basins. Included in the 2008 acquisition amounts is $140 million of proved property values and $71 million related to an interest in a portion of acquired assets that a third party subsequently exercised its contractual option to purchase from us, on the same terms and conditions. |
145
Table of Contents
| • | Exploration costs include the costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions, and retaining undeveloped leaseholds. | |
| • | Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins. |
Results
of Operations
| For The Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
Revenues:
|
||||||||||||
|
Oil and gas revenues
|
$ | 2,160 | $ | 2,093 | $ | 2,819 | ||||||
|
Other revenues
|
23 | 42 | 31 | |||||||||
|
Total revenues
|
2,183 | 2,135 | 2,850 | |||||||||
|
Costs:
|
||||||||||||
|
Production costs
|
776 | 627 | 741 | |||||||||
|
General & administrative
|
154 | 151 | 158 | |||||||||
|
Exploration expenses
|
61 | 58 | 27 | |||||||||
|
Depreciation, depletion & amortization
|
878 | 851 | 709 | |||||||||
|
Impairment of certain natural gas properties in the Fort Worth
basin
|
503 | — | — | |||||||||
|
Write down of costs associated with acquired unproven reserves
|
175 | 15 | — | |||||||||
|
Impairment of certain natural gas properties in the Arkoma basin
|
1 | — | 143 | |||||||||
|
Other (income) expense
|
(6 | ) | 34 | 2 | ||||||||
|
Total costs
|
2,542 | 1,736 | 1,780 | |||||||||
|
Results of operations
|
(359 | ) | 399 | 1,070 | ||||||||
|
(Provision) benefit for income taxes
|
134 | (151 | ) | (404 | ) | |||||||
|
Exploration and production net income (loss)
|
$ | (225 | ) | $ | 248 | $ | 666 | |||||
| • | Results of operations for producing activities consist of all related domestic oil and gas producing activities. Prior periods have been recast to reflect the impact of the sale of certain Piceance gathering and processing facilities to WPZ. Amounts for 2010 exclude a $1 billion impairment charge related to goodwill associated with the purchase of Barrett Resources Corporation (Barrett) in 2001. Amounts for 2008 exclude a $148 million gain on sale of a contractual right to a production payment on certain future international hydrocarbon production. | |
| • | Oil and gas revenues consist primarily of natural gas production sold and includes the impact of hedges. | |
| • | Other revenues consist of activities that are not a direct part of the producing activities. Other expenses in 2009 also include $32 million of expense related to penalties from the early release of drilling rigs. | |
| • | Production costs consist of costs incurred to operate and maintain wells and related equipment and facilities used in the production of natural gas. These costs also include production taxes other than income taxes, gathering, processing and transportation expenses (excluding charges for unutilized pipeline capacity), and administrative expenses in support of production activity. Excluded are depreciation, depletion and amortization of capitalized costs. | |
| • | Exploration expenses include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes, and the cost of retaining undeveloped leaseholds including lease amortization and impairments. |
146
Table of Contents
| • | Depreciation, depletion and amortization includes depreciation of support equipment. Amounts for 2010 include $26 million related to corrections of prior years’ production volumes and costs used in the calculation of depreciation, depletion and amortization expense. Additionally, 2009 includes $17 million additional depreciation, depletion and amortization as a result of our recalculation of fourth quarter depreciation, depletion and amortization utilizing our year-end reserves which were lower than 2008. The lower reserves in 2009 were primarily a result of the application of new rules issued by the SEC in 2009. |
Proved
Reserves
| 2010 | 2009 | 2008 | ||||||||||
| (Bcfe) | ||||||||||||
|
Proved reserves at the beginning of period
|
4,255 | 4,339 | 4,143 | |||||||||
|
Revisions
|
(233 | ) | (859 | ) | (220 | ) | ||||||
|
Purchases
|
162 | 159 | 31 | |||||||||
|
Extensions and discoveries
|
508 | 1,051 | 791 | |||||||||
|
Wellhead production
|
(420 | ) | (435 | ) | (406 | ) | ||||||
|
Proved reserves at the end of period
|
4,272 | 4,255 | 4,339 | |||||||||
|
Proved developed reserves at end of period
|
2,498 | 2,387 | 2,456 | |||||||||
| • | The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are generally limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation. | |
| • | Revisions in 2010 primarily relate to the reclassification of reserves from proved to probable reserves attributable to locations not expected to be developed within five years. A significant portion of the revisions for 2009 are a result of the impact of the new SEC rules. Proved reserves are lower because of the lower 12-month average, first-of-the-month price as compared to the 2008 year-end price, and the revision of proved undeveloped reserve estimates based on new guidance. Approximately one-half of the revisions for 2008 relate to the impact of lower average year-end natural gas prices used in 2008 compared to the 2007. | |
| • | Extensions and discoveries in 2009 are higher than other years due in part to the expanded definition of oil and gas reserves supported by reliable technology and reasonable certainty used for reserves estimation. | |
| • | Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit. Crude oil reserves are insignificant and have been included in the proved reserves on a basis of billion cubic feet equivalents (Bcfe). |
147
Table of Contents
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves
The following is based on the estimated quantities of proved
reserves. In 2009, we adopted prescribed accounting revisions
associated with oil and gas authoritative guidance. Those
revisions include using the
12-month
average price computed as an unweighted arithmetic average of
the price as of the first day of each month, unless prices are
defined by contractual arrangements. These revisions are
reflected in our 2010 and 2009 amounts. For the years ended
December 31, 2010 and 2009, the average natural gas
equivalent price used in the estimates was $3.78 and $2.76 per
MMcfe, respectively. For the year ended December 31, 2008,
the average year-end natural gas equivalent price used in the
estimates was $4.41 per MMcfe. Future income tax expenses have
been computed considering applicable taxable cash flows and
appropriate statutory tax rates. The discount rate of
10 percent is as prescribed by authoritative guidance.
Continuation of year-end economic conditions also is assumed.
The calculation is based on estimates of proved reserves, which
are revised over time as new data becomes available. Probable or
possible reserves, which may become proved in the future, are
not considered. The calculation also requires assumptions as to
the timing of future production of proved reserves, and the
timing and amount of future development and production costs. Of
the $2,960 million of future development costs,
approximately 57 percent is estimated to be spent in 2011,
2012, and 2013.
Numerous uncertainties are inherent in estimating volumes and
the value of proved reserves and in projecting future production
rates and timing of development expenditures. Such reserve
estimates are subject to change as additional information
becomes available. The reserves actually recovered and the
timing of production may be substantially different from the
reserve estimates.
Standardized
Measure of Discounted Future Net Cash Flows
| At December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Millions) | ||||||||
|
Future cash inflows
|
$ | 16,151 | $ | 11,729 | ||||
|
Less:
|
||||||||
|
Future production costs
|
4,927 | 3,990 | ||||||
|
Future development costs
|
2,960 | 2,833 | ||||||
|
Future income tax provisions
|
2,722 | 1,404 | ||||||
|
Future net cash flows
|
5,542 | 3,502 | ||||||
|
Less 10 percent annual discount for estimated timing of
cash flows
|
(2,728 | ) | (1,789 | ) | ||||
|
Standardized measure of discounted future net cash inflows
|
$ | 2,814 | $ | 1,713 | ||||
148
Table of Contents
Sources
of Change in Standardized Measure of Discounted Future Net Cash
Flows
| 2010 | 2009 | 2008 | ||||||||||
| (Millions) | ||||||||||||
|
Standardized measure of discounted future net cash flows
beginning of period
|
$ | 1,713 | $ | 3,173 | $ | 4,803 | ||||||
|
Changes during the year:
|
||||||||||||
|
Sales of oil and gas produced, net of operating costs
|
(1,446 | ) | (1,006 | ) | (2,091 | ) | ||||||
|
Net change in prices and production costs
|
1,921 | (3,310 | ) | (2,548 | ) | |||||||
|
Extensions, discoveries and improved recovery, less estimated
future costs
|
724 | 1,131 | 1,423 | |||||||||
|
Development costs incurred during year
|
633 | 389 | 817 | |||||||||
|
Changes in estimated future development costs
|
(292 | ) | 701 | (724 | ) | |||||||
|
Purchase of reserves in place, less estimated future costs
|
439 | 171 | 55 | |||||||||
|
Revisions of previous quantity estimates
|
(332 | ) | (923 | ) | (395 | ) | ||||||
|
Accretion of discount
|
220 | 450 | 714 | |||||||||
|
Net change in income taxes
|
(758 | ) | 932 | 1,108 | ||||||||
|
Other
|
(8 | ) | 5 | 11 | ||||||||
|
Net changes
|
1,101 | (1,460 | ) | (1,630 | ) | |||||||
|
Standardized measure of discounted future net cash flows end of
period
|
$ | 2,814 | $ | 1,713 | $ | 3,173 | ||||||
In relation to the SEC rules adopted in 2009, we estimated that
the standardized measure of discounted future net cash flows in
2009 declined approximately $840 million on a before tax
basis and excluding the overall price rule impact. The
significant components of this decline included an estimated
$640 million decrease included in revisions of previous
quantity estimates and a related $430 million decrease
included in the net change in prices and production costs,
partially offset by a $210 million increase included in
extensions, discoveries and improved recovery, less estimated
future costs. Additionally, we estimated that a significant
portion of the remaining net change in price and production
costs is due to the application of the new pricing rules which
resulted in the use of lower prices at December 31, 2009,
than would have resulted under the previous rules.
149
Table of Contents
THE
WILLIAMS COMPANIES, INC.
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
| ADDITIONS | ||||||||||||||||||||
|
Charged
|
||||||||||||||||||||
|
(Credited)
|
||||||||||||||||||||
|
Beginning
|
To Costs and
|
Ending
|
||||||||||||||||||
| Balance | Expenses | Other | Deductions | Balance | ||||||||||||||||
| (Millions) | ||||||||||||||||||||
|
2010:
|
||||||||||||||||||||
|
Allowance for doubtful accounts - accounts and notes
receivable(a)
|
$ | 22 | $ | (6 | ) | $ | — | $ | 1 | (c) | $ | 15 | ||||||||
|
Deferred tax asset valuation allowance(a)
|
289 | (40 | ) | — | — | 249 | ||||||||||||||
|
Price-risk management credit reserves — liabilities(b)
|
(3 | ) | 3 | (d) | — | — | — | |||||||||||||
|
2009:
|
||||||||||||||||||||
|
Allowance for doubtful accounts -accounts and notes receivable(a)
|
29 | 4 | — | 11 | (c) | 22 | ||||||||||||||
|
Deferred tax asset valuation allowance(a)
|
224 | 65 | — | — | 289 | |||||||||||||||
|
Price-risk management credit reserves — assets(a)
|
6 | (3 | )(d) | (3 | )(e) | — | — | |||||||||||||
|
Price-risk management credit reserves — liabilities(b)
|
(15 | ) | 12 | (d) | — | — | (3 | ) | ||||||||||||
|
2008:
|
||||||||||||||||||||
|
Allowance for doubtful accounts - accounts and notes
receivable(a)
|
16 | 15 | — | 2 | (c) | 29 | ||||||||||||||
|
Deferred tax asset valuation allowance(a)
|
274 | (14 | ) | — | 36 | (c) | 224 | |||||||||||||
|
Price-risk management credit reserves — assets(a)
|
1 | 1 | (d) | 4 | (e) | — | 6 | |||||||||||||
|
Price-risk management credit reserves — liabilities(b)
|
— | (16 | )(d) | 1 | (e) | — | (15 | ) | ||||||||||||
| (a) | Deducted from related assets. | |
| (b) | Deducted from related liabilities. | |
| (c) | Represents balances written off, reclassifications and recoveries. | |
| (d) | Included in revenues . | |
| (e) | Included in accumulated other comprehensive income (loss) . |
150
Table of Contents
| 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 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 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 the company have
been detected. These inherent limitations include the realities
that judgments in decision-making can be faulty, and that
breakdowns can occur because of simple error or mistake.
Additionally, controls can be circumvented by the individual
acts of some persons, by collusion of two or more people, or by
management override of the control. The design of any system of
controls also is based in part upon certain assumptions about
the likelihood of future events, and there can be no assurance
that any design will succeed in achieving its stated goals under
all potential future conditions. Because of the inherent
limitations in a cost-effective control system, misstatements
due to error or fraud may occur and not be detected. We monitor
our Disclosure Controls and make modifications as necessary; our
intent in this regard is that the Disclosure Controls will be
modified as systems change and conditions warrant.
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 Chief Executive Officer and Chief
Financial Officer. Based upon that evaluation, our Chief
Executive Officer and Chief Financial Officer concluded that
these Disclosure Controls are effective at a reasonable
assurance level.
Management’s
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 2010
that have materially affected, or are reasonably likely to
materially affect, our Internal Controls over financial
reporting.
| Item 9B. | Other Information |
None.
PART III
| Item 10. | Directors, Executive Officers and Corporate Governance |
The information regarding our directors and nominees for
director required by Item 401 of
Regulation S-K
will be presented under the heading.
“Proposal 1 — Election of Directors” in
our Proxy Statement prepared for the solicitation of proxies in
connection with our Annual Meeting of Stockholders to be held
May 19, 2011 (Proxy Statement), which information is
incorporated by reference herein.
151
Table of Contents
Information regarding our executive officers required by
Item 401(b) of
Regulation S-K
is presented at the end of Part I herein and captioned
“Executive Officers of the Registrant” as permitted by
General Instruction G(3) to
Form 10-K
and Instruction 3 to Item 401(b) of
Regulation S-K.
Information required by Item 405 of
Regulation S-K
will be included under the heading “Section 16(a)
Beneficial Ownership Reporting Compliance” in our Proxy
Statement, which information is incorporated by reference herein.
Information required by paragraphs (c)(3), (d)(4) and (d)(5) of
Item 407 of
Regulation S-K
will be included under the heading “Questions and Answers
About the Annual Meeting and Voting” and “Corporate
Governance and Board Matters” in our Proxy Statement, which
information is incorporated by reference herein.
We have adopted a Code of Ethics for Senior Officers that
applies to our Chief Executive Officer, Chief Financial Officer,
and Controller, or persons performing similar functions. The
Code of Ethics for Senior Officers, together with our Corporate
Governance Guidelines, the charters for each of our board
committees, and our Code of Business Conduct applicable to all
employees are available on our Internet website at
http://www.williams.com.
We will provide, free of charge, a copy of our Code of
Ethics or any of our other corporate documents listed above upon
written request to our Corporate Secretary at Williams, One
Williams Center, Suite 4700, Tulsa, Oklahoma 74172. We
intend to disclose any amendments to or waivers of the Code of
Ethics on behalf of our Chief Executive Officer, Chief Financial
Officer, Controller, and persons performing similar functions on
our Internet website at
http://www.williams.com
under the Investor Relations caption, promptly following the
date of any such amendment or waiver.
| Item 11. | Executive Compensation |
The information required by Item 402 and paragraphs (e)(4)
and (e)(5) of Item 407 of
Regulation S-K
regarding executive compensation will be presented under the
headings “Compensation Discussion and Analysis,”
“Executive Compensation and Other Information,”
“Compensation of Directors,” and “Compensation
Committee Report on Executive Compensation” in our Proxy
Statement, which information is incorporated by reference
herein. Notwithstanding the foregoing, the information provided
under the heading “Compensation Committee Report on
Executive Compensation” in our Proxy Statement is furnished
and shall not be deemed to be filed for purposes of
Section 18 of the Securities Exchange Act of 1934, as
amended, is not subject to the liabilities of that section and
is not deemed incorporated by reference in any filing under the
Securities Act of 1933, as amended.
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The information regarding securities authorized for issuance
under equity compensation plans required by Item 201(d) of
Regulation S-K
and the security ownership of certain beneficial owners and
management required by Item 403 of
Regulation S-K
will be presented under the headings “Equity Compensation
Stock Plans” and “Security Ownership of Certain
Beneficial Owners and Management” in our Proxy Statement,
which information is incorporated by reference herein.
| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
The information regarding certain relationships and related
transactions required by Item 404 and Item 407(a) of
Regulation S-K
will be presented under the heading “Corporate Governance
and Board Matters” in our Proxy Statement, which
information is incorporated by reference herein.
| Item 14. | Principal Accountant Fees and Services |
The information regarding our principal accountant fees and
services required by Item 9(e) of Schedule 14A will be
presented under the heading “Ratification of the
Appointment of Independent Auditors — Principal
Accounting Fees and Services” in our Proxy Statement, which
information is incorporated by reference herein.
152
PART IV
| Item 15. | Exhibits and Financial Statement Schedules |
(a) 1 and 2.
| Page | ||||
|
Covered by report of independent auditors:
|
||||
| 84 | ||||
| 85 | ||||
| 86 | ||||
| 87 | ||||
| 88 | ||||
|
Schedule for each year in the three-year period ended
December 31, 2010:
|
||||
| 150 | ||||
|
Not covered by report of independent auditors:
|
||||
| 143 | ||||
| 145 | ||||
All other schedules have been omitted since the required
information is not present or is not present in amounts
sufficient to require submission of the schedule, or because the
information required is included in the financial statements and
notes thereto.
(a) 3 and (b). The exhibits listed below are filed as part
of this annual report.
INDEX TO
EXHIBITS
| Exhibit No. | Description | |||
|
3.1
|
— | Amended and Restated Certificate of Incorporation, as supplemented (filed on May 26, 2010 as Exhibit 3.1 to the Company’s Form 8-K) and incorporated herein by reference. | ||
|
3.2
|
— | By-Laws (filed on May 26, 2010 as Exhibit 3.2 to the Company’s Current Report on Form 8-K) and incorporated herein by reference. | ||
|
4.1
|
— | Form of Senior Debt Indenture between Williams and Bank One Trust company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on September 8, 1997 as Exhibit 4.1 to The Williams Companies, Inc.’s Form S-3) and incorporated herein by reference. | ||
|
4.2
|
— | Fifth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed on March 12, 2001 as Exhibit 4(k) to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
4.3
|
— | Seventh Supplemental Indenture dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed on May 9, 2002 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
4.4
|
— | Senior Indenture dated February 25, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed February 25, 1997 as Exhibit 4.4.1 to MAPCO Inc.’s Amendment No. 1 to Form S-3) and incorporated herein by reference. | ||
|
4.5
|
— | Supplemental Indenture No. 1 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(o) to MAPCO Inc.’s Form 10-K for the fiscal year ended December 31, 1997) and incorporated herein by reference. |
153
Table of Contents
| Exhibit No. | Description | |||
|
4.6
|
— | Supplemental Indenture No. 2 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(p) to MAPCO Inc.’s Form 10-K for the fiscal year ended December 31, 1997) and incorporated herein by reference. | ||
|
4.7
|
— | Supplemental Indenture No. 3 dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(j) to Williams Holdings of Delaware, Inc.’s Form 10-K for the fiscal year ended December 31, 1998) and incorporated herein by reference. | ||
|
4.8
|
— | Supplemental Indenture No. 4 dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on March 28, 2000 as Exhibit 4(q) to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
4.9
|
— | Indenture dated as of May 28, 2003, by and between The Williams Companies, Inc. and JPMorgan Chase Bank, as Trustee for the issuance of the 5.50% Junior Subordinated Convertible Debentures due 2033 (filed on August 12, 2003 as Exhibit 4.2 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
4.10
|
— | Indenture dated as of March 5, 2009, among The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on March 11, 2009 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.11
|
— | Eleventh Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.12
|
— | First Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.2 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.13
|
— | Fifth Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.3 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.14
|
— | Amended and Restated Rights Agreement dated September 21, 2004 by and between The Williams Companies, Inc. and EquiServe Trust Company, N.A., as Rights Agent (filed on September 24, 2004 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.15
|
— | Amendment No. 1 dated May 18, 2007 to the Amended and Restated Rights Agreement dated September 21, 2004 (filed on May 22, 2007 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.16
|
— | Amendment No. 2 dated October 12, 2007 to the Amended and Restated Rights Agreement dated September 21, 2004 (filed on October 15, 2007 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
4.17
|
— | Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank, Trustee with regard to Northwest Pipeline’s 7.125% Debentures, due 2025 (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline’s Form S-3) and incorporated herein by reference. | ||
|
4.18
|
— | Indenture dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee, with regard to Northwest Pipeline’s $175 million aggregate principal amount of 7.00% Senior Notes due 2016 (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline’s Form 8-K) and incorporated herein by reference. | ||
|
4.19
|
— | 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 Corporation’s Form 8-K) (Commission File number 001-07414) and incorporated herein by reference. |
154
Table of Contents
| Exhibit No. | Description | |||
|
4.20
|
— | 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 GP’s Form 8-K) and incorporated herein by reference. | ||
|
4.21
|
— | 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 Corporation’s Form S-3) and incorporated herein by reference. | ||
|
4.22
|
— | 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 Corporation’s Form S-4) and incorporated herein by reference. | ||
|
4.23
|
— | 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) and incorporated herein by reference. | ||
|
4.24
|
— | 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 Line’s $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 Corporation’s Form 8-K) and incorporated herein by reference. | ||
|
4.25
|
— | 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 Corporation’s Form 8-K) and incorporated herein by reference. | ||
|
4.26
|
— | 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. Form 8-K) and incorporated herein by reference. | ||
|
4.27
|
— | 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. Form 8-K) and incorporated herein by reference. | ||
|
4.28
|
— | 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 The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.1
|
— | The Williams Companies Amended and Restated Retirement Restoration Plan effective January 1, 2008 (filed on February 25, 2009 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.2
|
— | The Williams Companies, Inc. 1996 Stock Plan (filed on March 27, 1996 as Exhibit A to The Williams Companies, Inc.’s Proxy Statement) and incorporated herein by reference. | ||
|
10.3
|
— | The Williams Companies, Inc. 1996 Stock Plan for Non-employee Directors (filed on March 27, 1996 as Exhibit B to The Williams Companies, Inc.’s Proxy Statement) and incorporated herein by reference. | ||
|
10.4
|
— | Form of Director and Officer Indemnification Agreement (filed on September 24, 2008 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.5*
|
— | Form of 2011 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers. | ||
|
10.6*
|
— | Form of 2011 Restricted Stock Unit Agreement among Williams and certain employees and officers. | ||
|
10.7*
|
— | Form of 2011 Nonqualified Stock Option Agreement among Williams and certain employees and officers. | ||
|
10.8*
|
— | Form of 2010 Restricted Stock Unit Agreement among Williams and non-management directors. |
155
Table of Contents
| Exhibit No. | Description | |||
|
10.9
|
— | The Williams Companies, Inc. 2002 Incentive Plan as amended and restated effective as of January 23, 2004 (filed on August 5, 2004 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
10.10
|
— | Amendment No. 1 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009 as Exhibit 10.11 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.11
|
— | Amendment No. 2 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009 as Exhibit 10.12 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.12
|
— | The Williams Companies, Inc. 2007 Incentive Plan (filed on April 8, 2010 as Appendix B to The Williams Companies, Inc.’s Definitive Proxy Statement 14A) and incorporated herein by reference. | ||
|
10.13
|
— | The Williams Companies, Inc. Employee Stock Purchase Plan (filed on April 10, 2007 as Appendix D to The Williams Companies, Inc.’s Definitive Proxy Statement 14A) and incorporated herein by reference. | ||
|
10.14
|
— | Amendment No. 1 to The Williams Companies, Inc. Employee Stock Purchase (filed on February 25, 2009 as Exhibit 10.16 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference Plan. | ||
|
10.15
|
— | Amendment No. 2 to The Williams Companies, Inc. Employee Stock Purchase Plan (filed on February 25, 2009 as Exhibit 10.17 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.16
|
— | Amendment No. 3 to The Williams Companies, Inc. Employee Stock Purchase Plan (filed on February 25, 2010 as Exhibit 10.17 the The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.17
|
— | Amendment No. 4 to The Williams Companies, Inc. Employee Stock Purchase Plan (filed on February 25, 2010 as Exhibit 10.17 the The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.18
|
— | Amended and Restated Change-in-Control Severance Agreement between the Company and certain executive officers (filed on February 25, 2009 as Exhibit 10.18 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
10.19
|
— | Amendment Agreement, dated May 9, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed on October 28, 2010as Exhibit 10.1 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
10.20
|
— | Amendment Agreement dated November 21, 2007 among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline GP, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed on November 28, 2007 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.21
|
— | Credit Agreement dated as of May 1, 2006, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and Williams Partners L.P., as Borrowers and Citibank, N.A., as Administrative Agent (filed on October 28, 2010 as Exhibit 10.2 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
10.22
|
— | Credit Agreement dated February 23, 2007 among Williams Production RMT Company, Williams Production Company, LLC, Citibank, N.A., Citigroup Energy Inc., Calyon New York Branch, and the banks named therein, and Citigroup Global Markets Inc. and Calyon New York Branch as joint lead arrangers and co-book runners (filed on October 28, 2010 as Exhibit 10.3 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. |
156
Table of Contents
| Exhibit No. | Description | |||
|
10.23
|
— | First Amendment dated as of March 30, 2007 to Credit Agreement dated as of February 23, 2007 among Williams Production RMT Company, Williams Production Company, LLC, Citibank, N.A., Citigroup Energy Inc., Calyon New York Branch, and the banks named therein, and Citigroup Global Markets Inc. and Calyon New York Branch as joint lead arrangers and co-book runners (filed on October 28, 2010 as Exhibit 10.4 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
10.24*
|
— | Second Amendment dated as of June 10, 2008 to Credit Agreement dated as of February 23, 2007 among Williams Production RMT Company, Williams Production Company, LLC, Citibank, N.A., Citigroup Energy Inc., Calyon New York Branch, and the banks named therein, and Citigroup Global Markets Inc. and Calyon New York Branch as joint lead arrangers and co-book runners (filed on October 28, 2010 as Exhibit 10.4 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
10.25*
|
— | Third Amendment dated as of July 12, 2010 to Credit Agreement dated as of February 23, 2007 among Williams Production RMT Company, Williams Production Company, LLC, Citibank, N.A., Citigroup Energy Inc., Calyon New York Branch, and the banks named therein, and Citigroup Global Markets Inc. and Calyon New York Branch as joint lead arrangers and co-book runners (filed on October 28, 2010 as Exhibit 10.4 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
10.26
|
— | 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 The Williams Companies Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
10.27
|
— | 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 July 29, 2010 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 10-Q) and incorporated herein by reference. | ||
|
12*
|
— | Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements. | ||
|
14
|
— | Code of Ethics for Senior Officers (filed on March 15, 2004 as Exhibit 14 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
21*
|
— | Subsidiaries of the registrant. | ||
|
23.1*
|
— | Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP. | ||
|
23.2*
|
— | Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP. | ||
|
23.3*
|
— | Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc. | ||
|
23.4*
|
— | Consent of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD. | ||
|
24*
|
— | Power of Attorney. | ||
|
31.1*
|
— | Certification of the Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
|
31.2*
|
— | Certification of the Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
|
32**
|
— | Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
|
99.1*
|
— | Report of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc. | ||
|
99.2*
|
— | Report of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD. | ||
|
101.INS**
|
— | XBRL Instance Document |
157
Table of Contents
| Exhibit No. | Description | |||
|
101.SCH**
|
— | XBRL Taxonomy Extension Schema | ||
|
101.CAL**
|
— | XBRL Taxonomy Extension Calculation Linkbase | ||
|
101.DEF**
|
— | XBRL Taxonomy Extension Definition Linkbase | ||
|
101.LAB**
|
— | XBRL Taxonomy Extension Label Linkbase | ||
|
101.PRE**
|
— | XBRL Taxonomy Extension Presentation Linkbase |
| * | Filed herewith |
| ** | Furnished herewith |
158
Table of Contents
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.
The Williams Companies,
Inc.
(Registrant)
| By: |
/s/
Ted
T. Timmermans
|
Ted T. Timmermans
Controller
Date: February 24, 2011
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/
Alan
S. Armstrong
|
President, Chief Executive Officer
and Director (Principal Executive Officer) |
February 24, 2011 | ||||
|
/s/
Donald
R. Chappel
|
Senior Vice President and Chief Financial Officer (Principal Financial Officer) | February 24, 2011 | ||||
|
/s/
Ted
T. Timmermans
|
Controller (Principal Accounting Officer) | February 24, 2011 | ||||
|
/s/
Joseph
R. Cleveland*
|
Director | February 24, 2011 | ||||
|
/s/
Kathleen
B. Cooper*
|
Director | February 24, 2011 | ||||
|
/s/
Irl
F. Engelhardt*
|
Director | February 24, 2011 | ||||
|
/s/
William
R. Granberry*
|
Director | February 24, 2011 | ||||
|
/s/
William
E. Green*
|
Director | February 24, 2011 | ||||
|
/s/
Juanita
H. Hinshaw*
|
Director | February 24, 2011 | ||||
|
/s/
W.R.
Howell*
|
Director | February 24, 2011 | ||||
159
Table of Contents
| Signature | Title | Date | ||||
|
/s/
George
A. Lorch*
|
Director | February 24, 2011 | ||||
|
/s/
William
G. Lowrie*
|
Director | February 24, 2011 | ||||
|
/s/
Frank
T. MacInnis*
|
Chairman of the Board | February 24, 2011 | ||||
|
/s/
Janice
D. Stoney*
|
Director | February 24, 2011 | ||||
|
/s/
Laura
A. Sugg*
|
Director | February 24, 2011 | ||||
| *By: |
/s/
La Fleur
C. Browne
Attorney-in-Fact |
February 24, 2011 | ||||
160
Table of Contents
INDEX TO EXHIBITS
| Exhibit | ||||
| No. | Description | |||
|
3.1
|
— | Amended and Restated Certificate of Incorporation, as supplemented (filed on May 26, 2010 as Exhibit 3.1 to the Company’s Form 8-K) and incorporated herein by reference. | ||
|
|
||||
|
3.2
|
— | By-Laws (filed on May 26, 2010 as Exhibit 3.2 to the Company’s Current Report on Form 8-K) and incorporated herein by reference. | ||
|
|
||||
|
4.1
|
— | Form of Senior Debt Indenture between Williams and Bank One Trust company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on September 8, 1997 as Exhibit 4.1 to The Williams Companies, Inc.’s Form S-3) and incorporated herein by reference. | ||
|
|
||||
|
4.2
|
— | Fifth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed on March 12, 2001 as Exhibit 4(k) to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
|
||||
|
4.3
|
— | Seventh Supplemental Indenture dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed on May 9, 2002 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
|
||||
|
4.4
|
— | Senior Indenture dated February 25, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed February 25, 1997 as Exhibit 4.4.1 to MAPCO Inc.’s Amendment No. 1 to Form S-3) and incorporated herein by reference. | ||
|
|
||||
|
4.5
|
— | Supplemental Indenture No. 1 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(o) to MAPCO Inc.’s Form 10-K for the fiscal year ended December 31, 1997) and incorporated herein by reference. | ||
|
|
||||
|
4.6
|
— | Supplemental Indenture No. 2 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(p) to MAPCO Inc.’s Form 10-K for the fiscal year ended December 31, 1997) and incorporated herein by reference. | ||
|
|
||||
|
4.7
|
— | Supplemental Indenture No. 3 dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(j) to Williams Holdings of Delaware, Inc.’s Form 10-K for the fiscal year ended December 31, 1998) and incorporated herein by reference. | ||
|
|
||||
|
4.8
|
— | Supplemental Indenture No. 4 dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on March 28, 2000 as Exhibit 4(q) to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
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||||
|
4.9
|
— | Indenture dated as of May 28, 2003, by and between The Williams Companies, Inc. and JPMorgan Chase Bank, as Trustee for the issuance of the 5.50% Junior Subordinated Convertible Debentures due 2033 (filed on August 12, 2003 as Exhibit 4.2 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
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|
||||
|
4.10
|
— | Indenture dated as of March 5, 2009, among The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee (filed on March 11, 2009 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. |
Table of Contents
| Exhibit | ||||
| No. | Description | |||
|
4.11
|
— | Eleventh Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
4.12
|
— | First Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.2 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
4.13
|
— | Fifth Supplemental Indenture dated as of February 1, 2010 between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.3 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
4.14
|
— | Amended and Restated Rights Agreement dated September 21, 2004 by and between The Williams Companies, Inc. and EquiServe Trust Company, N.A., as Rights Agent (filed on September 24, 2004 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
4.15
|
— | Amendment No. 1 dated May 18, 2007 to the Amended and Restated Rights Agreement dated September 21, 2004 (filed on May 22, 2007 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
4.16
|
— | Amendment No. 2 dated October 12, 2007 to the Amended and Restated Rights Agreement dated September 21, 2004 (filed on October 15, 2007 as Exhibit 4.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
4.17
|
— | Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank, Trustee with regard to Northwest Pipeline’s 7.125% Debentures, due 2025 (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline’s Form S-3) and incorporated herein by reference. | ||
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|
||||
|
4.18
|
— | Indenture dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee, with regard to Northwest Pipeline’s $175 million aggregate principal amount of 7.00% Senior Notes due 2016 (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline’s Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
4.19
|
— | 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 Corporation’s Form 8-K) (Commission File number 001-07414) and incorporated herein by reference. | ||
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|
||||
|
4.20
|
— | 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 GP’s Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
4.21
|
— | 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 Corporation’s Form S-3) and incorporated herein by reference. | ||
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|
||||
|
4.22
|
— | 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 Corporation’s Form S-4) and incorporated herein by reference. |
Table of Contents
| Exhibit | ||||
| No. | Description | |||
|
4.23
|
— | 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) and incorporated herein by reference. | ||
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|
||||
|
4.24
|
— | 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 Line’s $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 Corporation’s Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
4.25
|
— | 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 Corporation’s Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
4.26
|
— | 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. Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
4.27
|
— | 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. Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
4.28
|
— | 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 The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
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|
||||
|
10.1
|
— | The Williams Companies Amended and Restated Retirement Restoration Plan effective January 1, 2008 (filed on February 25, 2009 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
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|
||||
|
10.2
|
— | The Williams Companies, Inc. 1996 Stock Plan (filed on March 27, 1996 as Exhibit A to The Williams Companies, Inc.’s Proxy Statement) and incorporated herein by reference. | ||
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|
||||
|
10.3
|
— | The Williams Companies, Inc. 1996 Stock Plan for Non-employee Directors (filed on March 27, 1996 as Exhibit B to The Williams Companies, Inc.’s Proxy Statement) and incorporated herein by reference. | ||
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|
||||
|
10.4
|
— | Form of Director and Officer Indemnification Agreement (filed on September 24, 2008 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
|
||||
|
10.5*
|
— | Form of 2011 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers. | ||
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|
||||
|
10.6*
|
— | Form of 2011 Restricted Stock Unit Agreement among Williams and certain employees and officers. | ||
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|
||||
|
10.7*
|
— | Form of 2011 Nonqualified Stock Option Agreement among Williams and certain employees and officers. | ||
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|
||||
|
10.8*
|
— | Form of 2010 Restricted Stock Unit Agreement among Williams and non-management directors. |
Table of Contents
| Exhibit | ||||
| No. | Description | |||
|
10.9
|
— | The Williams Companies, Inc. 2002 Incentive Plan as amended and restated effective as of January 23, 2004 (filed on August 5, 2004 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
|
||||
|
10.10
|
— | Amendment No. 1 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009 as Exhibit 10.11 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
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|
||||
|
10.11
|
— | Amendment No. 2 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25, 2009 as Exhibit 10.12 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
|
||||
|
10.12
|
— | The Williams Companies, Inc. 2007 Incentive Plan (filed on April 8, 2010 as Appendix B to The Williams Companies, Inc.’s Definitive Proxy Statement 14A) and incorporated herein by reference. | ||
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|
||||
|
10.13
|
— | The Williams Companies, Inc. Employee Stock Purchase Plan (filed on April 10, 2007 as Appendix D to The Williams Companies, Inc.’s Definitive Proxy Statement 14A) and incorporated herein by reference. | ||
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|
||||
|
10.14
|
— | Amendment No. 1 to The Williams Companies, Inc. Employee Stock Purchase (filed on February 25, 2009 as Exhibit 10.16 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference Plan. | ||
|
|
||||
|
10.15
|
— | Amendment No. 2 to The Williams Companies, Inc. Employee Stock Purchase Plan (filed on February 25, 2009 as Exhibit 10.17 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
|
||||
|
10.16
|
— | Amendment No. 3 to The Williams Companies, Inc. Employee Stock Purchase Plan (filed on February 25, 2010 as Exhibit 10.17 the The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
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|
||||
|
10.17
|
— | Amendment No. 4 to The Williams Companies, Inc. Employee Stock Purchase Plan (filed on February 25, 2010 as Exhibit 10.17 The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
|
||||
|
10.18
|
— | Amended and Restated Change-in-Control Severance Agreement between the Company and certain executive officers (filed on February 25, 2009 as Exhibit 10.18 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
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|
||||
|
10.19
|
— | Amendment Agreement, dated May 9, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed on October 28, 2010as Exhibit 10.1 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
|
||||
|
10.20
|
— | Amendment Agreement dated November 21, 2007 among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline GP, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (filed on November 28, 2007 as Exhibit 10.1 to The Williams Companies, Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
|
||||
|
10.21
|
— | Credit Agreement dated as of May 1, 2006, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and Williams Partners L.P., as Borrowers and Citibank, N.A., as Administrative Agent (filed on October 28, 2010 as Exhibit 10.2 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. |
Table of Contents
| Exhibit | ||||
| No. | Description | |||
|
10.22
|
— | Credit Agreement dated February 23, 2007 among Williams Production RMT Company, Williams Production Company, LLC, Citibank, N.A., Citigroup Energy Inc., Calyon New York Branch, and the banks named therein, and Citigroup Global Markets Inc. and Calyon New York Branch as joint lead arrangers and co-book runners (filed on October 28, 2010 as Exhibit 10.3 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
|
||||
|
10.23
|
— | First Amendment dated as of March 30, 2007 to Credit Agreement dated as of February 23, 2007 among Williams Production RMT Company, Williams Production Company, LLC, Citibank, N.A., Citigroup Energy Inc., Calyon New York Branch, and the banks named therein, and Citigroup Global Markets Inc. and Calyon New York Branch as joint lead arrangers and co-book runners (filed on October 28, 2010 as Exhibit 10.4 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
|
||||
|
10.24*
|
— | Second Amendment dated as of June 10, 2008 to Credit Agreement dated as of February 23, 2007 among Williams Production RMT Company, Williams Production Company, LLC, Citibank, N.A., Citigroup Energy Inc., Calyon New York Branch, and the banks named therein, and Citigroup Global Markets Inc. and Calyon New York Branch as joint lead arrangers and co-book runners (filed on October 28, 2010 as Exhibit 10.4 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
|
||||
|
10.25*
|
— | Third Amendment dated as of July 12, 2010 to Credit Agreement dated as of February 23, 2007 among Williams Production RMT Company, Williams Production Company, LLC, Citibank, N.A., Citigroup Energy Inc., Calyon New York Branch, and the banks named therein, and Citigroup Global Markets Inc. and Calyon New York Branch as joint lead arrangers and co-book runners (filed on October 28, 2010 as Exhibit 10.4 to The Williams Companies, Inc.’s Form 10-Q) and incorporated herein by reference. | ||
|
|
||||
|
10.26
|
— | 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 The Williams Companies Inc.’s Form 8-K) and incorporated herein by reference. | ||
|
|
||||
|
10.27
|
— | 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 July 29, 2010 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 10-Q) and incorporated herein by reference. | ||
|
|
||||
|
12*
|
— | Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements. | ||
|
|
||||
|
14
|
— | Code of Ethics for Senior Officers (filed on March 15, 2004 as Exhibit 14 to The Williams Companies, Inc.’s Form 10-K) and incorporated herein by reference. | ||
|
|
||||
|
21*
|
— | Subsidiaries of the registrant. | ||
|
|
||||
|
23.1*
|
— | Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP. | ||
|
|
||||
|
23.2*
|
— | Consent of Independent Registered Public Accounting Firms, Deloitte & Touche LLP. | ||
|
|
||||
|
23.3*
|
— | Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc. |
Table of Contents
| Exhibit | ||||
| No. | Description | |||
|
23.4*
|
— | Consent of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD. | ||
|
|
||||
|
24*
|
— | Power of Attorney. | ||
|
|
||||
|
31.1*
|
— | Certification of the Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
|
|
||||
|
31.2*
|
— | Certification of the Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
|
|
||||
|
32**
|
— | Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | ||
|
|
||||
|
99.1*
|
— | Report of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc. | ||
|
|
||||
|
99.2*
|
— | Report of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD. | ||
|
|
||||
|
101.INS**
|
— | XBRL Instance Document | ||
|
|
||||
|
101.SCH**
|
— | XBRL Taxonomy Extension Schema | ||
|
|
||||
|
101.CAL**
|
— | XBRL Taxonomy Extension Calculation Linkbase | ||
|
|
||||
|
101.DEF**
|
— | XBRL Taxonomy Extension Definition Linkbase | ||
|
|
||||
|
101.LAB**
|
— | XBRL Taxonomy Extension Label Linkbase | ||
|
|
||||
|
101.PRE**
|
— | XBRL Taxonomy Extension Presentation Linkbase |
| * | Filed herewith | |
| ** | Furnished herewith |
TABLE OF CONTENTS
Part IprintItem 1. BusinessprintItem 1A. Risk FactorsprintItem 1B. Unresolved Staff CommentsprintItem 2. PropertiesprintItem 3. Legal ProceedingsprintPart IIprintItem 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesprintItem 6. Selected Financial DataprintItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsprintItem 7A. Quantitative and Qualitative Disclosures About Market RiskprintItem 8. Financial Statements and Supplementary DataprintNote 1. Description Of Business, Basis Of Presentation, and Summary Of Significant Accounting PoliciesprintNote 2. Discontinued OperationsprintNote 3. Investing ActivitiesprintNote 4. Asset Sales, Impairments and Other AccrualsprintNote 5. Provision (benefit) For Income TaxesprintNote 6. Earnings (loss) Per Common Share From Continuing OperationsprintNote 7. Employee Benefit PlansprintNote 8. InventoriesprintNote 9. Property, Plant, and EquipmentprintNote 10. Accounts Payable and Accrued LiabilitiesprintNote 11. Debt, Leases, and Banking ArrangementsprintNote 12. Stockholders EquityprintNote 13. Stock-based CompensationprintNote 14. Fair Value MeasurementsprintNote 15. Financial Instruments, Derivatives, Guarantees and Concentration Of Credit RiskprintNote 16. Contingent Liabilities and CommitmentsprintNote 17. Accumulated Other Comprehensive LossprintNote 18. Segment DisclosuresprintNote 19. Subsequent EventsprintItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureprintItem 9A. Controls and ProceduresprintItem 9B. Other InformationprintPart IIIprintItem 10. Directors, Executive Officers and Corporate GovernanceprintItem 11. Executive CompensationprintItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersprintItem 13. Certain Relationships and Related Transactions, and Director IndependenceprintItem 14. Principal Accountant Fees and ServicesprintPart IVprintItem 15. Exhibits and Financial Statement Schedulesprint