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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
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(Mark One)
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
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For the fiscal year ended December 31, 2004 |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
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For the transition period
from to |
Commission file number 1-4174
The Williams Companies, Inc.
(Exact name of Registrant as Specified in Its Charter)
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Delaware |
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73-0569878 |
(State or Other Jurisdiction of
Incorporation or Organization) |
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(IRS Employer
Identification No.) |
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One Williams Center, Tulsa, Oklahoma |
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74172 |
(Address of Principal Executive Offices) |
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(Zip Code) |
918-573-2000
(Registrants Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the
Act:
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Name of Each Exchange |
Title of Each Class |
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on Which Registered |
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Common Stock, $1.00 par value |
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New York Stock Exchange and
Pacific Stock Exchange |
Preferred Stock Purchase Rights |
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New York Stock Exchange and Pacific Stock
Exchange |
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Income PACs
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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 whether the registrant: (1) has
filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not
contained herein, and will not be contained, to the best of
registrants knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this
Form 10-K or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is an accelerated
filer (as defined in Exchange Act
Rule 12b-2). Yes þ No o
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 registrants most recently completed
second quarter was approximately $6,216,391,365.
The number of shares outstanding of the registrants common
stock held by non-affiliates outstanding at February 28,
2005 was 570,051,442.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrants Proxy Statement being prepared
for the solicitation of proxies in connection with the Annual
Meeting of Stockholders of the registrant for 2005 are
incorporated by reference in Part III of this
Form 10-K.
THE WILLIAMS COMPANIES, INC.
FORM 10-K
TABLE OF CONTENTS
i
ii
DEFINITIONS
We use the following oil and gas measurements in this report:
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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. |
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British Thermal Unit or BTU means a unit of
energy needed to raise the temperature of one pound of water by
one degree Fahrenheit. |
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BBtud means one billion BTUs per day. |
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Dekatherms or Dth or Dt means a unit of
energy equal to one million BTUs. |
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Mbbls/d means one thousand barrels per day. |
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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. |
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Mdt/d means one thousand dekatherms per day. |
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MMcf means one million cubic feet. |
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MMcf/d means one million cubic feet per day. |
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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. |
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MMdt means one million dekatherms. |
iii
PART I
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Items 1 and 2. |
Business and Properties |
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
SECs Public Reference Room at 450 Fifth Street, N.W.,
Washington, DC 20549. You may obtain information on the
operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. You may also obtain such reports from the
SECs Internet website at http://www.sec.gov.
Our Internet website is http://www.williams.com. We make
available free of charge on or through our Internet website our
annual report on Form 10-K, quarterly reports on
Form 10-Q, current reports on Form 8-K and amendments
to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Exchange Act as soon as
reasonably practicable after we electronically file such
material with, or furnish it to, the SEC. Our Corporate
Governance Guidelines, Code of Ethics, Board committee charters
and Code of Business Conduct are also available on our Internet
website.
GENERAL
We are a 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. We also manage a wholesale power business. Our
operations are concentrated in the Pacific Northwest, Rocky
Mountains, Gulf Coast, Southern California and Eastern Seaboard.
In February 2003, we announced our business strategy focused on
migrating to an integrated natural gas business comprised of a
smaller portfolio of natural gas businesses, reducing debt and
increasing our liquidity through asset sales, strategic levels
of financing and reductions in operating costs. During 2003, we
made substantial progress in executing the announced plan. In
2004, we continued to execute certain components, and completed
the plan (see Recent Developments for details on the steps of
the plan we completed in 2004). In 2004, we continued to focus
on disciplined growth, cash management and cost efficiencies.
With the completion of the 2003 plan and our decision to retain
the Power business, we have turned our attention to the creation
of superior, sustainable growth through Economic Value
Added®
(EVA®)1-based
disciplined investments in natural gas businesses. Our strategy
going forward is to sustain the strategic and financial
discipline followed during the implementation of the 2003
business strategy.
Our principal executive offices are located at One Williams
Center, Tulsa, Oklahoma 74172. Our telephone number is
918-573-2000.
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1 |
Economic Value Added® (EVA®) is a registered trademark
of Stern, Stewart & Co. |
1
RECENT DEVELOPMENTS
In 2004, we completed key components of our previously announced
business strategy through further planned asset sales,
additional reductions in costs, and certain debt restructuring
objectives. We also continued efforts to pursue growth projects
and to address issues surrounding our Power business which we
decided in 2004 to continue to operate. An overview of our
efforts and progress in these areas and other events follows.
Asset sales
Planned asset sales during 2004 were expected to generate
proceeds of approximately $800 million. On March 31,
2004, we sold our Alaska refinery, and related assets including
the retail stores and pipeline for approximately
$304 million. In addition, on July 28, 2004, we sold
three straddle plants in western Canada for approximately
$544 million.
Cost reduction efforts
In 2004 our selling, general and administrative and general
corporate expenses decreased by approximately $33 million.
On June 1, 2004, we selected International Business
Machines Corporation (IBM) to aid us in transforming and
managing certain areas of our accounting, finance and human
resources processes. In addition, IBM will manage key aspects of
our information technology. As a result of our seven and
one-half year agreement, approximately 455 of our former
employees were transferred to IBM beginning July 1, 2004.
Debt retirement and restructuring
In 2004 we continued to reduce debt through scheduled maturities
and early redemptions, eliminating approximately $4 billion
of indebtedness in 2004. In April 2004, we also replaced our
cash-collateralized letter of credit and revolver facility with
unsecured facilities that do not encumber cash. In January 2005,
these facilities were terminated and replaced with two new
facilities that contain similar economic terms but fewer
restrictions. For further information about debt retirement and
restructuring matters, please see Managements Discussion
and Analysis of Financial Condition and Results of Operations
and Note 11 of our Notes to Consolidated Financial
Statements.
Addressing Power issues
In September 2004, we announced that we would continue operating
our wholesale power business and cease efforts to exit that
business. During 2004, we reduced risk from this business
through the sale, termination or expiration of certain contracts
and through entering into new contracts that economically hedge
existing positions. We will continue our current program of
managing this business to minimize financial risk, generate cash
and manage existing contractual commitments.
In 2004 we also continued efforts to resolve various legal and
regulatory proceedings, challenges and investigations regarding
various aspects of the energy marketing and trading business.
These matters include refund proceedings, pipeline storage data
investigations, California Independent System Operator fines,
contract challenges and alleged market manipulation
investigations and proceedings. The market manipulation claims
include withholding of generating capacity, reporting of
inaccurate data to a trade periodical developer of natural gas
indices and other alleged market gaming. Certain of these
matters are also the subject of civil litigation. During the
year, we entered into a settlement with major California
utilities and others that resolved issues related to refunds for
wholesale power sales in California. However, many challenges,
legal actions and investigations are ongoing and could have a
material negative effect on us. For further information about
investigations and proceedings involving energy trading
practices, see Note 15 of our Notes to Consolidated
Financial Statements.
2
Disciplined growth
Since February 2004, we continued to focus on disciplined
growth. Our growth achievements in 2004 included, among others:
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Drilling 1,384 gross successful natural gas wells. |
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Completion of more than 500 well connections to our natural
gas gathering systems in Wyoming and New Mexico. |
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The operational start of our Devils Tower floating
production system and associated pipelines in the deepwater Gulf
of Mexico. |
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Completion of a new, nine mile, natural gas pipeline lateral in
western Washington to deliver an additional 113,000 dekatherms
per day of gas. |
Other events
On May 26, 2004, we announced an agreement to effectively
release us from certain historical indemnities related to our
previous ownership of operations, such as the Williams Pipe Line
system, that are now owned by Magellan Midstream Partners, L.P.
(Magellan). In June 2003 we divested interests in Magellan but
retained certain environmental and other indemnification
obligations. Under the terms of the agreement, we will pay a
total of $117.5 million to Magellan through four structured
annual payments beginning July 1, 2004 and ending
July 1, 2007. In exchange, Magellan released us from
certain historical indemnities, primarily related to
environmental remediation.
FINANCIAL INFORMATION ABOUT SEGMENTS
See Note 18 of our Notes to Consolidated Financial
Statements for information with respect to each segments
revenues, profits or losses and total assets.
BUSINESS SEGMENTS
General overview
Substantially all our operations are conducted through our
subsidiaries. To achieve organizational and operating
efficiencies, our activities are primarily operated through our
business segments including the following:
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Power manages our wholesale power and natural
gas commodity businesses through purchases, sales and other
related transactions, under our wholly-owned subsidiary Williams
Power Company and its subsidiaries. |
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Gas Pipeline includes our interstate natural
gas pipelines and pipeline joint venture investments organized
under our wholly-owned subsidiary, Williams Gas Pipeline
Company, LLC. |
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Exploration & Production produces,
develops and manages natural gas reserves primarily located in
the Rocky Mountain and Mid-Continent regions of the United
States and is comprised of several wholly-owned subsidiaries
including Williams Production Company LLC and Williams
Production RMT Company. |
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Midstream includes our natural gas gathering,
treating and processing business and is comprised of several
wholly-owned subsidiaries including Williams Field Services
Group, Inc. and Williams Natural Gas Liquids, Inc. |
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Other consists of corporate operations and
certain continuing operations previously reported within the
International and Petroleum Services segments. Other also
includes our interest in Longhorn Partners Pipeline, L.P.
(Longhorn). |
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This report is organized to reflect this structure.
An overview and detailed discussion of each of our business
segments follows.
Power
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Our Power segment, formerly known as Energy Marketing &
Trading, is an energy services provider that buys, sells and
transports energy and energy-related commodities, primarily
power and natural gas, on a wholesale level. |
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In 2004 we continued to focus on reducing risk and maximizing
expected cash flows in our Power segment. Following our decision
to retain Power in September 2004, we also focused on executing
new contracts to hedge our portfolio and support our natural gas
businesses. |
From June 2002 to September 2004, we pursued a strategy to exit
the power business and substantially reduce our financial
commitment to our Power segment. During this period, we
continued to operate and manage the risk associated with our
remaining contracts and our assets in order to maximize cash
flow and, where possible, reduce risk within the portfolio.
However, in September 2004, we announced our decision to
continue operating the power business and cease efforts to exit
that business. As a result, Power now focuses not only on its
objective of maximizing expected cash flows, but also on
executing new contracts to hedge its portfolio and providing
functions that support our natural gas businesses. Our contracts
include physical forward purchases and sales, various financial
instruments and structured transactions. Our financial
instruments include exchange-traded futures, as well as
exchange-traded and over-the-counter options and swaps.
Structured transactions include tolling contracts, full
requirements contracts and tolling resales, which are explained
in the next three paragraphs. Through our contracts, we buy,
sell, store and transport energy and energy-related commodities,
primarily power and natural gas.
Tolling contracts represent the most significant portion of our
portfolio. Under the tolling contracts, we have the right to
request a plant owner to convert our fuel (usually natural gas)
to electricity in exchange for a fixed fee. We have the right to
request approximately 7,700 megawatts of electricity under six
tolling agreements. The table below lists the locations and
capacity of each of our tolling agreements. These capacity
numbers are subject to change, and our contractual rights to
capacity may not reflect actual availability at the plants.
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Megawatts | |
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California
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4,141 |
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Alabama
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844 |
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Louisiana
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749 |
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New Jersey
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766 |
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Pennsylvania
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669 |
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Michigan
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541 |
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Total
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7,710 |
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We use portions of the electricity produced under the tolling
agreements to supply obligations under counterparty-tailored
arrangements known as full requirements contracts. Under full
requirements contracts, we supply the electricity required by
our counterparties to serve their customers. Through full
requirements contracts, we supply approximately 1,869 megawatts
of electricity to our customers in Georgia and Pennsylvania.
Through tolling resale agreements, we enter into transactions
that mirror, to varying degrees, some or all of our rights under
our underlying tolling arrangements, which remain in place with
our tolling counterparties.
4
We have resold part of our rights (1,045 to 1,175 megawatts)
under the California tolling arrangement to the California
Department of Water Resources through 2010.
Additionally, we have rights to sell energy and capacity from
two natural gas-fired electric generating plants owned by
affiliated companies and located near Bloomfield, New Mexico (60
megawatts, Milagro facility) and in Hazleton, Pennsylvania (147
megawatts).
In 2004, we marketed natural gas throughout North America with
total physical volumes averaging 2.5 billion cubic feet per
day. With approximately 10 percent of this natural gas, we
fuel electric generating plants we own or in which we have
contractual rights. We sell approximately 70 percent of
this natural gas to customers including local distribution
companies, utilities, producers, industrials and other gas
marketers. With the remaining 20 percent, we procure gas
supply for our Midstream operations, sell gas produced by
Exploration & Production and manage firm service
contracts for Gas Pipeline.
In 2004, we substantially exited our crude oil and refined
products activities.
In 2003, we substantially exited our European activities, which
had been conducted through our London office.
The following table summarizes marketing and trading gross sales
volumes, including sales volumes to other segments, for the
periods indicated:
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Year Ending December 31, | |
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2004 | |
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2002 | |
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U.S. Operations
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Marketing and trading physical volumes:
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Power (thousand megawatt hours)
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93,998 |
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165,908 |
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404,711 |
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Natural Gas (billion cubic feet per day)
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2.3 |
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2.7 |
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3.8 |
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Petroleum products (thousand barrels per day)
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50 |
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77 |
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832 |
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2004 | |
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2002 | |
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European Operations
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Marketing and trading physical volumes:
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Power (thousand megawatt hours)
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26,094 |
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Natural Gas (billion cubic feet per day)
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0.2 |
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Petroleum products (thousand barrels per day)
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23 |
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83 |
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In 2004, Power managed 2.5 billion cubic feet per day of
natural gas. The natural gas volumes managed include the
following (in billion cubic feet per day):
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2004 | |
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Sales to third parties
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1.7 |
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Sales to other segments
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.6 |
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For use in tolling agreements and by owned generation
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.2 |
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Total natural gas managed
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2.5 |
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As of December 31, 2004, our Power segment had
approximately 284 customers compared with 234 customers at the
end of 2003.
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Regulatory and legal matters |
Our Power business is subject to a variety of laws and
regulations at the local, state and federal levels. The Federal
Energy Regulatory Commission (FERC) and the Commodity Futures
Trading Commission regulate
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us. Electricity and natural gas markets in California and
elsewhere continue to be subject to numerous and wide-ranging
federal and state regulatory proceedings and investigations. We
are also subject to various federal and state actions and
investigations regarding, among other things, market structure,
behavior of market participants, market prices, and reporting to
trade publications. On December 17, 2004, a former trader
with Power pled guilty to manipulation of gas prices through
misreporting to an industry periodical. The Department of
Justices (DOJ) investigation of us in this matter is
continuing and it is reasonably possible that material penalties
could result. However, a reasonable estimate of such amount
cannot be determined at this time. Power has also been named as
a defendant in class-action lawsuits related to reporting to
natural gas trade periodicals. Discussions in California and
other states have ranged from threats of re-regulation to
suspension of plans to move forward with deregulation.
Allegations have also been made that wholesale price increases
resulted from the exercise of market power and collusion of the
power generators and sellers, such as Power. These allegations
have resulted in multiple state and federal investigations as
well as the filing of class-action lawsuits in which we are
named a defendant. Our long-term power contract with the
California Department of Water Resources has also been
challenged both at the FERC and in civil suits. On
November 11, 2002, we executed a settlement agreement that
resolved many of these disputes with the State of California
with respect to non-criminal matters. This settlement agreement
includes renegotiated long-term energy contracts. The settlement
also resolved complaints brought by the California Attorney
General against us and the State of Californias refund
claims. In addition, the settlement resolved ongoing
investigations by the States of California, Oregon, and
Washington. The settlement closed December 31, 2002,
although aspects of the settlement regarding certain
class-action lawsuits are on appeal. Notwithstanding this
settlement, numerous investigations and actions related to the
Power segment remain. We may be liable for refunds and other
damages and penalties as a result of the above actions and
investigations. We discuss each of these matters as well as
other regulatory and legal matters in more detail in
Note 15 of our Notes to Consolidated Financial Statements.
The outcome of these matters could affect our creditworthiness
and ability to perform contractual obligations as well as other
market participants creditworthiness and ability to
perform contractual obligations to us.
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Competition and market environment |
We compete directly with large independent energy marketers,
marketing affiliates of regulated pipelines and utilities and
natural gas producers. We also compete with both brokerage
houses and other energy-based companies offering similar
services. Since 2002, we have fewer competitors due to the exit
of independent energy marketers from the marketplace and the
exit of utilities from financial merchant activities. We
anticipate more competition in the future from brokerage houses,
which are increasing their trading activity.
Due to our current credit rating, certain counterparties request
adequate assurance or prepayment in support of business
transactions. In addition, we fund normal margin requirements
with cash, letters of credit or other negotiable instruments as
called for under standard industry agreements. As our credit and
liquidity continue to improve, we are able to negotiate lower
collateral requirements with certain counterparties.
Certain of our counterparties have experienced significant
declines in their financial stability and creditworthiness,
which may adversely impact their ability to perform under
contracts. Revenues from one counterparty, which has a credit
rating below investment grade, constitutes approximately five
percent of Powers gross revenues. Our exposure to this
counterparty is mitigated by the existence of a netting
arrangement. In conjunction with our previous efforts to sell or
liquidate all or portions of our portfolio, we closed out or
sold positions with a number of counterparties in 2004. Credit
constraints and financial instability of market participants are
expected to continue in 2005. These factors may also
significantly impact our ability to manage market risk.
Powers primary assets are its term contracts, related
systems and technological support. In addition, affiliates of
Power own the Hazelton and Milagro generating facilities
described above. As discussed further in Note 1 of our
Notes to Consolidated Financial Statements, derivative contracts
in our portfolio have been recognized at their estimated fair
value. According to generally accepted accounting principles
(GAAP), fair
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value is the amount at which an instrument could be exchanged in
a current transaction between willing parties other than in a
forced liquidation or sale. Non-derivative contracts are not
recognized until revenue is earned or expenses have been
incurred. With our September 2004 decision to continue operating
the Power business, Power became eligible for hedge accounting
under Statement of Financial Accounting Standard (SFAS) 133
on October 1, 2004. Under hedge accounting, future changes
in fair value are reported as changes in other comprehensive
income within the stockholders equity section of the balance
sheet. Upon adoption of hedge accounting on October 1,
2004, certain existing derivative contracts, which already had
significant fair value which had been previously recognized in
earnings as unrealized gains or losses, were designated as
hedges. Because the derivative contracts qualifying for hedge
accounting already had significant fair value which had been
recognized as unrealized gains or losses prior to
October 1, 2004, the amounts recognized in future earnings
under hedge accounting with respect to these derivatives will
not equal the amount of cash flows realized from the settlement
of those derivatives. Therefore, while future earnings will
reflect any losses from transactions that have been hedged by
the derivatives, such future earnings will not reflect the
amounts realized from hedges that were previously recognized as
mark-to-market unrealized gains or losses prior to the adoption
of hedge accounting. However, cash flows from Powers
portfolio will reflect the net amount from both the hedged
transactions and the hedges.
Our generation facilities are subject to various environmental
laws and regulations, including those regarding emissions. We
believe compliance with various environmental laws and
regulations will not have a material adverse effect on capital
expenditures, earnings or competitive position. However, these
laws and regulations may affect facility availability from time
to time.
Gas pipeline
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We own one of the nations largest interstate natural gas
pipeline systems with 14,700 miles of interstate natural
gas pipelines for transportation of natural gas across the
country to utilities and industrial customers. |
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Our pipelines include Transcontinental Gas Pipe Line Corporation
(Transco), Northwest Pipeline Corporation (Northwest Pipeline)
and several pipeline joint ventures. |
We also own a 50 percent interest in the Gulfstream Natural
Gas System, L.L.C. (Gulfstream).
We own and operate, through Williams Gas Pipeline Company, LLC
and its subsidiaries (Gas Pipeline), a combined total of
approximately 14,700 miles of pipelines with a total annual
throughput of approximately 2,600 trillion British Thermal Units
of natural gas and peak-day delivery capacity of approximately
12 MMdt of gas. Gas Pipeline consists of Transco and
Northwest Pipeline. Gas Pipeline also holds interests in joint
venture interstate and intrastate natural gas pipeline systems
including a 50 percent interest in Gulfstream.
Construction of the Gulfstream gas pipeline project which
consists of a natural gas pipeline system extending from the
Mobile Bay area in Alabama to markets in Florida, commenced in
June 2001. In December 2001, Gulfstream filed an application
with the FERC to allow Gulfstream to complete the construction
of its approved facilities in phases. In May 2002, the first
phase of the project was placed into service at a cost of
approximately $1.5 billion. The second phase of the project
was placed into service on February 1, 2005. The total
estimated capital cost of both phases of the project is
approximately $1.7 billion. At December 31, 2004, our
investment in Gulfstream was $726 million.
Gas Pipeline jointly pursued a project known as the Georgia
Strait Crossing Pipeline Project (GSX) with BC Hydro, in
part to meet the needs of the Vancouver Island Generation Plant.
On April 24, 2001 Gas Pipeline and BC Hydro filed separate
applications with the FERC and Canadas National Energy
Board (NEB) to construct and operate a new pipeline to
provide firm transportation capacity from Sumas,
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Washington to Vancouver Island, British Columbia. On
September 20, 2002, the FERC issued an order approving the
construction and operation of the U.S. portion of the
project. A NEB certificate approving the project in Canada was
issued on December 15, 2003. In December 2004, Gas Pipeline
and BC Hydro mutually agreed to discontinue development of the
project. Under terms of the agreement with Gas Pipeline, BC
Hydro assumes full responsibility for all project costs.
Gas Pipelines interstate transmission and storage
activities are subject to regulation by the FERC 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, the
extension, enlargement or abandonment of jurisdictional
facilities and accounting, 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 by Title I of the
Pipeline Safety Act of 1979 and the Pipeline Safety Improvement
Act of 2002, which regulate safety requirements in the design,
construction, operation and maintenance of interstate natural
gas transmission facilities. Cardinal Pipeline Company, LLC, an
intrastate natural gas pipeline company that is operated and
45 percent owned by Gas Pipeline, is subject to the
jurisdiction of the North Carolina Utilities Commission.
Each of our interstate natural gas pipeline companies
establishes its rates primarily through the FERCs
ratemaking process. Key determinants in the ratemaking process
are (1) costs of providing service, including depreciation
expense, (2) allowed rate of return, including the equity
component of the capital structure and related income taxes and
(3) volume throughput assumptions. The allowed rate of
return is determined in each rate case. Rate design and the
allocation of costs between the demand and commodity rates also
impact profitability. As a result of these proceedings, certain
revenues previously collected may be subject to refund. See
Note 15 of our Notes to Consolidated Financial Statements
for the amounts accrued for potential refund at
December 31, 2004.
The FERC has taken various actions to strengthen market forces
in the natural gas pipeline industry which has led to increased
competition throughout the industry. In a number of key markets,
interstate pipelines are now facing competitive pressures from
other major pipeline systems, enabling local distribution
companies and end users to choose a supplier or switch suppliers
based on the short-term price of gas and the cost of
transportation. We expect competition for natural gas
transportation to continue to intensify in future years due to
increased customer access to other pipelines, rates,
competitiveness among pipelines, customers desire to have
more than one transporter, shorter contract terms, and
regulatory developments. Future utilization of pipeline capacity
will depend on competition from other pipelines, use of
alternative fuels, the general level of natural gas demand, and
weather conditions. Electricity and distillate fuel oil are the
primary competitive forms of energy for residential and
commercial markets. Coal and residual fuel oil compete for
industrial and electric generation markets. Nuclear and
hydroelectric power and power purchased from electric
transmission grid arrangements among electric utilities also
compete with gas-fired electric generation in certain markets.
Suppliers of natural gas are able to compete for any gas markets
capable of being served by pipelines using nondiscriminatory
transportation services provided by the pipeline companies. As
the regulated environment has matured, many pipeline companies
have faced reduced levels of subscribed capacity as contractual
terms expire and customers opt to reduce firm capacity under
contract in favor of alternative sources of transmission and
related services. This situation, known in the industry as
capacity turnback, is forcing the pipeline companies
to evaluate the consequences of major demand reductions in
traditional long-term contracts. It could also result in
significant shifts in system utilization, and possible
realignment of cost structure for remaining customers since all
interstate natural gas pipeline companies continue to be
authorized to charge maximum rates approved by the FERC on a
cost of service basis. Gas Pipeline does not anticipate
8
any significant financial impact from capacity
turnback. We anticipate that we will be able to remarket
most future capacity subject to capacity turnback, although
competition may cause some of the remarketed capacity to be sold
at lower rates or for shorter terms.
Several state jurisdictions have been involved in implementing
changes similar to the changes that have occurred at the federal
level. New York, New Jersey, Pennsylvania, Maryland, Georgia,
Delaware, Virginia, California, Wyoming, and the District of
Columbia are currently at various points in the process of
unbundling services at local distribution companies. We expect
the implementation of these changes to encourage greater
competition in the natural gas marketplace.
Each of our interstate natural gas pipeline companies generally
owns its facilities, although some facilities are held jointly
with third parties. However, a substantial portion of each
pipeline companys facilities is constructed and maintained
pursuant to rights-of-way, easements, permits, licenses or
consents on and across properties owned by others. Our
compressor stations and appurtenant facilities are located on
lands owned by us or on sites leased from or permitted by public
authorities. The storage facilities are either owned or held
under long-term leases or easements.
Each of our interstate natural gas pipelines is subject to the
National Environmental Policy Act and federal, state and local
laws and regulations relating to environmental protection. We
believe that, with respect to any capital expenditures and
operation and maintenance expenses required to meet applicable
environmental standards and regulations, the FERC would grant
the requisite rate relief so that our pipeline companies could
recover most of the cost of these expenditures in their rates.
For this reason, we believe that compliance with applicable
environmental requirements by the interstate pipeline companies
is not likely to have a material adverse effect upon our
earnings or competitive position.
For a discussion of specific environmental issues involving the
interstate pipelines, including estimated cleanup costs
associated with certain pipeline activities, see
Environmental under Managements Discussion and
Analysis of Financial Condition and Results of Operations and
Environmental Matters in Note 15 of our Notes
to Consolidated Financial Statements.
|
|
|
Principal Companies in the Gas Pipeline Segment |
A business description of the principal companies in the
interstate natural gas pipeline group follows.
|
|
|
Transcontinental Gas Pipe Line Corporation
(Transco) |
Transco is an interstate natural gas transportation company that
owns and operates a 10,500-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 eleven southeast and Atlantic seaboard states,
including major metropolitan areas in Georgia, North Carolina,
New York, New Jersey, and Pennsylvania. Effective May 1,
1995, Transco transferred the operation of certain production
area facilities to Williams Field Services Group, Inc. (Williams
Field Services), an affiliated company and part of the Midstream
segment. Effective June 1, 2004 and due in part to FERC
Order No. 2004, the operation of the production area
facilities was transferred back to Transco.
|
|
|
Pipeline system and customers |
At December 31, 2004, Transcos system had a mainline
delivery capacity of approximately 4.7 MMdt of natural gas
per day from its production areas to its primary markets. Using
its Leidy Line that originates at the Canadian border in western
New York along with market-area storage capacity, Transco can
deliver an additional 3.4 MMdt of natural gas per day for a
system-wide delivery capacity total of approximately
9
8.1 MMdt of natural gas per day. Transcos system
includes 44 compressor stations, five underground storage
fields, two liquefied natural gas (LNG) storage facilities
and four processing plants. Compression facilities at a sea
level-rated capacity total approximately 1.5 million
horsepower.
Transcos major natural gas transportation customers are
public utilities and municipalities that provide service to
residential, commercial, industrial and electric generation end
users. Shippers on Transcos system include public
utilities, municipalities, intrastate pipelines, direct
industrial users, electrical generators, gas marketers and
producers. One customer accounted for approximately
11 percent of Transcos total revenues in 2004.
Transcos firm transportation agreements are generally
long-term agreements with various expiration dates and account
for the major portion of Transcos business. Additionally,
Transco offers storage services and interruptible transportation
services under short-term agreements.
Transco has natural gas storage capacity in five underground
storage fields located on or near its pipeline system or market
areas and operates three of these storage fields. Transco also
has storage capacity in a LNG storage facility and operates the
facility. 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 216 billion cubic feet of gas. In addition,
wholly-owned subsidiaries of Transco operate and hold a
35 percent ownership interest in Pine Needle LNG Company,
an LNG storage facility with four billion cubic feet of storage
capacity. Storage capacity permits Transcos customers to
inject gas into storage during the summer and off-peak periods
for delivery during peak winter demand periods.
|
|
|
Central New Jersey Expansion Project |
|
|
|
The Central New Jersey Expansion Project will involve an
expansion of Transcos existing natural gas transmission
system in Transcos Zone 6 from the Station 210 pooling
point to locations along Transcos Trenton-Woodbury Line.
The project will create approximately 105 Mdt/d of new firm
transportation capacity, which has been fully subscribed by one
shipper for a twenty-year primary term. The project facilities
will include approximately 3.5 miles of pipeline loop at an
estimated capital cost of $13 million. Transco filed an
application for FERC approval of the project on August 11,
2004, which the FERC approved on February 10, 2005. The
target in-service date for the project is November 1, 2005. |
|
|
|
Leidy to Long Island Expansion Project |
|
|
|
The Leidy to Long Island Expansion Project will involve an
expansion of our existing natural gas transmission system in
Zone 6 from the Leidy Hub in Pennsylvania to Long Island, New
York. The project will provide 100 Mdt/d of firm transportation
capacity, which has been fully subscribed by one shipper for a
twenty-year primary term. The project facilities will include
pipeline looping in Pennsylvania and looping and a natural gas
compressor facility in New Jersey. Based on the results of the
open season for the project and the incorporation of existing
capacity made available through a reverse open season, the
estimated capital cost of the project has been reduced to
$103 million. We expect that nearly three-quarters of the
project expenditures will occur in 2007. The FERC has granted
our request to initiate a pre-application environmental review,
soliciting early input from citizens, governmental entities and
other interested parties to identify and address potential
siting issues. We expect to file a formal application with the
FERC in September 2005. The target in-service date for the
project is November 1, 2007. |
10
The following table summarizes transportation data for the
Transco system for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(In trillion British | |
|
|
Thermal Units) | |
Market-area deliveries:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-haul transportation
|
|
|
782 |
|
|
|
771 |
|
|
|
824 |
|
|
Market-area transportation
|
|
|
817 |
|
|
|
802 |
|
|
|
777 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total market-area deliveries
|
|
|
1,599 |
|
|
|
1,573 |
|
|
|
1,601 |
|
Production-area transportation
|
|
|
317 |
|
|
|
297 |
|
|
|
179 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total system deliveries
|
|
|
1,916 |
|
|
|
1,870 |
|
|
|
1,780 |
|
|
|
|
|
|
|
|
|
|
|
Average Daily Transportation Volumes
|
|
|
5.2 |
|
|
|
5.1 |
|
|
|
4.9 |
|
Average Daily Firm Reserved Capacity
|
|
|
6.6 |
|
|
|
6.5 |
|
|
|
6.4 |
|
Transcos facilities are divided into eight rate zones.
Five are located in the production area, and three are located
in the market area. Long-haul transportation involves gas that
Transco receives in one of the production-area zones and
delivers to a market-area zone. Market-area transportation
involves gas that Transco both receives and delivers within the
market-area zones. Production-area transportation involves gas
that Transco both receives and delivers within the
production-area zones.
|
|
|
Northwest Pipeline Corporation (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, 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, 2004, Northwest Pipelines system,
having long-term firm transportation agreements with peaking
capacity of approximately 3.4 MMdt of natural gas per day,
was composed of approximately 4,200 miles of mainline and
lateral transmission pipelines and 42 compressor stations having
sea level-rated capacity of approximately 462,000 horsepower.
In December 2003, we received an Amended Corrective Action Order
(ACAO) from the U.S. Department of Transportations
Office of Pipeline Safety (OPS) regarding a segment of one of
our natural gas pipelines in western Washington. The pipeline
experienced two breaks in 2003, and we subsequently idled the
pipeline segment until its integrity could be assured.
By June 2004, we had successfully completed our hydrostatic
testing program and returned to service 111 miles of the
268 miles of pipe affected by the ACAO. That effort has
restored 131 Mdt/d of the 360 Mdt/d of idled capacity and is
anticipated to be adequate to meet most market conditions. To
date our ability to serve the market demand has not been
significantly impacted.
The restored facilities will be monitored and tested as
necessary until they are ultimately replaced. Through
December 31, 2004 approximately $40 million had been
spent on testing and remediation, including approximately
$9 million related to one segment of pipe that we recently
determined not to return to service and was therefore written
off in the second quarter of 2004. We estimate the total testing
and remediation costs will be between $40 million to
$45 million.
On October 4, 2004, we received a notice of probable
violation (NOPV) from OPS. Under the provisions of the NOPV, OPS
has issued a preliminary civil penalty of $100,000 for exceeding
the pressure restriction on
11
one of the segments covered under the original CAO. This penalty
was accrued in the third quarter of 2004. The incident occurred
on July 15, 2003 and did not occur as part of normal
operations, but in preparation for running an internal
inspection tool to test the integrity of the line. The operating
pressure dictated by the original CAO was exceeded for
approximately three hours due to the mechanical failure of an
overpressure device and we immediately reported the incident to
the OPS. There was no impact on pipeline facilities, and no
additional sections of the pipeline were affected. Following the
incident, new protocols were adopted to prevent similar
occurrences in the future. We requested a hearing on the
proposed OPS civil penalty, which was held in Denver, Colorado
on December 15, 2004. OPS will issue its decision in the
near future.
As required by OPS, we plan to replace the pipelines
entire capacity by November 2006 to meet long-term demands. We
conducted a reverse open season to determine whether any
existing customers were willing to relinquish or reduce their
capacity commitments to allow us to reduce the scope of pipeline
replacement facilities. That resulted in 13 Mdt/d of
capacity being relinquished and incorporated into the
replacement project. On November 29, 2004, we filed with
the FERC a certificate application for the Capacity
Replacement Project including construction of
approximately 79.5 miles of 36-inch pipeline and
10,760 net horsepower of additional compression at two
existing compressor stations and abandonment of approximately
268 miles of the existing 26-inch pipeline. The estimated
net cost of the Capacity Replacement Project included in the
filing is approximately $333 million. The majority of these
costs will be spent in 2005 and 2006. We anticipate filing a
rate case to recover the capitalized costs relating to
restoration and replacement facilities following the in-service
date of the replacement facilities.
In 2004, Northwest Pipeline served a total of
175 transportation and storage customers. Transportation
customers include distribution companies, municipalities,
interstate and intrastate pipelines, gas marketers and direct
industrial users. The two largest customers of Northwest
Pipeline in 2004 accounted for approximately 13.9 percent
and 11.3 percent, of its total operating revenues. No other
customer accounted for more than 10 percent of Northwest
Pipelines total operating revenues in 2004. Northwest
Pipelines firm transportation agreements are generally
long-term agreements with various expiration dates and account
for the major portion of Northwest Pipelines business.
Additionally, Northwest Pipeline offers interruptible and
short-term firm transportation service.
As a part of its transportation services, Northwest Pipeline
utilizes underground storage facilities in Utah and Washington
enabling it to balance daily receipts and deliveries. Northwest
Pipeline also owns and operates a LNG storage facility in
Washington that provides service for customers during a few days
of extreme demands. These storage facilities have an aggregate
firm delivery capacity of approximately 600 million cubic
feet of gas per day.
The following table summarizes volume and capacity data for the
Northwest Pipeline system for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(In trillion British | |
|
|
Thermal Units) | |
Total Throughput
|
|
|
650 |
|
|
|
682 |
|
|
|
729 |
|
Average Daily Throughput
|
|
|
1.8 |
|
|
|
1.9 |
|
|
|
2.0 |
|
Average Daily Reserved Capacity Under Long-Term Base Firm
Contracts, excluding peak capacity
|
|
|
2.5 |
|
|
|
2.3 |
|
|
|
2.3 |
|
Average Daily Reserved Capacity Under Short-Term Firm
Contracts(1)
|
|
|
.6 |
|
|
|
.8 |
|
|
|
.5 |
|
|
|
(1) |
Consists primarily of additional capacity created from time to
time through the installation of new receipt or delivery points
or the segmentation of existing mainline capacity. Such capacity
is generally marketed on a short-term firm basis, because it
does not involve the construction of additional mainline
capacity. |
12
Exploration & production
|
|
|
Exploration & production overview |
|
|
|
|
|
We produce, develop, and manage natural gas reserves primarily
located in the Rocky Mountain and Mid-Continent regions of the
United States. |
|
|
|
We produce natural gas predominately from tight-sand formations
and coal bed methane reserves. |
|
|
|
We own approximately 3.0 trillion cubic feet equivalent of
proved natural gas reserves in the United States as of
December 31, 2004. |
We also own and manage certain international oil and gas
investments, including a 69 percent equity investment in
APCO Argentina Inc., an oil and gas exploration and production
company whose securities are traded on the NASDAQ under symbol
APAGF.
|
|
|
Exploration & production details |
Our Exploration & Production segment, which is
comprised of several wholly owned subsidiaries, including
Williams Production Company LLC and Williams Production RMT
Company (RMT), produces, develops, and manages natural gas
reserves primarily located in the Rocky Mountain and
Mid-Continent regions of the United States. We specialize in
natural gas production from tight-sands formations and coal bed
methane reserves in the Piceance, San Juan, Powder River
and Arkoma basins. Over 99 percent of
Exploration & Productions domestic reserves are
natural gas. Our Exploration & Production segment also
has international oil and gas interests, which include a
69 percent equity interest in APCO Argentina, an oil and
gas exploration and production company with operations in
Argentina, and a 10 percent interest in the
La Concepcion area located in western Venezuela.
Exploration & Productions primary strategy is to
utilize its expertise in the development of tight-sands and coal
bed methane reserves. Exploration & Productions
current proved undeveloped and probable reserves provide us with
strong capital investment opportunities for several years into
the future. Exploration & Productions goal is to
drill its existing proved undeveloped reserves, which comprise
nearly 55 percent of proved reserves and to drill in areas
of probable reserves. In addition, Exploration &
Production provides a significant amount of equity production
that is gathered and/or processed by our Midstream facilities in
the San Juan basin.
Information for our Exploration & Production segment
relates only to domestic activity unless otherwise noted.
Certain exploration and production assets managed through RMT
serve as collateral for a $500 million term loan facility
established in May 2003 and amended in February 2004. This
facility, as amended in February 2004, matures May 30, 2008
and represents a first priority lien on substantially all our
Piceance and Powder River basin assets and any future assets in
these basins.
Exploration & Productions properties are located
primarily in the Rocky Mountain and Mid-Continent regions of the
United States. Rocky Mountain properties are located primarily
in New Mexico, Wyoming and Colorado. All our Mid-Continent
properties are located in Oklahoma. 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.
13
|
|
|
Rocky Mountain properties |
The Piceance Basin is located in northwestern Colorado, where we
primarily target the tight sands contained within the Williams
Fork Mesaverde formation. The Piceance Basin is our largest area
of concentrated development comprising approximately
61 percent of our proved reserves. This area has
approximately 1,200 undrilled proved locations in
inventory. Within this basin, we are the owner and operator of a
natural gas gathering system and, thus, have the ability to
gather, process and deliver to one intrastate and four
interstate pipelines. In 2004, we drilled 270 gross wells
and produced a net of approximately 81 billion cubic feet
equivalent (Bcfe) of natural gas from the Piceance Basin. Our
estimated proved reserves in the Piceance Basin at year-end 2004
were 1,830 Bcfe. During 2004 we began drilling in Trail
Ridge and Ryan Gulch, two new areas within the Piceance Basin.
In addition to the 270 gross wells drilled in the basin as
previously referenced, we drilled four wells at Trail Ridge and
three wells at Ryan Gulch for a total of 277 gross wells
drilled in the Piceance Basin.
The San Juan Basin is a large gas producing area, located
in northwest New Mexico and southwest Colorado. We produce
natural gas primarily from the Fruitland Coal, Mesaverde,
Pictured Cliffs and Dakota formations. In 2004, we participated
in the drilling of 241 gross wells, of which we operate 35,
and produced a net of approximately 55 Bcfe from the
San Juan Basin. Our estimated proved reserves in the
San Juan Basin at year-end 2004 were 671 Bcfe.
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. We are one of the
largest natural gas producers in the Powder River Basin and
operate approximately half of our large leasehold position in
the basin, where we own an interest in approximately
1,000,000 gross acres. We operate approximately
2,300 wells in the basin and have an interest in
approximately 2,400 additional wells. We have a significant
inventory of undrilled locations, providing long-term drilling
opportunities. In 2004, we drilled 723 gross wells from
this basin, of which we operate 387, and produced a net of
approximately 43 Bcfe of natural gas. Our estimated proved
reserves in the Powder River Basin at year-end 2004 were
304 Bcfe, which includes approximately 5 Bcfe of
reserves from conventional properties.
Our Arkoma Basin properties are located in southeastern
Oklahoma. Our production from the Arkoma Basin is primarily from
the Hartshorne coal bed methane formation. We utilize horizontal
drilling technology to develop the coal seams. We own and
operate a natural gas gathering system, which enables us to move
our natural gas production out of the basin. In 2004, we drilled
99 gross wells, of which we operate 49, and produced a net
of approximately 7 Bcfe of natural gas. Our estimated
proved reserves in the Arkoma Basin at year-end 2004 were
121 Bcfe.
We have production in other areas including the Green River in
southwest Wyoming and in the Gulf Coast region. These properties
represent approximately two percent of our estimated proved
reserves.
14
The following table summarizes our natural gas reserves as of
December 31 (using prices at December 31 held
constant) for the year indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Bcfe) | |
Proved developed natural gas reserves
|
|
|
1,348 |
|
|
|
1,165 |
|
|
|
1,368 |
|
Proved undeveloped natural gas reserves
|
|
|
1,638 |
|
|
|
1,538 |
|
|
|
1,466 |
|
|
|
|
|
|
|
|
|
|
|
Total proved natural gas reserves
|
|
|
2,986 |
|
|
|
2,703 |
|
|
|
2,834 |
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes our proved natural gas reserves
by basin as of December 31, 2004:
|
|
|
|
|
|
|
Percentage of | |
Basin |
|
Proved Reserves | |
|
|
| |
Piceance
|
|
|
61% |
|
San Juan
|
|
|
23% |
|
Powder River
|
|
|
10% |
|
Arkoma, Green River and Gulf Coast
|
|
|
6% |
|
|
|
|
|
|
|
|
100% |
|
|
|
|
|
No major discovery or other favorable or adverse event has
caused a significant change in estimated gas reserves since
year-end 2004. 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 the
Department of Energy (DOE) and the SEC. The estimates
furnished to the DOE have been consistent with those furnished
to the SEC, although Exploration & Production has not
yet filed any information with respect to its estimated total
reserves at December 31, 2004, with the DOE. Certain
estimates filed with the DOE may not necessarily be directly
comparable due to special DOE reporting requirements, such as
the requirement to report gross operated reserves only. The
underlying estimated reserves for the DOE did not differ by more
than five percent from the underlying estimated reserves
utilized in preparing the estimated reserves reported to the SEC.
Approximately 99 percent of our year-end 2004 United States
proved reserves estimates were either audited by Netherland,
Sewell & Associates, Inc., or, in the case of reserves
estimates related to properties underlying the Williams Coal
Seam Gas Royalty Trust, were prepared by Miller and Lents, LTD.
The following table summarizes our leased acreage as of
December 31, 2004:
|
|
|
|
|
|
|
|
|
|
|
Gross Acres | |
|
Net Acres | |
|
|
| |
|
| |
Developed
|
|
|
691,959 |
|
|
|
352,486 |
|
Undeveloped
|
|
|
1,198,824 |
|
|
|
612,669 |
|
At December 31, 2004, we owned interests in
10,001 gross producing wells (4,616 net) on our
leasehold lands.
15
We focus on lower-risk development drilling. Our drilling
success rate was over 99 percent in 2004 and
99 percent in 2003. The following tables summarize domestic
drilling activity by number and type of well for the periods
indicated:
|
|
|
|
|
|
|
|
|
|
|
Number of Wells |
|
Gross Wells | |
|
Net Wells | |
|
|
| |
|
| |
Development:
|
|
|
|
|
|
|
|
|
|
Drilled
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
1,395 |
|
|
|
710 |
|
|
|
2003
|
|
|
900 |
|
|
|
419 |
|
|
|
2002
|
|
|
1,347 |
|
|
|
723 |
|
|
Successful
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
1,384 |
|
|
|
706 |
|
|
|
2003
|
|
|
891 |
|
|
|
414 |
|
|
|
2002
|
|
|
1,334 |
|
|
|
714 |
|
Substantially all our natural gas production is currently being
sold to Power at prevailing market prices. Because we currently
have a low-risk drilling program in proven basins, the main
component of risk that we manage is price risk.
Exploration & Production has entered into derivative
contracts with Power that hedge 286 BBtud in fixed price
hedges (whole year) and 50 Bbtud in collars for January
through March for projected 2005 domestic natural gas
production. Power then enters into offsetting derivative
contracts with unrelated third parties. 400 BBtud of our
natural gas production in 2004 was hedged. Hedging decisions are
made considering the overall Williams commodity risk exposure
and are not executed independently by Exploration &
Production; there are gas purchase hedging contracts executed on
behalf of other Williams entities which taken as a net position
may counteract Exploration & Production gas sales
hedging derivatives.
The following table summarizes our sales and cost information
for the year indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
Total net production sold (in Bcfe)
|
|
|
189.4 |
|
|
|
182.1 |
|
|
|
211.5 |
|
Average production costs including production taxes per thousand
cubic feet of gas equivalent (Mcfe) produced
|
|
$ |
.88 |
|
|
$ |
.76 |
|
|
$ |
.58 |
|
Average sales price per Mcfe
|
|
$ |
4.48 |
|
|
$ |
3.87 |
|
|
$ |
2.03 |
|
Realized impact of hedging contracts [Gain (Loss)]
|
|
$ |
(1.32 |
) |
|
$ |
(.51 |
) |
|
$ |
1.20 |
|
Exploration & Production purchased additional producing
properties and acreage positions in our existing basins for a
total cash price of $21 million. The $21 million
includes 1.4 MMcf/d of net production and 24.4 Bcfe in
proved reserves, along with new acreage for future drilling
opportunities on probable and possible reserve locations.
|
|
|
Environmental and other regulatory matters |
Our Exploration & Production business is subject to
various federal, state and local laws and regulations on
taxation, 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.
16
Our operations are subject to complex environmental laws and
regulations adopted by the various jurisdictions in which we
operate. We could incur liability to governments or third
parties for any unlawful discharge of oil, gas or other
pollutants into the air, soil, or water, including
responsibility for remedial costs. We could potentially
discharge such materials into the environment in many ways
including:
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|
|
|
|
from a well or drilling equipment at a drill site; |
|
|
|
leakage from gathering systems, pipelines, transportation
facilities and storage tanks; |
|
|
|
damage to oil and gas wells resulting from accidents during
normal operations; and |
|
|
|
blowouts, cratering and explosions. |
Because the requirements imposed by such 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, because we acquire properties that have been operated
in the past by others, we may be liable for environmental damage
caused by such former operators.
The natural gas industry is highly competitive. We compete 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 the acquisition of
oil and gas properties and obtaining necessary equipment,
supplies and services. We also compete in recruiting and
retaining skilled employees.
The majority of our ownership interest in exploration and
production properties is held as working interests in oil and
gas leaseholds.
In 1993, Exploration & Production conveyed a net
profits interest in certain of its properties to the Williams
Coal Seam Gas Royalty Trust. Substantially all of the production
attributable to the properties conveyed to the trust was from
the Fruitland coal formation and constituted coal seam gas. We
subsequently sold trust units to the public in an underwritten
public offering and retained 3,568,791 trust units
representing 36.8 percent of outstanding trust units.
During 2000, we sold all of our trust units as part of a
Section 29 tax credit transaction, in which we retained an
option to repurchase the units. We registered the units with the
SEC and had been repurchasing the units and reselling the units
on the open market from time to time. In June 2003, we
repurchased the remaining 2,408,791 trust units covered by
the repurchase option. As of March 1, 2005, we own
995,791 trust units.
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|
|
International exploration and production interests |
We also have investments in international oil and gas interests.
We own approximately a 69 percent interest in APCO
Argentina Inc. (APCO Argentina), an oil and gas exploration and
production company with operations in Argentina. APCO
Argentinas principal business is its 52.9 percent
interest in the Entre Lomas concession in southwest Argentina.
It also owns an 82 percent interest in the Canadon Ramirez
concession, a 50 percent interest in the Capricorn
Exploration Permit and a 1.5 percent interest in the
Acambuco concession. We also own a direct 1.5 percent
interest in Acambuco through our Northwest Argentina subsidiary.
In Venezuela, we own a 10 percent interest in the
La Concepcion area, located in Western Venezuela, near Lake
Maracaibo. If combined with our domestic proved reserves, these
interests would make up 6.7 percent of our total proved
reserves.
17
Midstream
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|
|
|
|
We own and operate gas gathering, treating and processing
facilities within the western states of Wyoming, Colorado, and
New Mexico and onshore and offshore in and around the Gulf Coast
states of Texas, Louisiana, Mississippi, and Alabama. |
|
|
|
We operate and have ownership interests in various Venezuelan
midstream energy assets. |
|
|
|
We own interests in and/or operate natural gas liquids
transportation, fractionation and storage assets in central
Kansas and southern Louisiana. |
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|
|
We own and operate ethane cracking, olefin liquids extraction
and olefin fractionation assets within Louisiana. |
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|
|
We own an olefin liquids extraction plant and an olefin
fractionation facility within Alberta, Canada. |
Our Midstream segment, one of the nations largest natural
gas gatherers and processors, has primary service areas
concentrated in the major producing basins of San Juan,
Wyoming, the Gulf of Mexico, Venezuela and Western Canada. Our
primary businesses natural gas gathering, treating,
and processing; natural gas liquids (NGL) fractionation,
storage and transportation; and oil transportation
fall within the middle of the process of taking natural gas and
crude oil from the wellhead to the consumer. NGLs, ethylene and
propylene are extracted/produced at our plants. These products
are used primarily for the manufacture of plastics, home heating
and refinery feedstock.
Although most of our gas services are performed for a
volumetric-based fee, a portion of our gas processing contracts
are commodity-based and include two distinct types of commodity
exposure. The first type includes Keep Whole
processing contracts whereby we own the NGLs extracted and
replace the lost heating value with natural gas. Under these
contracts, we are exposed to the spread between NGLs and natural
gas prices. The second type consists of Percent of
Liquids contracts whereby we receive a portion of the
extracted liquids with no exposure to the price of natural gas.
Under these contracts, we are only exposed to NGL price
movements.
Our Canadian and Gulf Liquids olefin facilities have an exposure
similar to our Keep Whole contracts. We are exposed
to the spread between the price for natural gas and the products
we produce. In the Gulf Coast, our feedstock for the ethane
cracker is ethane and propane; as a result, we are exposed to
the price spread between ethane and propane and ethylene and
propylene.
Key variables for our business will continue to be (1) the
revenue growth associated with additional infrastructure
completed in late 2003 and 2004 in the deepwater portion of the
Gulf of Mexico, (2) disciplined growth in our core service
areas, and (3) the prices impacting our commodity-based
processing and olefin activities.
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|
Domestic gathering and processing |
Geographically, our Midstream natural gas assets are positioned
to maximize commercial and operational synergies with our other
assets. For example, most of our offshore gathering and
processing assets attach and process or condition natural gas
supplies delivered to the Transco pipeline. Also, our gathering
and processing facilities in the San Juan Basin handle
about 80 percent of our Exploration & Production
groups wellhead production in this basin. Several of our
western gathering systems serve as critical sources of supply
for Northwest Pipeline customers.
We own and/or operate domestic gas gathering and processing
assets primarily within the western states of Wyoming, Colorado
and New Mexico, and the onshore and offshore shelf and deepwater
areas in and around the Gulf Coast states of Texas, Louisiana,
Mississippi and Alabama. These assets consist of approximately
8,100 miles of gathering pipelines, nine processing plants
(one partially owned) and six natural
18
gas treating plants with a combined daily inlet capacity in
excess of 5.3 billion cubic feet per day. In addition to
these natural gas assets, we own and operate three crude oil
pipelines totaling approximately 270 miles with a capacity
of more than 300,000 barrels per day. This includes our
recently completed Mountaineer crude oil pipeline in the
deepwater Gulf of Mexico that serves the Dominion
Exploration & Production-operated Devils Tower field.
See Gathering and processing deepwater projects
below.
Included in the natural gas assets listed above are the assets
of Discovery Producer Services LLC and its subsidiary Discovery
Gas Transmission Services LLC (Discovery). We own a
50 percent interest in Discovery and operate its
facilities. Discoverys assets include a cryogenic natural
gas processing plant near Larose, Louisiana, a natural gas
liquids fractionator plant near Paradis, Louisiana and an
offshore natural gas gathering and transportation system.
Effective June 1, 2004, and due in part to our response to
FERC Order 2004, management, operations and decision-making
control of certain regulated gathering assets in the Midstream
segment was transferred to the Gas Pipeline segment. These
assets were owned by Transco, but were commercially and
physically operated by Midstream. We also requested and were
granted a partial waiver allowing us to continue to manage and
operate the Discovery Gas Transmission and Black Marlin assets.
In order to comply with the remaining provisions of the FERC
order, we determined it was necessary to transfer the management
of our equity investment in the Aux Sable processing plant to
Power. This transfer was effective September 21, 2004.
|
|
|
Gulf Coast petrochemical and olefins |
We own a
5/12 interest
in and are the operator for an ethane cracker at Geismar,
Louisiana, with a total production capacity of 1.3 billion
pounds per year of ethylene. During the fourth quarter of 2004,
we closed on the sale of our interest in an associated ethane/
ethylene storage and transportation complex located in Choctaw,
Louisiana. We continue to own a major ethane pipeline system in
Louisiana.
Our Gulf Liquids New River LLC (Gulf Liquids) business consists
of two refinery off-gas processing facilities, an olefins
fractionator and propylene splitter and connecting pipeline
system in Louisiana. We continue to market Gulf Liquids with the
expectation that these assets will be sold by the end of the
second quarter 2005.
Our Venezuelan investments involve gas compression and gas
processing and natural gas liquids fractionation operations. We
own controlling interests in three gas compressor facilities
which provide roughly 65 percent of the gas injections in
eastern Venezuela. These facilities help stabilize the reservoir
and enhance the recovery of crude oil by re-injecting natural
gas at high pressures. We also own a 49.25 percent interest
in two 400 MMcf/d natural gas liquids extraction plants, a
50,000 barrels per day natural gas liquids fractionation
plant and associated storage and refrigeration facilities.
Prior to 2003, our Venezuelan operations included an operations
contract for an oil loading and storage facility. We operated
these facilities on behalf of Petróleos de Venezuela, S.A.
(PDVSA), the state owned petroleum corporation of Venezuela, the
owner of these facilities. In December 2002, we were removed as
operator of these facilities in connection with the nationwide
strike within Venezuela. We are presently in arbitration with
PDVSA regarding the termination of this contract.
Our Canadian operations include an olefin liquids extraction
plant located near Ft. McMurray, Alberta and an olefin
fractionation facility near Edmonton, Alberta. These facilities
extract olefin liquids from the off-gas produced from oil sands
bitumen upgrading and then fractionate, treat, store and
terminal the propane and propylene recovered from this process.
During 2004, approximately 1.9 million barrels of propane
and 129 million pounds of polymer grade propylene were
produced. We continue to be the only olefins fractionator in
Western Canada and the only treater/processor of oil sands
off-gas. These operations extract valuable
19
petrochemical feedstocks from tar sands refinery off-gas streams
allowing our customers to burn cleaner natural gas streams and
reduce overall air emissions.
We sold our three straddle plants in Western Canada to Inter
Pipeline Fund of Calgary on July 28, 2004. The sale
included our 100 percent ownership interest in the Cochrane
and Empress II plants, and our 50 percent interest in
the Empress V facility.
We own interests in and/or operate natural gas liquid
fractionation and storage assets. These assets include two
partially owned natural gas liquid fractionation facilities near
McPherson, Kansas and Baton Rouge, Louisiana that have a
combined capacity in excess of 160,000 barrels per day. We
also own approximately 20 million barrels of natural gas
liquid storage capacity in central Kansas.
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|
|
Gathering and processing Wyoming expansion |
In the first quarter of 2004, we began processing additional gas
volumes at our Opal processing plant following an expansion
completed by Willbros Mt. West, Inc., a business unit of
Willbros Group, Inc. The new volumes are being produced by
affiliates of Shell Exploration & Production Company in
southwestern Wyomings Pinedale Anticline and other area
producers. This expansion involved the construction of a fourth
cryogenic processing train at our existing gas plant in Opal,
Wyoming.
We operate the new unit under a long-term agreement with
Willbros Mt. West. The terms of the agreement provide for
revenue opportunities to both parties. This project boosts
Opals overall processing capacity from 750 MMcf/d to
more than 1.1 billion cubic feet per day, with the ability
to recover in excess of 50 Mbbls/d of NGL products. At the
end of 2004, the gas volumes processed at the Opal plant were
over 1.1 billion cubic feet per day.
From the Opal plant, gas can be delivered to markets throughout
the West Coast and in the Rockies via connections to three
interstate pipelines Colorado Interstate Pipeline,
Kern River Pipeline and our own Northwest Pipeline.
|
|
|
Gathering and processing deepwater
projects |
The deepwater Gulf continues to be an attractive growth area for
our Midstream business. Investments like our Alpine pipeline and
Devils Tower production facilities continue to increase our
fee-based business and our scale in the Gulf.
Our new floating production system and associated pipelines,
Devils Tower, became operational on May 5, 2004. Initially
built to serve Dominion Exploration & Productions
Devils Tower field, the floating production system is located in
Mississippi Canyon Block 773, approximately 150 miles
south-southwest of Mobile, Alabama. Located in 5,610 feet
of water, it is the worlds deepest dry tree spar. The
platform, which is operated by Dominion on our behalf, is
capable of producing 110 MMcf/d of natural gas and
60 Mbbls/d of oil.
The Devils Tower project includes gas and oil pipelines. The
102-mile Canyon Chief gas line consists of 18-inch diameter
pipe. The 117-mile Mountaineer oil pipeline is a combination of
18- and 20-inch diameter pipe. The gas is delivered into
Transcos pipeline, and processed at our Mobile Bay Plant
to recover the natural gas liquids. The oil is transported to
ChevronTexacos Empire Terminal in Plaquemines Parish,
Louisiana.
Our 18-inch oil pipeline, Alpine, which became operational on
December 14, 2003 is averaging approximately
17.6 Mbbls/d for the fourth quarter of 2004. The pipeline
extends 96 miles from Garden Banks Block 668 in the
central Gulf of Mexico to our shallow-water platform at
Galveston Area Block A244. From this platform, the oil is
delivered onshore through ExxonMobils Hoover Offshore Oil
Pipeline System under a joint tariff agreement. This production
is coming from the Gunnison field, which is located in
3,150 feet of
20
water and operated by Kerr-McGee Oil & Gas Corporation,
a wholly-owned subsidiary of Kerr-McGee Corporation.
Since 1997, we have invested almost $1 billion in new
midstream assets in the Gulf of Mexico. These facilities provide
both onshore and offshore services through pipelines, platforms
and processing plants. The new facilities could also attract
incremental gas volumes to Transcos pipeline system in the
southeastern United States.
Our domestic gas gathering and processing customers are
generally natural gas producers who have proved and/or producing
natural gas fields in the areas surrounding our infrastructure.
During 2004, these operations gathered and processed gas for
approximately 200 gas gathering customers and 100 processing
customers. Our top three gathering and processing customers
accounted for about thirty percent (30%) of our domestic
gathering revenue and processing gross margin. Our gathering and
processing agreements are generally long-term agreements.
In addition to our gathering and processing operations, we also
market NGLs and petrochemical products to a wide range of users
in the energy and petrochemical industries. We provide these
products to third parties from the production at our domestic
facilities. The majority of domestic sales are based on supply
contracts of less than one-year in duration. The production from
our Canadian facilities is marketed in Canada and in the United
States.
Our Venezuelan assets were constructed and are currently
operated for the exclusive benefit of PDVSA. The significant
contracts have a remaining term between 13 and 17 years and
our revenues are based on a combination of fixed capital
payments, throughput volumes, and, in the case of one of the gas
compression facilities, a minimum throughput guarantee. During
2004, Venezuelan President Hugo Chavez successfully defeated a
referendum vote calling for his removal from office. The
internal political situation has enjoyed relative calm since the
conclusion of the referendum. However, President Chavez has
confirmed his public criticism of U.S. policy and has
implemented unilateral changes to existing energy related
contracts, indicating that a level of political risk still
remains.
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Financial & operating statistics |
The following table summarizes our significant operating
statistics for Midstream (as restated, see Note 1 of our
Notes to Consolidated Financial Statements):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
Volumes(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic Gathering (trillion British Thermal Units)(2)
|
|
|
1,252 |
|
|
|
1,272 |
|
|
|
1,308 |
|
Domestic Natural Gas Liquid Production (Mbbls/d)(3)
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|
|
155 |
|
|
|
129 |
|
|
|
135 |
|
Crude Oil Gathering (Mbbls/d)(3)
|
|
|
83 |
|
|
|
68 |
|
|
|
24 |
|
|
|
(1) |
Excludes volumes associated with partially owned assets that are
not consolidated for financial reporting purposes. |
|
(2) |
Prior periods for Domestic Gathering have been restated to
reflect the transfer of the jurisdictional assets to Transco. |
|
(3) |
Annual Average Mbbls/d |
|
|
|
Regulatory and environmental matters |
Under the NGA, gathering and processing facilities and services
are generally not subject to the regulatory authority of the
FERC. Onshore gathering is reserved to the states and offshore
gathering is subject to the Outer Continental Shelf Lands Act
(OCSLA).
21
Of the states where Midstream operates, currently only Kansas
and Texas actively regulate gathering activities. Those states
regulate gathering primarily through complaint mechanisms under
which the state commission may resolve disputes involving an
individual gathering arrangement. Although gathering facilities
located offshore are not subject to the NGA, some controversy
exists as to how the FERC should determine whether offshore
facilities function as gathering. These issues are currently
before the FERC. Most gathering facilities offshore are subject
to the OCSLA, which provides in part that outer continental
shelf pipelines must provide open and nondiscriminatory
access to both owner and non-owner shippers.
Midstreams business operations are subject to various
federal, state, and local environmental and safety laws and
regulations. The Discovery and Black Marlin pipeline systems are
subject to FERC regulation common to interstate gas
transmission. Midstreams liquid pipeline operations are
subject to the provisions of the Hazardous Liquid Pipeline
Safety Act. Certain of our pipelines also file tariff rates
covering intrastate movements with various state commissions.
The United States Department of Transportation has prescribed
safety regulations for common carrier pipelines. The pipeline
systems are subject to various state laws and regulations
concerning safety standards, exercise of eminent domain, and
similar matters. The Kansas Department of Health and Environment
has adopted new regulations to govern underground storage in
Kansas, which will require additional equipment and testing for
Midstreams storage operations in Kansas.
Our remaining Midstream Canadian assets are regulated by the
Alberta Energy & Utilities Board (AEUB) 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 non-compliance with the applicable
regulations is at issue, the AEUB and Alberta Environment have
implemented an enforcement process with escalating consequences.
The gathering and processing business is a regional business
with varying competitive factors in each basin. Our gathering
and processing business competes with other midstream companies,
interstate and intrastate pipelines, master limited partnerships
(MLP), producers and independent gatherers and processors. We
primarily compete with five to ten companies across all basins
in which we provide services. Our focus is to provide our
customers with the most reliable and consistent service at a
competitive price.
Numerous factors impact any given customers choice of a
gathering or processing services provider, including rate,
location, term, timeliness of well connections, pressure
obligations and the willingness of the provider to process for
either a fee or for liquids taken in-kind. Our gathering and
processing services are generally covered by long-term contracts
with applicable acreage or reserve dedications. The active
drilling programs near our relatively large positions in the
San Juan Basin, Wyoming area and Gulf Coast Region indicate
that demand for future gathering and processing infrastructure
and services should continue.
We typically own our gathering and processing facilities. We
construct and maintain gathering pipeline systems pursuant to
rights-of-way, easements, permits, licenses, and consents on and
across properties owned by others. Some portion of the
compression equipment used to lower field pressures to the
natural gas wells that we gather is leased. The compressor
stations and gas processing and treating facilities are located
in whole or in part on lands owned by our subsidiaries or on
sites held under leases or permits issued or approved by public
authorities.
Other
At December 31, 2003, we owned approximately 32% of
Longhorn which owns a refined petroleum products pipeline from
Houston, Texas to El Paso, Texas. During February 2004, we
participated in a recapitalization plan completed by Longhorn,
following which our subsidiaries, Longhorn Enterprises of Texas,
Inc. (LETI) and Williams Petroleum Services, LLC (WPS),
together own, directly or indirectly, approximately 94.7% of the
Class B Interests in Longhorn Pipeline Investors, LLC
(Pipeline Investors) and
22
approximately 21.3% of the Common Interests therein. Pipeline
Investors now indirectly owns Longhorn. The recapitalization
provided the funds necessary to complete final construction and
start-up of the pipeline, and operations commenced in January
2005. As part of the recapitalization, LETI sold a portion of
its limited partner interests in Longhorn for
$11.4 million, and LETI and WPS sold a portion of the debt
owed to them individually by Longhorn for approximately
$58 million. In addition, in exchange for the Common
Interests described above, LETI contributed the remaining
balance of its limited partnership interests, and WPS
contributed all of its general partnership interests in the
general partner of Longhorn. LETI and WPS also exchanged the
remaining debt owed by Longhorn for the Class B Interests
described above. The Class B Interests are preferred
interests but subordinate to the new investors preferred
interests, and the Common Interests are subordinate to both.
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 sold in 2002, 2003 and 2004 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.
Our corporate parent company performs certain management, legal,
financial, tax, consultative, administrative and other services
for our subsidiaries.
Our principal sources of cash are from external financings,
dividends and advances from our subsidiaries, investments,
payments by subsidiaries for services rendered, interest
payments from subsidiaries on cash advances and net proceeds
from asset sales. The amount of dividends available to us from
subsidiaries largely depends upon each subsidiarys
earnings and operating capital requirements. The terms of many
of our subsidiaries borrowing arrangements limit the
transfer of funds to our corporate parent.
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 Power, we are required by counterparties 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.
ENVIRONMENTAL MATTERS
In addition to the environmental matters included in the
business segment discussions above, a description of
environmental claims is included in Note 15 of our Notes to
Consolidated Financial Statements and is incorporated herein by
reference.
EMPLOYEES
At February 28, 2005, we had approximately
3,656 full-time employees including 728 at the corporate
level, 141 at Power, 1,562 at Gas Pipeline, 411 at
Exploration & Production, and 814 at Midstream. None of
our employees are represented by unions or covered by collective
bargaining agreements.
FORWARD LOOKING STATEMENTS/ RISK FACTORS AND CAUTIONARY
STATEMENT
FOR PURPOSES OF THE SAFE HARBOR PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Certain matters discussed in this annual report, excluding
historical information, include forward-looking
statements statements that discuss our expected
future results based on current and pending business
23
operations. We make these forward-looking statements in reliance
on the safe harbor protections provided under the Private
Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts,
included in this Form 10-K which address activities, events
or developments which we expect, believe or anticipate will or
may occur in the future are forward-looking statements.
Forward-looking statements can be identified by words such as
anticipates, believes,
could, continues, estimates,
expects, forecasts, might,
planned, potential,
projects, scheduled or similar
expressions. These forward-looking statements include, among
others, such things as:
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amounts and nature of future capital expenditures; |
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expansion and growth of our business and operations; |
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business strategy; |
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estimates of proved gas and oil reserves; |
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reserve potential; |
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development drilling potential; |
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cash flow from operations; and |
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power and gas prices and demand. |
These statements are based on certain assumptions and analysis
made by us in light of our experience and our perception of
historical trends, current conditions and expected future
developments as well as other factors we believe are appropriate
in the circumstances. Although we believe these forward-looking
statements are based on reasonable assumptions, statements made
regarding future results are subject to a number of assumptions,
uncertainties and risks that could cause future results to be
materially different from the results stated or implied in this
document.
These risks and uncertainties include:
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general economic and market conditions; |
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changes in laws or regulations; |
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continued availability of capital and financing; and |
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other factors, most of which are beyond our control. |
See the Risk Factors section of this report for a
more detailed discussion of these risks and uncertainties. When
considering forward-looking statements, one should keep in mind
the risk factors described in Risk Factors below.
The risk factors could cause our actual results to differ
materially from those contained in any forward-looking
statement. We disclaim any obligation 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.
RISK FACTORS
You should carefully consider the following risk factors in
addition to the other information in this annual 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 our business
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Our risk measurement and hedging activities might not
prevent losses. |
Although we have risk measurement systems in place that use
various methodologies to quantify risk, these systems might not
always be followed or might not always work as planned. Further,
such risk measurement systems do not in themselves manage risk,
and adverse changes in energy commodity market
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prices, volatility, adverse correlation of commodity prices, the
liquidity of markets, and changes in interest rates might still
adversely affect our earnings and cash flows and our balance
sheet under applicable accounting rules, even if risks have been
identified.
To lower our financial exposure related to commodity price and
market fluctuations, we have entered into contracts to hedge
certain risks associated with our assets and operations,
including our long-term tolling agreements. In these hedging
activities, we have used fixed-price, forward, physical purchase
and sales contracts, futures, financial swaps and option
contracts traded in the over-the-counter markets or on
exchanges, as well as long-term structured transactions when
feasible. Substantial declines in market liquidity, however, as
well as our current credit rating, and termination of existing
positions (due for example to credit concerns) have greatly
limited our ability to hedge risks identified and have caused
previously hedged positions to become unhedged. To the extent we
have unhedged positions, fluctuating commodity prices could
cause our net revenues and net income to be volatile.
Some of the hedges of our tolling contracts are more effective
than others in reducing economic risk and creating future cash
flow certainty. For example, we may resell our rights under a
tolling contract through a forward contract, which has terms
that match those of the tolling contract. This type of forward
contract would be very effective at hedging not only the
commodity price risk but also the volatility risk inherent in
the tolling contract. However, this forward contract would not
hedge the tolling contracts counterparty credit or
performance risk. A default by the tolling contract counterparty
could result in a future loss of economic value and a change in
future cash flows. Other economic hedges of the tolling
contract, including full requirements contracts, forward
physical commodity contracts and financial swaps and futures,
could also effectively hedge the commodity price risk of a
tolling contract. However, these types of contracts would be
less effective or ineffective in hedging the volatility risk
associated with the tolling contract because they do not possess
the same optionality characteristics as the tolling contract.
These other contracts would also be ineffective in hedging
counterparty credit or performance risk.
We manage counterparty credit risk at the enterprise level for
our unregulated businesses and at the business unit level for
our regulated business. Risk is managed within the guidelines
established by our Credit Policy. We believe that the
application of the requirements under the credit policy and the
associated control framework, along with our analytical
capabilities inherent in our credit system, will enhance our
ability to manage counterparty credit risk. However, we might
not be able to successfully manage all credit risk and as such,
future cash flows could be impacted by counterparty default.
The impact of changes in market prices for natural gas on the
average gas prices received by us may be reduced based on the
level of our hedging strategies. These hedging arrangements may
limit our potential gains if the market prices for natural gas
were to rise substantially over the price established by the
hedge. In addition, our hedging arrangements expose us to the
risk of financial loss in certain circumstances, including
instances in which:
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production is less than expected; |
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a change in the difference between published price indexes
established by pipelines in which our hedged production is
delivered and the reference price established in the hedging
arrangements is such that we are required to make payments to
our counterparties; or |
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the counterparties to our hedging arrangements fail to honor
their financial commitments. |
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Electricity, natural gas liquids and gas prices 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, profitability, future rate of
growth and the value of our power and gas businesses depend
primarily upon the prices we receive for natural gas and other
commodities. Prices also affect the amount of cash flow
available for capital expenditures and our ability to borrow
money or raise additional capital.
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Historically, the markets for these commodities have been
volatile and they are likely to continue to be volatile. Wide
fluctuations in prices might result from relatively minor
changes in the supply of and demand for these commodities,
market uncertainty and other factors that are beyond our
control, including:
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worldwide and domestic supplies of electricity, natural gas,
petroleum, and related commodities; |
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turmoil in the Middle East and other producing regions; |
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terrorist attacks on production or transportation assets; |
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weather conditions; |
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the level of consumer demand; |
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the price and availability of other types of fuels; |
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the availability of pipeline capacity; |
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the price and level of foreign imports; |
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domestic and foreign governmental regulations and taxes; |
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volatility in the natural gas markets; |
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the overall economic environment; and |
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the credit of participants in the markets where products are
bought and sold. |
These factors and the volatility of the energy markets make it
extremely difficult to predict future electricity and gas price
movements with any certainty. Further, electricity and gas
prices do not necessarily move in tandem.
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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 portfolios consist of wholesale contracts to buy and sell
commodities, including contracts for electricity, natural gas,
natural gas liquids 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, we could
realize material losses from our marketing. 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. In such event, 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 financing
transaction fails to perform and any collateral that secures our
counterpartys obligation is inadequate, we will lose money.
If we are unable to perform under our energy agreements, we
could be required to pay damages. These damages generally would
be based on the difference between the market price to acquire
replacement energy or energy services and the relevant contract
price. Depending on price volatility in the wholesale energy
markets, such damages could be significant.
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Our operating results might fluctuate on a seasonal and
quarterly basis. |
Revenues from our businesses, including gas transmission and the
sale of electric power, can have seasonal characteristics. In
many parts of the country, demand for power peaks during the hot
summer months, with market prices also peaking at that time. In
other areas, demand for power peaks during the winter. In
addition, demand for gas and other fuels peaks during the
winter. As a result, our overall operating results in the future
might fluctuate substantially on a seasonal basis. Demand for
gas and other fuels could vary significantly from our
expectations depending on the nature and location of our
facilities and pipeline
26
systems and the terms of our power sale agreements and gas
transmission arrangements relative to demand created by unusual
weather patterns.
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Our investments and projects located outside of the United
States expose us to risks related to laws of other countries,
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 non-recourse project 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 in foreign countries also can present currency
exchange rate and convertibility, inflation and repatriation
risk. In certain conditions under which we develop or acquire
projects, or make investments, economic and monetary conditions
and other factors could affect our ability to convert 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. Foreign currency
risk can also arise when the revenues received by our foreign
subsidiaries are not in U.S. dollars. In such cases, a
strengthening of the U.S. dollar could reduce the amount of
cash and income we receive from these foreign subsidiaries.
While we believe we have hedges and contracts in place to
mitigate our most significant foreign currency exchange risks,
our hedges might not be sufficient or we might have some
exposures that are not hedged which could result in losses or
volatility in our revenues.
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Our debt agreements impose restrictions on us that may
adversely affect our ability to operate our business. |
Our debt agreements contain covenants that limit, among other
things, our ability to create liens, sell assets, make certain
distributions, repurchase equity 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. Our ability to
comply with these covenants may be affected by many events
beyond our control, and we cannot assure you that our future
operating results will be sufficient to comply with the
covenants or, in the event of a default under any of our debt
agreements, to remedy that default.
Although we are currently in compliance with our financial and
other covenants in our debt agreements, our failure to comply
with such financial or other covenants could result in events of
default. Upon the occurrence of an event of default under our
debt agreements, 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. By reason of cross-default or cross-acceleration
provisions in certain of our debt agreements, such a default or
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, and the lenders
under the affected debt agreement 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.
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Risks related to the regulation of our businesses
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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. |
Existing regulations might be revised or reinterpreted, new laws
and regulations might be adopted or become applicable to us or
our facilities, and future changes in laws and regulations might
have a detrimental effect on our business. Over the past few
years, certain restructured energy markets have experienced
supply problems and price volatility. In some of these markets,
including California, proposals have been made by governmental
agencies and other interested parties to re-regulate areas of
these markets which have previously been deregulated. Various
forms of market controls and limitations including price caps
and bid caps have already been implemented and new controls and
market restructuring proposals are in various stages of
development, consideration and implementation. We cannot assure
you that changes in market structure and regulation will not
adversely affect our business. We cannot assure you that other
proposals to re-regulate will not be made or that legislative or
other attention to the electric power restructuring process will
not cause the deregulation process to be delayed or reversed.
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Our revenues might decrease if we are unable to gain
adequate, reliable and affordable access to transmission and
distribution assets due to the FERC and regional regulation of
wholesale market transactions for electricity and gas. |
We depend on transmission and distribution facilities owned and
operated by utilities and other energy companies to deliver the
electricity and natural gas we buy and sell in the wholesale
market. If transmission is disrupted, if capacity is inadequate,
or if credit requirements or rates of such utilities or energy
companies are increased, our ability to sell and deliver
products might be hindered. The FERC has issued power
transmission regulations that require wholesale electric
transmission services to be offered on an open-access,
non-discriminatory basis. Although these regulations are
designed to encourage competition in wholesale market
transactions for electricity, some companies have failed to
provide fair and equal access to their transmission systems or
have not provided sufficient transmission capacity to enable
other companies to transmit electric power. We cannot predict
whether and to what extent the industry will comply with these
initiatives, or whether the regulations will fully accomplish
the FERCs objectives.
In addition, the independent system operators who oversee the
transmission systems in regional power markets, such as
California, have in the past been authorized to impose, and
might continue to impose, price limitations and other mechanisms
to address volatility in the power markets. These types of price
limitations and other mechanisms might adversely impact the
profitability of our wholesale power marketing and trading.
Given the extreme volatility and lack of meaningful long-term
price history in many of these markets and the imposition of
price limitations by regulators, independent system operators or
other marker operators, we can offer no assurance that we will
be able to operate profitably in all wholesale power markets.
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Our gas sales, transmission, and storage operations are
subject to government regulations and rate proceedings that
could have an adverse impact on our ability to recover the costs
of operating our pipeline facilities. |
Our interstate gas sales, transmission, and storage operations
conducted through our Gas Pipelines business are subject to the
FERCs rules and regulations in accordance with the Natural
Gas Act of 1938 and the Natural Gas Policy Act of 1978. The
FERCs regulatory authority extends to:
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transportation and sale for resale of natural gas in interstate
commerce; |
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rates and charges; |
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construction; |
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acquisition, extension or abandonment of services or facilities; |
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accounts and records; |
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depreciation and amortization policies; and |
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operating terms and conditions of service. |
The FERC has taken certain actions to strengthen market forces
in the natural gas pipeline industry that has led to increased
competition throughout the industry. In a number of key markets,
interstate pipelines are now facing competitive pressure from
other major pipeline systems, enabling local distribution
companies and end users to choose a transmission provider based
on economic and other considerations.
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The different regional power markets in which we compete
or will compete in the future have changing regulatory
structures, which could affect our growth and performance in
these regions. |
Our results are likely to be affected by differences in the
market and transmission regulatory structures in various
regional power markets. Problems or delays that might arise in
the formation and operation of new regional transmission
organizations (RTOs) might restrict our ability to sell power
produced by our generating capacity to certain markets if there
is insufficient transmission capacity otherwise available. The
rules governing the various regional power markets might also
change from time to time which could affect our costs or
revenues. Because it remains unclear which companies will be
participating in the various regional power markets, or how RTOs
will develop and evolve or what regions they will cover, we are
unable to assess fully the impact that these power markets might
have on our business.
Risks related to legal proceedings and governmental
investigations
Public and regulatory scrutiny of the energy industry and of the
capital markets has resulted in increased regulation being
either proposed or implemented. Such scrutiny has also resulted
in various inquiries, investigations and court proceedings,
including a DOJ investigation and private class actions and
shareholder lawsuits in which we are a named defendant.
Such inquiries, investigations and court proceedings are ongoing
and continue to adversely affect our business as a whole. We
might see these adverse effects 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 against us arising out of the
operation of our Power business, our former telecommunications
subsidiary, or other matters related to our ongoing business
include environmental matters, disputes over gas measurement and
royalty payments, ERISA litigation, shareholder class action
suits, regulatory appeals and similar matters. Any or all of
these 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.
Risks affecting our strategy and financing needs
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Developments affecting the wholesale power and energy
trading industry sector have reduced market activity and
liquidity and might continue to adversely affect our results of
operations. |
In June 2002, we announced our intention to exit the wholesale
power and energy trading business and divest our trading
portfolio. We have since decided to maintain our wholesale power
and energy trading business and trading portfolio.
Therefore, the legacy issues arising out of the 2000-2001 energy
crisis in California, the resulting collapse in energy merchant
credit and volatility in natural gas prices, the Enron
Corporation bankruptcy filing, and investigations by
governmental authorities into energy trading activities and
increased litigation related to such inquiries, could continue
to affect us in the future.
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Because we no longer maintain investment grade credit
ratings, our counterparties have required us to provide higher
amounts of credit support which raises our cost of doing
business. |
Our transactions in each of our businesses require greater
credit assurances, both to be given from, and received by, us to
satisfy credit support requirements. Additionally, certain
market disruptions or a further downgrade of our credit rating
might further increase our cost of borrowing or further impair
our ability to access one or any of the capital markets. Such
disruptions could include:
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further economic downturns; |
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capital market conditions generally; |
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market prices for electricity and natural gas; |
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terrorist attacks or threatened attacks on our facilities or
those of other energy companies; or |
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the overall health of the energy industry, including the
bankruptcy or insolvency of other energy companies. |
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Despite our restructuring efforts, we may not attain
investment grade ratings. |
Credit rating agencies perform independent analysis when
assigning credit ratings. Given the significant changes in
capital markets and the energy industry over the last few years,
credit rating agencies continue to review the criteria for
attaining investment grade ratings and make changes to those
criteria from time to time. Our goal is to attain investment
grade ratios. However, there is no guarantee that the credit
rating agencies will assign us investment grade ratings even if
we meet or exceed their criteria for investment grade ratios.
Risks related to outsourcing of non-core support services
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Institutional knowledge represented by our former
employees now employed by our outsourcing service provider might
not be adequately preserved. |
Due to the large number of our former employees who migrated to
an outsourcing provider, access to significant amounts of
internal historical knowledge and expertise could become
unavailable to us, particularly if knowledge transfer
initiatives are delayed or ineffective.
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Failure of the outsourcing relationship 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, 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.
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Our ability to receive services from outsourcing provider
locations outside of the United States might be impacted by
cultural differences, political instability, or unanticipated
regulatory requirements in jurisdictions outside the United
States. |
Certain information technology application development, human
resources, and helpdesk services that are currently provided by
an outsourcer will be relocated to service centers operated by
our outsourcing provider outside of the United States during
2005. 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, 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.
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Risks related to environmental matters
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We could incur material losses if we are held liable for
the environmental condition of any of our assets or divested
assets, which could include losses that exceed our current
expectations. |
We are generally responsible for all on-site liabilities
associated with the environmental condition of our facilities
and assets, which we have acquired or developed, regardless of
when the liabilities arose and whether they are known or
unknown. In addition, in connection with certain acquisitions
and sales of assets, we might obtain, or be required to provide,
indemnification against certain environmental liabilities. If we
incur a material liability, or the other party to a transaction
fails to meet its indemnification obligations to us, we could
suffer material losses. If a purchaser of one of our divested
assets incurs a liability due to the environmental condition of
the divested asset, we may have a contractual obligation to
indemnify that purchaser or otherwise retain responsibility for
the environmental condition of the divested asset. We may also
have liability for the environmental condition of divested
assets under applicable federal or state laws and regulations.
Changes to applicable laws and regulations, or changes to their
interpretation, may increase our liability. Environmental
conditions of divested assets may not be covered by insurance.
Even if environmental conditions could be covered by insurance,
policy conditions may not be met.
We make assumptions and develop expectations about possible
liability 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. Our assumptions and expectations are also based on
available information. If more information becomes available to
us, our assumptions may change. Any of these changes may result
in not only increased risk related to one or more of our assets,
but material losses in excess of current estimates.
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Environmental regulation and liability relating to our
business will be subject to environmental legislation in all
jurisdictions in which it operates, and any changes in such
legislation could negatively affect our results of
operations. |
Our operations are subject to extensive environmental regulation
pursuant to a variety of federal, provincial, state and
municipal laws and regulations. Such environmental legislation
imposes, among other things, restrictions, liabilities and
obligations in connection with the generation, handling, use,
storage, transportation, treatment and disposal of hazardous
substances and waste and in connection with spills, releases and
emissions of various substances into the environment.
Environmental legislation also requires that our facilities,
sites and other properties associated with our operations be
operated, maintained, abandoned and reclaimed to the
satisfaction of applicable regulatory authorities. Existing
environmental regulations could also be revised or
reinterpreted, new laws and regulations could be adopted or
become applicable to us or our facilities, and future changes in
environmental laws and regulations could occur. The federal
government and several states recently have proposed increased
environmental regulation of many industrial activities,
including increased regulation of air quality, water quality and
solid waste management.
Compliance with environmental legislation will require
significant expenditures, including expenditures for compliance
with the Clean Air Act and similar legislation, for clean up
costs and damages arising out of contaminated properties, and
for failure to comply with environmental legislation and
regulations which might result in the imposition of fines and
penalties. The steps we take to bring certain of our facilities
into compliance could be 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.
Further, our regulatory rate structure and our contracts with
clients might not necessarily allow us to recover capital costs
we incur to comply with new environmental regulations. Also, we
might not be able to obtain or maintain from time to time all
required environmental regulatory approvals for certain
development projects. If there is a delay in obtaining any
required environmental regulatory approvals or if we fail to
obtain and comply with them, the operation of our facilities
could be prevented or become subject to additional costs. Should
we fail to comply with all applicable environmental laws, we
might be subject to penalties and fines imposed against us by
regulatory authorities. Although we do not expect that the costs
of complying with current environmental legislation will have a
material adverse effect on our financial condition or results of
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operations, no assurance can be made that the costs of complying
with environmental legislation in the future will not have such
an effect.
Risks relating to accounting standards
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Potential changes in accounting standards might cause us
to revise our financial results and disclosure in the future,
which might change the way analysts measure our business or
financial performance. |
Accounting irregularities discovered in the past few years in
various industries have forced regulators and legislators to
take a renewed look at accounting practices, financial
disclosures, companies relationships with their
independent auditors and retirement plan practices. Because it
is still unclear what laws or regulations will ultimately
develop, we cannot predict the ultimate impact of any future
changes in accounting regulations or practices in general with
respect to public companies or the energy industry or in our
operations specifically.
In addition, the Financial Accounting Standards Board
(FASB) or the SEC could enact new accounting standards that
might impact how we are required to record revenues, expenses,
assets and liabilities.
Risks relating to our industry
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The long-term financial condition of our natural gas
transmission and midstream businesses are dependent on the
continued availability of natural gas reserves. |
The development of additional natural gas reserves 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, or
the lack of available capital for these projects could adversely
affect the development of additional reserves and production,
gathering, storage and pipeline transmission and import and
export of natural gas supplies. Additional natural gas reserves
might not be developed in commercial quantities and in
sufficient amounts to fill the capacities of our gathering and
processing pipeline facilities.
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Our drilling, production, gathering, processing and
transporting activities involve numerous risks that might result
in accidents and other operating risks and costs. |
Our operations are subject to all of the risks and hazards
typically associated with the exploitation, development and
exploration for, and the production and transportation of oil
and gas. These operating risks include, but are not limited to:
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blowouts, cratering and explosions; |
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uncontrollable flows of oil, natural gas or well fluids; |
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fires; |
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formations with abnormal pressures; |
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pollution and other environmental risks; and |
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natural disasters. |
In addition, there are inherent in our gas gathering, processing
and transporting properties a variety of hazards and operating
risks, such as leaks, explosions and mechanical problems that
could cause substantial financial losses. In addition, these
risks could result in loss of human life, 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. The location of pipelines near
populated areas, including residential areas, commercial
business centers and industrial sites, could increase the level
of damages resulting from these risks. We implemented an
Integrity Management Plan (IMP) for our gas transmission
pipelines in December 2004, as required by the Pipeline Safety
Improvement Act. As part of the IMP, we identified High
Consequence Areas (HCA) through which our pipelines run. An
HCA is an area where the potential consequence of a gas pipeline
accident may be
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significant or do considerable harm to people or property.
Certain segments of our pipelines run through HCAs. An event
such as those described above in a HCA not only could cause
considerable harm to people or property, but could have a
material adverse effect on our financial position 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. Such circumstances could
adversely impact our ability to meet contractual obligations and
retain customers. For example, the 26 inch segment of
Northwest Pipeline from Sumas to Washougal, Washington was idled
in 2003 after a line break associated with stress corrosion
cracking (SCC). SCC is caused by a specific combination of
stress and exposure to environmental factors such as soil
acidity, moisture, and electro chemical properties that occurs
in older pipelines. This type of corrosion cracking is a very
complex technical phenomenon and, while the industry is making
progress in developing methods to predict and identify SCC,
there are still many unknowns.
In December 2003, we received an Amended Corrective Action Order
(ACAO) from the U.S. Department of
Transportations Office of Pipeline Safety
(OPS) regarding a segment of one of our natural gas
pipelines in western Washington. The pipeline experienced two
breaks in 2003 and we subsequently idled the pipeline segment
until its integrity could be assured.
By June 2004 we had successfully completed our hydrostatic
testing program and returned to service 111 miles of the
268 miles of pipe affected by the ACAO. That effort has
restored 131 Mdt/d of the 360 Mdt/d of idled capacity and is
anticipated to be adequate to meet most market conditions. To
date our ability to serve the market demand has not been
significantly impacted.
As required by OPS, we plan to replace the pipelines
entire capacity by November 2006 to meet long-term demands. We
conducted a reverse open season to determine whether any
existing customers were willing to relinquish or reduce their
capacity commitments to allow us to reduce the scope of pipeline
replacement facilities. That resulted in 13 Mdt/d of capacity
being relinquished and incorporated into the replacement
project. On November 29, 2004 we filed with the FERC a
certificate application for the Capacity Replacement
Project including construction of approximately
79.5 miles of 36-inch pipeline and 10,760 net
horsepower of additional compression at two existing compressor
stations and abandonment of approximately 268 miles of the
existing 26-inch pipeline. The estimated net cost of the
Capacity Replacement Project included in the filing is
approximately $333 million. The majority of these costs
will be spent in 2005 and 2006. We anticipate filing a rate case
to recover the capitalized costs relating to restoration and
replacement facilities following the in-service date of the
replacement facilities.
|
|
|
Estimating reserves and future net revenues involves
uncertainties and negative revisions to reserve estimates, and
oil and gas price declines may lead to 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. 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 Form 10-K 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 over time.
Quantities of proved reserves are estimated based on economic
conditions in existence during the period of assessment. Lower
oil and gas prices 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. The
33
revisions may also be sufficient to trigger impairment losses on
certain properties which would result in a further non-cash
charge to earnings. Although unlikely, the revisions could also
affect the evaluation of Exploration &
Productions goodwill for impairment purposes.
Other risks
|
|
|
The threat of terrorist activities and the potential for
continued military and other actions could adversely affect our
business. |
The continued threat of terrorism and the impact of continued
military and other action by the United States and its allies
might lead to increased political, economic and financial market
instability and volatility in prices for natural gas, which
could affect the market for our gas operations. In addition,
future acts of terrorism could be directed against companies
operating in the United States, and it has been reported that
terrorists might be targeting domestic energy facilities. While
we are taking steps that we believe are appropriate to increase
the security at locations where our energy assets are located,
there is no assurance that we can completely secure our
locations or to completely protect them against a terrorist
attack. These developments have subjected our operations to
increased risks and, depending on their ultimate magnitude,
could have a material adverse effect on our business. In
particular, we might experience increased capital or operating
costs to implement increased security for our energy assets.
|
|
|
Historic performance of our exploration and production
business is no guarantee of future performance. |
Performance of our exploration and production business is
affected in part by factors beyond our control, such as:
|
|
|
|
|
regulations and regulatory approvals; |
|
|
|
availability of capital for drilling projects which may be
affected by other risk factors discussed in this report; |
|
|
|
cost-effective availability of drilling rigs and necessary
equipment; |
|
|
|
availability of cost-effective transportation for
products; or |
|
|
|
market risks already discussed in this report. |
Our success rate for drilling projects in 2004 should not be
considered a predictor of future performance. Reserves that are
proven reserves are those estimated quantities of
crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty are
recoverable in future years form known reservoirs under existing
economic and operating conditions, but should not be considered
as a guarantee of results for future drilling projects.
|
|
|
Our assets and operations can be affected by weather and
other natural phenomena. |
Our assets and operations, especially those located offshore,
can be adversely affected by hurricanes, 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.
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. See Note 18 of our Notes to
Consolidated Financial Statements for information relating to
long-lived assets during the last two fiscal years, other than
financial instruments, long-term customer relationships of a
financial institution, mortgage and other servicing rights and
deferred policy acquisition costs, located in the United States
and all foreign countries.
34
|
|
Item 3. |
Legal Proceedings |
The information called for by this item is provided in
Note 15 Contingent liabilities and commitments included in
the Notes to Consolidated Financial Statements of this report,
which information is incorporated by reference into this item.
35
|
|
Item 4. |
Submission of Matters to a Vote of Security Holders |
None.
Item 4A. Executive Officers of the Registrant
The name, age, period of service, and title of each of our
executive officers as of February 28, 2005, are listed
below.
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|
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Alan S. Armstrong
|
|
Senior Vice President, Midstream
Age: 42
Position held since February 2002. |
|
|
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. |
James J. Bender
|
|
Senior Vice President and General Counsel
Age 48
Position held since December 16, 2002. |
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|
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. since June 1997. NRG Energy,
Inc. filed a voluntary bankruptcy petition during 2003 and its
plan of reorganization was approved in December 2003. |
Donald R. Chappel
|
|
Senior Vice President and Chief Financial Officer
Age: 53
Position held since April 16, 2003. |
|
|
Prior to joining us, Mr. Chappel during 2000 founded and
served as chief executive officer of a development business in
Chicago, Illinois through April, 2003 when he joined us.
Mr. Chappel joined Waste Management, Inc. in 1987 and held
various financial, administrative and operational leadership
positions, including twice serving as chief financial officer,
during 1997 and 1998 and most recently during 1999 through
February 2000. |
Ralph A. Hill
|
|
Senior Vice President, Exploration and Production
Age: 45
Position held since December 1998. |
|
|
Mr. Hill was vice president of the exploration and
production unit from 1993 to 1998 as well as Senior Vice
President Petroleum Services from 1998 to 2003. |
William E. Hobbs
|
|
Senior Vice President, Power
Age: 45
Position held since October 2002 |
|
|
From February 2000 to October 2002, Mr. Hobbs was President
and Chief Executive Officer of Williams Energy
Marketing & Trading. From 1997 to February 2000, he
served as a Vice President of various Williams subsidiaries. |
Michael P. Johnson, Sr.
|
|
Senior Vice President and Chief Administrative Officer
Age: 57
Position held since May 2004. |
|
|
Mr. Johnson was named our Senior Vice President of Human
Resources and Administration in April 1999. Prior to joining us
in December 1998, he held officer level positions, such as Vice
President of Human Resources, Vice President for Corporate
People Strategies, and Vice President Human Resource Services,
for Amoco Corporation from 1991 to 1998. |
Steven J. Malcolm
|
|
Chairman of the Board, Chief Executive Officer and President
Age: 56
Position held since September 21, 2001. |
|
|
Mr. Malcolm was elected Chief Executive Officer of Williams
in January 2002 and Chairman of the Board in May 2002. He was
elected President and Chief Operating Officer in September 2001.
Prior to that, he was our Executive Vice President from May
2001, President and Chief Executive Officer of our subsidiary
Williams Energy Services, LLC, since December 1998 and the
Senior Vice President and General Manager of our subsidiary,
Williams Field Services Company, since November 1994. |
36
|
|
|
Phillip D. Wright
|
|
Senior Vice President, Gas Pipeline
Age: 49
Position held since January 2005. |
|
|
From October 2002 to January 2005, Mr. Wright 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. From 1996
until September 2001, he was Senior Vice President, Enterprise
Development and Planning for our energy services group.
Mr. Wright has held various positions with us since 1989. |
PART II
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|
Item 5. |
Market for Registrants Common Equity and Related
Stockholder Matters |
Our common stock is listed on the New York Stock Exchange and
Pacific Stock Exchanges under the symbol WMB. At the
close of business on February 28, 2005, we had
approximately 13,234 holders of record of our common stock. The
high and low closing sales price ranges (New York Stock Exchange
composite transactions) and dividends declared by quarter for
each of the past two years are as follows:
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|
2004 | |
|
2003 | |
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| |
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| |
Quarter |
|
High | |
|
Low | |
|
Dividend | |
|
High | |
|
Low | |
|
Dividend | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
1st
|
|
$ |
11.30 |
|
|
$ |
8.75 |
|
|
$ |
.01 |
|
|
$ |
4.74 |
|
|
$ |
2.60 |
|
|
$ |
.01 |
|
2nd
|
|
$ |
12.23 |
|
|
$ |
9.89 |
|
|
$ |
.01 |
|
|
$ |
8.77 |
|
|
$ |
4.87 |
|
|
$ |
.01 |
|
3rd
|
|
$ |
12.51 |
|
|
$ |
11.45 |
|
|
$ |
.01 |
|
|
$ |
9.42 |
|
|
$ |
6.20 |
|
|
$ |
.01 |
|
4th
|
|
$ |
17.10 |
|
|
$ |
12.35 |
|
|
$ |
.05 |
|
|
$ |
10.62 |
|
|
$ |
8.94 |
|
|
$ |
.01 |
|
Some of our subsidiaries borrowing arrangements limit the
transfer of funds to us. These terms have not impeded, nor are
they expected to impede, our ability to pay dividends. However,
until January 20, 2005, the credit agreements underlying
our two unsecured revolving credit facilities totaling
$500 million prohibited us from paying quarterly cash
dividends on our common stock in excess of $0.05 per share.
On January 20, 2005, these facilities were terminated and
replaced with two new facilities. As part of the transaction,
the dividend restriction, along with most of the other
restrictive covenants, was removed from the new credit
agreements.
37
|
|
Item 6. |
Selected Financial Data |
The following financial data as of December 31, 2004 and
2003 and for the three years ended December 31, 2004 are an
integral part of, and should be read in conjunction with, the
consolidated financial statements and notes thereto. All other
amounts have been prepared from our financial records. Certain
amounts below have been restated or reclassified. See
Note 1 of Notes to Consolidated Financial Statements in
Item 8 for discussion of changes in 2004, 2003 and 2002.
Results for the years 2001 and 2000 also include amounts related
to the discontinued operations of Williams Communications Group,
our previously owned communications subsidiary (WilTel).
Information concerning significant trends in the financial
condition and results of operations is contained in
Managements Discussion & Analysis of Financial
Condition and Results of Operations of this report.
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|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
2001 | |
|
2000 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Millions, except per-share amounts) | |
Revenues(1)
|
|
$ |
12,461.3 |
|
|
$ |
16,651.0 |
|
|
$ |
3,434.5 |
|
|
$ |
4,899.5 |
|
|
$ |
4,859.2 |
|
Income (loss) from continuing operations(2)
|
|
|
93.2 |
|
|
|
(57.5 |
) |
|
|
(618.4 |
) |
|
|
640.5 |
|
|
|
666.5 |
|
Income (loss) from discontinued operations(3)
|
|
|
70.5 |
|
|
|
326.6 |
|
|
|
(136.3 |
) |
|
|
(1,118.2 |
) |
|
|
(142.2 |
) |
Cumulative effect of change in accounting principles(4)
|
|
|
|
|
|
|
(761.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per common share:
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
.18 |
|
|
|
(.17 |
) |
|
|
(1.37 |
) |
|
|
1.28 |
|
|
|
1.49 |
|
|
Income (loss) from discontinued operations
|
|
|
.13 |
|
|
|
.63 |
|
|
|
(.26 |
) |
|
|
(2.23 |
) |
|
|
(.32 |
) |
|
Cumulative effect of change in accounting principles
|
|
|
|
|
|
|
(1.47 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total assets at December 31
|
|
|
23,993.0 |
|
|
|
27,021.8 |
|
|
|
34,988.5 |
|
|
|
38,614.2 |
|
|
|
34,776.6 |
|
Short-term notes payable and long-term debt due within one year
|
|
|
250.1 |
|
|
|
938.5 |
|
|
|
2,077.1 |
|
|
|
2,510.4 |
|
|
|
3,193.2 |
|
Long-term debt at December 31
|
|
|
7,711.9 |
|
|
|
11,039.8 |
|
|
|
11,075.7 |
|
|
|
8,285.0 |
|
|
|
6,316.8 |
|
Preferred interests in consolidated subsidiaries at
December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
976.4 |
|
|
|
877.9 |
|
Williams obligated mandatorily redeemable preferred securities
of Trust at December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
189.9 |
|
Stockholders equity at December 31(5)
|
|
|
4,955.9 |
|
|
|
4,102.1 |
|
|
|
5,049.0 |
|
|
|
6,044.0 |
|
|
|
5,892.0 |
|
Cash dividends per common share
|
|
|
.08 |
|
|
|
.04 |
|
|
|
.42 |
|
|
|
.68 |
|
|
|
.60 |
|
|
|
(1) |
As discussed in Note 1 of Notes to Consolidated Financial
Statements, the adoption of Emerging Issues Task Force Issue
No. 02-3 (EITF 02-3) requires that revenues and costs
of sale from non-derivative contracts and certain physically
settled derivative contracts be reported on a gross basis. Prior
to the adoption on January 1, 2003, these revenues were
presented net of costs. As permitted by EITF 02-3, prior
year amounts have not been restated. Also, see Note 1 of
Notes to Consolidated Financial Statements for discussion of
revenue recognized in 2003 related to the correction of prior
period items. |
|
(2) |
See Note 4 of Notes to Consolidated Financial Statements
for discussion of asset sales, impairments and other accruals in
2004, 2003 and 2002. |
|
(3) |
See Note 2 of Notes to Consolidated Financial Statements
for the discussion of the 2004, 2003 and 2002 income (loss) from
discontinued operations. Results for the years 2001 and 2000
also include amounts related to the discontinued operations of
WilTel. |
|
(4) |
The 2003 cumulative effect of change in accounting principles
includes a $762.5 million charge related to the adoption of
EITF 02-3, Issues Involved in Accounting for
Derivative Contracts Held for Trading Purposes and Contracts
Involved in Energy Trading and Risk Management Activities,
slightly offset by $1.2 million related to the adoption of
SFAS No. 143, Accounting for Asset Retirement
Obligations. The $762.5 million charge primarily
consists of the fair value of power tolling, load serving,
transportation and storage contracts. These contracts did not
meet the definition of a derivative and, therefore, are no
longer reported at fair value. |
|
(5) |
Stockholders equity for 2001 includes the January 2001
common stock issuance, the issuance of common stock for the
Barrett acquisition and the impact of the WilTel spinoff. |
38
|
|
Item 7. |
Managements Discussion and Analysis of Financial
Condition and Results of Operations |
In February 2003, we outlined our planned business strategy in
response to the events that significantly impacted the energy
sector and our company during late 2001 and 2002. The plan
focused upon migrating to an integrated natural gas business
comprised of a strong, but smaller, portfolio of natural gas
businesses, reducing debt and increasing our liquidity through
asset sales, strategic levels of financing and reductions in
operating costs. The plan provided us with a clear strategy to
address near-term and medium-term debt and liquidity issues, to
de-leverage the company with the objective of returning to
investment grade status and to develop a balance sheet capable
of supporting and ultimately growing our remaining businesses. A
component of our plan was to reduce the risk and liquidity
requirements of the Power segment while realizing the value of
Powers portfolio.
In 2004, we continued to execute certain components of the plan
and substantially completed our plan as outlined in February
2003. Our results for 2004 include the following.
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|
|
Completion of planned asset sales, which resulted in proceeds of
approximately $877.8 million. |
|
|
|
Replacement of our cash-collateralized letter of credit and
revolver facility with facilities that do not encumber cash. |
|
|
|
Reduction of approximately $4 billion of debt through
scheduled maturities and early redemptions, including an
exchange offer for our FELINE PACS units. |
|
|
|
Reduction of risk and liquidity requirements of the Power
segment. |
|
|
|
Reduction of approximately $33 million in our combined
selling, general and administrative (SG&A) and general
corporate expenses. |
|
|
|
On June 1, 2004, we announced an agreement with
International Business Machines Corporation (IBM) to aid us
in transforming and managing certain areas of our accounting,
finance and human resources processes. Under the agreement, IBM
will also manage key aspects of our information technology,
including enterprise wide infrastructure and application
development. The
71/2 year
agreement began July 1, 2004 and is expected to reduce
costs in these areas while maintaining a high quality of service. |
As a result of the accomplishments noted above, we enter 2005
with improved financial condition and liquidity. To manage our
operations and meet unforeseen or extraordinary calls on cash,
we expect to maintain liquidity from cash and revolving credit
facilities of at least $1 billion.
In September 2004, our Board of Directors approved the decision
to retain Power and end our efforts to exit that business.
Several factors affected our decision to retain the business,
including:
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|
|
the cash flow expected to be generated by the business (Power
has contracts in place expected to generate cash in amounts that
substantially cover its obligations through 2010); |
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|
|
the negative effect of depressed wholesale power markets on the
marketability of the Power segment; and |
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|
|
our progress over the last two years in reducing the risk and
increasing the certainty of cash flows from long-term power
contracts. |
Our strategy is to continue managing this business to minimize
financial risk, maximize cash flow and meet contractual
commitments. In the fourth quarter of 2004, we elected to begin
applying hedge accounting to qualifying derivative contracts,
which is expected to reduce Powers mark-to-market earnings
volatility.
39
Having successfully completed the key components of our February
2003 plan to strengthen our finances, we are now in a position
to shift from restructuring to disciplined growth.
Our plan for 2005 includes the following objectives:
|
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|
|
increase focus and disciplined EVA®-based investments in
natural gas businesses; |
|
|
|
continue to steadily improve credit ratios and ratings with the
goal of achieving investment grade ratios; |
|
|
|
continue to reduce risk and liquidity requirements while
maximizing cash flow in the Power segment; |
|
|
|
maintain liquidity from cash and revolving credit facilities of
at least $1 billion; and |
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|
|
generate sustainable growth in EVA® and shareholder value. |
As a result of the strategy to grow our natural gas asset base,
we estimate capital and investment expenditures will increase to
approximately $1.0 to $1.2 billion in 2005 compared to
$787.4 million in 2004. We expect to fund capital and
investment expenditures, debt payments and working-capital
requirements through cash and cash equivalents on hand and cash
generated from operations, which is currently estimated to be
between $1.3 billion and $1.6 billion in 2005.
Potential risks and or obstacles that could prevent us from
achieving these objectives include:
|
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|
|
lower than expected levels of cash flow from operations; |
|
|
|
volatility of commodity prices; |
|
|
|
decreased drilling success at Exploration & Production; |
|
|
|
exposure associated with our efforts to resolve regulatory and
litigation issues (see Note 15 of Notes to Consolidated
Financial Statements); and |
|
|
|
general economic and industry downturn. |
We continue to address these risks through utilization of
commodity hedging strategies, focused efforts to resolve
regulatory issues and litigation claims, disciplined investment
strategies and maintaining our desired level of at least
$1 billion in liquidity from cash and revolving credit
facilities.
Critical accounting policies & estimates
Our financial statements reflect the selection and application
of accounting policies that require management to make
significant estimates and assumptions. The selection of these
has been discussed with our Audit Committee. We believe that the
following are the more critical judgment areas in the
application of our accounting policies that currently affect our
financial condition and results of operations.
|
|
|
Revenue recognition derivatives |
We hold a substantial portfolio of derivative contracts for a
variety of purposes. Many of these are designated as hedge
positions meaning changes in their fair value are not reflected
in earnings until the associated hedged item impacts earnings.
Others have not been designated as hedges or do not qualify for
hedge accounting. The net change in fair value of these
non-hedge contracts represents unrealized gains and losses and
is recognized in income currently (marked-to-market). The fair
value for each of these derivative contracts is determined based
on the nature of the transaction and the market in which
transactions are executed. We also incorporate assumptions and
judgments about counterparty performance and credit
considerations in our determination of fair value. Certain
contracts are executed in exchange traded or over-the-counter
markets where quoted prices in active markets may exist.
Transactions are also executed in exchange-traded or
over-the-counter markets for which market prices may exist, but
which may be relatively inactive with limited price
transparency. As a result, the ability to determine the fair
value of the contract is
40
more subjective than if an independent third party quote were
available. A limited number of transactions are also executed
for which quoted market prices are not available. Determining
fair value for these contracts involves assumptions and
judgments when estimating prices at which market participants
would transact if a market existed for the contract or
transaction. We estimate the fair value of these various
derivative contracts by incorporating information about
commodity prices in actively quoted markets, quoted prices in
less active markets, and other market fundamental analysis. The
estimated fair value of all these derivative contracts is
continually subject to change as the underlying energy commodity
market changes and as managements assumptions and
judgments change.
Additional discussion of the accounting for energy contracts at
fair value is included in Note 1 of Notes to Consolidated
Financial Statements, Energy Trading Activities, and
Item 7A Qualitative and Quantitative
Disclosures About Market Risk.
|
|
|
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/or 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.
|
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|
|
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. These projected future cash flows are used: |
|
|
|
|
o |
to estimate the fair value of oil
and gas properties for purposes of assessing them for
impairment; and
|
|
|
o |
to estimate the fair value of the
Exploration & Production reporting unit for purposes of
assessing its goodwill for impairment.
|
|
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|
|
|
Certain estimated reserves are used as collateral to secure
financing. |
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, 99 percent of our
reserve estimates are either audited or prepared by independent
experts. The data may change substantially over time as a result
of numerous factors, including additional development 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. A reasonably likely revision of our
reserve estimates is not expected to result in an impairment of
our oil and gas properties or goodwill. However, reserve
estimate revisions would impact our depreciation and depletion
expense prospectively. For example, a change of approximately
10 percent in oil and gas reserves for each basin would
change our annual depreciation, depletion and amortization
expense between approximately $16 million and
$22 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 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 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. A reasonably likely unfavorable change
in the forward price curve is not expected to result in an
impairment of our oil and gas properties or goodwill.
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 reflected in income in
the period in which new or different facts or information become
known or
41
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 advice of legal counsel, engineers, or other third parties
regarding the probable outcomes of the matter. As new
developments occur or more information becomes available, it is
possible that our assumptions and estimates in these matters
will change. Changes in our assumptions and estimates or
outcomes different from our current assumptions and estimates
could materially affect future results of operations for any
particular quarterly or annual period. See Note 15 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 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. At December 31, 2004,
we have $780 million of deferred tax assets for which a
$62 million valuation allowance has been established. When
assessing the need for a valuation allowance, we considered
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. Based
on our projections, we believe that it is probable that we can
utilize our year-end 2004 federal tax net operating loss
carryovers and capital loss carryovers prior to their
expiration. We do not expect to be able to utilize
$21 million, or approximately $8 million of tax
benefit, of the charitable contribution carryovers expiring in
2005. The remaining $43 million of charitable contribution
carryovers are expected to be utilized prior to their
expiration. We also do not expect to be able to utilize
$54 million of foreign deferred tax assets related to
carryovers. See Note 5 of Notes to Consolidated Financial
Statements for additional information regarding the 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.
We frequently 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. In
evaluating the liability associated with our various filing
positions, we record a liability for probable tax contingencies.
The ultimate disposition of these contingencies could have a
material impact on 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.
|
|
|
Impairment of long-lived assets and investments |
We evaluate our long-lived assets and investments for impairment
when we believe events or changes in circumstances indicate that
we may not be able to recover the carrying value of certain
long-lived assets or the decline in carrying value of an
investment is other-than-temporary. In addition to those
long-lived assets and investments for which impairment charges
were recorded (see Notes 2, 3 and 4 of Notes to
Consolidated Financial Statements), certain others were reviewed
for which no impairment was required. Our computations utilized
judgments and assumptions in the following areas:
|
|
|
|
|
the probability that we would sell an asset or continue to hold
and use it; |
|
|
|
undiscounted future cash flows if a long-lived asset is held for
use; |
|
|
|
estimated fair value of the asset; |
|
|
|
estimated sales proceeds if an asset is sold; |
|
|
|
form and timing of the asset disposition; |
|
|
|
counterparty performance considerations under contracted sales
transactions; and |
|
|
|
for investments that are impaired, whether the impairment is
other than temporary. |
42
An indicator of impairment relating to our Canadian olefins
assets was identified during 2004. It is possible that our
investment in these assets may not be recoverable without
modifications to or a renegotiation of key terms in an off-gas
processing agreement. Therefore, we performed recoverability
tests that considered a possible sale of the assets versus
successful renegotiation of the processing agreements. Our
computations utilized judgments and assumptions in the following
areas:
|
|
|
|
|
varying terms of renegotiated contracts; |
|
|
|
commodity pricing; |
|
|
|
probability weighting of different scenarios; and |
|
|
|
estimated sales proceeds if the assets were sold. |
After applying probability weightings to the various scenarios,
we determined that the assets did not require impairment at
December 31, 2004. A critical assumption in our impairment
analysis was the valuation of future contract terms in the
related processing agreement. Under the most likely scenario, a
decrease of approximately 25 percent or more in our
estimate of the contract valuation would likely result in an
impairment.
Our Gulf Liquids New River Project LLC (Gulf Liquids) operations
are classified as held for sale at December 31,
2004. These assets were written down to the then estimated fair
value less costs to sell at December 31, 2003. Additional
analysis during 2004 resulted in an impairment of
$2.5 million. We estimated fair value based on a
probability-weighted analysis that considered sales price
negotiations, salvage value estimates, and discounted future
cash flows. This estimate involved significant judgment,
including:
|
|
|
|
|
commodity pricing; |
|
|
|
probability weighting of the different scenarios; and |
|
|
|
range of estimated sales proceeds, salvage value and future cash
flows. |
The estimated cash flows from the various scenarios ranged from
approximately $4 million above to $8 million below our
estimated fair value at December 31, 2004.
43
|
|
|
Pension and postretirement obligations |
We have employee benefit plans that include pension and other
postretirement benefits. Pension and other postretirement
benefit plan expense and obligations are determined by a
third-party actuary and 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. We review these assumptions annually and make
adjustments as needed. The assumptions utilized to compute
expense and the benefit obligations are shown in Note 7 of
Notes to Consolidated Financial Statements. The table below
presents the estimated increase (decrease) in pension and other
postretirement benefit expense and obligations resulting from a
one-percentage-point change in these assumptions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
$ |
(14 |
) |
|
$ |
15 |
|
|
$ |
(125 |
) |
|
$ |
146 |
|
|
Expected long-term rate of return on plan assets
|
|
|
(8 |
) |
|
|
8 |
|
|
|
|
|
|
|
|
|
|
Rate of compensation increase
|
|
|
3 |
|
|
|
(2 |
) |
|
|
11 |
|
|
|
(11 |
) |
Other postretirement benefits:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
(1 |
) |
|
|
5 |
|
|
|
(48 |
) |
|
|
58 |
|
|
Expected long-term rate of return on plan assets
|
|
|
(2 |
) |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
Assumed health care cost trend rate
|
|
|
8 |
|
|
|
(3 |
) |
|
|
52 |
|
|
|
(41 |
) |
The expected long-term rates of return on plan assets are
determined by combining a review of historical returns realized
within the portfolio, the investment strategy included in the
plans Investment Policy Statement, and the capital market
projections provided by our independent investment consultant
for the asset classifications in which the portfolio is invested
as well as the target weightings of each asset classification.
These rates are impacted by changes in general market
conditions, but because they are long-term in nature, short-term
market swings do not significantly impact the rates. Changes to
our target asset allocation would also impact these rates.
The discount rates are used to discount future benefit
obligations to todays dollars. Decreases in this rate
cause the obligation and related expense to increase. The
discount rates for our pension and other postretirement benefit
plans were 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 which affect
interest rates on long-term high quality corporate bonds.
The expected rate of compensation increase represents average
long-term salary increases. An increase in this rate causes
pension obligation and expense to increase.
The assumed health care cost trend rates used by the actuaries
are based on our actual historical cost rates and then adjusted
for expected changes in the health care industry.
One of our subsidiaries, Williams Alaska Petroleum, Inc.
(WAPI) is actively engaged in administrative litigation
being conducted jointly by the FERC and the Regulatory
Commission of Alaska (RCA) concerning the Trans-Alaska
Pipeline System (TAPS) Quality Bank. Primary issues being
litigated include the appropriate valuation of the naphtha,
heavy distillate, vacuum gas oil and residual product cuts
within the
44
TAPS Quality Bank as well as the appropriate retroactive effects
of the determinations. Due to the sale of WAPIs interests
on March 31, 2004, we are no longer responsible for paying
into the Quality Bank. We are responsible for any liability that
existed as of that date including potential liability for any
retroactive payments that might be awarded in these proceedings
for the period prior to March 31, 2004. The FERC and RCA
presiding administrative law judges rendered their joint and
individual initial decisions during the third quarter of 2004.
The initial decisions set forth methodologies for determining
the valuations of the product cuts under review and also
approved the retroactive application of the approved
methodologies for the heavy distillate and residual product cuts
(see Note 15 in Notes to Consolidated Financial Statements).
Based on our computation and assessment of the 2004 initial
decisions by both the FERC and RCA, we recorded an increase to
our accrual of approximately $134 million in the third
quarter of 2004. Because the application of certain aspects of
the initial decisions is subject to interpretation, the exercise
of significant judgment is required to calculate the impact of
the order. We have calculated the reasonably possible impact of
the decisions, if fully adopted by the FERC and RCA, to result
in additional exposure to us of approximately $32 million
more than we have accrued at December 31, 2004. Therefore,
the final outcome could potentially be materially different than
we have estimated and accrued.
|
|
|
Recent accounting standards |
In December 2004, the FASB issued revised
SFAS No. 123, Share-Based Payment. The
Statement requires that compensation cost for all share based
awards to employees be recognized in the financial statements at
fair value. The Statement is effective as of the beginning of
the first interim or annual reporting period that begins after
June 15, 2005. We intend to adopt the revised Statement as
of the interim reporting period beginning July 1, 2005.
The Statement requires an option pricing model to estimate the
fair value of employee stock awards. We are evaluating the
appropriateness of several option pricing models, including a
Black-Scholes model and a lattice model (such as a binomial
model). Application of these two models could result in
different estimates of fair value with resulting differences in
compensation costs. Pro forma expense associated with options
can be found in Note 1 of Notes to Consolidated Financial
Statements. We have not determined the impact of the Statement
on net income beyond the presentation of the pro forma
disclosures.
General
In accordance with the provisions related to discontinued
operations within Statement of Financial Accounting Standard
(SFAS) No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, the consolidated financial
statements and notes in Part II Item 8 reflect our
results of operations, financial position and cash flows through
the date of sale, as applicable, of certain components as
discontinued operations (see Note 2 of Notes to
Consolidated Financial Statements).
Unless indicated otherwise, the following discussion and
analysis of results of operations, 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.
45
Results of operations
The following table and discussion is a summary of our
consolidated results of operations for the three years ended
December 31, 2004. The results of operations by segment are
discussed in further detail following this Consolidated Overview
discussion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
|
|
% Change | |
|
|
|
% Change | |
|
|
|
|
|
|
from | |
|
|
|
from | |
|
|
|
|
2004 | |
|
2003(1) | |
|
2003 | |
|
2002(1) | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Millions) | |
|
|
|
(Millions) | |
|
|
|
(Millions) | |
Revenues
|
|
$ |
12,461.3 |
|
|
|
-25 |
% |
|
$ |
16,651.0 |
|
|
|
NM |
|
|
$ |
3,434.5 |
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and operating expenses
|
|
|
10,751.7 |
|
|
|
+28 |
% |
|
|
15,004.3 |
|
|
|
NM |
|
|
|
1,987.7 |
|
|
Selling, general and administrative expenses
|
|
|
355.5 |
|
|
|
+16 |
% |
|
|
421.3 |
|
|
|
+27 |
% |
|
|
575.6 |
|
|
Other (income) expense net
|
|
|
(51.6 |
) |
|
|
+142 |
% |
|
|
(21.3 |
) |
|
|
NM |
|
|
|
240.4 |
|
|
General corporate expenses
|
|
|
119.8 |
|
|
|
-38 |
% |
|
|
87.0 |
|
|
|
+39 |
% |
|
|
142.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
11,175.4 |
|
|
|
+28 |
% |
|
|
15,491.3 |
|
|
|
NM |
|
|
|
2,946.5 |
|
Operating income
|
|
|
1,285.9 |
|
|
|
+11 |
% |
|
|
1,159.7 |
|
|
|
+138 |
% |
|
|
488.0 |
|
Interest accrued net
|
|
|
(827.7 |
) |
|
|
+34 |
% |
|
|
(1,248.0 |
) |
|
|
-9 |
% |
|
|
(1,141.9 |
) |
Interest rate swap loss
|
|
|
(5.0 |
) |
|
|
-127 |
% |
|
|
(2.2 |
) |
|
|
+98 |
% |
|
|
(124.2 |
) |
Investing income (loss)
|
|
|
48.0 |
|
|
|
-34 |
% |
|
|
73.2 |
|
|
|
NM |
|
|
|
(113.1 |
) |
Early debt retirement costs
|
|
|
(282.1 |
) |
|
|
NM |
|
|
|
(66.8 |
) |
|
|
NM |
|
|
|
|
|
Minority interest in income and preferred returns of
consolidated subsidiaries
|
|
|
(21.4 |
) |
|
|
-10 |
% |
|
|
(19.4 |
) |
|
|
+54 |
% |
|
|
(41.8 |
) |
Other income net
|
|
|
26.8 |
|
|
|
-34 |
% |
|
|
40.7 |
|
|
|
+67 |
% |
|
|
24.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes and
cumulative effect of change in accounting principles
|
|
|
224.5 |
|
|
|
NM |
|
|
|
(62.8 |
) |
|
|
+93 |
% |
|
|
(908.7 |
) |
Provision (benefit) for income taxes
|
|
|
131.3 |
|
|
|
NM |
|
|
|
(5.3 |
) |
|
|
-98 |
% |
|
|
(290.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
93.2 |
|
|
|
NM |
|
|
|
(57.5 |
) |
|
|
+91 |
% |
|
|
(618.4 |
) |
Income (loss) from discontinued operations
|
|
|
70.5 |
|
|
|
-78 |
% |
|
|
326.6 |
|
|
|
NM |
|
|
|
(136.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principles
|
|
|
163.7 |
|
|
|
-39 |
% |
|
|
269.1 |
|
|
|
NM |
|
|
|
(754.7 |
) |
Cumulative effect of change in accounting principles
|
|
|
|
|
|
|
+100 |
% |
|
|
(761.3 |
) |
|
|
NM |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
163.7 |
|
|
|
NM |
|
|
|
(492.2 |
) |
|
|
+35 |
% |
|
|
(754.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividends
|
|
|
|
|
|
|
+100 |
% |
|
|
29.5 |
|
|
|
+67 |
% |
|
|
90.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) applicable to common stock
|
|
$ |
163.7 |
|
|
|
NM |
|
|
$ |
(521.7 |
) |
|
|
+38 |
% |
|
$ |
(844.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
+ = Favorable Change; = Unfavorable Change; NM = A
percentage calculation is not meaningful due to change in signs,
a zero-value denominator or a percentage change greater than 200. |
46
The $4.2 billion decrease in revenues is due primarily to
an approximately $3.9 billion decrease in revenues at Power
resulting from lower realized revenues from power and crude and
refined products. Partially offsetting the decrease was an
increase in Midstreams revenues of $97.8 million
reflecting higher volumes and improved natural gas liquids
(NGL) margins.
The $4.3 billion decrease in costs and operating expenses
is due primarily to lower costs and operating expenses at Power.
This decrease is due primarily to lower purchase volumes of
power and crude and refined products.
The $65.8 million decrease in selling, general and
administrative (SG&A) expenses is due primarily to a
$36 million decrease in compensation expense at Power due
to reduced staffing levels, combined with the absence of
$13.6 million of expense related to the accelerated
recognition of deferred compensation during 2003. In addition,
Midstreams SG&A expense declined $18 million
largely due to asset sales and lower legal expense.
Other (income) expense net, within operating income,
in 2004 includes:
|
|
|
|
|
$93.6 million income from an insurance arbitration award
for Gulf Liquids, included in the Midstream segment; |
|
|
|
$16.2 million of gains from the sale of
Exploration & Productions securities, invested in
a coal seam royalty trust, that were purchased for resale; |
|
|
|
a $9.5 million gain on the sale of Louisiana olefins assets
in the Midstream segment; |
|
|
|
a $15.4 million loss provision related to an ownership
dispute on prior period production included in the
Exploration & Production segment; |
|
|
|
an $11.8 million environmental expense accrual related to
the Augusta refinery facility, included in the Other segment; and |
|
|
|
a $9 million write-off of previously-capitalized costs on
an idled segment of Northwest Pipelines system included in
the Gas Pipeline segment. |
Other (income) expense net, within operating income,
in 2003 includes:
|
|
|
|
|
a $188 million gain from the sale of a Power contract; |
|
|
|
$96.7 million in net gains from the sale of
Exploration & Productions interests in certain
natural gas properties in the San Juan basin; |
|
|
|
a $16.2 million gain from Midstreams sale of the
wholesale propane business; |
|
|
|
a $12.2 million gain on foreign currency exchange at Power; |
|
|
|
a $9.2 million gain on sale of blending assets at the Other
segment; |
|
|
|
$7.2 million of income at Transcontinental Gas Pipe Line
Corporation (Transco) due to a partial reduction of accrued
liabilities for claims associated with certain producers as a
result of settlements and court rulings included in the Gas
Pipeline segment; |
|
|
|
a $108.7 million impairment on Gulf Liquids, included in
the Midstream segment; |
|
|
|
a $45 million goodwill impairment at Power; |
|
|
|
a $44.1 million impairment of the Hazelton generation plant
at Power; |
|
|
|
a $25.6 million charge at Northwest Pipeline to write-off
capitalized software development costs for a service delivery
system included in the Gas Pipeline segment; |
|
|
|
a $20 million charge related to a settlement by Power with
the Commodity Futures Trading Commission (CFTC) (see
Note 15 of Notes to Consolidated Financial Statements); |
47
|
|
|
|
|
a $19.5 million expense accrual at Power related to an
adjustment of California rate refund and other related
accruals; and |
|
|
|
a $7.2 million impairment of the Aspen project at the Other
segment. |
The $32.8 million increase in general corporate expenses is
due primarily to efforts to evaluate and implement certain cost
reduction strategies, and initial costs associated with
outsourcing of certain services, increased legal costs due
primarily to shareholder litigation and Employee Retirement
Income Security Act (ERISA) matters, and increased
third-party costs associated with certain mandated compliance
activities.
The $420.3 million decrease in interest accrued
net includes:
|
|
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|
|
$206 million lower interest expense and fees at
Exploration & Production, due primarily to the May 2003
prepayment of a secured note payable of Williams Production RMT
Company (the RMT note); |
|
|
|
a $164 million decrease reflecting lower average borrowing
levels; |
|
|
|
$46 million lower amortization expense related to deferred
debt issuance costs, primarily due to the reduction of debt; |
|
|
|
a $24 million decrease reflecting lower average interest
rates on long-term debt; |
|
|
|
the absence in 2004 of $14 million of interest expense at
Power related to a FERC ruling in 2003; |
|
|
|
the absence in 2004 of $10 million of interest expense
related to a petroleum pricing dispute in 2003; and |
|
|
|
a $35 million decrease in capitalized interest due
primarily to completion of certain Midstream projects in the
Gulf Coast region. |
The $25.2 million decrease in investing income includes
$57.1 million lower interest income due primarily to higher
net interest income at Power as a result of certain 2003 FERC
proceedings. The decrease was partially offset by
$29.6 million higher equity earnings. See Note 3 of
Notes to Consolidated Financial Statements.
Early debt retirement costs include payments in excess of the
carrying value of the debt, dealer fees and the write-off of
deferred debt issuance costs and discount/premium on the debt.
The provision (benefit) for income taxes increased by
$136.6 million due primarily to pre-tax income in 2004
compared to a pre-tax loss in 2003. The effective income tax
rate for 2004 is higher than the federal statutory rate due
primarily to state income taxes, a charge associated with
charitable contribution carryovers and the effect of taxes on
foreign operations. A 2004 accrual for tax contingencies was
offset by favorable settlements of certain Federal and state
income tax matters. The effective income tax rate for 2003 is
lower than the federal statutory rate due primarily to
non-deductible impairment of goodwill, non-deductible expenses,
an accrual for tax contingencies and the effect of state income
taxes, somewhat offset by the tax benefit of capital losses.
Income from discontinued operations decreased
$256.1 million (see Note 2 of Notes to Consolidated
Financial Statements). The decrease in the operating results
from discontinued operations activities of $318.8 million
is reflective of the following pre-tax items:
|
|
|
|
|
the $153 million of charges to increase our accrued
liability associated with certain Quality Bank litigation
matters (see Note 15); |
|
|
|
the absence in 2004 of approximately $108 million of income
(net of losses) from discontinued operations in 2003 of Canadian
liquids, Williams Energy Partners, Bio-energy facilities, Raton
Basin and Hugoton Embayment natural gas exploration and
production properties, Texas Gas, Midsouth refinery and related
assets and Williams travel centers; and |
48
|
|
|
|
|
a decrease of approximately $50 million in income from the
Canadian straddle plants and Alaska refining, retail and
pipeline operations, which were sold in 2004. |
The 2004 net gain on sales of discontinued operations of
$200.5 million includes a $189.8 million gain on the
sale of three straddle plants in western Canada.
The 2003 net gain on sales of discontinued operations of
$277.7 million includes the following pre-tax items:
|
|
|
|
|
$463.4 million of gains on sales of assets; |
|
|
|
$176.1 million of impairments of assets; and |
|
|
|
$9.6 million of loss on sale of assets. |
See Note 2 of Notes to Consolidated Financial Statements
for detail of the gains and losses on sales and asset
impairments.
The cumulative effect of change in accounting principles reduced
net income for 2003 by $761.3 million due to a
$762.5 million charge related to the adoption of
EITF 02-3 (see Note 1 of Notes to Consolidated Financial
Statements), slightly offset by $1.2 million related to the
adoption of SFAS No. 143, Accounting for Asset
Retirement Obligations (see Note 9 of Notes to
Consolidated Financial Statements).
In June 2003, we redeemed all of our outstanding
9.875 percent cumulative-convertible preferred shares.
Thus, no preferred dividends were paid in 2004.
The $13.2 billion increase in revenues is due primarily to
increased revenues at Power and Midstream as a result of the
January 1, 2003 adoption of EITF 02-3, which requires
that revenues and costs of sales from non-derivative contracts
and certain physically settled derivative contracts be reported
on a gross basis (see Note 1 of Notes to Consolidated
Financial Statements). Prior to the adoption of EITF 02-3,
revenues and costs of sales related to non-derivative contracts
and certain physically settled derivative contracts were
reported in revenues on a net basis. As permitted by
EITF 02-3, 2002 amounts have not been restated.
Powers revenues increased $13.3 billion and
Midstreams revenues increased $1.6 billion due
primarily to the effect of EITF 02-3. The increase in
revenues also includes $210 million due primarily to higher
natural gas liquids (NGL) revenues at Midstreams gas
processing plants as a result of moderate market price
increases, partially offset by lower NGL production volumes.
Results for 2003 include approximately $117 million of
revenue related to the correction of the accounting treatment
previously applied to certain third party derivative contracts
during 2002 and 2001. This matter was initially disclosed in our
Form 10-Q for the second quarter of 2003. Loss from
continuing operations before income taxes and cumulative effect
of change in accounting principles in 2003 was
$62.8 million. Absent the corrections, we would have
reported a larger pre-tax loss from continuing operations in
2003. Approximately $83 million of this revenue relates to
a correction of net energy trading assets for certain derivative
contract terminations occurring in 2001. The remaining
$34 million relates to net gains on certain other
derivative contracts entered into in 2002 and 2001 that we now
believe should not have been deferred as a component of other
comprehensive income due to the incorrect designation of these
contracts as cash flow hedges. Our management, after
consultation with our independent auditor, concluded that the
effect of the previous accounting treatment was not material to
2003 and prior periods and the trend of earnings.
The $13 billion increase in costs and operating expenses is
due primarily to the effect of reporting certain costs on a
gross basis at Power and Midstream, as discussed above. Costs
increased $12.9 billion at Power and $1.9 billion at
Midstream due primarily to the effect of EITF 02-3.
Contributing to the increase at our Midstream segment is
$113 million attributable to rising market prices for
natural gas used to replace the heating value of NGLs extracted
at their gas processing facilities. The cost increases at these
operating units were partially offset by $1.5 billion
higher intercompany eliminations resulting primarily from
intercompany costs that were previously netted in revenues prior
to the adoption of EITF 02-3.
49
The $154.3 million decrease in SG&A expenses is due
primarily to reduced staffing levels at Power reflective of our
strategy to exit this business. Also contributing to the
decrease was the absence of $22 million of costs related to
an enhanced benefit early retirement option offered to certain
employee groups in 2002.
Other (income) expense net, within operating income,
in 2003 is included above in the 2004 vs. 2003 discussion. Other
(income) expense net, within operating income, in
2002 includes:
|
|
|
|
|
$244.6 million of impairment charges, loss accruals, and
write-offs within Power, including a partial impairment of
goodwill; |
|
|
|
$78.2 million of impairment charges related to
Midstreams Canadian olefin assets; and |
|
|
|
$141.7 million in net gains from the sale of
Exploration & Productions interests in natural
gas properties. |
The $55.8 million decrease in general corporate expenses is
due primarily to the absence in 2003 of $24 million of
various restructuring costs associated with the liquidity and
business issues addressed beginning third-quarter 2002. We also
incurred $19 million higher advertising and branding costs
in 2002 (due primarily to golf events and other advertising
campaigns that were not continued in 2003).
The $106.1 million increase in interest accrued
net is primarily due to:
|
|
|
|
|
$48.1 million higher interest expense and fees primarily
related to the RMT note payable, which was prepaid in May 2003; |
|
|
|
an $18.2 million increase in capitalized interest, which
offsets interest accrued, due primarily to Midstreams
projects in the Gulf Coast Region; |
|
|
|
$21 million higher amortization expense related to deferred
debt issuance costs including a $14.5 million write-off of
accelerated amortization of costs from the termination of a
revolving credit agreement in June 2003; |
|
|
|
a $43 million increase reflecting higher average interest
rates on long-term debt; |
|
|
|
a $15 million decrease reflecting lower average borrowing
levels; and |
|
|
|
$14 million of interest expense at Power as a result of
certain 2003 FERC proceedings. |
In 2002, we began entering into interest rate swaps with
external counterparties primarily in support of the
energy-trading portfolio. The change in market value of these
swaps was $122 million more favorable in 2003 than 2002,
due largely to a reduction in overall swap positions during the
second half of 2002. The total notional amount of these swaps is
approximately $300 million at December 31, 2003.
The $186.3 million increase in investing income in 2003
includes:
|
|
|
|
|
the absence in 2003 of a $268.7 million loss provision
relating to the estimated recoverability of receivables from
WilTel; |
|
|
|
$56.1 million higher interest income due primarily to
higher net interest income at Power as a result of certain 2003
FERC proceedings; |
|
|
|
$22.9 million higher impairments of cost-based investments; |
|
|
|
$25.3 million loss from investments in 2003 compared to
$42.1 million income from investments in 2002; and |
|
|
|
$52.7 million lower equity earnings. |
Minority interest in income and preferred returns of
consolidated subsidiaries in 2003 is lower than 2002 due
primarily to the absence of preferred returns totaling
$23 million on the preferred interests in Castle Associates
L.P., Piceance Production Holdings L.L.C., and Williams Risk
Holdings L.L.C., which were modified and reclassified as debt in
third-quarter 2002, and Arctic Fox, L.L.C., which was modified
and reclassified as debt in April 2002.
50
Other income net, below operating income, in 2003
includes $84.7 million of foreign currency transaction
gains on a Canadian dollar denominated note receivable.
Partially offsetting these gains were $79.8 million of
derivative losses on a forward contract to fix the
U.S. dollar principal cash flows from this note.
The provision (benefit) for income taxes was unfavorable by
$285 million due primarily to reduced pre-tax loss in 2003
compared to 2002. The effective income tax rate for 2003 is
lower than the federal statutory rate due primarily to
non-deductible impairment of goodwill, non-deductible expenses,
an accrual for tax contingencies and the effect of state income
taxes, somewhat offset by the tax benefit of capital losses. The
effective income tax rate for 2002 is less than the federal
statutory rate due primarily to the effect of taxes on foreign
operations, non-deductible impairment of goodwill, an accrual
for tax contingencies and income tax credits recapture that
reduced the tax benefit of the pre-tax loss somewhat offset by
the tax benefit of capital losses and the effect of state income
taxes.
The 2003 net gain on sales of discontinued operations of
$277.7 million is included above in the 2004 vs. 2003
discussion.
The 2002 net loss on sales of discontinued operations of
$567.8 million includes:
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|
|
$771.8 million impairment of assets; |
|
|
|
$97.7 million loss on sale of assets; and |
|
|
|
$301.7 million gain on sale of assets. |
The cumulative effect of change in accounting principles reduces
net income for 2003 by $761.3 million due to a
$762.5 million charge related to the adoption of
EITF 02-3 (see Note 1 of Notes to Consolidated
Financial Statements), slightly offset by $1.2 million
related to the adoption of SFAS No. 143,
Accounting for Asset Retirement Obligations (see
Note 9 of Notes to Consolidated Financial Statements).
In June 2003, we redeemed all of our outstanding
9.875 percent cumulative-convertible preferred shares for
approximately $289 million, plus $5.3 million for
accrued dividends (see Note 12 of Notes to Consolidated
Financial Statements). Preferred stock dividends in 2002
reflects the first-quarter 2002 impact of recording a
$69.4 million non-cash dividend associated with the
accounting for a preferred security that contained a conversion
option that was beneficial to the purchaser at the time the
security was issued.
Results of operations segments
We are currently organized into the following segments: Power,
Gas Pipeline, Exploration & Production, Midstream and
Other. Other primarily consists of corporate operations and
certain continuing operations formerly included in the
previously reported International and Petroleum Services
segments. Our management currently evaluates performance based
on segment profit (loss) from operations (see Note 18 of
Notes to Consolidated Financial Statements).
Prior period amounts have been restated to reflect all segment
changes. The following discussions relate to the results of
operations of our segments.
Power
Powers 2004 operating results were significantly
influenced by past efforts to exit from the Power business and
the effect of price changes on derivative contracts.
Prior to September 2004, Power continued to focus on
1) terminating or selling all or portions of its portfolio,
2) maximizing cash flow, 3) reducing risk, and
4) managing existing contractual commitments. These efforts
were consistent with our 2002 decision to sell all or portions
of Powers portfolio. The decrease in revenues, costs and
SG&A expenses in 2004 reflects our lower levels of business
activity pursuant to our past efforts to exit the Power business.
51
In September 2004, we announced our decision to continue
operating the Power business and cease efforts to exit that
business. As a result, subsequent to September 2004, Power
continued to focus on its objectives of minimizing financial
risk, maximizing cash flow, meeting contractual commitments and
providing functions that support our natural gas businesses. In
addition, Power began executing new contracts to hedge its
portfolio.
As a result of our past intent to exit the Power business,
Powers derivative contracts did not previously qualify for
hedge accounting. Therefore, we reported changes in the forward
fair value of our derivative contracts in earnings as unrealized
gains or losses. However, with the decision to retain the
business, Powers derivative contracts became eligible for
hedge accounting under SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities,
(SFAS 133) and Power elected hedge accounting on a
prospective basis beginning October 1, 2004 for certain
qualifying derivative contracts. Under cash flow hedge
accounting, to the extent that the hedges are effective,
prospective changes in the forward fair value of the hedges are
reported as changes in Accumulated other comprehensive income in
the Stockholders equity section of the Consolidated
Balance Sheet, and then reclassified to earnings when the
underlying hedged transactions (i.e. power sales and gas
purchases) affect earnings.
Key factors that influence Powers financial condition and
operating performance include the following:
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|
|
prices of power and natural gas, including changes in the margin
between power and natural gas prices; |
|
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|
changes in market liquidity, including changes in the ability to
effectively hedge the portfolio; |
|
|
|
changes in power and natural gas price volatility; |
|
|
|
changes in interest rates; |
|
|
|
changes in the regulatory environment; |
|
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|
changes in power and natural gas supply and demand; and |
|
|
|
the inability of counterparties to perform under contractual
obligations due to their own credit constraints. |
In 2005, Power intends to service its customers needs
while increasing the certainty of cash flows from its long-term
contracts.
As Power continues to apply hedge accounting in 2005, its future
earnings may be less volatile. However, not all of Powers
derivative contracts qualify for hedge accounting. Power will
continue to report changes in the fair value of those remaining
non-hedge contracts in earnings as unrealized gains or losses.
In addition, the ineffective portion of the change in the
forward fair value of qualifying hedges will also continue to be
reported in earnings. Because the derivative contracts
qualifying for hedge accounting have significant fair value that
has been recognized as unrealized gains or losses prior to
October 1, 2004, the amounts recognized in future earnings
under hedge accounting will not necessarily align with the
expected cash flows to be realized from the settlement of those
derivatives. Therefore, it is expected that future earnings will
reflect losses from underlying transactions that have been
hedged by the derivatives, but will not reflect the
corresponding offsetting positive value from the hedges since
such positive value has already been recognized in prior
periods. However, cash flows from Powers portfolio
continue to reflect the net amount from both the hedged
transactions and the hedges.
Even with the adoption of hedge accounting, some variability in
Powers earnings will remain as a result of:
|
|
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|
|
market movements of commodity-based derivatives held for trading
purposes or which did not qualify for hedge accounting; and |
52
|
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|
|
ineffectiveness of cash flow hedges primarily caused by
locational differences between the hedging derivative and the
hedged item, changes in the creditworthiness of counterparties
and the hedging derivative contract having a fair value upon
designation. |
The fair value of Powers tolling, full requirements,
transportation, storage and transmission contracts are not
reflected in the balance sheet since these contracts are not
derivatives. Some of these contracts have a significant negative
estimated fair value and, therefore, could also result in future
operating gains or losses as a result of the volatile nature of
energy commodity markets. The inability of counterparties to
perform under contractual obligations due to their own credit
constraints could also affect future operations.
|
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|
Year-over-year operating results |
|
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|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Realized revenues
|
|
$ |
8,954.7 |
|
|
$ |
12,930.5 |
|
|
$ |
(278.7 |
)* |
Forward unrealized mark-to-market gains
|
|
|
304.0 |
|
|
|
262.1 |
|
|
|
193.5 |
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues
|
|
|
9,258.7 |
|
|
|
13,192.6 |
|
|
|
(85.2 |
) |
Cost of sales
|
|
|
9,073.3 |
|
|
|
12,954.6 |
|
|
|
28.9 |
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin
|
|
|
185.4 |
|
|
|
238.0 |
|
|
|
(114.1 |
) |
Operating expenses
|
|
|
23.7 |
|
|
|
35.3 |
|
|
|
40.0 |
|
Selling, general and administrative expenses
|
|
|
83.2 |
|
|
|
124.0 |
|
|
|
209.0 |
|
Other income (expense) net
|
|
|
(1.8 |
) |
|
|
56.4 |
|
|
|
(263.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
Segment profit (loss)
|
|
$ |
76.7 |
|
|
$ |
135.1 |
|
|
$ |
(626.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
* |
In 2002, Power reported its trading operations physical
sales transactions net of the related purchase costs. See
Note 1 of Notes to Consolidated Financial Statements. |
The $3.9 billion decrease in revenues includes an
approximately $4 billion decrease in realized revenues
partially offset by a $41.9 million increase in forward
unrealized mark-to-market gains.
Realized revenues represent 1) revenue from the sale of
commodities or completion of energy-related services, and
2) gains and losses from the net financial settlement of
derivative contracts. The approximately $4 billion decrease
in realized revenues is primarily due to an approximately
$3.1 billion decrease in power and natural gas realized
revenues and an $862 million decrease in crude and refined
products realized revenues.
Power and natural gas realized revenues decreased primarily due
to a 47 percent decrease in power sales volumes, partially
offset by a five percent increase in power sales prices. Sales
volumes decreased because Power did not replace certain
long-term physical contracts that expired or were terminated in
2003, primarily due to a lack of market liquidity and past
efforts to reduce our commitment to the Power business. In
addition, results for 2003 include a realized gain of
$126.8 million based on the terms of an agreement to
terminate a derivative contract. In addition, during 2003,
revenues include the correction of the accounting treatment
previously applied to certain third party derivative contracts
during 2002 and 2001, resulting in the recognition of
approximately $117 million in revenues attributable to
prior periods. Refer to Note 1 of Notes to Consolidated
Financial Statements for further information. Additionally,
power and natural gas revenues in 2003 include a
$37 million reduction for increased power rate refunds owed
to the state of California as the result of FERC rulings. Crude
and refined products revenues decreased primarily due to the
sale of the crude gathering business in 2003, the sale of the
refined products business in 2004 and the past efforts to exit
this line of business.
Net forward unrealized mark-to-market gains and losses represent
changes in the fair values of derivative contracts with a future
settlement or delivery date. In 2004, Power had net forward
unrealized mark-to-market
53
gains of $304 million, an increase of $41.9 million
from 2003. The increase in unrealized gains is due to a
$75 million increase associated with power and gas
contracts, partially offset by an $11 million decrease in
crude and refined products and a $22 million decrease in
the interest rate portfolio. The increase in power and gas
primarily results from a greater increase associated with
near-term natural gas forward prices in 2004 than in 2003. Also
contributing to the increase was the absence in 2004 of
unrealized losses of approximately $70 million recognized
in first-quarter 2003 on contracts for which we elected the
normal purchases and sales exception in second-quarter 2003.
Another factor contributing to the increase was the impact of
cash flow hedge accounting, which was prospectively applied to
certain of Powers forecasted transactions beginning
October 1, 2004. A net loss of $15 million related to
the effective portion of the hedges was reported in Accumulated
other comprehensive income in 2004. The decrease in crude and
refined products primarily results from the sale of the crude
gathering business in 2003, the sale of the refined products
business in 2004 and the past efforts to exit this line of
business. These activities led to a significantly smaller
derivative position in 2004 than in 2003 which resulted in lower
unrealized mark-to-market gains. The decrease in the interest
rate portfolio is due primarily to a decrease in forward
interest rates in first-quarter 2004 compared to a slight
increase in first-quarter 2003.
The $3.9 billion decrease in Powers costs is
primarily due to a decrease in power and natural gas costs of
approximately $3 billion and a decrease in crude and
refined products costs of $904.5 million. Power and natural
gas costs decreased primarily due to a 48 percent decrease
in power purchase volumes, partially offset by a two percent
increase in power prices. A $10.4 million reduction to
certain contingent loss accruals in 2004 and a
$13.8 million loss for other contingencies in 2003, both
associated with power marketing activities in California during
2000 and 2001, contributed to the decrease in costs discussed
above. Costs in 2004 also reflect a $13 million payment
made to terminate a non-derivative power sales contract, which
partially offsets the decrease in power and natural gas costs.
Crude and refined products costs decreased primarily due to the
sale of the crude gathering business in 2003, the sale of the
refined products business in 2004, and other past efforts to
exit this line of business.
The $40.8 million decrease in SG&A expenses is largely
due to a $36 million decline in compensation expense,
primarily as a result of staff reductions in prior years
combined with the accelerated recognition of $13.6 million
in 2003 of certain deferred compensation arrangements. In
addition, a $6.3 million reduction of allowance for bad
debts resulting from the 2004 settlement with certain California
utilities and the absence of a $6.5 million bad debt charge
associated with a termination settlement in 2003 also
contributed to the decrease.
Other (income) expense net in 2004 includes
$6.1 million in fees related to the sale of certain
receivables to a third party. Other (income) expense
net in 2003 includes a $188 million gain from the sale of
an energy-trading contract and a $13.8 million gain from
the sale of certain investments. These income items are
partially offset by the effect of the following 2003 items:
|
|
|
|
|
a $20 million charge for a settlement with the CFTC; |
|
|
|
accruals of $19.5 million for power marketing activities in
California in prior periods (see Note 15 of Notes to
Consolidated Financial Statements); |
|
|
|
a $45 million impairment of goodwill; |
|
|
|
a $44.1 million impairment on a power generating facility
(see Note 4 of Notes to Consolidated Financial
Statements); and |
|
|
|
a $14.1 million impairment associated with the Aux Sable
partnership investment (see Note 4 of Notes to Consolidated
Financial Statements). |
The $58.4 million decrease in segment profit is primarily
due to lower sales volumes and the absence in 2004 of income
from certain terminated contracts and prior period adjustments
and the effect of the other income changes noted above,
partially offset by lower SG&A.
54
The $13.3 billion increase in revenues includes an
approximately $13.2 billion increase in realized revenues
and a $68.6 million increase in forward unrealized
mark-to-market gains.
Realized revenues increased primarily as a result of the
implementation of EITF 02-3 on January 1, 2003.
EITF 02-3 impacts how Power present revenues and costs from
certain transactions in the statement of operations. The table
below summarizes items included in revenues and costs before and
after January 1, 2003:
|
|
|
|
Before |
|
After |
|
|
|
Revenues:
|
|
Revenues: |
|
Realized revenues:
|
|
Realized revenues: |
|
Revenue from sales of commodities or completion of
energy-related services
|
|
Revenue from sales of commodities or
completion of energy-related services |
|
Gains and losses from net financial settlement of
derivative contracts
|
|
Gains and losses from net financial
settlement of derivative contracts |
|
Costs from purchases of commodities or fees from
energy-related services that were not associated with property,
plant and equipment we owned
|
|
|
|
Forward unrealized mark-to-market gains:
|
|
Forward unrealized mark-to-market gains: |
|
Gains and losses from changes in fair value of
all energy trading contracts with a future settlement or
delivery date
|
|
Gains and losses from changes in fair
value of only derivative contracts with a future
settlement or delivery date |
Costs:
|
|
Costs: |
|
Costs from purchases of commodities or fees from
energy-related services for use in property, plant and equipment
that we owned
|
|
Costs from purchases of all
commodities or fees for energy-related services |
As illustrated in the table above, Power now reports certain
purchases in costs instead of reporting them as reduction of
revenues. Revenues for 2003 include a realized gain of
$126.8 million based on the terms of an agreement to
terminate a derivative contract. Additionally, during 2003,
Power corrected the accounting treatment previously applied to
certain third party derivative contracts during 2002 and 2001,
resulting in the recognition in 2003 of approximately
$117 million in revenues attributable to prior periods.
This matter was initially disclosed in our Form 10-Q for
the second quarter of 2003. Refer to Note 1 of Notes to
Consolidated Financial Statements for further information.
Realized revenues in 2003 also include a $37 million loss
for increased power rate refunds owed to the state of California
as the result of FERC rulings, which partially offsets the
general increase discussed above. Increased power supply in the
mid-continent and eastern regions contributed to lower prices
received on power sales in 2003, which further offsets the
general increase in realized revenues.
EITF 02-3 also affects forward unrealized mark-to-market
gains. Before the adoption of EITF 02-3, Power reported the
fair value of all its energy contracts, energy-related contracts
and inventory on the balance
55
sheet. Power reported changes in the fair value of the items, or
forward unrealized mark-to-market gains, from period to period
in revenues. Examples of derivative and non-derivative contracts
are as follows:
|
|
|
Derivative Contracts |
|
Non-Derivative Contracts |
|
|
|
Forward purchase and sale contracts
|
|
Spot purchase and sale contracts |
Futures contracts
|
|
Transportation contracts |
Option contracts
|
|
Storage contracts |
Swap agreements
|
|
Tolling agreements (power conversion contracts) |
|
|
Full requirement or load serving contracts (power
sales contracts in which we supply all of the customers
requirements for power) |
In 2003, Power continued to reflect the changes in fair value of
derivative contracts in revenues and segment profit. However,
for non-derivative contracts, Power does not recognize revenue
until commodities are delivered or services are completed. The
$68.6 million increase in forward unrealized mark-to-market
gains includes a $44 million increase in the power and
natural gas portfolios and a $71 million increase in the
interest rate portfolio, partially offset by a $46 million
decrease in the crude and refined products portfolio. Power and
natural gas forward unrealized mark-to-market gains in 2003
reflect the impact of decreased forward power prices on net
power sales contracts (derivative contracts) and increased
forward gas prices on net gas purchase contracts (derivative
contracts). Increased power supply in the mid-continent and
eastern U.S. significantly contributed to the decrease in
forward power prices. Unrealized mark-to-market gains in 2002
were lower primarily due to the impact of decreased margins
between forward power prices and the estimated cost to produce
the power on tolling contracts (non-derivative contracts). The
decline in volatility of the power and natural gas markets in
2002 also contributed to a decrease in fair value of tolling
contracts within certain of our tolling portfolios as it does
other option contracts. Tolling contracts possess
characteristics of options since we have the right but not the
obligation to request the plant owner to convert natural gas to
power. Results in 2002 also reflect an unfavorable
$74.8 million valuation adjustment on certain
non-derivative power sale contracts. Quotes received during
sales efforts in 2002 resulted in the valuation adjustment. The
effect of decreased interest rates on power and natural gas
derivative and non-derivative contracts in 2002 partially
offsets the general increase discussed above. As interest rates
decreased in 2002, the overall fair value of these commodity
contracts increased. Further offsetting the general increase is
a lack of origination in 2003. In 2002, we recognized
$85.1 million of power and natural gas revenues by
originating new contracts, a portion of which realized during
2002. The favorable net effect of approximately $85 million
resulting from a settlement with the state of California in 2002
also partially offsets the increase in power and natural gas
forward unrealized mark-to-market gains. The $85 million
reflects the increase in fair value on power sales contracts
with the California Department of Water Resources, which
resulted from a restructuring of the contracts and the improved
credit standing of the counterparty. The increase in the
interest rate portfolio reflects a lesser decrease in forward
interest rates in 2003 than in 2002. The decrease in crude and
refined products portfolios reflects a lack of origination in
2003. In 2002, Power recognized $118.8 million of forward
unrealized mark-to-market gains within the petroleum products
portfolio by originating new contracts, a portion of which
realized in 2002.
The $12.9 billion increase in costs is primarily due to the
implementation of EITF 02-3 as discussed above. As a result
of EITF 02-3, Power now reports certain purchases in costs
instead of reporting them as reduction of revenues. The increase
in costs caused by EITF 02-3 does not affect gross margin
or segment profit. Also included in 2003 costs is a
$13.8 million loss for other contingencies related to our
power marketing activities in the state of California.
The reduced focus on the Power business resulted in further
employee reductions in 2003. We employed approximately 250
employees at the end of 2003 compared to approximately 410 at
the end of 2002. This decrease in employees was a primary factor
in the $85 million, or 41 percent, decrease in
SG&A expenses.
The $319.5 million variance in other income
(expense) net is primarily due to Power terminating
or selling certain contracts and other assets, resulting in
losses in 2002 and gains in 2003. In 2002, Power
56
terminated certain power related capital projects,
which resulted in $138.8 million of impairments. Power also
recorded a $44.7 million impairment in 2002 from the
January 2003 sale of the Worthington generation facility. In
2003, Power sold a non-derivative energy-trading contract
resulting in a $188 million gain on sale. Power also sold
an interest in certain investments accounted for under the
equity method in 2003 for a gain of $13.8 million. A
$45 million goodwill impairment in 2003 compared to a
$61.1 million goodwill impairment in 2002 also contributed
to the increase in Other (income) expense-net. See Note 4
of Notes to Consolidated Financial Statements. Other factors
offset the increase in Other income (expense) net.
In 2003, Power recognized a $44.1 million impairment on a
power generating facility (see Note 4 of Notes to
Consolidated Financial Statements). Power also reached a
settlement with the Commodity Futures Trading Commission as
discussed in Note 16 of Notes to Consolidated Financial
Statements, resulting in a charge of $20 million. In
addition, Power recognized $14.1 million of impairment
charges associated with the Aux Sable partnership investment.
Finally, Power recorded accruals of $19.5 million for power
marketing activities in California during 2000 and 2001 (see
Note 15 of Notes to Consolidated Financial Statements).
The $761.3 million increase in segment profit is primarily
due to an increase in realized revenues and forward unrealized
mark-to-market gains that were greater than the increase in
costs. Further impacting this increase are the changes in other
(income) expense net and a decrease in selling,
general and administrative expenses as discussed above.
Gas Pipeline
Gas Pipelines interstate transmission and storage
activities are subject to regulation by the FERC and as such,
our rates and charges for the transportation of natural gas in
interstate commerce, and the extension, enlargement or
abandonment of jurisdictional facilities and accounting, among
other things, are subject to regulation. The rates are
established through the FERCs ratemaking process. Changes
in commodity prices and volumes transported have little impact
on revenues because the majority of cost of service is recovered
through firm capacity reservation charges in transportation
rates.
Effective June 1, 2004, and due in part to FERC Order 2004,
management and decision-making control of certain regulated gas
gathering assets was transferred from our Midstream segment to
our Gas Pipeline segment. Consequently, the results of
operations were similarly reclassified. All prior periods
reflect these classifications.
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|
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Northwest Pipeline in western Washington |
In December 2003, we received an Amended Corrective Action Order
(ACAO) from the U.S. Department of
Transportations Office of Pipeline Safety
(OPS) regarding a segment of one of our natural gas
pipelines in western Washington. The pipeline experienced two
breaks in 2003 and we subsequently idled the pipeline segment
until its integrity could be assured.
By June 2004, we had successfully completed our hydrostatic
testing program and returned to service 111 miles of the
268 miles of pipe affected by the ACAO. That effort has
restored 131 thousand dekatherms per day (Mdt/d) of the 360
Mdt/d of idled capacity and is anticipated to be adequate to
meet most market conditions. The decision to idle the pipeline
has not had a significant impact on our ability to meet market
demand to date.
The restored facilities will be monitored and tested as
necessary until they are ultimately replaced. As of December 31,
2004, approximately $40 million has been spent on testing and
remediation, including approximately $9 million related to
one segment of pipe that we determined not to return to service
and therefore was written off in the second quarter of 2004. We
estimate additional testing and remediation costs of up to
$5 million.
On October 4, 2004 we received a notice of probable
violation (NOPV) from OPS. Under the provisions of
the NOPV, OPS has issued a preliminary civil penalty of $100,000
for exceeding the pressure restriction on one of the segments
covered under the original CAO. This penalty was accrued in the
third
57
quarter of 2004. The incident occurred on July 15, 2003 and
did not occur as part of normal operations, but in preparation
for running an internal inspection tool to test the integrity of
the line. The operating pressure dictated by the original CAO
was exceeded for approximately three hours due to the mechanical
failure of an overpressure device and we immediately reported
the incident to the OPS. There was no impact on pipeline
facilities, and no additional sections of the pipeline were
affected. Following the incident, new protocols were adopted to
ensure that a similar situation would not occur in the future.
We requested a hearing on the proposed OPS civil penalty, which
was held on December 15, 2004. We expect OPS to issue its
decision in the near future.
As required by OPS, we plan to replace the pipelines
entire capacity by November 2006 to meet long-term demands. We
conducted a reverse open season to determine whether any
existing customers were willing to relinquish or reduce their
capacity commitments to allow us to reduce the scope of pipeline
replacement facilities, which resulted in 13 Mdt/d of capacity
being relinquished and incorporated into the replacement
project. On November 29, 2004, we filed with the FERC a
certificate of application for the Capacity Replacement
Project, including construction of approximately
79.5 miles of 36-inch pipeline and 10,760 net
horsepower of additional compression at two existing compressor
stations and abandonment of approximately 268 miles of the
existing 26-inch pipeline. The estimated net cost of the
Capacity Replacement Project included in the filing is
approximately $333 million. The majority of these costs
will be spent in 2005 and 2006. We anticipate filing a rate case
to recover the capitalized costs relating to restoration and
replacement facilities following the in-service date of the
replacement facilities.
In February 2004, Transco placed an expansion into service
increasing capacity on its natural gas system by 54 Mdt/d. The
expansion provides additional firm transportation capacity to
serve Transcos southeastern market area.
In December 2004, we mutually agreed with British Columbia Hydro
and Power Authority (BC Hydro) to end plans to construct a
$209 million natural gas pipeline across the Strait of
Georgia to serve electric generation facilities on Vancouver
Island, B.C. Under the terms of the agreement, BC Hydro assumes
full responsibility for all project costs.
|
|
|
Gulfstream Natural Gas System, L.L.C. |
In February 2005, Gulfstream placed into service its 110-mile
Phase II natural gas pipeline extension, expanding its
reach across Florida and facilitating the increase of long-term
firm service by 350 million cubic feet per day. Gulfstream
now has the capacity of approximately 1.1 billion cubic
feet per day. The cost for Phase II of the project is
estimated at $200 million.
|
|
|
Central New Jersey Expansion Project |
In February 2005, Transco received authorization from the FERC
to construct and operate the Central New Jersey Expansion
Project on its natural gas pipeline system. The expansion will
provide an additional 105 Mdt/d of firm natural gas
transportation service in Transcos northeastern market
area. The estimated cost of the project is $13 million. The
construction is scheduled to begin in the summer of 2005 and is
expected to be placed into service in November 2005.
Significant risk factors that could affect the profitability of
our Gas Pipeline segment include:
|
|
|
|
|
legal and regulatory events such as FERC rate authorization
and/or rate case settlements (see Note 15 of Notes to
Consolidated Financial Statements), |
58
|
|
|
|
|
market demand for expansion projects to increase revenue and
segment profit, |
|
|
|
catastrophic events affecting our infrastructure, such as
pipeline ruptures, and |
|
|
|
regulatory accounting changes regarding pipeline assessment
costs. |
|
|
|
Year-over-year operating results |
The following discussions relate to the current continuing
businesses of our Gas Pipeline segment which includes Transco,
Northwest Pipeline and various joint venture projects. Certain
assets sold during 2002 are included in the 2002 results. In
addition, any gains or losses on the sale and results of
operations related to Texas Gas, Central and Kern River are
excluded and are reported within discontinued operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Segment revenues
|
|
$ |
1,362.3 |
|
|
$ |
1,368.3 |
|
|
$ |
1,301.2 |
|
Segment profit
|
|
$ |
585.8 |
|
|
$ |
555.5 |
|
|
$ |
535.8 |
|
The $6 million decrease in Gas Pipeline revenues is due
primarily to $25 million lower revenues associated with
reimbursable costs, which are passed through to customers
(offset in costs and operating expenses and general and
administrative expenses) and $12 million lower revenues
from the sale of environmental mitigation credits. These
decreases were partially offset by $29 million higher
transportation revenues and $7 million higher revenue from
exchange imbalance settlements (offset in costs and operating
expenses). The $29 million increase in transportation
revenues is due primarily to $46 million higher revenue
from expansion projects, partially offset by $17 million
lower revenue from all other operations. The $17 million
decrease is due primarily to $5 million lower commodity
revenues at Transco and $9 million lower short-term firm
revenues at Northwest Pipeline.
Costs and operating expenses decreased $2 million due
primarily to $18 million lower recovery of reimbursable
costs which are passed through to customers (offset in
revenues); an $8.5 million reduction of expense related to
adjustments to depreciation recognized in a prior period; an
$8 million reduction of depreciation, depletion and
amortization expense related to capitalized environmental
mitigation credits; and the absence of a $4 million
write-off of certain receivables at Transco in 2003. These
decreases were partially offset by $11 million higher
maintenance expenses, $10 million higher fuel expense at
Transco reflecting a reduction in pricing differentials on the
volumes of gas used in operations as compared to 2003,
$7 million higher gas exchange imbalance settlements
(offset in revenues), and a $5 million increase in
regulatory charges.
General and administrative costs decreased $11 million, or
nine percent, due primarily to $6 million lower
reimbursable costs (offset in revenues) and $4 million
lower rent resulting from the terms of a new office lease at
Transco.
Other (income) expense net in 2004 includes an
approximate $9 million charge for the write-off of
previously-capitalized costs incurred on an idled segment of
Northwest Pipelines system that we determined will not be
returned to service. Other (income) expense net in
2003 includes a $25.6 million charge at Northwest Pipeline
to write-off capitalized software development costs for a
service delivery system following a decision not to implement
and $7.2 million of income at Transco resulting from a
reduction of accrued liabilities for claims associated with
certain producers as a result of settlements and court rulings
(see Royalty indemnifications in Note 15 of Notes to
Consolidated Financial Statements).
59
|
|
|
Summarized changes in Gas Pipelines segment
profit |
The $30.3 million, or five percent, increase in segment
profit, which includes equity earnings and income (loss) from
investments is due to the following:
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|
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|
the absence of the 2003 $25.6 million charge discussed
above, |
|
|
|
$13.4 million higher equity earnings primarily from our
investment in the Gulfstream Pipeline, |
|
|
|
$12 million higher revenues, excluding reimbursable costs
that do not impact segment profit, and |
|
|
|
$5 million lower general and administrative expense,
excluding reimbursable costs that do not impact segment profit. |
These increases to segment profit were partially offset by the
following:
|
|
|
|
|
a $9 million charge for the write-off of previously
capitalized costs discussed above, |
|
|
|
$9 million higher costs and operating expenses, excluding
reimbursable costs that do not impact segment profit; and |
|
|
|
the absence of the 2003 $7.2 million of income resulting
from a reduction of accrued liabilities discussed above. |
The $67.1 million, or five percent, increase in revenues is
due primarily to $61 million higher demand revenues on the
Transco system resulting from new expansion projects
(MarketLink, Momentum and Sundance) and higher rates approved
under Transcos rate proceedings that became effective in
late 2002 and $27 million on the Northwest Pipeline system
resulting from new projects (Grays Harbor, Centralia, and
Chehalis). Revenue also increased due to $14 million higher
commodity revenue on Transco. Partially offsetting these
increases was the absence in 2003 of $28 million of revenue
from reductions in the rate refund liabilities and other
adjustments associated with a rate case settlement on Transco in
2002 and $13 million lower storage demand revenues in 2003
due to lower storage rates in connection with Transcos
rate proceedings that became effective in late 2002.
Cost and operating expenses increased $21 million, or three
percent, due primarily to $25 million higher depreciation
expense due to additional property, plant and equipment placed
into service and $12 million higher state sales and use, ad
valorem and franchise taxes. These increases were partially
offset by $15 million lower fuel expense on Transco,
resulting primarily from pricing differentials on the volumes of
gas used in operation.
General and administrative costs decreased $32 million, or
20 percent, due primarily to the absence in 2003 of
$23 million of early retirement pension costs recorded in
2002 and other employee-related benefits costs associated with
reduced employee levels as well as the absence of a
$5 million write-off in 2002 of capitalized software
development costs resulting from cancellation of a project.
Other (income) expense net in 2003 includes a
$25.6 million charge at Northwest Pipeline to write-off
capitalized software development costs for a service delivery
system. Subsequent to the implementation of the same system at
Transco in the second quarter of 2003 and a determination of the
unique and additional programming requirements that would be
needed to complete the system at Northwest Pipeline, management
determined that the system would not be implemented at Northwest
Pipeline. Other (income) expense net in 2003 also
includes $7.2 million of income at Transco due to a partial
reduction of accrued liabilities for claims associated with
certain producers as a result of settlements and court rulings.
Other income (expense) net in 2002 includes a
$17 million charge associated with a FERC penalty (see
Investigations related to natural gas storage inventory in
Note 15 of Notes to Consolidated Financial Statements) and
a $3.7 million loss on the sale of the Cove Point facility.
60
|
|
|
Summarized changes in Gas Pipelines segment
profit |
The $19.7 million, or four percent, increase in segment
profit, which includes equity earnings and income (loss) from
investments, is due to the following favorable 2003 items:
|
|
|
|
|
the $67.1 million increase in revenues, |
|
|
|
the $32 million decrease in general and administrative
costs, |
|
|
|
the absence of a 2002 $17 million FERC charge discussed
above; and |
|
|
|
the absence of the 2002 $12.3 million write off of Gas
Pipelines investment in a cancelled pipeline project and a
2002 $10.4 million loss on the sale of Gas Pipelines
14.6 percent ownership interest in Alliance Pipeline. Both
items were included in income (loss) from investment, which is
included in Investing income (loss). |
These increases to segment profit were partially offset by the
following:
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|
|
|
|
$73 million lower equity earnings, |
|
|
|
the $25.6 million charge at Northwest Pipeline to write-off
capitalized software costs discussed previously, |
|
|
|
the $21 million higher operating costs, and |
|
|
|
the absence of a 2002 $8.7 million gain on the sale of our
general partnership interest in Northern Border
Partners, L.P. |
The $73 million decrease to equity earnings reflects
$24 million lower equity earnings from our investment in
the Gulfstream Pipeline, the absence of a $27.4 million
benefit in 2002 related to the contractual construction
completion fee received by an equity affiliate and the absence
of $19 million of equity earnings following the October
2002 sale of Gas Pipelines 14.6 percent ownership in
Alliance Pipeline. The lower earnings from our investment in the
Gulfstream Pipeline were primarily due to the absence in 2003 of
interest capitalized on internally generated funds as allowed by
the FERC during construction. The Gulfstream pipeline was placed
into service during second-quarter 2002.
Exploration & Production
In 2004, our strategy focused on expanding our development
drilling program in order to surpass results experienced in
prior years. We achieved this goal consistently throughout 2004
with our major accomplishments including the following:
|
|
|
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|
We increased daily production volumes by 27 percent from
the beginning of the year. The domestic average daily production
for the quarter ending December 31, 2004 was approximately
566 million cubic feet of gas equivalent (MMcfe) compared
to 447 MMcfe for the same period in 2003. |
|
|
|
We increased our development drilling program throughout 2004,
surpassing annual drilling capital expenditures prior to 2004
and more than doubling the expenditures occurring in 2003.
Capital expenditures for domestic drilling activity in 2004 were
approximately $436 million compared to approximately
$200 million in 2003. |
|
|
|
We improved the timing and efficiency of our drilling cycle,
particularly in the Piceance basin, by reducing the number of
days to drill from eighteen to sixteen, thereby increasing the
number of wells drilled during a given time period. |
The benefit of the higher production volumes was partially
offset by increased operating costs and lower net average
realized prices which were the result of increased derivative
hedge losses in 2004. The increase in operating costs was the
result of escalated overall production and maintenance
activities among oil and gas producers, which caused service
companies to increase their fees.
61
Our expectations for 2005 include:
|
|
|
|
|
a continuing development drilling program in our key basins with
an increase in activity in the Piceance, San Juan, and
Arkoma basins with associated planned capital expenditures of
$500 million to $575 million in 2005; and |
|
|
|
increasing our fourth-quarter 2004 average daily domestic
production level of 566 MMcfe per day by at least ten
percent by the end of 2005. |
Approximately 286 MMcfe of our forecasted 2005 daily
domestic production of 600 to 700 MMcfe per day is hedged at
prices that average $4.00 per MMcfe at a basin level. In
addition, we have approximately 50 MMcfe of our daily
estimated January 2005 through March 2005 production hedged in
NYMEX collar agreements that have an average floor price of
$7.50 per MMcfe and an average ceiling price of
$10.49 per MMcfe at a basin level.
Risks that we may not be able to accomplish our objectives
include drilling rig availability as well as obtaining permits
as planned for drilling.
|
|
|
Year-over-year operating results |
The following discussions of the year-over-year results
primarily relate to our continuing operations. However, the
results do include those operations that were sold during 2003
or 2002 that did not qualify for discontinued operations
reporting. The operations classified as discontinued operations
are the properties in the Hugoton and Raton basins.
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|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Segment revenues
|
|
$ |
777.6 |
|
|
$ |
779.7 |
|
|
$ |
860.4 |
|
Segment profit
|
|
$ |
235.8 |
|
|
$ |
401.4 |
|
|
$ |
508.6 |
|
The $2.1 million, or less than one percent, decrease in
revenues is primarily due to the absence of $24 million in
income realized during 2003 from derivative instruments that did
not qualify for hedge accounting, partially offset by an
increase in domestic production revenues of $22 million
during 2004. The increase in domestic production revenues
primarily results from $49 million higher revenues
associated with a nine percent increase in production volumes
partially offset by $27 million lower revenues associated
with a four percent decrease in net realized average prices for
production sold. Net realized average prices include the effect
of hedge positions which were at prices below market levels. The
increase in production volumes primarily reflects an increase in
the number of producing wells resulting from our successful 2004
drilling program. We expect production volumes to continue to
increase in 2005 as our development drilling program continues.
To manage the risk and volatility associated with the ownership
of producing gas properties, we enter into derivative forward
sales contracts that economically lock in a price relating to a
portion of our future production. Approximately 77 percent
of domestic production in 2004 was hedged at a weighted average
price of $3.65 per MMcfe at a basin level. These hedges are
executed with our Power segment which, in turn, executes
offsetting derivative contracts with unrelated third parties.
Generally, Power bears the counterparty performance risks
associated with unrelated third parties. Hedging decisions are
made considering our overall commodity risk exposure and are not
executed independently by Exploration & Production.
62
Total costs and expenses increased $167 million, which
includes the absence of $95 million in net gains on sales
of assets occurring in 2003. The remaining increase in costs and
expenses primarily reflects:
|
|
|
|
|
$18 million higher depreciation, depletion and amortization
expense primarily as a result of increased production volumes as
well as increased capitalized drilling costs reflective of
greater levels of drilling and increased prices for tubular
goods occurring in response to supply conditions in the
worldwide steel market; |
|
|
|
$20 million higher lease operating expense associated with
the higher number of producing wells and an increase in well
maintenance activities, higher labor and fuel costs, and an
increase in overhead payments to another operator; |
|
|
|
$17 million higher operating taxes due primarily to
increased production volumes sold; |
|
|
|
a $16 million gain attributable to the sales of securities,
associated with a coal seam royalty trust, that were purchased
for resale; and |
|
|
|
a $15.4 million loss provision regarding an ownership
dispute on prior period production. |
The $165.6 million decrease in segment profit is due
primarily to the absence of $95 million in net gains on
sales of assets occurring in 2003, the increase in operating
expenses, and the loss provision of $15.4 million relating
to an ownership dispute on prior period production partially
offset by the $16 million gain attributable to the sales of
securities associated with our coal seam royalty trust that were
purchased for resale. Segment profit also includes
$25 million and $18 million related to international
activities for 2004 and 2003, respectively. This increase is
primarily driven by the improved operating results of Apco
Argentina.
The $80.7 million, or nine percent decrease in revenues is
due primarily to $66 million lower production revenues due
to lower production volumes as the result of property sales and
reduced drilling activities and $21 million lower other
revenues primarily due to the absence in 2003 of deferred income
relating to transactions in prior years that transferred certain
economic benefits to a third party.
The decrease in domestic production revenues reflects
$68 million associated with an eleven percent decrease in
net domestic production volumes, partially offset by
$2 million higher revenues from increased net realized
average prices for production. Net realized average prices
include the effect of hedge positions. The decrease in
production volumes primarily results from the sales of
properties in 2002 and 2003 and the impact of reduced drilling
activity. Drilling activity was lower in the January through
August period of 2003 due to our capital constraints. During the
third quarter, drilling activities on our retained properties
began to increase and by the fourth quarter of 2003 returned to
levels more consistent with 2002 levels. Approximately
86 percent of domestic production in 2003 was hedged using
the same methodology discussed above.
Total costs and expenses increased $32 million primarily
due to $46 million lower net gains on sales of assets in
2003 as compared to 2002. The remaining variance in costs and
expenses primarily reflects:
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|
|
$17 million lower exploration expenses reflecting our focus
of the company on developing proved properties while reducing
exploratory activities; |
|
|
|
$10 million lower depreciation, depletion and amortization
expense primarily as a result of lower production volumes; |
|
|
|
$7 million lower selling, general and administrative
expense; and |
|
|
|
$19 million higher operating taxes due primarily to higher
market prices. |
The $107.2 million decrease in segment profit is due
primarily to $46 million lower net gains on sales of assets
in 2003 as compared to 2002, as discussed above. Additionally,
lower production revenues due primarily to lower production
volumes also contributed to the decrease. Segment profit also
includes $18.2 million and $11.8 million related to
international activities for 2003 and 2002, respectively. This
increase is primarily driven by the improved operating results
of Apco Argentina.
63
Midstream Gas & Liquids
In 2004, we continued to expand our Midstream operations where
we have large scale assets that are positioned in growth basins
and to divest less strategic assets. Consistent with this plan,
we placed into service additional infrastructure in the
deepwater offshore area of the Gulf of Mexico and expanded the
Opal gas processing facility in Wyoming. In the deepwater Gulf
of Mexico, the Devils Tower production handling facility, the
Canyon Chief gas pipeline, and the Mountaineer oil pipeline
began flowing product in May 2004, while the Gunnison oil
pipeline volumes increased throughout the year. Our ongoing
focus is to develop and operate large-scale Midstream
infrastructure where our assets can be fully utilized and
provide the highest level of reliability to our customers.
The following factors impacted our business during 2004.
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|
Substantial Completion of Our Asset Sales
Goals In 2004, we completed our asset sales
program. The July sale of the western Canadian straddle plants
represented our most significant divestiture of 2004 yielding
approximately $544 million in U.S. funds. The
estimated pre-tax gain on sale of approximately
$190 million was recognized in discontinued operations in
the third quarter. |
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|
Favorable Commodity Price Margins Our natural
gas liquids (NGL) margins benefited from a significant
increase in crude oil prices and an increased demand for
petrochemical feedstocks such as ethane and propane. As
indicated in the graph below, our quarterly margins exceeded the
historical five-year annual average throughout the second half
of 2004. Our gas processing facilities produced strong financial
results as a result of near record high NGL margins and operated
at full capacity throughout most of the year. Our olefins
businesses also benefited from favorable commodity prices
associated with additional demand for ethylene and propylene. |
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![(BAR CHART)](d22803d2280377.gif) |
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Impact of Hurricane Ivan In September 2004,
portions of our Gulf Coast operations were interrupted by
Hurricane Ivan. The Mobile Bay gas processing plant, Canyon
Station and Devils Tower platforms were located in the path of
the hurricane and incurred varying levels of damage. Hurricane
Ivan caused temporary shut-downs of both our facilities and
producers facilities, which reduced product flows
resulting in lower segment profit of approximately
$11 million in 2004. The majority of the repairs related to
Hurricane Ivan are expected to be covered by our insurance.
Repairs to the Devils Tower facility were completed in October
2004 while our other impacted assets were returned to service by
the end of September 2004. However, product flows to our
deepwater |
64
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facilities were reduced significantly during the fourth-quarter
as incidental damage to our customers facilities was being
repaired. |
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Gulf Liquids Reclassification to Continuing
Operations During fourth-quarter 2004, we
reclassified the operations of Gulf Liquids to continuing
operations within our Midstream segment in accordance with EITF
Issue No. 03-13, Applying the Conditions in
Paragraph 42 of FASB Statement No. 144, Accounting for
the Impairment or Disposal of Long-Lived Assets, in Determining
Whether to Report Discontinued Operations,
(EITF 03-13). Under the provisions of EITF 03-13, Gulf
Liquids no longer qualifies for reporting as discontinued
operations based on managements expectation that we will
continue to have significant commercial activity with the
disposed entity. All periods presented reflect this restatement. |
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Gulf Liquids Insurance Arbitration Award
During fourth-quarter 2004, an arbitration panel awarded Gulf
Liquids $93.6 million, plus interest of $9.6 million.
Prior to this judgment, the insurer had disputed coverage of
certain financial assurances provided to Gulf Liquids on
multiple construction contracts. |
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Compliance with FERC Order 2004 Effective
June 1, 2004, and due in part to our response to FERC Order
2004, management and decision-making control of certain
regulated gas gathering assets was transferred from our
Midstream segment to our Gas Pipeline segment. We also requested
a waiver from the FERC regarding compliance with FERC Order 2004
for the operation of Discovery Gas Transmission and Black Marlin
assets. In July 2004, the FERC granted a partial waiver allowing
our Midstream segment to continue to manage these assets without
subjecting Midstream to energy affiliate status under FERC Order
2004. In order to comply with the remaining provisions of the
FERC order, we determined it was necessary to transfer
management of our equity investment in the Aux Sable processing
plant to our Power segment. This transfer was effective
September 21, 2004. All periods presented reflect these
classifications. |
The following factors could impact our business in 2005 and
beyond.
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As evidenced in recent years, natural gas and crude oil markets
are highly volatile. Although NGL margins earned at our gas
processing plants in 2004 were very favorable, we expect unit
margins in 2005 to trend downward towards historical averages.
NGL production volumes at our facilities are expected to be at
or above levels of previous years due to continued strong
drilling activities in our core basins. |
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We are planning to expand our investment in the Wamsutter
gathering system in 2005 and 2006. |
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Our olefins unit margins were also favorable in 2004. While we
believe this trend should continue in the near term, olefins
margins are highly volatile and levels in 2004 are not
necessarily indicative of levels expected for 2005. However, a
fire at a Canadian oil sands facility that supplies us with
off-gas feedstock reduced our throughput in January 2005. We
expect this throughput reduction to continue through late 2005,
partially offsetting the expected favorable margins. |
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Continued growth in the deepwater areas of the Gulf of Mexico is
expected to contribute to, and become a larger component of, our
future segment revenues and segment profit. We expect these
additional fee-based revenues to lower our proportionate
exposure to commodity price risks. |
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We continue efforts to sell our Gulf Liquids refinery off-gas
and propylene splitting business in Louisiana and anticipate
closing by the end of the second quarter of 2005. |
65
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Period-over-period results |
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Years Ended December 31, | |
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| |
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|
2004 | |
|
2003 | |
|
2002 | |
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| |
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| |
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| |
|
|
(Millions) | |
Segment revenues
|
|
$ |
2,882.6 |
|
|
$ |
2,784.8 |
|
|
$ |
1,183.7 |
|
Segment profit (loss)
|
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|
|
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|
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Domestic Gathering & Processing
|
|
|
342.7 |
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|
|
272.9 |
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|
|
203.5 |
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Venezuela
|
|
|
83.4 |
|
|
|
74.9 |
|
|
|
75.4 |
|
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Other
|
|
|
123.6 |
|
|
|
(150.5 |
) |
|
|
(106.7 |
) |
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|
|
|
|
|
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|
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Total
|
|
$ |
549.7 |
|
|
$ |
197.3 |
|
|
$ |
172.2 |
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|
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The $97.8 million increase in Midstreams revenues is
primarily the result of favorable commodity prices on our gas
processing and olefins businesses, largely offset by lower
trading revenues resulting from the fourth-quarter 2003 sale of
our wholesale propane business. Revenues associated with
production of NGLs increased $417 million, of which
$214 million is due to higher volumes and $203 million
is due to higher NGL prices. Olefins revenues increased
$223 million as a result of both higher market prices and
higher volumes. In addition, our deepwater service revenues
increased $9 million due to the addition of new
infrastructure. Other factors affecting total revenues include
approximately $1 billion in lower trading revenues
resulting from the fourth-quarter 2003 sale of our wholesale
propane business, partially offset by a $263 million
increase as the result of marketing NGLs on behalf of our
customers. Before 2004, our purchases of customers NGLs
were netted within revenues. In 2004, these purchases of
customers NGLs are included in costs and operating
expenses which substantially offset the change in revenues. Of
this $263 million increase, approximately $146 million
results from the difference in financial reporting presentation;
the remaining increase is due to higher NGL volumes and prices.
Also partially offsetting the lower trading revenues is
$141 million in higher crude sales associated with the 2004
startup of one of our deepwater pipelines, which is offset in
costs and operating expenses below.
Costs and operating expenses decreased $56 million
primarily as a result of approximately $1 billion in lower
trading costs due to the sale of our wholesale propane business
in 2003. This decline was partially offset by $312 million
in higher costs related to the production of NGLs and
$157 million in higher costs related to the production of
olefins products. These costs increased as a result of both the
higher production volumes noted above and the higher prices for
natural gas and olefins feedstock. Maintenance and depreciation
expenses increased $33 million in large part due to newly
constructed deepwater assets. Similar to the impact to revenues,
total costs and operating expenses increased $263 million
due to the marketing of NGLs on behalf of customers and
$141 million in higher crude purchases related to the same
deepwater pipeline mentioned above.
The $352.4 million increase in Midstream segment profit
includes the $93.6 million gain from the Gulf Liquids
insurance arbitration award in 2004 and the absence of a
$108.7 million impairment charge in 2003 related to these
same assets both of which are included in Other (income)
expense - net, within operating income. The remaining
increase in segment profit is primarily due to higher NGL and
olefins production volume and unit margins, higher service
revenues, and reduced general and administrative expenses. These
increases are partially offset by higher operating expenses and
asset impairment charges. A more detailed analysis of segment
profit of Midstreams various operations is presented below.
Domestic Gathering & Processing: The
$69.8 million increase in domestic gathering and processing
segment profit includes a $59.6 million increase in the
West region and an $10.2 million increase in the Gulf Coast
region.
66
The $59.6 million increase in our West regions
segment profit reflects higher NGL volume and unit margins
offset by lower fee revenues and higher operating expenses. The
significant components of this increase are explained below.
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Our West regions net NGL margins for 2004 increased
$69 million compared to the same period in 2003. Net NGL
margins are defined as NGL revenues less BTU replacement cost,
plant fuel, transportation and fractionation expense. Average
per unit NGL margins increased 49 percent and comprised
$51 million of the increase in NGL margins. As a result of
the higher spread between the prices of NGLs and natural gas,
our West plants operated at near capacity and produced
21 percent higher volumes comprising the remaining
$18 million increase in NGL net margins. |
The $10.2 million increase in our Gulf Coast regions
segment profit is due to higher NGL margins partially offset by
lower fee revenues and higher depreciation expense. The
significant components of the net increase include the following.
|
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|
Net NGL margins at our Gulf Coast gas processing plants
increased $35 million due to a 101 percent increase in
NGL production volumes which represented $28 million of the
increase in margins. The significantly higher NGL volumes were
driven by the favorable spread between NGL and natural gas
prices coupled with the recently completed production handling
infrastructure flowing additional deepwater gas production to
our plants. Per unit margins in the Gulf Coast region increased
13 percent and comprised the remaining $7 million
increase in net NGL margins. |
|
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|
Segment profit from our deepwater assets declined
$21 million primarily due to $29 million in higher
costs associated with assets placed into service in the first
two quarters of 2004 partially offset by $9 million in
higher services revenues. The increase in revenues includes
$22 million in incremental revenues from newly constructed
assets partially offset by a $13 million decline in
handling and gathering revenues due to lower production volumes
on other deepwater assets substantially resulting from the
effects of Hurricane Ivan. While revenues from the Devils Tower
deepwater facility are recognized as volumes are delivered over
the life of the reserves, cash payments from our customer are
based on a contractual fixed fee received over a defined term.
As a result, $36 million of cash received, which is
included in cash flow from operations, was deferred at
December 31, 2004 and will be recognized as revenue in
future periods. |
Venezuela: The $8.5 million increase in segment
profit for our Venezuelan assets is primarily due to the absence
of a fire at the El Furrial facility that reduced revenues by
$10 million in the first quarter of 2003.
Other: The $274.1 million increase in segment profit
in our other businesses includes the $93.6 million Gulf
Liquids insurance arbitration award and the absence of
$108.7 million in Gulf Liquids impairment charges in 2003.
The remaining increase is comprised of the following.
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Combined margins from our olefins businesses improved
$66 million reflecting the overall improvement in olefins
pricing and higher production volumes. Market prices for
ethylene and propylene products increased due to higher demand
and lower inventories. Production volumes increased as a result
of increased spot sales and the new higher fixed margin contract
at our Giesmar facility while our Canadian and Gulf Liquids
volumes benefited from improved plant operations. |
|
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|
Selling, general and administrative expenses declined
$23 million largely due to asset sales and lower legal
expenses. |
|
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|
The favorable variances above are partially offset by a 2004
$16.9 million impairment charge related to our equity
investment in the Discovery partnership, reflecting
managements assessment that there has been an
other-than-temporary decline in the value of this investment. |
Revenues increased $1.6 billion primarily as a result of
adopting EITF 02-3, which changed how we report natural gas
liquids trading activities. The costs of such activities are no
longer reported as reductions in revenues. EITF 02-3 does
not require restatement of prior year amounts. In addition to
this effect, our
67
revenues increased $210 million primarily due to higher NGL
revenues at our gas processing plants as a result of moderate
market price increases, partially offset by lower NGL production
volumes. Additional fee revenues associated with newly
constructed deepwater assets and higher olefins sales also
contributed to the revenue increase.
Costs and operating expenses also increased $1.9 billion
primarily due to the adoption of EITF 02-3 as discussed in
the previous paragraph. In addition to this effect, costs and
expenses increased $360 million, of which $113 million
is attributable to rising market prices for natural gas used to
replace the heating value of NGLs extracted at our gas
processing facilities. Feedstock purchases for the olefins
facilities increased $214 million due to higher NGL and gas
prices as well as higher purchase volumes.
Segment profit increased $25.1 million and includes
impairment charges of $108.7 million in 2003 related to the
Gulf Liquids facilities and $78.2 million in 2002 relating
to the Redwater/ Fort McMurray olefins assets. The
remaining $55.6 million increase is largely attributable to
higher deepwater and other Gulf Coast fee revenues partially
offset by unfavorable results in our Canadian and Gulf olefins
operations. Segment profit benefited from increased processing
margins in both 2003 and 2002 due to rising NGL prices coupled
with depressed natural gas prices in the Wyoming area. In
contrast, Canadian and Gulf olefins production margins suffered
as market prices for ethane and propane feedstocks increased
more than those for the olefins produced at these facilities,
which lowered operating results. In addition, gains on asset and
investment sales, reduced selling, general and administrative
expenses, and gathering system net gains are offset by lower
partnership earnings and higher depreciation expense. A more
detailed analysis of segment profit of our various operations is
presented below:
Domestic Gathering & Processing: The
$69.4 million increase in domestic gathering and processing
segment profit includes a $76.1 million increase in the
Gulf Coast region, partially offset by a $6.7 million
decline in the West region.
The Gulf Coast regions $76 million improvement is
largely attributable to $42 million of incremental segment
profit associated with new infrastructure in the deepwater area
of the Gulf of Mexico. The Canyon Station production platform,
Seahawk gas gathering pipeline, and Banjo oil transportation
system were placed into service during the latter half of 2002
and each contributed to Midstreams segment profit. The
remaining Gulf Coast gathering and processing assets provided
approximately $34 million in additional net revenues,
primarily from $12 million in higher processing margins and
$23 million in higher fee-based revenues. A portion of this
increase relates to the temporary processing agreements which
allow producers gas to be processed to achieve pipeline
quality standards.
The West regions $6.7 million segment profit decline
reflects the absence of $7 million in operating profit
associated with the Kansas Hugoton gathering system sold in
August 2002. Although 2003 segment profit is comparable to 2002,
the West regions segment results were impacted by several
offsetting factors discussed below.
|
|
|
|
|
Gas processing margins declined $10 million compared to
margins experienced in 2002. Throughout 2002 and the first
quarter of 2003, rising NGL prices and depressed Wyoming natural
gas prices yielded very favorable processing margins. Wyoming
natural gas prices rebounded at the end of the first quarter
2003 as the completion of the Kern River Pipeline system added
transportation capacity relieving downward price pressure.
Margins recovered somewhat in the fourth quarter as Wyoming gas
prices lagged behind the increases in other energy commodities. |
|
|
|
Gathering and processing fee revenues declined $11 million
primarily due to fewer customers electing the fee-based billing
option of processing contracts. |
|
|
|
Non-reimbursed fuel expenses declined $8 million, largely
attributed to favorable adjustments in the annual fuel
reimbursement rates. |
|
|
|
We realized $17 million in non-recurring net product gains
related to our gas gathering system. These gains represent less
than one-third of one percent of total gas gathered and are
within industry |
68
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|
|
|
|
standards. Historically our gathering system realizes net gains
and losses, and therefore, we do not consider these gains to be
recurring in nature. |
|
|
|
Depreciation expense was $10 million higher in large part
due to additional investments in the West region. |
Venezuela: Segment profit for our Venezuelan assets
remained virtually unchanged. Higher compression rates in 2003
and the 2002 currency exchange loss resulted in $11 million
higher profits at the PIGAP gas compression facility. These
higher profits were partially offset by an $10 million
decrease in the El Furrial revenues attributed to plant downtime
caused by a fire that occurred in the first quarter of 2003.
Also offsetting the increase in PIGAP operating profit is a
$4 million decline resulting from the termination of the
Jose Terminal operations contract in December 2002. Our
Venezuelan assets were constructed and are currently operated
for the exclusive benefit of Petroleos de Venezuela S.A.
(PDVSA), the state owned Petroleum Corporation of Venezuela. The
Venezuelan economic and political environment can be volatile,
but has not significantly impacted the operations and cash flows
of our facilities.
Effective February 7, 2004, the Venezuelan government
revalued the fixed exchange rate for their local currency from
1,600 Bolivars to the dollar to 1,920 Bolivars to the dollar.
This effect of this currency devaluation was recorded in the
first quarter of 2004 and did not have a significant impact on
our first quarter segment profit.
Other: The $43.8 million decline in segment profit
for Midstreams other operations includes impairment
charges of $108.7 million in 2003 related to the Gulf
Liquids facilities and the absence of $78.2 million of
profit in 2002 relating to the Redwater/ Fort McMurray
olefins assets. The remaining decrease is attributed to lower
domestic olefins margins and unfavorable partnership earnings,
partially offset by the gain on sale of our wholesale propane
operations as discussed below.
|
|
|
|
|
Excluding impairment charges, segment profit for our olefins
businesses declined $26 million primarily as a result of
reduced olefins margins as the price of ethane, propane, and
natural gas feedstocks increased more than the price of olefins
products. Higher maintenance expenses also contributed to the
decline in segment profit. Olefins production margins continue
to be impacted by weak consumer demand for products produced by
petrochemical facilities. |
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|
|
Segment profit from partially owned domestic assets accounted
for using the equity method remained largely unchanged and
includes $21 million lower earnings from partially-owned
investments primarily resulting from $13 million in prior
period accounting adjustments recorded on the Discovery
partnership and the 2003 sale of other investments that
generated $5 million in higher 2002 earnings. These
unfavorable results were partially offset by net gains totaling
approximately $20 million from the sale of our interests in
the West Texas, Rio Grande, Wilprise, and Tri-States liquids
pipeline partnerships. |
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|
|
Segment profit for our trading, fractionation, and storage group
increased $14 million primarily due to a $16 million
gain on the fourth-quarter 2003 sale of our wholesale propane
business consisting of certain supply contracts and seven
propane distribution terminals. Our NGL trading operations
activities were substantially curtailed in 2003, resulting in
$11 million lower selling, general, and administrative
costs partially offset by $8 million in lower net trading
revenues. In addition, NGL service fees declined $5 million
due to the sale of several NGL terminals in 2002. |
Other
During February 2004, we were a party to a recapitalization plan
completed by Longhorn. As a result of this plan, we sold a
portion of our equity investment in Longhorn for
$11.4 million, received $58 million in repayment of a
portion of our advances to Longhorn and converted the remaining
advances, including accrued interest, into preferred equity
interests in Longhorn. These preferred equity interests are
subordinate to the preferred interests held by the new
investors. No gain or loss was recognized on this transaction.
69
In 2005, we expect to see improved results from our investment
in Longhorn. The first product shipments on the Longhorn
pipeline occurred in December 2004 and volumes should increase
throughout 2005. New shippers have been approved and more
approvals are currently in process. In addition, during the
first quarter of 2005, we finalized a sales agreement on our
Longhorn operating agreement. The sale is expected to close
during the first quarter or early in the second quarter of 2005.
We expect to receive proceeds on the sale over the remaining
term of the operating agreement, which expires on June 30,
2012. We do not expect to recognize a gain or loss on the sale.
|
|
|
Year-over-year operating results |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Segment revenues
|
|
$ |
32.8 |
|
|
$ |
72.0 |
|
|
$ |
124.1 |
|
Segment profit (loss)
|
|
$ |
(41.6 |
) |
|
$ |
(50.5 |
) |
|
$ |
14.1 |
|
Other segment revenues for 2003 includes approximately
$22 million of revenues related to certain butane blending
assets, which were sold during third-quarter 2003.
Other segment loss for 2004 includes $11.8 million of
accrued environmental remediation expense associated with the
Augusta refinery, and a $10.8 million impairment,
$9.8 million of equity losses, and $6.5 million of net
unreimbursed advisory fees, all related to our investment in
Longhorn. The environmental accrual results from new information
obtained in the fourth quarter of 2004. The impairment charge
reflects managements belief that there was an other than
temporary decline in the fair value of this investment following
a determination that additional funding would be required to
commission the pipeline into service. The project incurred cost
overruns in preparation for commissioning, including higher
priced line fill costs. The net unreimbursed advisory fees
relate to the recapitalization of Longhorn as discussed above.
If the project achieves certain future performance measures, the
unreimbursed fees may be recovered.
Other segment loss for 2003 includes a $43.1 million
impairment related to our investment in equity and debt
securities of Longhorn. The impairment resulted from our
assessment that there had been an other than temporary decline
in the fair value of this investment.
Other segment loss for 2003 includes the $43.1 million
impairment of Longhorn noted above. Longhorn equity earnings
increased $15.7 million during 2003 from a loss of
$13.8 million in 2002. The 2002 segment profit includes a
$58.5 million gain on the sale of our 27 percent
ownership interest in the Lithuanian operations partially offset
by a $12.6 million equity loss for those operations.
70
Energy trading activities
As of December 31, 2002, we held all of these energy and
energy-related contracts for trading purposes and carried them
on the Consolidated Balance Sheet at fair value. With the
adoption of EITF 02-3 on January 1, 2003, we reversed
approximately $1.2 billion of non-derivative fair value
through a cumulative adjustment from a change in accounting
principle. These contracts are now accounted for under the
accrual method. Effective January 1, 2003, only energy
contracts meeting the definition of a derivative are reflected
at fair value on the Consolidated Balance Sheet.
|
|
|
Fair value of trading and non-trading derivatives |
The chart below reflects the fair value of derivatives held for
trading purposes as of December 31, 2004. We have presented
the fair value of assets and liabilities by the period in which
we expect them to be realized.
Net Assets (Liabilities)
(Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
To be | |
|
To be | |
|
To be | |
|
To be | |
|
|
Realized in | |
|
Realized in | |
|
Realized in | |
|
Realized in | |
|
|
1-12 Months | |
|
13-36 Months | |
|
36-60 Months | |
|
61-120 Months | |
|
Net Fair | |
(Year 1) | |
|
(Years 2-3) | |
|
(Years 4-5) | |
|
(Years 6-10) | |
|
Value | |
| |
|
| |
|
| |
|
| |
|
| |
$ |
15 |
|
|
$ |
16 |
|
|
$ |
(3 |
) |
|
$ |
(2 |
) |
|
$ |
26 |
|
As the table above illustrates, we are not materially engaged in
trading activities. However, we hold a substantial portfolio of
non-trading derivative contracts. Non-trading derivative
contracts are those that hedge or could possibly hedge on an
economic basis forecasted transactions associated with
Powers long-term structured contract position and owned
generation, Exploration & Productions forecasted
sales of natural gas production, as well as the activities of
our other segments. As a result of our decision to retain the
Power business, in the fourth quarter of 2004 we designated a
portion of the existing derivatives as SFAS 133 cash flow
hedges. Many of these non-trading derivatives had an existing
fair value prior to their designation as cash flow hedges.
Certain other of Powers derivatives have not been
designated as or do not qualify as SFAS 133 hedges. We also
hold certain derivative contracts, which also qualify as
SFAS 133 cash flow hedges, that primarily hedge
Exploration & Productions forecasted natural gas
sales. The chart below reflects the fair value of derivatives
held for non-trading purposes as of December 31, 2004. Of
the total fair value of non-trading derivatives, SFAS 133
cash flow hedges had a net liability value of
$328.8 million as of December 31, 2004, which includes
the fair value of the derivatives upon their designation as
SFAS 133 cash flow hedges.
Net Assets (Liabilities)
(Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
To be | |
|
To be | |
|
To be | |
|
To be | |
|
To be | |
|
|
Realized in | |
|
Realized in | |
|
Realized in | |
|
Realized in | |
|
Realized in | |
|
|
1-12 Months | |
|
13-36 Months | |
|
36-60 Months | |
|
61-120 Months | |
|
121+ Months | |
|
Net Fair | |
(Year 1) | |
|
(Years 2-3) | |
|
(Years 4-5) | |
|
(Years 6-10) | |
|
(Years 11+) | |
|
Value | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
$ |
89 |
|
|
$ |
120 |
|
|
$ |
108 |
|
|
$ |
44 |
|
|
$ |
4 |
|
|
$ |
365 |
|
|
|
|
Methods of estimating fair value |
Most of the derivatives we hold settle in active periods and
markets in which quoted market prices are available. Quoted
market prices in active markets are readily available for
valuing, future contracts, swap agreements and physical
commodity purchases and sales in the commodity markets in which
we transact. While an active market may not exist for the entire
period, quoted prices can generally be obtained for natural gas
through 2012 and power through 2010.
These prices reflect the economic and regulatory conditions that
currently exist in the marketplace and are subject to change in
the near term due to changes in market conditions. The
availability of quoted market prices in active markets varies
between periods and commodities based upon changes in market
conditions.
71
The ability to obtain quoted market prices also varies greatly
from region to region. The time periods noted above are an
estimation of aggregate liquidity. An immaterial portion of our
total net derivative value of $391 million relates to
periods in which active quotes cannot be obtained. We use prices
of current transactions to further validate price estimates.
However, the decline in overall market liquidity since 2002 has
limited our ability to validate prices.
We estimate energy commodity prices in illiquid periods by
incorporating information about commodity prices in actively
quoted markets, quoted prices in less active markets, and other
market fundamental analysis.
Due to the adoption of EITF 02-3, modeling and other
valuation techniques are not used significantly in determining
the fair value of our derivatives. Such techniques were
primarily used in previous years for valuing non-derivative
contracts such as transportation, storage, full requirements,
load serving, transmission and power tolling contracts, which
are no longer reported at fair value (see Note 1 of Notes
to Consolidated Financial Statements).
|
|
|
Counterparty credit considerations |
We include an assessment of the risk of counterparty
non-performance in our estimate of fair value for all contracts.
Such assessment considers 1) the credit rating of each
counterparty as represented by public rating agencies such as
Standard & Poors and Moodys Investors
Service, 2) the inherent default probabilities within these
ratings, 3) the regulatory environment that the contract is
subject to and 4) the terms of each individual contract.
Risks surrounding counterparty performance and credit could
ultimately impact the amount and timing of expected cash flows.
We continually assess this risk. We have credit protection
within various agreements to call on additional collateral
support if necessary. At December 31, 2004, we held
collateral support of $336 million.
We also enter into netting agreements to mitigate counterparty
performance and credit risk. During 2004, we did not incur any
significant losses due to recent counterparty bankruptcy filings.
The gross credit exposure from our derivative contracts as of
December 31, 2004 is summarized below.
|
|
|
|
|
|
|
|
|
|
|
Investment | |
|
|
Counterparty Type |
|
Grade(a) | |
|
Total | |
|
|
| |
|
| |
|
|
(Millions) | |
Gas and electric utilities
|
|
$ |
556.4 |
|
|
$ |
609.4 |
|
Energy marketers and traders
|
|
|
1,185.7 |
|
|
|
3,268.3 |
|
Financial institutions
|
|
|
2,023.9 |
|
|
|
2,023.9 |
|
Integrated gas and oil
|
|
|
90.0 |
|
|
|
90.0 |
|
Other
|
|
|
5.6 |
|
|
|
21.1 |
|
|
|
|
|
|
|
|
|
|
$ |
3,861.6 |
|
|
|
6,012.7 |
|
|
|
|
|
|
|
|
Credit reserves
|
|
|
|
|
|
|
(26.4 |
) |
|
|
|
|
|
|
|
Gross credit exposure from derivatives(b)
|
|
|
|
|
|
$ |
5,986.3 |
|
|
|
|
|
|
|
|
72
We assess our credit exposure on a net basis. The net credit
exposure from our derivatives as of December 31, 2004 is
summarized below.
|
|
|
|
|
|
|
|
|
|
|
Investment | |
|
|
Counterparty Type |
|
Grade(a) | |
|
Total | |
|
|
| |
|
| |
|
|
(Millions) | |
Gas and electric utilities
|
|
$ |
93.4 |
|
|
$ |
119.8 |
|
Energy marketers and traders
|
|
|
454.9 |
|
|
|
613.3 |
|
Financial institutions
|
|
|
217.4 |
|
|
|
217.4 |
|
Other
|
|
|
1.1 |
|
|
|
1.6 |
|
|
|
|
|
|
|
|
|
|
$ |
766.8 |
|
|
|
952.1 |
|
|
|
|
|
|
|
|
Credit reserves
|
|
|
|
|
|
|
(26.4 |
) |
|
|
|
|
|
|
|
Net credit exposure from derivatives(b)
|
|
|
|
|
|
$ |
925.7 |
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
We determine investment grade primarily using publicly available
credit ratings. We included counterparties with a minimum
Standard & Poors rating of BBB- or Moodys
Investors Service rating of Baa3 in investment grade. We also
classify counterparties that have provided sufficient
collateral, such as cash, standby letters of credit, adequate
parent company guarantees, and property interests, as investment
grade. |
|
(b) |
|
One counterparty within the California power market represents
more than ten percent of the derivative assets and is included
in investment grade. Standard & Poors and
Moodys Investors Service do not currently rate this
counterparty. We included this counterparty in the investment
grade column based upon contractual credit requirements. |
We have policies and procedures that govern our trading and risk
management activities and transactions. These policies cover
authority and delegation thereof in addition to control
requirements, authorized commodities and term and exposure
limitations. Powers value-at-risk is limited in aggregate
and calculated at a 95 percent confidence level.
73
Financial condition and liquidity
Entering 2003, we faced significant liquidity challenges with
sizeable maturing debt obligations and limited financial
flexibility due in part to covenants arising from 2002
short-term financing. In February 2003, we outlined our planned
business strategy to address these issues.
During 2003, we made substantial progress in strengthening our
finances by generating cash proceeds of approximately
$3.0 billion from asset sales, retiring $3.2 billion
in debt, redeeming $275 million in preferred stock and
issuing $2 billion in debt at more favorable market rates.
In 2004, we continued to execute certain components of the plan.
Our key results for 2004 include the following.
|
|
|
|
|
The replacement of our cash-collateralized letter of credit and
revolver facility with facilities that do not encumber cash. |
|
|
|
Completion of planned asset sales, which resulted in proceeds of
approximately $877.8 million (see further discussion in
Investing activities). |
|
|
|
Significant debt reduction of approximately $4 billion in
2004 through scheduled maturities and early redemptions,
including an exchange offer for our FELINE PACS units (see
further discussion in Financing activities). |
|
|
|
Reduction of the risk and liquidity requirements of our Power
business. As discussed previously, our Board of Directors
approved the decision to retain Power and end our efforts to
exit that business. We have and will continue to manage this
business to minimize financial risk, generate cash and manage
existing contractual commitments. During 2004, we reduced risk
through the sale, termination or expiration of certain contracts
and through entering into new contracts that economically hedge
existing positions. |
|
|
|
Additional net reduction of $33 million in our selling,
general and administrative costs and general corporate expenses.
In an effort to further reduce costs in the future, we entered
into an agreement with IBM to provide support services for
certain areas of our business as discussed previously. |
Our liquidity is derived from both internal and external
sources. Certain of those sources are available to us (at the
parent level) and others are available to certain of our
subsidiaries.
At December 31, 2004, we have the following sources of
liquidity from cash and cash equivalents:
|
|
|
|
|
cash-equivalent investments at the corporate level of
$735 million as compared to $2.2 billion at
December 31, 2003, and |
|
|
|
cash and cash-equivalent investments of various international
and domestic entities of $195 million, as compared to
$91 million at December 31, 2003 |
At December 31, 2004, we have capacity of $28 million
available under our two unsecured revolving credit facilities
totaling $500 million. In April 2004, we entered into two
unsecured bank revolving credit facilities totaling
$500 million. These facilities provide for both borrowings
and letters of credit, but are used primarily for issuing
letters of credit. Use of these new facilities released
approximately $496 million of restricted cash, restricted
investments and margin deposits in the second quarter. In
January 2005, these facilities were terminated and replaced with
two new facilities that contain similar terms but fewer
restrictions (see Note 11 of Notes to Consolidated
Financial Statements).
At December 31, 2004, we also have capacity of
$853 million available under our $1.275 billion
secured revolving facility. On May 3, 2004, we entered into
a new three-year, $1 billion secured revolving credit
facility
74
which is available for borrowings and letters of credit. In
August 2004, we expanded the credit facility by an additional
$275 million. Northwest Pipeline and Transco each have
access to $400 million under the facility, which is secured
by certain Midstream assets and guaranteed by Williams Gas
Pipeline Company, LLC, the parent company of Transco and
Northwest Pipeline (WGP) (see Note 11 of Notes to the
Consolidated Financial Statements).
At December 31, 2003, we had capacity of $447 million
available under the $800 million revolving and letter of
credit facility which was terminated on May 3, 2004.
We have an effective shelf registration statement with the
Securities and Exchange Commission that authorizes us to issue
an additional $2.2 billion of a variety of debt and equity
securities. In addition, our wholly owned subsidiaries,
Northwest Pipeline and Transco, also have outstanding
registration statements filed with approximately
$350 million of shelf availability remaining under these
registration statements at December 31, 2004. Our ability
to utilize these registration statements for debt securities was
restricted by certain covenants of our debt agreements at
December 31, 2004. On January 20, 2005, this
restriction was removed from the parent and from Transco with
the replacement of our two unsecured revolving credit facilities
(see Note 11 of Notes to the Consolidated Financial
Statements). Interest rates, market conditions, and industry
conditions will affect amounts raised, if any, in the capital
markets.
During 2004, we satisfied liquidity needs with:
|
|
|
|
|
$1.1 billion in cash generated from sales of investments,
property, and other assets, including the sale of the Alaska
refinery and related assets and the sale of the Canadian
straddle plants; |
|
|
|
approximately $1.5 billion in cash generated from operating
activities of continuing operations, including the release of
approximately $212 million of restricted cash and margin
deposits previously used to collateralize certain credit
facilities; and |
|
|
|
the release of approximately $284 million of restricted
investments previously used to collateralize certain credit
facilities. |
As part of executing the business plan announced in February
2003, we established a goal of returning to investment grade
ratios. Our decision to remain in the Power business could delay
that goal. Our Standard and Poors, Moodys Investors
Service (Moodys), and Fitch Ratings (Fitch) debt ratings
at December 31, 2004 are as follows.
Current Senior Unsecured Debt Ratings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northwest | |
|
|
|
|
Williams | |
|
Pipeline | |
|
Transco | |
|
|
| |
|
| |
|
| |
Standard & Poors
|
|
|
B+ |
|
|
|
B+ |
|
|
|
B+ |
|
Moodys Investors Service
|
|
|
B1 |
|
|
|
Ba2 |
|
|
|
Ba2 |
|
Fitch Ratings
|
|
|
BB |
|
|
|
BB+ |
|
|
|
BB+ |
|
On July 30, 2004, Standard & Poors raised
our debt ratings outlook from negative to stable citing our debt
reduction efforts. With respect to Standard &
Poors, a rating of BBB or above indicates an
investment grade rating. A rating below BBB
indicates that the security has significant speculative
characteristics. A B rating indicates that Standard
and Poors believes the issuer has the capacity to meet its
financial commitment on the obligation, but that adverse
business, financial or economic conditions will likely impair
the obligors capacity or willingness to meet its financial
commitment to the obligation. Standard and Poors may
modify its ratings with a + or a
sign to show the obligors
relative standing within a major rating category.
On November 8, 2004, Moodys Investors Service raised
our senior implied rating to Ba3 from B2 and our senior
unsecured rating to B1 from B3, with a stable outlook. With
respect to Moodys, a rating of Baa or above
indicates an investment grade rating. A rating below
Baa is considered to have speculative
75
elements. A Ba ranking indicates an obligation that
is judged to have speculative elements and is subject to
substantial credit risk. A B rating from
Moodys signifies an obligation that is considered
speculative and is subject to high credit risk. The
1, 2 and 3 modifiers show
the relative standing within a major category. A 1
indicates that an obligation ranks in the higher end of the
broad rating category, 2 indicating a mid-range
ranking, and 3 ranking at the lower end of the
category.
On December 10, 2004, Fitch raised our senior unsecured
rating to BB from B+ and revised the ratings outlook to stable
from positive. With respect to Fitch, a rating of
BBB or above indicates an investment grade rating. A
rating below BBB is considered speculative grade. A
BB rating from Fitch indicates that there is a
possibility of credit risk developing, particularly as the
result of adverse economic change over time; however, business
or financial alternatives may be available to allow financial
commitments to be met. Fitch may add a + or a
sign to show the obligors
relative standing within a major rating category.
As our financial ratios improve and we continue to reduce debt
in line with forecasts, our ratings could improve. Improved
ratings could result in lower borrowing costs. However, if our
financial ratios do not meet expected levels, the outlook and
the rating could decline.
Our historical debt to capitalization ratios and our forecasted
amount for 2005 are shown below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected | |
|
|
2002 | |
|
2003 | |
|
2004 | |
|
2005 | |
|
|
| |
|
| |
|
| |
|
| |
Debt to Capitalization*
|
|
|
72.3% |
|
|
|
74.5% |
|
|
|
61.6% |
|
|
|
59%-60% |
|
|
|
* |
Debt includes Long-term debt and Long-term debt due within one
year. Capitalization includes debt as calculated above plus
Stockholders equity. |
|
|
|
Off-balance sheet financing arrangements and guarantees of
debt or other commitments to third parties |
As discussed in Sources of liquidity, in April 2004, we
entered into two unsecured bank revolving credit facilities
totaling $500 million. We were able to obtain the unsecured
credit facilities because the funding bank syndicated its
associated credit risk into the institutional investor market.
Upon the occurrence of certain credit events, letters of credit
outstanding under the agreement become cash collateralized,
creating a borrowing under the facilities. Concurrently, the
bank can deliver the facilities to the institutional investors,
whereby the investors replace the bank as lender under the
facilities.
To facilitate the syndication of the facilities, the bank
established trusts funded by the institutional investors. The
assets of the trusts serve as collateral to reimburse the bank
for our borrowings in the event the facilities are delivered to
the investors. We have no asset securitization or collateral
requirements under the new facilities. During the second
quarter, use of these new facilities released approximately
$496 million of restricted cash, restricted investments and
margin deposits. In January 2005, these facilities were
terminated and replaced with two new facilities that contain
similar terms but fewer restrictions (see Note 11 of Notes
to the Consolidated Financial Statements).
We have various guarantees which are disclosed in
Notes 3, 10, 11, 14 and 15 of Notes to Consolidated
Financial Statements. We do not believe these guarantees or the
possible fulfillment of them will negatively impact our
liquidity.
The increase in cash flow from operations from 2003 to 2004 is
primarily due to:
|
|
|
|
|
the increase in cash flow from changes in accounts payable of
$512 million, |
|
|
|
the increase in cash flow from changes in derivatives and energy
risk management and trading assets and liabilities of
$190 million, |
|
|
|
the reduction of margin deposit requirements of
$170 million, and |
|
|
|
the improvement in Income (loss) from continuing operations of
$151 million. |
76
Lower margin deposit funding requirements in 2004, facilitated
by letter of credit issues, resulted in higher cash inflow in
2004. In addition, positive cash flows resulting from the
settlement of derivative contracts contributed to higher cash
inflow primarily from Power in 2004.
The increase in cash flows from operations were largely offset
by a decrease in cash flow from changes in accounts receivable
of $434 million, due primarily to the operation of
Powers managed assets.
Additionally, on November 1, 2004, Winterthur remitted
approximately $85 million to us in the settlement of
certain disputes regarding insurance obligations under
construction contracts (see Note 4 of Notes to Consolidated
Financial Statements).
The increase in funds from noncurrent restricted cash of
$124.5 million in 2004 is primarily due to the release of
cash held as collateral for various surety bonds.
We recorded approximately $86.7 million,
$231.9 million and $399.1 million in provisions for
losses on property and other assets in 2004, 2003, and 2002,
respectively. We also recorded net gain on disposition of assets
of $18.1 million, $142.8 million, and
$190.4 million, in 2004, 2003, and 2002, respectively (see
Notes 3 and 4 of Notes to Consolidated Financial
Statements).
In 2003, we recorded an accrual for fixed rate interest included
in the secured note payable of Williams Production RMT company
(the RMT Note) on the Consolidated Statement of Cash Flows
representing the quarterly non-cash reclassification of the
deferred fixed rate interest from an accrued liability to the
RMT Note. The Amortization of deferred set-up fee and fixed rate
interest on the RMT Note relates to amounts recognized in the
Consolidated Statement of Operations as interest expense, but
which were not payable until maturity. The RMT Note was repaid
in May 2003.
In March 2002, WilTel exercised its option to purchase certain
network assets under a transaction for which we had previously
provided a guarantee. On March 29, 2002, as guarantor under
the agreement, we paid $753.9 million related to
WilTels purchase of these network assets.
Other, including changes in noncurrent assets and liabilities,
includes contributions to our tax qualified pension plans of
$136.8 million, $42.8 million and $77.0 million
in 2004, 2003 and 2002, respectively. It is our policy to fund
our tax qualified pension plans the greater of the actuarially
computed annual normal cost plus any unfunded actuarial accrued
liability, amortized over approximately five years, or the
minimum required contribution under existing tax laws.
Additional amounts may be contributed to increase the funded
status of the plans. In an effort to strengthen our funded
status and take advantage of very strong cash flows, we
contributed approximately $98.9 million more than our
funding policy required in 2004.
During 2004, we made significant progress on our plan to reduce
debt. We retired approximately $4 billion of debt through
scheduled maturities, early debt retirements, and an exchange
offer on our FELINE PACS units. In 2005, scheduled maturities
are approximately $247 million. Significant reductions in
debt during 2004 include the following.
|
|
|
|
|
On March 15, we retired the remaining $679 million
outstanding balance of the 9.25 percent senior unsecured
notes due March 15, 2004. |
|
|
|
In June and September, we retired a total of approximately
$2 billion through tender offers. In May we also
repurchased on the open market approximately $255 million
of various notes. In conjunction with the tendered notes,
related consents, and the debt repurchase, we paid premiums of
approximately $214 million. The premiums, as well as
related fees and expenses, together totaling
$252.4 million, are included in Early debt retirement costs
on the Consolidated Statement of Cash Flows. |
|
|
|
In June, we made a payment of approximately $109 million
for accrued interest, short-term payables, and long-term debt on
borrowings collateralized by certain receivables from the
California Power Exchange that were previously sold to a third
party. Approximately $79 million of the |
77
|
|
|
|
|
payment is included in Payments of long-term debt on the
Consolidated Statement of Cash Flows. In July 2004, we received
payment of approximately $104 million from the California
Power Exchange which is reported in Changes in accounts and
notes receivable on the Consolidated Statement of Cash Flows. |
|
|
|
In October, we completed the exchange of approximately
33.1 million FELINE PACS units for one share of our common
stock plus $1.47 in cash for each unit resulting in the
retirement of $827 million of debt. |
|
|
|
In November, we completed the purchase and retirement of
approximately $200 million of the remaining notes in
connection with our FELINE PACS remarketing. Approximately
$73.1 million of the original $1.1 billion of notes
remains outstanding and is due on February 16, 2007. |
For additional discussion of other repayments in 2004, see
Note 11 of Notes to Consolidated Financial Statements.
We made significant reductions in our debt in 2003. We retired
$3.2 billion in debt, redeemed $275 million in
preferred stock, and issued $2 billion in debt at more
favorable market rates.
Significant borrowings and repayments during 2003 included the
following.
|
|
|
|
|
On March 4, our Northwest Pipeline subsidiary completed an
offering of $175 million of 8.125 percent senior notes
due 2010. Proceeds from the issuance were used for general
corporate purposes, including the funding of capital
expenditures. |
|
|
|
On May 28, we issued $300 million of 5.5 percent
junior subordinated convertible debentures due 2033. The
proceeds were used to redeem all outstanding 9.875 percent
cumulative-convertible preferred shares. |
|
|
|
In May, we repaid the RMT Note totaling $1.15 billion,
which included certain contractual fees and deferred interest. |
|
|
|
On May 30, a subsidiary in our Exploration &
Production segment entered into a $500 million secured note
due May 30, 2007, at a floating interest rate of LIBOR plus
3.75 percent. This loan refinanced a portion of the RMT
Note discussed above. On February 25, 2004 we completed an
amendment that provided more favorable terms including a lower
interest rate and an extension of the maturity by one year. |
|
|
|
On June 6, we entered into a two-year $800 million
revolving and letter of credit facility, primarily for the
purpose of issuing letters of credit. The facility was secured
by cash and/or acceptable government securities. We terminated
this facility in May 2004. |
|
|
|
On June 10, we issued $800 million of
8.625 percent senior unsecured notes due 2010. The notes
were issued under our $3 billion shelf registration
statement. The proceeds were used to improve corporate
liquidity, general corporate purposes, and payment of maturing
debt obligations. We retired $793 million of these notes in
an August 2004 tender offer. |
|
|
|
On June 10, we also redeemed all the outstanding
9.875 percent cumulative-convertible preferred shares for
approximately $289 million, plus $5.3 million for
accrued dividends. |
|
|
|
In October, we retired $721 million of senior unsecured
9.25 percent notes and $230 million of other notes and
debentures through tender offers. In conjunction with the
tendered notes and related consents, we paid premiums of
approximately $58 million. The premiums, as well as related
fees and expenses, together totaling $66.8 million, are
included in Early debt retirement costs on the Consolidated
Statement of Cash Flows. |
|
|
|
In October, our PIGAP high-pressure gas compression project in
Venezuela obtained $230 million in non-recourse financing.
We own a 70 percent interest in the project and, therefore,
the debt is reflected on our Consolidated Balance Sheet.
Proceeds from the loan were used to repay us for notes due and
the other owner for a portion of the initial funding of
construction-related costs. Upon the |
78
|
|
|
|
|
execution of the loan, the project made additional cash
distributions to the owners based on their respective ownership
interests. We received approximately $183 million in cash
proceeds, net of amounts paid relating to an up front premium,
the purchase of an interest rate lock and cash used to fund a
debt service reserve. |
Significant borrowings and repayments in 2002 included the
following.
|
|
|
|
|
On January 14, we completed the sale of 44 million
publicly traded units, known as FELINE PACS, that include a
senior debt security and an equity purchase contract, for net
proceeds of approximately $1.1 billion. As discussed
previously, only $73.1 million of notes remains outstanding
at December 31, 2004. |
|
|
|
On March 19, we issued $850 million of 30-year notes
with an interest rate of 8.75 percent and $650 million
of 10-year notes with an interest rate of 8.125 percent.
The proceeds were used to repay approximately $1.4 billion
outstanding commercial paper, provide working capital and for
general corporate purposes. |
|
|
|
In May, Power entered into an agreement which transferred the
rights to certain receivables, along with risks associated with
that collection, in exchange for cash. Due to the structure of
the agreement, Power accounted for this transaction as debt
collateralized by the claims and recorded $79 million of
debt. As discussed previously, this amount was paid in June 2004. |
|
|
|
RMT entered into a $900 million credit agreement dated as
of July 31, 2002. As discussed previously, this amount was
repaid in May 2003. |
Dividends paid on common stock were increased from $.01 to
$.05 per common share in fourth-quarter 2004 and totaled
$43.4 million for the year ended 2004. One of the covenants
under the former $500 million revolving credit facilities
limited our quarterly common stock dividends to not more than
$.05 per common share. The covenant was removed when the
facilities were replaced on January 20, 2005.
In 2003, we also paid $32.6 million in accrued dividends on
the 9.875 percent cumulative-convertible preferred shares
that were redeemed in June 2003. The $32.6 million of
preferred dividends paid includes the 2003 payment of
$6.8 million in dividends accrued at December 31,
2002. The $29.5 million of preferred stock dividends
reported on the Consolidated Statement of Operations also
includes $3.7 million of issuance costs.
During 2002, structural changes to certain limited liability
company member interests required classification of these
outside investor interests as debt. These structural changes
also included the repayment of the investors preferred
interest in installments. During 2002, approximately
$558 million was repaid related to these interests and is
included in the payments of long-term debt. During 2003, the
remaining balances associated with these interests were paid.
Approximately $323 million of payments are included in
payments of long-term debt for 2003.
In third-quarter 2002, the downgrade of our senior unsecured
rating below BB by Standard & Poors, and Ba1 by
Moodys Investors Service, resulted in the early retirement
of an outside investors preferred ownership interest for
$135 million.
Significant items reflected as discontinued operations within
financing activities in the Consolidated Statement of Cash
Flows, including the cash provided by financing activities,
include the following items:
|
|
|
|
|
proceeds from long-term debt of Williams Energy Partners LP
related to financing entered into in 2002 of $489 million,
and |
|
|
|
net proceeds from issuance of common units by Williams Energy
Partners LP in 2002 of $279 million. |
79
Capital expenditures by segment are presented below.
Capital Expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment |
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Power
|
|
$ |
1.0 |
|
|
$ |
1.0 |
|
|
$ |
135.8 |
|
Gas Pipeline
|
|
|
251.0 |
|
|
|
497.6 |
|
|
|
672.0 |
|
E&P
|
|
|
445.4 |
|
|
|
202.0 |
|
|
|
364.1 |
|
Midstream
|
|
|
84.2 |
|
|
|
252.9 |
|
|
|
432.8 |
|
Other
|
|
|
5.8 |
|
|
|
2.5 |
|
|
|
57.3 |
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
787.4 |
|
|
$ |
956.0 |
|
|
$ |
1,662.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power made capital expenditures in 2002 primarily to purchase
power-generating turbines. |
|
|
|
Gas Pipeline made capital expenditures in 2004 primarily for the
maintenance of existing facilities and in 2002 through 2003
primarily to expand deliverability into the east and west coast
markets. Planned expenditures for 2005 are primarily for the
maintenance of existing facilities and certain regulatory
compliance measures. |
|
|
|
Exploration & Production made capital expenditures in
2002 through 2004 primarily for continued development of our
natural gas reserves through the drilling of wells. Planned
expenditures for 2005 are focused on increasing production from
our portfolio of undeveloped reserves and pursuing expansion
opportunities in existing and new basins. |
|
|
|
Midstream made capital expenditures in 2002 through 2004
primarily to acquire, expand, develop and modernize gathering
and processing facilities and terminals. Included in capital
expenditures are the following amounts related to the deepwater
project: 2004 $31 million; 2003
$189 million; and 2002 $343 million.
Planned expenditures for 2005 are focused on attracting new
volumes to our assets and further expanding our systems in
existing basins. |
In September 2004, we received a $67.9 million payment from
WilTel, which included payment in full on the balance of our
short-term note receivable of $54.6 million and a principal
payment on the long-term note receivable in the amount of
$13.3 million. This activity is included in Payments
received on notes receivable from WilTel on the Consolidated
Statement of Cash Flows. In December 2004, we reached an
agreement to sell the remaining balance of the WilTel Note. In
January 2005, the sale closed and we received approximately
$54.6 million.
During the first four months of 2004, we purchased
$471.8 million of restricted investments comprised of
U.S. Treasury notes and received proceeds of
$851.4 million on the scheduled maturity of certain of this
type investment. We made these purchases to satisfy the
105 percent cash collateralization requirement in the
$800 million revolving credit facility. This facility was
terminated on May 3, 2004, after we obtained the
$1 billion secured revolving credit facility, amended to
$1.275 billion in August 2004 (see Note 11 of Notes to
Consolidated Financial Statements). In 2003, we purchased
$739.9 million of restricted investments comprised of
U.S. Treasury notes. We sold $10 million of these
notes and retired $341.8 million on their scheduled
maturity date.
During February 2004, we participated in a recapitalization plan
completed by Longhorn. As a result of this plan, we received
approximately $58 million in repayment of a portion of our
advances to and deferred payments from Longhorn and converted
the remaining advances, including accrued interest, into
preferred equity interests in Longhorn. The $58 million
received is included in Proceeds from dispositions of
investments and other assets.
80
Purchase of investments/advances to affiliates in 2003 consists
primarily of $127 million of additional investment by
Midstream in Discovery. The cash investment was used by
Discovery to pay maturing debt (see Note 3 of Notes to
Consolidated Financial Statements). Purchases in 2002 include
approximately $234 million towards the development of the
Gulfstream joint venture project, one of our equity method
investments.
In 2004, 2003 and 2002, we realized significant cash proceeds
from asset dispositions, the sales of businesses, and the
disposition of investments as part of our overall plan to
increase liquidity and reduce debt. The following sales provided
significant proceeds and include various adjustments subsequent
to the actual date of sale:
|
|
|
|
|
approximately $544 million in net proceeds related to the
sale of our Canadian straddle plants; and |
|
|
|
$305 million related to the sale of Alaska refinery, retail
and pipeline and related assets. |
|
|
|
|
|
$803 million related to the sale of Texas Gas Transmission
Corporation; |
|
|
|
$465 million related to the sale of certain natural gas
exploration and production properties in Kansas, Colorado, New
Mexico and Utah; |
|
|
|
$455 million (net of cash held by Williams Energy Partners)
related to the sale of our general partnership interest and
limited partner investment in Williams Energy Partners; |
|
|
|
$452 million related to the sale of the Midsouth refinery; |
|
|
|
$246 million related to the sale of certain natural gas
liquids assets in Redwater, Alberta; and |
|
|
|
$188 million related to the sale of the Williams travel
centers. |
|
|
|
|
|
$1.15 billion related to the sale of Mid-American and
Seminole Pipeline; |
|
|
|
$464 million related to the sale of Kern River; |
|
|
|
$380 million related to the sale of Central; |
|
|
|
$326 million related to the sale of properties in the Jonah
Field and the Anadarko Basin; |
|
|
|
$229 million related to the sale of the Cove Point LNG
facility; and |
|
|
|
$173 million related to the sale of our interest in
Alliance Pipeline. |
In fourth-quarter 2002, we received $180 million in cash
proceeds from the sale of notes receivable from WilTel to
Leucadia.
Significant items reflected as discontinued operations within
investing activities on the Consolidated Statement of Cash Flows
include capital expenditures of Texas Gas, primarily for
expansion of its interstate natural gas pipeline system, of
$41.9 million in 2002.
|
|
|
Outlook for 2005 and beyond |
We enter 2005 having completed our restructuring plan and are
now in a position to shift to growth through disciplined
investments in natural gas businesses. In 2005, we expect to
continue to reduce debt, although not at the levels experienced
in the last year. As noted previously, we expect to maintain
liquidity from cash and revolving credit facilities of at least
$1 billion. We are maintaining this level as we consider
the potential impact of significant changes in commodity prices,
contract margin requirements above current levels, unplanned
capital spending needs and the need to meet near term scheduled
debt payments.
81
As of December 31, 2004, our two unsecured revolving credit
facilities contained covenants that restricted our ability to
issue new debt, with minimal exceptions, until a certain fixed
charge coverage ratio was achieved. In January 2005, these
facilities were terminated and replaced with two new facilities
from which most of the restrictive covenants, including this
fixed charge ratio, were removed.
As a result of our growth, we estimate capital and investment
expenditures will increase in the future to approximately
$1 billion to $1.2 billion in 2005. Of the estimated
capital expenditures for 2005, approximately $610 million
to $695 million is for maintenance related projects
primarily at Gas Pipeline, including pipeline replacement and
Clean Air Act projects. We expect to fund capital and investment
expenditures, debt payments, and working-capital requirements
through cash and cash equivalents on hand and cash generated
from operations, which is currently estimated to be between
$1.3 billion and $1.6 billion in 2005.
Potential risks associated with our planned levels of liquidity
and the planned capital and investment expenditures discussed
above include.
|
|
|
|
|
Lower than expected levels of cash flow from operations. |
|
|
|
To mitigate this exposure, Exploration & Production has
economically hedged the price of natural gas for approximately
286 MMcfe per day of its expected 2005 production of 600 to
700 MMcfe per day. Power estimates that it has economically
hedged revenues, of varying degrees of certainty, covering
approximately 97 percent of its fixed demand obligations
through 2010. |
|
|
|
|
|
Sensitivity of margin requirements associated with our
marginable commodity contracts. |
|
|
|
As of December 2004, we estimate our exposure to additional
margin requirements over the next 360 days to no more than
$353 million. |
|
|
|
|
|
Exposure associated with our efforts to resolve regulatory and
litigation issues (see Note 15 of Notes to Consolidated
Financial Statements). |
Based on our available cash on hand and expected cash flows from
operations, we believe we have, or have access to, the financial
resources and liquidity necessary to meet future cash
requirements and maintain a sufficient level of liquidity to
reasonably protect against unforeseen circumstances requiring
the use of funds.
82
The table below summarizes the maturity dates of our contractual
obligations by period.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006- | |
|
2008- | |
|
|
|
|
|
|
2005 | |
|
2007 | |
|
2009 | |
|
Thereafter | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Millions) | |
Long-term debt, including current portion:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal
|
|
$ |
247 |
|
|
$ |
515 |
|
|
$ |
769 |
|
|
$ |
6,457 |
|
|
$ |
7,988 |
|
|
Interest
|
|
|
574 |
|
|
|
1,124 |
|
|
|
1,014 |
|
|
|
6,562 |
|
|
|
9,274 |
|
Capital leases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases(1)(5)
|
|
|
194 |
|
|
|
379 |
|
|
|
367 |
|
|
|
1,412 |
|
|
|
2,352 |
|
Purchase obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel conversion and other service contracts(2)(5)
|
|
|
239 |
|
|
|
490 |
|
|
|
501 |
|
|
|
2,844 |
|
|
|
4,074 |
|
|
Other(5)
|
|
|
400 |
|
|
|
446 |
|
|
|
312 |
|
|
|
454 |
(4) |
|
|
1,612 |
|
Other long-term liabilities, including current portion:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Physical & financial derivatives:(3)(5)
|
|
|
564 |
|
|
|
301 |
|
|
|
178 |
|
|
|
189 |
|
|
|
1,232 |
|
|
Other(5)
|
|
|
47 |
|
|
|
80 |
|
|
|
30 |
|
|
|
16 |
|
|
|
173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
2,265 |
|
|
$ |
3,335 |
|
|
$ |
3,171 |
|
|
$ |
17,934 |
|
|
$ |
26,705 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Excludes sublease income of $875 million consisting of
$168 million in 2005, $334 million in 2006-2007,
$250 million in 2008-2009 and $123 million thereafter.
Includes a Power tolling agreement that is now accounted for as
an operating lease as a result of our implementation of EITF
Issue No. 01-8, Determining Whether An Arrangement
Contains a Lease, (EITF 01-8). This agreement was
previously included in fuel conversion and other service
contracts within purchase obligations. See Note 11 of Notes
to Consolidated Financial Statements for additional information. |
|
(2) |
Power has entered into certain contracts giving us the right to
receive fuel conversion services as well as certain other
services associated with electric generation facilities that are
currently in operation throughout the continental United States. |
|
(3) |
Although the amounts presented represent expected cash outflows,
a portion of those obligations have previously been paid in
accordance with third party margining agreements. As of
December 31, 2004, we have paid $72 million in
margins, adequate assurance, and prepays related to the
obligations included in this disclosure. In addition, the
obligations for physical and financial derivatives are based on
market information as of December 31, 2004. Because market
information changes daily and has the potential to be volatile,
significant changes to the values in this category may occur. |
|
(4) |
Includes one year of annual payments totaling $2 million
for contracts with indefinite termination dates. |
|
(5) |
Expected offsetting cash inflows resulting from product sales or
net positive settlements are not reflected in these amounts. The
offsetting expected cash inflows as of December 31, 2004
are $5 billion. |
Effects of inflation
Our operations in recent years have benefited from relatively
low inflation rates. Approximately 49 percent of our gross
property, plant and equipment is at Gas Pipeline and
approximately 51 percent is at other operating units. Gas
Pipeline is subject to regulation, which limits recovery to
historical cost. While amounts in excess of historical cost are
not recoverable under current FERC practices, we anticipate
being allowed to recover and earn a return based on increased
actual cost incurred to replace existing assets. Cost based
regulation, along with competition and other market factors, may
limit our ability to recover such increased costs. For the other
operating units, operating costs are influenced to a greater
extent by specific price changes in oil and natural gas and
related commodities than by changes in general inflation. Crude,
83
refined product, natural gas, natural gas liquids and power
prices are particularly sensitive to OPEC production levels
and/or the market perceptions concerning the supply and demand
balance in the near future.
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 15 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
$72 million, all of which are recorded as liabilities on
our balance sheet at December 31, 2004. We expect to seek
recovery of approximately $23 million of the accrued costs
through future natural gas transmission rates. The remainder of
these costs will be funded from operations. During 2004, we paid
approximately $10 million for cleanup and/or remediation
and monitoring activities. We expect to pay approximately
$14 million in 2005 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, 2004, certain assessment studies were still in
process for which the ultimate outcome may yield significantly
different estimates of most likely costs. Therefore, the actual
costs incurred will depend on the final amount, type and extent
of contamination discovered at these sites, the final cleanup
standards mandated by the EPA or other governmental authorities,
and other factors.
We are subject to the federal Clean Air Act and to the federal
Clean Air Act Amendments of 1990 which require the EPA to issue
new regulations. We are also subject to regulation at the state
and local level. In September 1998, the EPA promulgated rules
designed to mitigate the migration of ground-level ozone in
certain states. In March 2004 and June 2004, the EPA promulgated
additional regulation regarding hazardous air pollutants which
may impose additional controls. Capital expenditures necessary
to install emission control devices on our Transco gas pipeline
system to comply with rules were approximately $62 million
in 2004 and are estimated to be between $110 million and
$125 million over the next three years. This estimate of
remaining expenditures is more than 50 percent lower than
previous estimates due to 2004 expenditures, further analysis of
the requirements, and also more clarification and finalization
of government regulations. The actual costs incurred will depend
on the final implementation plans developed by each state to
comply with these regulations. We consider these costs on our
Transco system associated with compliance with these
environmental laws and regulations to be prudent costs incurred
in the ordinary course of business and, therefore, recoverable
through its rates.
84
|
|
Item 7A. |
Qualitative and Quantitative Disclosures About Market
Risk |
Interest rate risk
Our current interest rate risk exposure is related primarily to
our debt portfolio, which was significantly reduced in 2004 by
early retirements and payments. We reduced our total long-term
debt, including current portion, from approximately
$12 billion at December 31, 2003, to approximately
$8 billion at December 31, 2004 (see Note 11 of
Notes to Consolidated Financial Statements).
The majority of our debt portfolio is comprised of fixed rate
debt in order to mitigate the impact of fluctuations in interest
rates. The maturity of our long-term debt portfolio is partially
influenced by the expected life of our operating assets.
The tables below provide information as of December 31,
2004 and 2003, about our interest rate risk sensitive
instruments. Long-term debt in the tables represents principal
cash flows, net of (discount) premium, and weighted-average
interest rates by expected maturity dates.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
2005 | |
|
2006 | |
|
2007 | |
|
2008 | |
|
2009 | |
|
Thereafter | |
|
Total | |
|
2004 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Dollars in millions) | |
Long-term debt, including current portion:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate
|
|
$ |
235 |
|
|
$ |
104 |
|
|
$ |
381 |
|
|
$ |
153 |
|
|
$ |
41 |
|
|
$ |
6,386 |
|
|
$ |
7,300 |
|
|
$ |
8,167 |
|
|
Interest rate
|
|
|
7.6 |
% |
|
|
7.7 |
% |
|
|
7.7 |
% |
|
|
7.7 |
% |
|
|
7.7 |
% |
|
|
7.7 |
% |
|
|
|
|
|
|
|
|
|
Variable rate
|
|
$ |
15 |
|
|
$ |
15 |
|
|
$ |
15 |
|
|
$ |
563 |
|
|
$ |
12 |
|
|
$ |
42 |
|
|
$ |
662 |
|
|
$ |
675 |
|
|
Interest rate(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
2004 | |
|
2005 | |
|
2006 | |
|
2007 | |
|
2008 | |
|
Thereafter | |
|
Total | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Dollars in millions) | |
Long-term debt, including current portion:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate
|
|
$ |
841 |
|
|
$ |
232 |
|
|
$ |
957 |
|
|
$ |
1,527 |
|
|
$ |
374 |
|
|
$ |
7,362 |
|
|
$ |
11,293 |
|
|
$ |
11,574 |
|
|
Interest rate
|
|
|
7.5 |
% |
|
|
7.5 |
% |
|
|
7.5 |
% |
|
|
7.7 |
% |
|
|
7.8 |
% |
|
|
7.7 |
% |
|
|
|
|
|
|
|
|
|
Variable rate
|
|
$ |
94 |
|
|
$ |
15 |
|
|
$ |
15 |
|
|
$ |
493 |
|
|
$ |
11 |
|
|
$ |
54 |
|
|
$ |
682 |
|
|
$ |
709 |
|
|
Interest rate(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional amount(3)
|
|
$ |
379 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
379 |
|
|
$ |
381 |
|
|
Fixed rate
|
|
|
3.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
The weighted-average interest rate for 2004 is LIBOR plus
2.3 percent. |
|
(2) |
The weighted-average interest rate for 2003 was LIBOR plus
3.75 percent. |
|
(3) |
The marketable equity securities matured in 2004. The
Consolidated Balance Sheet classification was determined based
on the expected term of the underlying collateral requirement. |
Commodity price risk
We are exposed to the impact of market fluctuations in the price
of natural gas, power, crude oil, refined products and natural
gas liquids and additionally to other market factors, such as
market volatility and commodity price correlations, including
correlations between crude oil and gas prices and between
natural gas and power prices. 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. The fair value of derivative
contracts is subject to changes in energy-commodity market
prices, the liquidity and volatility of the markets in which the
contracts are
85
transacted, and changes in interest rates. 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. The value-at-risk model
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.
Beginning in 2004, the value-at-risk model uses a Monte Carlo
method to simulate hypothetical movements in future market
prices. The simulation method uses historical correlations and
market forward prices and volatilities. In applying the
value-at-risk methodology, we do not consider that the simulated
hypothetical movements affect the positions or would cause any
potential liquidity issues. In 2003, the value at risk model
used historical simulations to estimate hypothetical movements
in future market prices, assuming normal market conditions and
historical market prices. In applying both value-at-risk
methodologies, we do not consider that changing the portfolio in
response to market conditions could affect market prices and
could take longer than a one-day holding period to execute.
While a one-day holding period has historically been the
industry standard, a longer holding period could more accurately
represent the true market risk given market liquidity and our
own credit and liquidity constraints.
We segregate our derivative contracts into trading and
non-trading contracts, as defined in the following paragraphs.
We calculate value at risk separately for these two categories.
Derivative contracts designated as normal purchases or sales
under SFAS 133 and non-derivative energy contracts have
been excluded from our estimation of value at risk.
Our trading portfolio consists of derivative contracts entered
into to provide price risk management services to third-party
customers. Only contracts that meet the definition of a
derivative are carried at fair value on the balance sheet. Our
value at risk for contracts held for trading purposes was
$1 million at December 31, 2004 and $5 million at
December 31, 2003. During the year ended December 31,
2004, our value at risk for these contracts ranged from a high
of $3 million to a low of $1 million.
Our non-trading portfolio consists of contracts that hedge or
could potentially hedge the price risk exposure from the
following activities:
|
|
|
Segment |
|
Commodity Price Risk Exposure |
|
|
|
Exploration & Production
|
|
Natural gas sales |
|
Midstream
|
|
Natural gas purchases |
|
Power
|
|
Natural gas purchases |
|
|
Electricity purchases |
|
|
Electricity sales |
The value at risk for contracts held for non-trading purposes
was $29 million and $18 million at December 31,
2004 and 2003, respectively. During the year ended
December 31, 2004, our value at risk for these contracts
ranged from a high of $29 million to a low of
$18 million. Certain of the contracts held for non-trading
purposes were accounted for as cash flow hedges under
SFAS 133. We did not consider the underlying commodity
positions to which the cash flow hedges relate in our
value-at-risk model. Therefore, value at risk does not represent
economic losses that could occur on a total non-trading
portfolio that includes the underlying commodity positions.
Foreign currency risk
We have international investments that could affect our
financial results if the investments incur a permanent decline
in value as a result of changes in foreign currency exchange
rates and the economic conditions in foreign countries.
86
International investments accounted for under the cost method
totaled $52 million and $95 million at
December 31, 2004, and 2003, respectively. These
investments are primarily in non-publicly traded companies for
which it is not practicable to estimate fair value. We believe
that we can realize the carrying value of these investments
considering the status of the operations of the companies
underlying these investments. If a 20 percent change
occurred in the value of the underlying currencies of these
investments against the U.S. dollar, the fair value at
December 31, 2004, could change by approximately
$10 million assuming a direct correlation between the
currency fluctuation and the value of the investments.
The sale of our Canadian straddle plants in July 2004 decreased
our exposure to foreign currency risk. Net assets of
consolidated foreign operations whose functional currency is the
local currency are located primarily in Canada and approximate
six percent of our net assets at December 31, 2004,
compared to 15 percent of our net assets at
December 31, 2003. These foreign operations do not have
significant transactions or financial instruments denominated in
other currencies. However, these investments do have the
potential to impact our financial position, due to fluctuations
in these local currencies arising from the process of
re-measuring 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
could have changed stockholders equity by approximately
$64 million at December 31, 2004.
We historically have not utilized derivatives or other financial
instruments to hedge the risk associated with the movement in
foreign currencies with the exception of a Canadian
dollar-denominated note receivable which was terminated in 2004
(see Note 14 of Notes to Consolidated Financial
Statements). However, we monitor currency fluctuations and could
potentially use derivative financial instruments or employ other
investment alternatives if cash flows or investment returns so
warrant.
87
MANAGEMENTS REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
Williams 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) and for the assessment of the
effectiveness of internal control over financial reporting. Our
internal control system was 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. Therefore, even those systems determined
to be effective can provide only reasonable assurance with
respect to financial statement preparation and presentation.
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.
Our management assessed the effectiveness of Williams
internal control over financial reporting as of
December 31, 2004. In making this assessment, management
used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) in
Internal Control Integrated Framework.
Managements assessment included an evaluation of the
design of our internal control over financial reporting and
testing of the operational effectiveness of our internal control
over financial reporting. Based on our assessment we believe
that, as of December 31, 2004, Williams internal
control over financial reporting is effective based on those
criteria.
Ernst & Young, LLP, our independent registered public
accounting firm has issued an audit report on our assessment of
the companys internal control over financial reporting. A
copy of this report is included in this Annual Report on
Form 10-K.
88
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors and Stockholders of
The Williams Companies, Inc.
We have audited managements assessment, included in the
accompanying Managements Report on Internal Control Over
Financial Reporting, that The Williams Companies, Inc.
maintained effective internal control over financial reporting
as of December 31, 2004, 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. Our responsibility
is to express an opinion on managements assessment and an
opinion on the effectiveness of the Companys internal
control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, evaluating
managements assessment, testing and evaluating the design
and operating effectiveness of internal control, and performing
such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, managements assessment that The Williams
Companies, Inc. maintained effective internal control over
financial reporting as of December 31, 2004, is fairly
stated, in all material respects, based on the COSO criteria.
Also, in our opinion, The Williams Companies, Inc. maintained,
in all material respects, effective internal control over
financial reporting as of December 31, 2004, 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, 2004 and 2003, and the related consolidated
statements of operations, stockholders equity, and cash
flows for each of the three years in the period ended
December 31, 2004 of The Williams Companies, Inc. and our
report dated March 8, 2005 expressed an unqualified opinion
thereon.
Tulsa, Oklahoma
March 8, 2005
89
|
|
Item 8. |
Financial Statements and Supplementary Data |
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, 2004 and
2003, and the related consolidated statements of operations,
stockholders equity, and cash flows for each of the three
years in the period ended December 31, 2004. 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 Companys
management. Our responsibility is to express an opinion on these
financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the
consolidated financial position of The Williams Companies, Inc.
at December 31, 2004 and 2003, and the consolidated results
of its operations and its cash flows for each of the three years
in the period ended December 31, 2004, 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 explained in Note 1 and Note 9 to the consolidated
financial statements, effective January 1, 2003, the
Company adopted Emerging Issues Task Force Issue No. 02-3,
Issues Related to Accounting for Contracts Involved in
Energy Trading and Risk Management Activities (see
third paragraph of Energy commodity risk management and
trading activities and revenues section in
Note 1) and Statement of Financial Accounting Standards
No. 143, Accounting for Asset Retirement
Obligations (see the penultimate paragraph of
Note 9).
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of The Williams Companies, Inc.s internal
control over financial reporting as of December 31, 2004,
based on criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated
March 8, 2005 expressed an unqualified opinion thereon.
Tulsa, Oklahoma
March 8, 2005
90
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions, except per-share amounts) | |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$ |
9,272.4 |
|
|
$ |
13,195.5 |
|
|
$ |
56.2 |
|
|
Gas Pipeline
|
|
|
1,362.3 |
|
|
|
1,368.3 |
|
|
|
1,301.2 |
|
|
Exploration & Production
|
|
|
777.6 |
|
|
|
779.7 |
|
|
|
860.4 |
|
|
Midstream Gas & Liquids
|
|
|
2,882.6 |
|
|
|
2,784.8 |
|
|
|
1,183.7 |
|
|
Other
|
|
|
32.8 |
|
|
|
72.0 |
|
|
|
124.1 |
|
|
Intercompany eliminations
|
|
|
(1,866.4 |
) |
|
|
(1,549.3 |
) |
|
|
(91.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
12,461.3 |
|
|
|
16,651.0 |
|
|
|
3,434.5 |
|
|
|
|
|
|
|
|
|
|
|
Segment costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and operating expenses
|
|
|
10,751.7 |
|
|
|
15,004.3 |
|
|
|
1,987.7 |
|
|
Selling, general and administrative expenses
|
|
|
355.5 |
|
|
|
421.3 |
|
|
|
575.6 |
|
|
Other (income) expense net
|
|
|
(51.6 |
) |
|
|
(21.3 |
) |
|
|
240.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment costs and expenses
|
|
|
11,055.6 |
|
|
|
15,404.3 |
|
|
|
2,803.7 |
|
|
|
|
|
|
|
|
|
|
|
General corporate expenses
|
|
|
119.8 |
|
|
|
87.0 |
|
|
|
142.8 |
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
|
86.5 |
|
|
|
145.3 |
|
|
|
(471.7 |
) |
|
Gas Pipeline
|
|
|
557.6 |
|
|
|
539.6 |
|
|
|
461.3 |
|
|
Exploration & Production
|
|
|
223.9 |
|
|
|
392.5 |
|
|
|
504.9 |
|
|
Midstream Gas & Liquids
|
|
|
552.2 |
|
|
|
178.0 |
|
|
|
153.2 |
|
|
Other
|
|
|
(14.5 |
) |
|
|
(8.7 |
) |
|
|
(16.9 |
) |
|
General corporate expenses
|
|
|
(119.8 |
) |
|
|
(87.0 |
) |
|
|
(142.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total operating income
|
|
|
1,285.9 |
|
|
|
1,159.7 |
|
|
|
488.0 |
|
|
|
|
|
|
|
|
|
|
|
Interest accrued
|
|
|
(834.4 |
) |
|
|
(1,293.5 |
) |
|
|
(1,169.2 |
) |
Interest capitalized
|
|
|
6.7 |
|
|
|
45.5 |
|
|
|
27.3 |
|
Interest rate swap loss
|
|
|
(5.0 |
) |
|
|
(2.2 |
) |
|
|
(124.2 |
) |
Investing income (loss)
|
|
|
48.0 |
|
|
|
73.2 |
|
|
|
(113.1 |
) |
Early debt retirement costs
|
|
|
(282.1 |
) |
|
|
(66.8 |
) |
|
|
|
|
Minority interest in income and preferred returns of
consolidated subsidiaries
|
|
|
(21.4 |
) |
|
|
(19.4 |
) |
|
|
(41.8 |
) |
Other income net
|
|
|
26.8 |
|
|
|
40.7 |
|
|
|
24.3 |
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes and
cumulative effect of change in accounting principles
|
|
|
224.5 |
|
|
|
(62.8 |
) |
|
|
(908.7 |
) |
Provision (benefit) for income taxes
|
|
|
131.3 |
|
|
|
(5.3 |
) |
|
|
(290.3 |
) |
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
93.2 |
|
|
|
(57.5 |
) |
|
|
(618.4 |
) |
Income (loss) from discontinued operations
|
|
|
70.5 |
|
|
|
326.6 |
|
|
|
(136.3 |
) |
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principles
|
|
|
163.7 |
|
|
|
269.1 |
|
|
|
(754.7 |
) |
Cumulative effect of change in accounting principles
|
|
|
|
|
|
|
(761.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
163.7 |
|
|
|
(492.2 |
) |
|
|
(754.7 |
) |
Preferred stock dividends
|
|
|
|
|
|
|
29.5 |
|
|
|
90.1 |
|
|
|
|
|
|
|
|
|
|
|
Income (loss) applicable to common stock
|
|
$ |
163.7 |
|
|
$ |
(521.7 |
) |
|
$ |
(844.8 |
) |
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
$ |
.18 |
|
|
$ |
(.17 |
) |
|
$ |
(1.37 |
) |
|
Income (loss) from discontinued operations
|
|
|
.13 |
|
|
|
.63 |
|
|
|
(.26 |
) |
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principles
|
|
|
.31 |
|
|
|
.46 |
|
|
|
(1.63 |
) |
|
Cumulative effect of change in accounting principles
|
|
|
|
|
|
|
(1.47 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
.31 |
|
|
$ |
(1.01 |
) |
|
$ |
(1.63 |
) |
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
$ |
.18 |
|
|
$ |
(.17 |
) |
|
$ |
(1.37 |
) |
|
Income (loss) from discontinued operations
|
|
|
.13 |
|
|
|
.63 |
|
|
|
(.26 |
) |
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before cumulative effect of change in accounting
principles
|
|
|
.31 |
|
|
|
.46 |
|
|
|
(1.63 |
) |
|
Cumulative effect of change in accounting principles
|
|
|
|
|
|
|
(1.47 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$ |
.31 |
|
|
$ |
(1.01 |
) |
|
$ |
(1.63 |
) |
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
91
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED BALANCE SHEET
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
(Dollars in millions, | |
|
|
except per-share | |
|
|
amounts) | |
ASSETS |
Current assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
930.0 |
|
|
$ |
2,315.7 |
|
|
Restricted cash
|
|
|
77.4 |
|
|
|
47.1 |
|
|
Restricted investments
|
|
|
|
|
|
|
93.2 |
|
|
Accounts and notes receivable less allowance of $98.8 ($112.2 in
2003)
|
|
|
1,422.8 |
|
|
|
1,613.2 |
|
|
Inventories
|
|
|
261.1 |
|
|
|
242.9 |
|
|
Derivative assets
|
|
|
2,961.0 |
|
|
|
3,166.8 |
|
|
Margin deposits
|
|
|
131.7 |
|
|
|
553.9 |
|
|
Assets of discontinued operations
|
|
|
13.6 |
|
|
|
381.2 |
|
|
Deferred income taxes
|
|
|
89.0 |
|
|
|
106.6 |
|
|
Other current assets and deferred charges
|
|
|
157.0 |
|
|
|
274.4 |
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
6,043.6 |
|
|
|
8,795.0 |
|
Restricted cash
|
|
|
35.3 |
|
|
|
159.8 |
|
Restricted investments
|
|
|
|
|
|
|
288.1 |
|
Investments
|
|
|
1,316.2 |
|
|
|
1,463.6 |
|
Property, plant and equipment net
|
|
|
11,886.8 |
|
|
|
11,734.0 |
|
Derivative assets
|
|
|
3,025.3 |
|
|
|
2,495.6 |
|
Goodwill
|
|
|
1,014.5 |
|
|
|
1,014.5 |
|
Assets of discontinued operations
|
|
|
|
|
|
|
345.1 |
|
Other assets and deferred charges
|
|
|
671.3 |
|
|
|
726.1 |
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
23,993.0 |
|
|
$ |
27,021.8 |
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
Current liabilities:
|
|
|
|
|
|
|
|
|
|
Notes payable
|
|
$ |
|
|
|
$ |
3.3 |
|
|
Accounts payable
|
|
|
1,043.2 |
|
|
|
1,186.8 |
|
|
Accrued liabilities
|
|
|
991.7 |
|
|
|
987.9 |
|
|
Liabilities of discontinued operations
|
|
|
1.6 |
|
|
|
93.4 |
|
|
Derivative liabilities
|
|
|
2,859.3 |
|
|
|
3,064.2 |
|
|
Long-term debt due within one year
|
|
|
250.1 |
|
|
|
935.2 |
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
5,145.9 |
|
|
|
6,270.8 |
|
Long-term debt
|
|
|
7,711.9 |
|
|
|
11,039.8 |
|
Deferred income taxes
|
|
|
2,470.1 |
|
|
|
2,453.4 |
|
Derivative liabilities
|
|
|
2,735.7 |
|
|
|
2,124.1 |
|
Other liabilities and deferred income
|
|
|
873.8 |
|
|
|
947.5 |
|
Contingent liabilities and commitments (Note 15)
|
|
|
|
|
|
|
|
|
Minority interests in consolidated subsidiaries
|
|
|
99.7 |
|
|
|
84.1 |
|
Stockholders equity:
|
|
|
|
|
|
|
|
|
|
Common stock, $1 per share par value, 960 million
shares authorized, 561.2 million issued in 2004,
521.4 million issued in 2003
|
|
|
561.2 |
|
|
|
521.4 |
|
|
Capital in excess of par value
|
|
|
6,005.9 |
|
|
|
5,195.1 |
|
|
Accumulated deficit
|
|
|
(1,306.5 |
) |
|
|
(1,426.8 |
) |
|
Accumulated other comprehensive loss
|
|
|
(244.2 |
) |
|
|
(121.0 |
) |
|
Other
|
|
|
(21.9 |
) |
|
|
(28.0 |
) |
|
|
|
|
|
|
|
|
|
|
4,994.5 |
|
|
|
4,140.7 |
|
|
Less treasury stock (at cost), 3.2 million shares of common
stock in 2004 and 2003
|
|
|
(38.6 |
) |
|
|
(38.6 |
) |
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
4,955.9 |
|
|
|
4,102.1 |
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$ |
23,993.0 |
|
|
$ |
27,021.8 |
|
|
|
|
|
|
|
|
See accompanying notes.
92
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated | |
|
|
|
|
|
|
|
|
|
|
|
|
Capital in | |
|
|
|
Other | |
|
|
|
|
|
|
|
|
|
|
|
|
Excess of | |
|
Retained | |
|
Comprehensive | |
|
|
|
|
|
|
|
|
Preferred | |
|
Common | |
|
Par | |
|
Earnings | |
|
Income | |
|
|
|
Treasury | |
|
|
|
|
Stock | |
|
Stock | |
|
Value | |
|
(Deficit) | |
|
(Loss) | |
|
Other | |
|
Stock | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Dollars in millions) | |
Balance, December 31, 2001
|
|
$ |
|
|
|
$ |
518.9 |
|
|
$ |
5,085.1 |
|
|
$ |
199.6 |
|
|
$ |
345.1 |
|
|
$ |
(65.0 |
) |
|
$ |
(39.7 |
) |
|
$ |
6,044.0 |
|
Comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss 2002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(754.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(754.7 |
) |
Other comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses on cash flow hedges, net of
reclassification adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(298.9 |
) |
|
|
|
|
|
|
|
|
|
|
(298.9 |
) |
|
|
Net unrealized appreciation on marketable equity securities, net
of reclassification adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.6 |
|
|
|
|
|
|
|
|
|
|
|
4.6 |
|
|
|
Foreign currency translation adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(.1 |
) |
|
|
|
|
|
|
|
|
|
|
(.1 |
) |
|
|
Minimum pension liability adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16.9 |
) |
|
|
|
|
|
|
|
|
|
|
(16.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(311.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,066.0 |
) |
Issuance of 9.875 percent cumulative convertible preferred
stock (1.5 million shares)
|
|
|
271.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
271.3 |
|
Cash dividends Common stock ($.42 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(216.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(216.8 |
) |
|
|
|
Preferred stock ($14.14 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20.8 |
) |
Issuance of equity of consolidated limited partnership
|
|
|
|
|
|
|
|
|
|
|
44.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44.6 |
|
Beneficial conversion option on issuance of convertible
preferred stock (Note 13)
|
|
|
|
|
|
|
|
|
|
|
69.4 |
|
|
|
(69.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FELINE PACS equity contract adjustment (Note 13)
|
|
|
|
|
|
|
|
|
|
|
(76.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(76.7 |
) |
Allowance for and repayments of stockholders notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.8 |
|
|
|
(1.3 |
) |
|
|
6.5 |
|
Stock award transactions, including tax benefit
(1.2 million common shares)
|
|
|
|
|
|
|
1.0 |
|
|
|
33.1 |
|
|
|
|
|
|
|
|
|
|
|
.4 |
|
|
|
2.4 |
|
|
|
36.9 |
|
ESOP loan repayment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26.5 |
|
|
|
|
|
|
|
26.5 |
|
Other
|
|
|
|
|
|
|
|
|
|
|
21.7 |
|
|
|
(22.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2002
|
|
|
271.3 |
|
|
|
519.9 |
|
|
|
5,177.2 |
|
|
|
(884.3 |
) |
|
|
33.8 |
|
|
|
(30.3 |
) |
|
|
(38.6 |
) |
|
|
5,049.0 |
|
Comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss 2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(492.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(492.2 |
) |
Other comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses on cash flow hedges, net of
reclassification adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(236.9 |
) |
|
|
|
|
|
|
|
|
|
|
(236.9 |
) |
|
|
Net unrealized depreciation on marketable equity securities, net
of reclassification adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7.4 |
) |
|
|
|
|
|
|
|
|
|
|
(7.4 |
) |
|
|
Foreign currency translation adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
77.0 |
|
|
|
|
|
|
|
|
|
|
|
77.0 |
|
|
|
Minimum pension liability adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12.5 |
|
|
|
|
|
|
|
|
|
|
|
12.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(154.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(647.0 |
) |
Redemption of 9.875 percent cumulative convertible
preferred stock (1.5 million shares)
|
|
|
(271.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(271.3 |
) |
Cash dividends Common stock ($.04 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20.8 |
) |
|
|
|
Preferred stock ($20.14 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29.5 |
) |
Repayments of stockholders notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.3 |
|
|
|
|
|
|
|
2.3 |
|
Stock award transactions, including tax benefit
(1.5 million common shares)
|
|
|
|
|
|
|
1.5 |
|
|
|
17.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2003
|
|
|
|
|
|
|
521.4 |
|
|
|
5,195.1 |
|
|
|
(1,426.8 |
) |
|
|
(121.0 |
) |
|
|
(28.0 |
) |
|
|
(38.6 |
) |
|
|
4,102.1 |
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
163.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
163.7 |
|
Other comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net unrealized losses on cash flow hedges, net of
reclassification adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(142.7 |
) |
|
|
|
|
|
|
|
|
|
|
(142.7 |
) |
|
|
Net unrealized appreciation on marketable equity securities, net
of reclassification adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.9 |
|
|
|
|
|
|
|
|
|
|
|
1.9 |
|
|
|
Foreign currency translation adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15.8 |
|
|
|
|
|
|
|
|
|
|
|
15.8 |
|
|
|
Minimum pension liability adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.8 |
|
|
|
|
|
|
|
|
|
|
|
1.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(123.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40.5 |
|
Issuance of common stock (33.1 million shares) and
settlement of forward contracts as a result of FELINE PACS
exchange (Note 11)
|
|
|
|
|
|
|
33.1 |
|
|
|
782.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
816.0 |
|
Cash dividends Common stock ($.08 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(43.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(43.4 |
) |
Allowance for and repayment of stockholders notes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.1 |
|
|
|
|
|
|
|
6.1 |
|
Stock award transactions, including tax benefit
(6.7 million common shares)
|
|
|
|
|
|
|
6.7 |
|
|
|
27.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2004
|
|
$ |
|
|
|
$ |
561.2 |
|
|
$ |
6,005.9 |
|
|
$ |
(1,306.5 |
) |
|
$ |
(244.2 |
) |
|
$ |
(21.9 |
) |
|
$ |
(38.6 |
) |
|
$ |
4,955.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
93
THE WILLIAMS COMPANIES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
$ |
93.2 |
|
|
$ |
(57.5 |
) |
|
$ |
(618.4 |
) |
|
Adjustments to reconcile to cash provided (used) by
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
668.5 |
|
|
|
657.4 |
|
|
|
648.8 |
|
|
|
Provision (benefit) for deferred income taxes
|
|
|
123.0 |
|
|
|
12.3 |
|
|
|
(212.5 |
) |
|
|
Payments of guarantees and payment obligations related to WilTel
|
|
|
|
|
|
|
|
|
|
|
(753.9 |
) |
|
|
Provision for loss on investments, property and other assets
|
|
|
86.7 |
|
|
|
231.9 |
|
|
|
399.1 |
|
|
|
Net gain on dispositions of assets
|
|
|
(18.1 |
) |
|
|
(142.8 |
) |
|
|
(190.4 |
) |
|
|
Early debt retirement costs
|
|
|
282.1 |
|
|
|
66.8 |
|
|
|
|
|
|
|
Provision for uncollectible accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WilTel
|
|
|
|
|
|
|
|
|
|
|
268.7 |
|
|
|
|
Other
|
|
|
(.8 |
) |
|
|
7.3 |
|
|
|
9.7 |
|
|
|
Minority interest in income and preferred returns of
consolidated subsidiaries
|
|
|
21.4 |
|
|
|
19.4 |
|
|
|
41.8 |
|
|
|
Amortization of stock-based awards
|
|
|
9.5 |
|
|
|
27.1 |
|
|
|
31.2 |
|
|
|
Payment of deferred set-up fee and fixed rate interest on RMT
note payable
|
|
|
|
|
|
|
(265.0 |
) |
|
|
|
|
|
|
Accrual for fixed rate interest included in RMT note payable
|
|
|
|
|
|
|
99.3 |
|
|
|
32.2 |
|
|
|
Amortization of deferred set-up fee and fixed rate interest on
RMT note payable
|
|
|
|
|
|
|
154.5 |
|
|
|
110.9 |
|
|
|
Cash provided (used) by changes in current assets and
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted cash
|
|
|
(14.1 |
) |
|
|
(1.4 |
) |
|
|
(4.0 |
) |
|
|
|
Accounts and notes receivable
|
|
|
234.6 |
|
|
|
668.7 |
|
|
|
243.7 |
|
|
|
|
Inventories
|
|
|
(18.3 |
) |
|
|
88.6 |
|
|
|
85.6 |
|
|
|
|
Margin deposits
|
|
|
422.2 |
|
|
|
252.2 |
|
|
|
(633.4 |
) |
|
|
|
Other current assets and deferred charges
|
|
|
112.8 |
|
|
|
10.3 |
|
|
|
(264.1 |
) |
|
|
|
Accounts payable
|
|
|
(118.5 |
) |
|
|
(630.2 |
) |
|
|
(547.2 |
) |
|
|
|
Accrued liabilities
|
|
|
(227.0 |
) |
|
|
(363.6 |
) |
|
|
(285.7 |
) |
|
Changes in current and noncurrent derivative and energy risk
management and trading assets and liabilities
|
|
|
(160.4 |
) |
|
|
(350.0 |
) |
|
|
579.5 |
|
|
Changes in noncurrent restricted cash
|
|
|
86.5 |
|
|
|
17.6 |
|
|
|
(104.1 |
) |
|
Other, including changes in noncurrent assets and liabilities
|
|
|
(111.2 |
) |
|
|
84.8 |
|
|
|
65.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by operating activities of
continuing operations
|
|
|
1,472.1 |
|
|
|
587.7 |
|
|
|
(1,096.9 |
) |
|
|
|
Net cash provided by operating activities of discontinued
operations
|
|
|
15.8 |
|
|
|
182.4 |
|
|
|
581.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by operating activities
|
|
|
1,487.9 |
|
|
|
770.1 |
|
|
|
(515.3 |
) |
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from notes payable
|
|
|
|
|
|
|
|
|
|
|
913.4 |
|
|
Payments of notes payable
|
|
|
(3.3 |
) |
|
|
(960.8 |
) |
|
|
(2,051.7 |
) |
|
Proceeds from long-term debt
|
|
|
75.0 |
|
|
|
2,006.5 |
|
|
|
3,481.5 |
|
|
Payments of long-term debt
|
|
|
(3,263.2 |
) |
|
|
(2,187.1 |
) |
|
|
(2,536.2 |
) |
|
Proceeds from issuance of common stock
|
|
|
20.6 |
|
|
|
1.2 |
|
|
|
5.2 |
|
|
Dividends paid
|
|
|
(43.4 |
) |
|
|
(53.3 |
) |
|
|
(230.8 |
) |
|
Proceeds from issuance of preferred stock
|
|
|
|
|
|
|
|
|
|
|
271.3 |
|
|
Repurchase of preferred stock
|
|
|
|
|
|
|
(275.0 |
) |
|
|
(135.0 |
) |
|
Payments for debt issuance costs
|
|
|
(26.0 |
) |
|
|
(78.6 |
) |
|
|
(186.3 |
) |
|
Premiums paid on early debt retirements and FELINE PACS exchange
|
|
|
(246.9 |
) |
|
|
(57.7 |
) |
|
|
|
|
|
Payments/dividends to minority and preferred interests
|
|
|
(5.9 |
) |
|
|
(19.8 |
) |
|
|
(48.0 |
) |
|
Changes in restricted cash
|
|
|
21.7 |
|
|
|
67.9 |
|
|
|
(182.1 |
) |
|
Changes in cash overdrafts
|
|
|
(21.4 |
) |
|
|
(29.7 |
) |
|
|
28.4 |
|
|
Other net
|
|
|
(11.5 |
) |
|
|
(2.8 |
) |
|
|
(8.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by financing activities of continuing operations
|
|
|
(3,504.3 |
) |
|
|
(1,589.2 |
) |
|
|
(678.7 |
) |
|
|
|
Net cash provided (used) by financing activities of
discontinued operations
|
|
|
(1.2 |
) |
|
|
(94.8 |
) |
|
|
524.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by financing activities
|
|
|
(3,505.5 |
) |
|
|
(1,684.0 |
) |
|
|
(154.0 |
) |
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(787.4 |
) |
|
|
(956.0 |
) |
|
|
(1,662.0 |
) |
|
|
Proceeds from dispositions
|
|
|
12.0 |
|
|
|
603.9 |
|
|
|
549.1 |
|
|
Purchases of investments/advances to affiliates
|
|
|
(2.1 |
) |
|
|
(150.4 |
) |
|
|
(308.7 |
) |
|
Purchases of restricted investments
|
|
|
(471.8 |
) |
|
|
(739.9 |
) |
|
|
|
|
|
Proceeds from sales of businesses
|
|
|
877.8 |
|
|
|
2,250.5 |
|
|
|
2,300.4 |
|
|
Proceeds from sale of restricted investments
|
|
|
851.4 |
|
|
|
351.8 |
|
|
|
|
|
|
Proceeds from dispositions of investments and other assets
|
|
|
94.1 |
|
|
|
128.6 |
|
|
|
273.0 |
|
|
Proceeds received on advances to affiliates
|
|
|
|
|
|
|
|
|
|
|
75.0 |
|
|
Proceeds received on sale of receivables from WilTel
|
|
|
|
|
|
|
|
|
|
|
180.0 |
|
|
Payments received on notes receivable from WilTel
|
|
|
69.1 |
|
|
|
16.0 |
|
|
|
34.5 |
|
|
Other net
|
|
|
(12.9 |
) |
|
|
15.5 |
|
|
|
(37.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by investing activities of continuing
operations
|
|
|
630.2 |
|
|
|
1,520.0 |
|
|
|
1,403.6 |
|
|
|
|
Net cash used by investing activities of discontinued operations
|
|
|
(.8 |
) |
|
|
(23.9 |
) |
|
|
(299.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by investing activities
|
|
|
629.4 |
|
|
|
1,496.1 |
|
|
|
1,104.2 |
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents
|
|
|
(1,388.2 |
) |
|
|
582.2 |
|
|
|
434.9 |
|
Cash and cash equivalents at beginning of year
|
|
|
2,318.2 |
|
|
|
1,736.0 |
|
|
|
1,301.1 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year*
|
|
$ |
930.0 |
|
|
$ |
2,318.2 |
|
|
$ |
1,736.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
Includes cash and cash equivalents of discontinued operations of
$2.5 million and $85.6 million for 2003 and 2002,
respectively. |
See accompanying notes.
94
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
Note 1. |
Description of business, basis of presentation and summary of
significant accounting policies |
Operations of our company are located principally in the United
States and are organized into the following reporting segments:
Gas Pipeline, Exploration & Production, Midstream
Gas & Liquids, and Power.
Gas Pipeline is comprised primarily of two interstate natural
gas pipelines as well as investments in natural gas
pipeline-related companies. The Gas Pipeline operating segments
have been aggregated for reporting purposes and include
Northwest Pipeline, which extends from the San Juan Basin
in northwestern New Mexico and southwestern Colorado to Oregon
and Washington, and Transcontinental Gas Pipe Line (Transco),
which extends from the Gulf of Mexico region to the northeastern
United States.
Exploration & Production includes natural gas
development, production and gas management activities primarily
in the Rocky Mountain and Mid-Continent regions of the United
States and in Argentina.
Midstream Gas & Liquids (Midstream) is comprised of
natural gas gathering and processing and treating facilities in
the Rocky Mountain and Gulf Coast regions of the United States,
oil gathering and transportation facilities in the Gulf Coast
region of the United States, majority-owned natural gas
compression and transportation facilities in Venezuela, and
assets in Canada including a natural gas liquids extraction
facility and a fractionation plant.
Power is an energy services provider that buys, sells, stores,
and transports energy and energy-related commodities, primarily
power and natural gas, on a wholesale level. Prior to September
2004, Power continued to focus on 1) terminating or selling
all or portions of its portfolio, 2) maximizing cash flow,
3) reducing risk, and 4) managing existing contractual
commitments. These efforts were consistent with our 2002
decision to sell all or portions of Powers portfolio. In
September 2004, we announced our decision to continue operating
the Power business and cease efforts to exit that business. As a
result, subsequent to that date, Power has focused on its
objectives of minimizing financial risk, maximizing cash flow,
meeting contractual commitments and providing functions that
support our natural gas businesses. In addition, Power began
executing new contracts to hedge its portfolio.
In February 2003, we outlined our planned business strategy in
response to the events that significantly impacted the energy
sector and our company during late 2001 and 2002. The plan
focused upon migrating to an integrated natural gas business
comprised of a strong, but smaller, portfolio of natural gas
businesses, reducing debt and increasing our liquidity through
asset sales, strategic levels of financing and reductions in
operating costs. The plan provided us with a clear strategy to
address near-term and medium-term debt and liquidity issues, to
de-leverage the company with the objective of returning to
investment grade status and to develop a balance sheet capable
of supporting and ultimately growing our remaining businesses. A
component of our plan was to reduce the risk and liquidity
requirements of the Power segment while realizing the value of
Powers portfolio.
In 2004, we continued to execute certain components of the plan
and substantially completed our plan as outlined in February
2003. Our results for 2004 include the following.
|
|
|
|
|
Completion of planned asset sales, which resulted in proceeds of
approximately $877.8 million. |
|
|
|
Replacement of our cash-collateralized letter of credit and
revolver facility with facilities that do not encumber cash. |
|
|
|
Significant debt reduction of approximately $4 billion of
debt through scheduled maturities and early redemptions,
including an exchange offer for our FELINE PACS units. |
95
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
Reduction of risk and liquidity requirements of the Power
segment. |
|
|
|
Reduction of approximately $33 million in our combined
selling, general and administrative (SG&A) and general
corporate expenses. |
|
|
|
On June 1, 2004, we announced an agreement with IBM to aid
us in transforming and managing certain areas of our accounting,
finance and human resources processes. Under the agreement, IBM
will also manage key aspects of our information technology,
including enterprise wide infrastructure and application
development. The
71/2
year agreement began July 1, 2004 and is expected to reduce
costs in these areas while maintaining a high quality of service. |
As a result of the accomplishments noted above, we enter 2005
with improved financial condition and liquidity. To manage our
operations and meet unforeseen or extraordinary calls on cash,
we expect to maintain liquidity from cash and revolving credit
facilities of at least $1 billion.
In September 2004, our Board of Directors approved the decision
to retain Power and end our efforts to exit that business.
Several factors affected our decision to retain the business,
including:
|
|
|
|
|
the cash flow expected to be generated by the business (Power
has contracts in place expected to generate cash in amounts that
substantially cover its obligations through 2010); |
|
|
|
the negative effect of depressed wholesale power markets on the
marketability of the Power segment; and |
|
|
|
our progress over the last two years in reducing the risk of and
increasing the certainty of cash flows from long-term power
contracts. |
Our strategy is to continue managing this business to minimize
financial risk, maximize cash flow and meet contractual
commitments. In the fourth quarter of 2004, we elected to begin
applying hedge accounting to qualifying derivative contracts,
which is expected to reduce Powers mark-to-market earnings
volatility.
Having successfully completed the key components of our February
2003 plan to strengthen our finances, we are now in a position
to shift from restructuring to disciplined growth.
Our plan for 2005 includes the following objectives:
|
|
|
|
|
increase focus and disciplined EVA®-based investments in
natural gas businesses; |
|
|
|
continue to steadily improve credit ratios and ratings with the
goal of achieving investment grade ratios; |
|
|
|
continue to reduce risk and liquidity requirements while
maximizing cash flow in the Power segment; |
|
|
|
maintain liquidity from cash and revolving credit facilities of
at least $1 billion; and |
|
|
|
generate sustainable growth in EVA® and shareholder value. |
Results for 2003 include approximately $117 million of
revenue related to the correction of the accounting treatment
previously applied to certain third party derivative contracts
during 2002 and 2001. This matter was initially disclosed in our
Form 10-Q for the second quarter of 2003. Loss from
continuing operations before income taxes and cumulative effect
of change in accounting principles in 2003 was
$62.8 million. Absent the corrections, we would have
reported a pretax loss from continuing operations in 2003.
Approximately $83 million of this revenue relates to a
correction of net energy trading assets for certain derivative
contract terminations occurring in 2001. The remaining
$34 million relates to net gains on certain other
derivative contracts entered into in 2002 and 2001 that we now
believe should not have been deferred as a component of other
comprehensive income due to the incorrect designation of these
contracts as cash flow
96
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
hedges. Our management, after consultation with our independent
auditor, concluded that the effect of the previous accounting
treatment was not material to 2003 and prior periods and the
trend of earnings.
In accordance with the provisions related to discontinued
operations within SFAS No. 144, Accounting for
the Impairment or Disposal of Long-Lived Assets, the
accompanying consolidated financial statements and notes reflect
the results of operations, financial position and cash flows of
the following components as discontinued operations (see
Note 2):
|
|
|
|
|
Kern River Gas Transmission (Kern River), previously one of Gas
Pipelines segments; |
|
|
|
two natural gas liquids pipeline systems, Mid-American Pipeline
and Seminole Pipeline, previously part of the Midstream segment; |
|
|
|
Central natural gas pipeline, previously one of Gas
Pipelines segments; |
|
|
|
retail travel centers concentrated in the Midsouth, part of the
previously reported Petroleum Services segment; |
|
|
|
refining and marketing operations in the Midsouth, including the
Midsouth refinery, part of the previously reported Petroleum
Services segment; |
|
|
|
Texas Gas Transmission Corporation, previously one of Gas
Pipelines segments; |
|
|
|
natural gas properties in the Hugoton and Raton basins,
previously part of the Exploration & Production segment; |
|
|
|
bio-energy operations, part of the previously reported Petroleum
Services segment; |
|
|
|
general partnership interest and limited partner investment in
Williams Energy Partners, previously the Williams Energy
Partners segment; |
|
|
|
the Colorado soda ash mining operations, part of the previously
reported International segment; |
|
|
|
certain gas processing, natural gas liquids fractionation,
storage and distribution operations in western Canada and at a
plant in Redwater, Alberta, previously part of the Midstream
segment; |
|
|
|
refining, retail and pipeline operations in Alaska, part of the
previously reported Petroleum Services segment; and |
|
|
|
straddle plants in western Canada, previously part of the
Midstream segment. |
During fourth-quarter 2004, we reclassified the operations of
Gulf Liquids to continuing operations within our Midstream
segment in accordance with EITF Issue No. 03-13,
Applying the Conditions in Paragraph 42 of FASB
Statement No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, in Determining Whether to Report
Discontinued Operations, (EITF 03-13), which was
issued in the fourth quarter. Under the provisions of
EITF 03-13, Gulf Liquids activities no longer qualify for
reporting as discontinued operations, based on managements
expectation that we will continue to have significant commercial
activity with the disposed entity. The operations of Gulf
Liquids were reclassified to continuing operations within our
Midstream segment. All periods presented reflect this
reclassification.
At December 31, 2004, the operations of Gulf Liquids are
classified as held for sale and are included in Other current
assets and Accrued liabilities on the balance sheet. Assets held
for sale are $57 million at December 31, 2004 and
$60.1 million at December 31, 2003. Liabilities held
for sale are $2.2 million at December 31, 2004 and
$2.3 million at December 31, 2003. Included in assets
held for sale are property, plant and equipment net
of $55.3 million at December 31, 2004 and
$57.8 million at December 31, 2003. We are
97
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
currently negotiating purchase and sale agreements related to
the sale of these assets. We expect the sale of the operations
to close by the end of the second quarter of 2005.
Management and decision-making control of certain activities
have been transferred between segments (see Note 18).
Consequently, the results of operations have been similarly
reclassified. All periods presented reflect these
classifications.
Unless indicated otherwise, the information in the Notes to the
Consolidated Financial Statements relates to our continuing
operations.
We have restated all segment information in the Notes to the
Consolidated Financial Statements for all prior periods
presented to reflect discontinued operations noted above.
Certain other amounts have been reclassified to conform to the
current classifications.
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Summary of significant accounting policies |
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Principles of consolidation |
The consolidated financial statements include the accounts of
our corporate parent and our majority-owned subsidiaries and
investments. We account for companies in which we and our
subsidiaries own 20 percent to 50 percent of the
voting common stock, or otherwise exercise significant influence
over operating and financial policies of the company, under the
equity method.
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States
requires management to make estimates and assumptions that
affect the amounts reported in the consolidated financial
statements and accompanying notes. Actual results could differ
from those estimates.
Estimates and assumptions which, in the opinion of management,
are significant to the underlying amounts included in the
financial statements and for which it would be reasonably
possible that future events or information could change those
estimates include:
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impairment assessments of investments, long-lived assets and
goodwill; |
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litigation-related contingencies; |
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valuations of energy contracts, including energy-related
contracts; |
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environmental remediation obligations; |
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realization of deferred income tax assets; |
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Gas Pipeline and Power revenues subject to refund; |
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valuation of Exploration & Productions
reserves; and |
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pension and post retirement valuation variables. |
These estimates are discussed further throughout the
accompanying notes.
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Cash and cash equivalents |
Cash and cash equivalents include demand and time deposits,
certificates of deposit and other marketable securities with
maturities of three months or less when acquired.
98
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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Restricted cash and investments |
Restricted cash within current assets at December 31, 2004,
consists primarily of collateral as required by certain loan
agreements for our Venezuelan operations and escrow accounts
established to fund payments required by Powers California
settlement (see Note 15). Restricted cash within noncurrent
assets relates primarily to certain borrowings by our Venezuelan
operations and letters of credit. We do not expect this cash to
be released within the next twelve months. The current and
noncurrent restricted cash is primarily invested in short-term
money market accounts with financial institutions.
Both short-term and long-term restricted investments at
December 31, 2003 consist of short-term U.S. Treasury
securities as required under the previous $800 million
revolving and letter of credit facility. In the second quarter
of 2004, this $800 million facility was replaced with two
new unsecured revolving credit facilities totaling
$500 million (see Note 11). The restricted investments
held at December 31, 2003 were purchased and sold based on
the balance required in the collateral account. Therefore, these
securities were accounted for as available-for-sale.
These securities were marked to market with the unrealized
holding gains and losses included in Other Comprehensive Income,
until realized (see Note 17). Realized gains or losses were
reclassified into earnings and based on specific identification
of the securities sold.
The classification of restricted cash and investments is
determined based on the expected term of the collateral
requirement and not necessarily the maturity date of the
investment vehicle.
Accounts receivable are carried on a gross basis, with no
discounting, less the allowance for doubtful accounts. No
allowance for doubtful accounts is recognized at the time the
revenue, which generates the accounts receivable, is recognized.
We estimate the allowance for doubtful accounts based on
existing economic conditions, the financial 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 recognized at the time full
payment is received or collectibility is assured. Past due
accounts are generally written off against the allowance for
doubtful accounts only after all collection attempts have been
exhausted.
All inventories are stated at cost, which is not in excess of
market. We determined the cost of certain natural gas
inventories held by Transco using the last-in, first-out (LIFO)
cost method; and we determined the cost of the remaining
inventories primarily using the average-cost method or market,
if lower.
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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. Depreciation of general plant is
provided on a group basis at straight-line rates. Depreciation
rates used for major regulated gas plant facilities at
December 31, 2004, 2003, and 2002 are as follows:
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Category of Property |
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Depreciation Rates | |
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Gathering facilities
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0% - 3.80% |
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Storage facilities
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1.05% - 2.50% |
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Onshore transmission facilities
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2.35% - 5.00% |
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Offshore transmission facilities
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0.85% - 1.50% |
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99
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Depreciation for non-regulated entities is provided primarily on
the straight-line method over estimated useful lives except as
noted below regarding oil and gas exploration and production
activities. The estimated useful lives are as follows:
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Estimated | |
Category of Property |
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Useful Lives | |
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(In years) | |
Natural Gas Gathering and Processing Facilities
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10 to 40 |
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Power Generation Facilities
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30 |
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Transportation Equipment
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3 to 10 |
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Building and Improvements
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10 to 45 |
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Right of Way
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4 to 40 |
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Office Furnishings & Computers
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3 to 20 |
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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 net income (loss).
Ordinary maintenance and repair costs are expensed as incurred.
Costs of major renewals and replacements are capitalized as
property, plant and equipment.
Oil and gas exploration and production activities are accounted
for under the successful efforts method of accounting. 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. Unproved properties are
evaluated annually, or as conditions warrant, to determine any
impairment in carrying value. Depreciation, depletion and
amortization are provided under the units of production method
on a field basis.
Proved properties, including developed and undeveloped, and
costs associated with unproven reserves, are assessed for
impairment using estimated future cash flows on a field basis.
Estimating future cash flows involves the use of complex
judgments such as estimation of the proved and unproven 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.
We record an asset and a liability equal to the present value of
each expected future asset retirement obligation (ARO). The ARO
asset is depreciated in a manner consistent with the
depreciation of the underlying physical asset. We measure
changes in the liability due to passage of time by applying an
interest method of allocation. This amount is recognized as an
increase in the carrying amount of the liability and as a
corresponding accretion expense included in segment profit.
Goodwill represents the excess of cost over fair value of assets
of businesses acquired. Goodwill is evaluated for impairment by
first comparing our managements estimate of the fair value
of a reporting unit with its carrying value, including goodwill.
If the carrying value 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. We
have goodwill of approximately $1 billion at
December 31, 2004 and 2003 at our Exploration &
Production segment.
When a reporting unit is sold or classified as held for sale,
any goodwill of that reporting unit is included in its carrying
value for purposes of determining any impairment or gain/loss on
sale. If a portion of a reporting
100
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
unit with goodwill is sold or classified as held for sale and
that asset group represents a business, a portion of the
reporting units goodwill is allocated to and included in
the carrying value of that asset group. With the exception of
Bio-energy, which was sold in 2002, none of the operations sold
during 2004, 2003, or 2002 or classified as held for sale at
December 31, 2004, represented reporting units with
goodwill or businesses within reporting units to which goodwill
was required to be allocated.
Judgments and assumptions are inherent in our managements
estimate of undiscounted future cash flows used to determine the
estimate of the reporting units fair value. The use of
alternate judgments and/or assumptions could result in the
recognition of different levels of impairment charges in the
financial statements.
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.
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Energy commodity risk management and trading
activities |
Prior to 2003, we, through Power and the natural gas liquids
trading operations (reported within the Midstream segment), had
energy commodity risk management and trading operations that
entered into energy and energy-related contracts to provide
price-risk management services to our third-party customers. We
held all of these contracts for trading purposes. Subsequent to
2002, our energy commodity risk management and trading
operations that provided price-risk management services to
third-party customers has been significantly curtailed with
Power currently focused on realizing expected cash flows from
its portfolio, executing new contracts to hedge its portfolio
and providing functions that support our natural gas businesses.
Energy contracts included futures contracts, option contracts,
swap agreements, and forward contracts involving short- and
long-term purchases and sales of a physical energy commodity.
Energy-related contracts included power tolling contracts, full
requirements contracts, load serving contracts, storage
contracts, transportation contracts, and transmission contracts.
In addition, we entered into interest rate and credit default
agreements to manage the interest rate and credit risk in our
energy trading portfolio.
Prior to 2003, we valued all energy and energy-related contracts
and physical commodity inventories used in energy commodity risk
management and trading activities at fair value in accordance
with SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, and Issue
No. 98-10, Accounting for Contracts Involved in
Energy Trading and Risk Management Activities. We
recognized the net change in fair value of these contracts
representing unrealized gains and losses in income currently as
revenues in the Consolidated Statement of Operations. Power and
the natural gas liquids trading operations, reported their
trading operations physical sales transactions net of the
related purchase costs in revenues, consistent with fair value
accounting for such trading activities.
In 2002, the EITF reached a consensus on Issue No. 02-3
that rescinded EITF Issue No. 98-10. As a result, beginning
in 2003, we no longer apply fair value accounting to
1) energy and energy-related contracts that are not
derivatives as defined in SFAS No. 133 and
2) physical commodity trading inventories. The consensus
was applicable for fiscal periods beginning after
December 15, 2002, and we applied the consensus effective
January 1, 2003. We reported the initial application of the
consensus as a cumulative effect of a change in accounting
principle and the effect of initially applying the consensus
reduced net income by $762.5 million, net of a
$471.4 million benefit for income taxes. The charge
primarily consisted of the fair value of energy-related
contracts, as these contracts did not meet the definition of a
derivative and thus are no longer reported at fair value.
Beginning January 1, 2003, these contracts were accounted
for under the accrual basis of accounting. The cumulative effect
charge also included the amount by which the December 31,
2002 fair value of physical commodity trading inventories
exceeded cost. We continue to carry derivatives at fair
101
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
value. See further discussion on our accounting and reporting
for derivatives in the Derivative instruments and hedging
activities section within this Note.
Prior to 2003, we determined the fair value of energy and
energy-related contracts based on the nature of the transaction
and the market in which the transaction was executed. We
executed certain transactions in exchange-traded or
over-the-counter markets for which quoted prices in active
periods existed. Quoted market prices for varying periods in
active markets were readily available for valuing futures
contracts, swap agreements and purchase and sales transactions
in the commodity markets in which Power and the natural gas
liquids trading operations transacted. Market data in active
periods was also available for interest rate transactions, which
affected the trading portfolio. For contracts or transactions
that also had terms extending into illiquid periods for which
actively quoted prices were not available, Power and the natural
gas liquids trading operations estimated energy commodity prices
in the illiquid periods by incorporating information obtained
from commodity prices in actively quoted markets, quoted prices
in less active markets, prices reflected in current transactions
and other market fundamental analysis. For contracts where
quoted market prices were not available, primarily option
contracts, transportation, storage, full requirements, load
serving, transmission and power tolling contracts, Power
estimated fair value using proprietary models and other
valuation techniques that reflected the best information
available under the circumstances. In situations where Power had
received current information from negotiation activities with
potential buyers of these contracts, Power considered this
information in the determination of the fair value of the
contract. The valuation techniques used when estimating fair
value for these contracts considered option pricing theory and
present value concepts incorporating risk from the uncertainty
of the timing and amount of estimated cash flows. Also
considered were factors such as contractual terms, quoted energy
commodity market prices, estimates of energy commodity market
prices in the absence of quoted market prices, volatility
factors underlying the positions, estimated correlation of
energy commodity prices, contractual volumes, estimated volumes
under option and other arrangements, liquidity of the market in
which the contract was transacted, and a risk-free market
discount rate.
In estimating fair value, Power assumed liquidation of the
positions in an orderly manner over a reasonable period of time
in a transaction between a willing buyer and seller. Fair value
reflected a risk premium that market participants would consider
in their determination of fair value. Regardless of the method
for which fair value was determined, we considered the risk of
non-performance and credit considerations of the counterparty in
estimating the fair value of all contracts. We adjusted the
estimates of fair value as assumptions changed or as
transactions became closer to settlement and enhanced estimates
became available.
The fair value of our trading portfolio was continually subject
to change due to changing market conditions and changing trading
portfolio positions. Determining fair value for these contracts
also involved complex assumptions including estimating natural
gas and power market prices in illiquid periods and markets,
estimating market volatility and liquidity and correlation of
natural gas and power prices, evaluating risk arising from
uncertainty inherent in estimating cash flows, and estimates
regarding counterparty performance and credit considerations.
Changes in valuation methodologies or the underlying assumptions
could have resulted in significantly different fair values.
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Derivative instruments and hedging activities |
We report all derivatives at fair value on the Consolidated
Balance Sheet in current and noncurrent derivative assets and
current and noncurrent derivative liabilities. We determine the
classification of current and noncurrent based on the timing of
expected future cash flows.
We utilize derivatives to manage our commodity price risk.
Derivative instruments held by us to manage commodity price risk
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 execute
102
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
most of these transactions in exchange-traded or
over-the-counter markets for which quoted prices in active
periods exist. For contracts with terms that exceed the time
period for which actively quoted prices are available, we must
estimate commodity prices during the illiquid periods when
determining fair value. We estimate commodity prices during
illiquid periods utilizing internally developed valuations
incorporating information obtained from commodity prices in
actively quoted markets, quoted prices in less active markets,
prices reflected in current transactions and other market
fundamental analysis.
Prior to fourth-quarter 2004, interest rate risk related to
Powers commodity trading and non-trading portfolio was
managed on an enterprise basis by the corporate parent, where
Power primarily entered into derivative instruments (usually
swaps) with the corporate parent. The corporate parent
determined the notional amount, term and nature of derivative
instruments entered into with external parties. The effect of
Powers intercompany interest rate swaps with the corporate
parent is included in Powers segment revenues and segment
profit (loss) as shown in the reconciliation within the segment
disclosures (see Note 18). Interest rate derivative
instruments related to these activities with external
counterparties were recorded at fair value, with changes in fair
value reported currently in earnings as interest rate swap loss
in the Consolidated Statement of Operations below operating
income (loss). During the fourth quarter of 2004, all external
and intercompany interest rate derivative instruments related to
managing Powers interest rate risk were terminated.
For commodity derivatives held that are not designated in a
hedging relationship, both trading and non-trading, we report
changes in fair value currently in earnings. The accounting for
changes in the fair value of commodity derivatives designated in
a hedging relationship depends on the type of hedging
relationship. In the second quarter of 2003, we elected the
normal purchases and normal sales exception, available under
SFAS No. 133, for certain commodity derivative
contracts held by Power involving short- and long-term purchases
and sales of a physical energy commodity. We reflect these
contracts in current and noncurrent derivative assets and
liabilities at their fair value on the date of the election less
the amount of that fair value realized during settlement periods
subsequent to the election.
To qualify for designation in a hedging relationship, specific
criteria have to be met and the appropriate documentation
maintained. 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 expected to be,
and remains, highly effective in achieving offsetting changes in
fair value or cash flows attributable to the underlying risk
being hedged. If a derivative ceases to be or is no longer
expected to be highly effective, hedge accounting is
discontinued prospectively, and future changes in the fair value
of the derivative are recognized currently in earnings.
For commodity derivatives designated as a hedge of a forecasted
transaction (cash flow hedges), the effective portion of the
change in fair value of the derivative is reported in other
comprehensive income and reclassified into earnings in the
period in which the hedged item affects earnings. Amounts
excluded from the effectiveness calculation and any ineffective
portion of the derivatives change in fair value are
recognized currently in earnings. Gains or losses deferred in
accumulated other comprehensive income associated with
terminated derivatives, derivatives that cease to be highly
effective hedges and cash flow hedges that have been otherwise
discontinued remain in accumulated other comprehensive income
until the hedged item affects earnings or it is probable that
the hedged item will not occur by the end of the originally
specified time period or within two months thereafter.
Forecasted transactions designated as the hedged item in a cash
flow hedge are regularly evaluated to assess whether they
continue to be probable of occurring. When it is probable the
forecasted transaction will not occur, any gain or loss deferred
in accumulated other comprehensive income is recognized in
earnings at that time.
For commodity derivatives designated as a hedge of a recognized
asset or liability or an unrecognized firm commitment (fair
value hedges), we recognize the changes in the fair value of the
derivative as well as changes in the fair value of the hedged
item attributable to the hedged risk each period in earnings. If
we
103
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
terminate a firm commitment designated as the hedged item in a
fair value hedge or it otherwise no longer qualifies as the
hedged item, we recognize any asset or liability previously
recorded as part of the hedged item currently in earnings.
In Issue No. 02-3, the EITF reached a consensus that gains
and losses on derivative instruments within the scope of
SFAS No. 133 should be shown net in the income
statement if the derivative instruments are held for trading
purposes. On July 31, 2003, the EITF reached a consensus on
Issue No. 03-11 Reporting Realized Gains and Losses
on Derivative Instruments That Are Subject to FASB Statement
No. 133, and Not Held for Trading Purposes as
Defined in Issue No. 02-3. In this issue, the EITF
concluded that determining whether realized gains and losses on
physically settled derivative contracts not held for trading
purposes should be reported in the income statement on a gross
or net basis is a matter of judgment that depended on the
relevant facts and circumstances. We report unrealized gains and
losses on all commodity derivative contracts not designated as
cash flow hedges on a net basis as revenues in the Consolidated
Statement of Operations. We report realized gains and losses on
all commodity derivative contracts that settle financially on a
net basis as revenues. For commodity derivatives designated in a
hedging relationship, amounts excluded from the effectiveness
calculation and amounts from ineffectiveness are recorded net in
revenues. For contracts that result in physical delivery, we
apply the indicators provided in Issue No. 99-19,
Reporting Revenue Gross as a Principal versus Net as an
Agent to determine the proper reporting. Based on our
assessment under Issue No. 99-19, we report revenues and
purchase costs for all contracts, derivatives and
non-derivatives, that result in physical delivery on a gross
basis as revenues and costs and operating expenses,
respectively, in the Consolidated Statement of Operations. In
determining that gross reporting is appropriate, we considered
several factors, including that we act as a principal in these
transactions, we take title to the commodity products that we
buy and sell, and we have the risks and rewards of ownership,
including credit risk and latitude in establishing sales prices.
EITF 02-3 and Issue No. 03-11 did not require
restatement of prior year amounts. Therefore, we did not restate
our Consolidated Statement of Operations for 2002 related to
Power and natural gas liquids trading operations.
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Assessment of energy-related contracts for lease
classification |
The accounting for energy-related contracts requires us to
assess whether certain of these contracts are executory service
arrangements or leases pursuant to SFAS No. 13,
Accounting for Leases. EITF 01-8, became effective
on July 1, 2003, and provides guidance for
determining whether certain contracts such as transportation,
transmission, storage, full requirements, and tolling agreements
are executory service arrangements or leases pursuant to
SFAS No. 13. The consensus is applied prospectively to
arrangements consummated or modified after July 1, 2003.
Prior to July 1, 2003, we accounted for these
energy-related contracts as executory service arrangements and
continue this accounting, unless a contract is modified
subsequent to July 1, 2003 and is evaluated to be a lease.
For these executory service arrangements, the monthly demand
payments are expensed as incurred. Certain of Powers
tolling agreements could be considered leases under the
consensus if the tolling agreements are modified after
July 1, 2003. One tolling agreement was modified subsequent
to July 1, 2003 and is accounted for as an operating lease.
For tolling agreements that are modified and deemed to be
operating leases, the monthly demand payments are expensed as
incurred. If the monthly demand payments are not incurred on a
straight line basis, expense is nevertheless recognized on a
straight line basis. If such tolling agreements were modified
and deemed to be capital leases, the net present value of the
demand payments would be reported on the balance sheet
consistent with debt as an obligation under capital lease, and
as an asset in property, plant and equipment.
Revenues for sales of products are recognized in the period of
delivery, and revenues from the transportation of gas are
recognized in the period the service is provided. Gas Pipeline
is subject to Federal Energy Regulatory Commission (FERC)
regulations and, accordingly, certain revenues collected may be
104
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
subject to possible refunds upon final orders in pending rate
cases. Gas Pipeline records estimates of rate refund liabilities
considering Gas Pipeline and other third-party regulatory
proceedings, advice of counsel and estimated total exposure, as
discounted and risk weighted, as well as collection and other
risks.
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Revenues, other than gas pipeline and energy commodity
risk management and trading activities |
Revenues generally are recorded when services are performed or
products have been delivered.
Additionally, 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 & Productions net working interest,
which are determined to be non-recoverable through remaining
production, are recognized as accounts receivable or accounts
payable, as appropriate. Cumulative differences between volumes
sold and entitlement volumes are not significant.
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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 managements judgment, that
the carrying value of such assets may not be recoverable. When
an indicator of impairment has occurred, we compare our
managements estimate of undiscounted future cash flows
attributable to the assets to the carrying value of the assets
to determine whether an impairment has occurred. 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 in accordance with
SFAS No. 144, 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
redetermined when related events or circumstances change.
We evaluate our investments for impairment when events or
changes in circumstances indicate, in our managements
judgment, that the carrying value of such investments may have
experienced an other-than-temporary decline in value. When
evidence of loss in value has occurred, we compare our estimate
of fair value of the investment to the carrying value of the
investment to determine whether an impairment has occurred. If
the estimated fair value is less than the carrying value and we
consider the decline in value to be other than temporary, the
excess of the carrying value over the fair value is recognized
in the financial statements as an impairment.
Judgments and assumptions are inherent in our managements
estimate of undiscounted future cash flows used to determine
recoverability of an asset and the estimate of an assets
fair value used to calculate the amount of impairment to
recognize. Additionally, our managements judgment is used
to determine the probability of sale with respect to assets
considered for disposal. The use of alternate judgments and/or
assumptions could result in the recognition of different levels
of impairment charges in the financial statements.
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Capitalization of interest |
We capitalize interest on major projects during construction.
Interest is capitalized on borrowed funds and, where regulation
by the FERC exists, on internally generated funds. The rates
used by regulated companies are calculated in accordance with
FERC rules. Rates used by unregulated companies are based on
105
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
the average interest rate on debt. Interest capitalized on
internally generated funds, as permitted by FERC rules, is
included in non-operating other income (expense) net.
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Employee stock-based awards |
Employee stock-based awards are accounted for under Accounting
Principles Board (APB) Opinion No. 25, Accounting for
Stock Issued to Employees, and related interpretations.
Fixed-plan common stock options generally do not result in
compensation expense because the exercise price of the stock
options equals the market price of the underlying stock on the
date of grant. The plans are described more fully in
Note 13. The following table illustrates the effect on net
income (loss) and income (loss) per share if we had applied the
fair value recognition provisions of SFAS No. 123,
Accounting for Stock-Based Compensation.
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Years Ended December 31, | |
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|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Dollars in millions, except | |
|
|
per share amount) | |
Net income (loss), as reported
|
|
$ |
163.7 |
|
|
$ |
(492.2 |
) |
|
$ |
(754.7 |
) |
Add: Stock-based employee compensation expense included in the
Consolidated Statement of Operations, net of related tax effects
|
|
|
8.9 |
|
|
|
18.7 |
|
|
|
19.1 |
|
Deduct: Total stock based employee compensation expense
determined under fair value based method for all awards, net of
related tax effects
|
|
|
(25.1 |
) |
|
|
(31.6 |
) |
|
|
(34.5 |
) |
|
|
|
|
|
|
|
|
|
|
Pro forma net income (loss)
|
|
$ |
147.5 |
|
|
$ |
(505.1 |
) |
|
$ |
(770.1 |
) |
|
|
|
|
|
|
|
|
|
|
Income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic as reported
|
|
$ |
.31 |
|
|
$ |
(1.01 |
) |
|
$ |
(1.63 |
) |
|
|
|
|
|
|
|
|
|
|
|
Basic pro forma
|
|
$ |
.28 |
|
|
$ |
(1.03 |
) |
|
$ |
(1.66 |
) |
|
|
|
|
|
|
|
|
|
|
|
Diluted as reported
|
|
$ |
.31 |
|
|
$ |
(1.01 |
) |
|
$ |
(1.63 |
) |
|
|
|
|
|
|
|
|
|
|
|
Diluted pro forma
|
|
$ |
.28 |
|
|
$ |
(1.03 |
) |
|
$ |
(1.66 |
) |
|
|
|
|
|
|
|
|
|
|
Pro forma amounts for 2004 include compensation expense from
awards of our company stock made in 2004, 2003, 2002 and 2001.
Also included in the 2004 pro forma expense is $3.3 million
of incremental expense associated with a stock option exchange
program (see Note 13). Pro forma amounts for 2003 include
compensation expense from awards made in 2003, 2002 and 2001.
Also included in 2003 pro forma expense is $2 million of
incremental expense associated with the stock option exchange
program. Pro forma amounts for 2002 include compensation expense
from awards made in 2002 and 2001 and from certain awards made
in 1999.
Since compensation expense from stock options is recognized over
the future years vesting period for pro forma disclosure
purposes and additional awards are generally made each year, pro
forma amounts may not be representative of future years
amounts.
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 managements judgment and
income tax assumptions are used to determine the levels, if any,
of valuation allowances associated with deferred tax assets.
106
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
Earnings (loss) per share |
Basic earnings (loss) per share is based on the sum of the
weighted average number of common shares outstanding and
issuable restricted and vested deferred shares. Diluted earnings
(loss) per share includes any dilutive effect of stock options,
unvested deferred shares and, for applicable periods presented,
convertible preferred stock and convertible debt, unless
otherwise noted.
|
|
|
Foreign currency translation |
Certain of our foreign subsidiaries and equity method investees
use their local currency as their functional currency. These
foreign currencies include the Canadian dollar, British pound
and Euro. Assets and liabilities of certain foreign subsidiaries
and equity investees are translated at the spot rate in effect
at the applicable reporting date, and the combined statements of
operations and our share of the results of operations of our
equity affiliates 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 other comprehensive income
(loss).
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 transactions gains and losses which are reflected in the
Consolidated Statement of Operations.
|
|
|
Issuance of equity of consolidated subsidiary |
Sales of common stock by a consolidated subsidiary are accounted
for as capital transactions with the adjustment to capital in
excess of par value. No gain or loss is recognized on these
transactions.
|
|
|
Recent accounting standards |
As disclosed in Derivative instruments and hedging activities
and in accordance with the provisions of EITF Issue
No. 99-19, we report all non-trading contracts, including
both derivatives and non-derivatives, that result in physical
delivery on a gross basis as revenues and costs and operating
expenses. In Issue 04-13, the EITF is considering transactions
in which an entity may sell inventory to another entity in the
same line of business from which it also purchases inventory.
Specifically, the EITF is considering whether there are any
circumstances under which non-monetary transactions within the
scope of APB Opinion No. 29 that involve inventory should
be recognized at fair value. Additionally, the SEC has recently
requested that companies disclose amounts related to certain
types of buy/sell arrangements that are reported on a gross
basis in the statement of operations in which the amount of
purchases and sales exceed that which would typically relate to
an entitys primary operations. We have preliminarily
evaluated our businesses to identify any such buy/sell
arrangements. Powers primary operations consist of
dispatching electricity from power generation plants and
marketing and supplying gas on behalf of our other consolidated
subsidiaries. Power engages in economic hedging activities that
often result in the purchase or sale of volumes in excess of its
primary operations, primarily due to economic hedging activities
in fluctuating commodity markets. Based on preliminary analysis,
our businesses do not have activities that result in significant
levels of arrangements in which terms for a buy and sell
agreement are entered into concurrently or in contemplation of
one another through a single transaction or a series of
transactions with a single counterparty. However, further
evaluation as to the impact
107
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
to our Statement of Operations and disclosures will be required
upon issuance of any new guidance by the EITF or the SEC.
The SEC staff, in a letter to the EITF Chairman, questioned
whether leased mineral rights should be presented as intangible
assets rather than property, plant and equipment. In March 2004,
the EITF reached a consensus that all mineral rights should be
considered tangible assets for accounting purposes. In September
2004, the FASB issued a Staff Position (FSP) that supported the
consensus of the EITF. Therefore, no reclassification is
required.
In May 2004, the FASB issued FSP No. FAS 106-2,
Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of
2003. This guidance was effective for us beginning in
third-quarter 2004 and supersedes FSP No. FAS 106-1.
See Note 7 for additional information regarding this Issue,
including the implementation effect for the year ended
December 31, 2004.
EITF Issue No. 03-1, The Meaning of Other Than
Temporary Impairment and Its Application to Certain
Investments, contains recognition and measurement guidance
that must be applied to investment impairment evaluations.
Specifically, the Issue provides guidance to determine whether
an investment is impaired and whether that impairment is other
than temporary. The Issue applies to debt and equity securities,
except equity securities accounted for under the equity method.
The FASB is currently considering implementation guidance for
the measurement and recognition provisions for this Issue and
has delayed implementation. This Issue is required to be adopted
on a prospective basis. We will continue to monitor this Issue
to determine its potential impact to our Consolidated Balance
Sheet and Consolidated Statement of Operations.
In December 2004, the FASB issued two Staff Positions
(FSP) that provide accounting guidance on how companies
should account for the effect of the American Jobs Creation Act
of 2004 that was signed into law on October 22, 2004. In
FSP FAS 109-1, Application of FASB Statement
No. 109, Accounting for Income Taxes, to the Tax
Deduction on Qualified Production Activities Provided by the
American Jobs Creation Act of 2004, the FASB concluded
that the special tax deduction for domestic manufacturing,
created by the new legislation, should be accounted for as a
special deduction instead of a tax rate reduction.
As such, the special tax deduction for domestic manufacturing is
recognized no earlier than the year in which the deduction is
taken on the tax return. FSP FAS 109-2, Accounting
and Disclosure Guidance for the Foreign Earnings Repatriation
Provision within the American Jobs Creation Act of 2004,
allows additional time to evaluate the effects of the new
legislation on any plan for reinvestment or repatriation of
foreign earnings for purposes of applying FASB Statement
No. 109. We anticipate that the legislation will not impact
our plan for reinvestment of foreign earnings and accordingly
FSP FAS 109-2 is not currently expected to have a material
impact on our consolidated financial statements. The FSPs were
effective December 21, 2004.
In December 2004, the FASB issued revised
SFAS No. 123, Share-Based Payment. The
Statement requires that compensation costs for all share based
awards to employees be recognized in the financial statements at
fair value. The Statement is effective as of the beginning of
the first interim or annual reporting period that begins after
June 15, 2005. We intend to adopt the revised Statement as
of the interim reporting period beginning July 1, 2005.
The revised Statement allows either a modified prospective
application or a modified retrospective application for
adoption. We will use a modified prospective application for
adoption and thus will apply the statement to new awards and to
awards modified, repurchased, or cancelled after July 1,
2005. Also, for unvested stock awards outstanding as of
July 1, 2005, compensation costs for the portion of these
awards for which the requisite service has not been rendered
will be recognized as the requisite service is rendered after
July 1, 2005. Compensation costs for these awards will be
based on fair value at the original grant date as estimated for
the pro forma disclosures under SFAS No. 123, as
amended by SFAS No. 148, Accounting for
Stock-Based Compensation Transition and
Disclosure an amendment of
SFAS No. 123. Additionally,
108
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
a modified retrospective application requires restating periods
prior to July 1, 2005 on a basis consistent with the pro
forma disclosures required by SFAS No. 123,
Accounting for Stock-Based Compensation, as amended
by SFAS No. 148. Since we plan to use a modified
perspective application, we will not restate prior periods.
Certain of our stock awards currently result in compensation
cost under APB No. 25 and related guidance. These stock
awards are subject to vesting provisions and our policy is to
adjust compensation cost for forfeitures when they occur. Upon
the July 1, 2005 adoption of the statement, we must adjust
net income for previously recognized compensation cost, net of
income taxes, related to the estimated number of these
outstanding stock awards that are expected to be forfeited. This
adjustment will be recognized in net income as the cumulative
effect of a change in accounting principle. We have not
estimated the amount of the adjustment for expected forfeitures.
We currently present pro forma disclosure of net income (loss)
and income (loss) per share as if compensation costs from all
stock awards were recognized based on the fair value recognition
provisions of SFAS No. 123, Accounting for
Stock-Based Compensation. We have not determined the
Statements impact on net income beyond presentation of the
pro forma disclosures. The Statement requires use of valuation
techniques including option pricing models to estimate the fair
value of employee stock awards. We are evaluating the
appropriateness of several option pricing models including a
Black-Scholes model and a lattice model (such as a binomial
model). Application of these two models could result in
different estimates of fair value with resulting differences in
compensation costs.
|
|
Note 2. |
Discontinued operations |
The businesses discussed below represent components that have
been sold or approved for sale by our Board of Directors as of
December 31, 2004 and also meet all requirements to be
treated as discontinued operations. Therefore, their results of
operations (including any impairments, gains or losses),
financial position and cash flows have been reflected in the
consolidated financial statements and notes as discontinued
operations.
During second-quarter 2003, our Board of Directors approved a
plan authorizing management to negotiate and facilitate a sale
of the assets of Gulf Liquids. Subsequent to Board approval and
through third-quarter 2004, we reported Gulf Liquids as a
discontinued operation. During fourth-quarter 2004, we
reclassified Gulf Liquids to continuing operations within the
Midstream segment for all periods presented as a result of
applying EITF 03-13 (see Note 1).
109
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
Summarized results of discontinued operations |
The following table presents the summarized results of
discontinued operations for the years ended December 31,
2004, 2003 and 2002. Income (loss) from discontinued operations
before income taxes for the year ended December 31, 2004
includes charges of approximately $153 million to increase
our accrued liability associated with certain Quality Bank
litigation matters (see Note 15). The provision for income
taxes for the year ended December 31, 2004 is less than the
federal statutory rate due primarily to the effect of net
Canadian tax benefits realized from the sale of the Canadian
straddle plants partially offset by the United States tax effect
of earnings associated with these assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Revenues
|
|
$ |
353.4 |
|
|
$ |
2,614.6 |
|
|
$ |
5,967.1 |
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from discontinued operations before income taxes
|
|
$ |
(121.3 |
) |
|
$ |
197.5 |
|
|
$ |
382.4 |
|
(Impairments) and gain (loss) on sales net
|
|
|
200.5 |
|
|
|
277.7 |
|
|
|
(567.8 |
) |
Benefit (provision) for income taxes
|
|
|
(8.7 |
) |
|
|
(148.6 |
) |
|
|
49.1 |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from discontinued operations
|
|
$ |
70.5 |
|
|
$ |
326.6 |
|
|
$ |
(136.3 |
) |
|
|
|
|
|
|
|
|
|
|
110
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
Summarized assets and liabilities of discontinued
operations |
The following table presents the summarized assets and
liabilities of discontinued operations as of December 31,
2004 and 2003. The December 31, 2004 balances include
certain Alaska retail operations that were not included in the
March 31, 2004 sale but that remain held for sale. The
December 31, 2003 balances include the assets and
liabilities of the Canadian straddle plants and the Alaska
refining, retail and pipeline operations. The assets and
liabilities from discontinued operations are reflected on the
Consolidated Balance Sheet as current beginning in the period
they are both approved for sale and expected to be sold within
twelve months.
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
(Millions) | |
Total current assets
|
|
$ |
12.3 |
|
|
$ |
173.9 |
|
|
|
|
|
|
|
|
Property, plant and equipment net
|
|
|
1.2 |
|
|
|
551.2 |
|
Other non-current assets
|
|
|
.1 |
|
|
|
1.2 |
|
|
|
|
|
|
|
|
|
Total non-current assets
|
|
|
1.3 |
|
|
|
552.4 |
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
13.6 |
|
|
$ |
726.3 |
|
|
|
|
|
|
|
|
Reflected on balance sheet as:
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$ |
13.6 |
|
|
$ |
381.2 |
|
|
Non-current assets
|
|
|
|
|
|
|
345.1 |
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
13.6 |
|
|
$ |
726.3 |
|
|
|
|
|
|
|
|
Long-term debt due within one year
|
|
$ |
|
|
|
$ |
1.1 |
|
Other current liabilities
|
|
|
1.1 |
|
|
|
80.0 |
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
1.1 |
|
|
|
81.1 |
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
|
|
|
|
.3 |
|
Other non-current liabilities
|
|
|
.5 |
|
|
|
12.0 |
|
|
|
|
|
|
|
|
|
Total non-current liabilities
|
|
|
.5 |
|
|
|
12.3 |
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$ |
1.6 |
|
|
$ |
93.4 |
|
|
|
|
|
|
|
|
Reflected on balance sheet as:
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$ |
1.6 |
|
|
$ |
93.4 |
|
|
|
|
|
|
|
|
|
|
|
2004 completed transactions |
On July 28, 2004, we completed the sale of the Canadian
straddle plants for approximately $544 million in
U.S. funds. During third-quarter 2004, we recognized a
pre-tax gain on the sale of $189.8 million, which is
included in (Impairments) and gain (loss) on sales
net in the preceding table of summarized results of discontinued
operations. These assets were previously written down to
estimated fair value, resulting in a $36.8 million
impairment in 2002 and an additional $41.7 million
impairment in 2003. In 2004, the fair value of the assets
increased substantially due primarily to renegotiation of
certain customer contracts and a general improvement in the
market for processing assets. These operations were part of the
Midstream segment.
111
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
Alaska refining, retail and pipeline operations |
On March 31, 2004, we completed the sale of our Alaska
refinery, retail and pipeline and related assets for
approximately $304 million, subject to closing adjustments
for items such as the value of petroleum inventories. We
received $279 million in cash at the time of sale and
$25 million in cash during the second quarter of 2004.
Throughout the sales negotiation process, we regularly
reassessed the estimated fair value of these assets based on
information obtained from the sales negotiations using a
probability-weighted approach. As a result, impairment charges
of $8 million and $18.4 million were recorded in 2003
and 2002, respectively. We recognized a $3.6 million
pre-tax gain on the sale during first-quarter 2004. The gain and
impairment charges are included in (Impairments) and gain (loss)
on sales net in the preceding table of summarized
results of discontinued operations. These operations were part
of the previously reported Petroleum Services segment.
|
|
|
2003 completed transactions |
|
|
|
Canadian liquids operations |
During third quarter of 2003, we completed the sales of certain
gas processing, natural gas liquids fractionation, storage and
distribution operations in western Canada and at our Redwater,
Alberta plant for total proceeds of $246 million in
U.S. funds. We recognized pre-tax gains totaling
$92.1 million in 2003 on the sales which are included in
(Impairments) and gain (loss) on sales-net in the preceding
table of summarized results of discontinued operations. These
operations were part of our Midstream segment.
On September 9, 2003, we completed the sale of our soda ash
mining facility located in Colorado. The December 31, 2002
carrying value resulted from the recognition of impairments of
$133.5 million and $170 million in 2002 and 2001,
respectively, and reflected the then estimated fair value less
cost to sell. During 2003, ongoing sale negotiations continued
to provide new information regarding estimated fair value, and,
as a result, we recognized additional impairment charges of
$17.4 million in 2003. We also recognized a pre-tax loss on
the sale in 2003 of $4.2 million. The 2003 and 2002
impairments and the loss on the sale are included in
(Impairments) and gain (loss) on sales-net in the preceding
table of summarized results of discontinued operations. The soda
ash operations were part of the previously reported
International segment.
On June 17, 2003, we completed the sale of our
100 percent general partnership interest and
54.6 percent limited partner investment in Williams Energy
Partners for $512 million in cash and assumption by the
purchasers of $570 million in debt. In December 2003, we
received additional cash proceeds of $20 million following
the occurrence of a contingent event. We recognized a total
pre-tax gain of $310.8 million on the sale during 2003,
including the $20 million of additional proceeds, all of
which is included in (Impairments) and gain (loss) on sales-net
in the preceding table of summarized results of discontinued
operations. We deferred an additional $113 million
associated with certain environmental indemnifications we
provided the purchasers under the sales agreement. In
second-quarter 2004, we settled these indemnifications with an
agreement to pay $117.5 million over a four-year period
(see Notes 10 and 15). Williams Energy Partners was a
previously reported segment.
On May 30, 2003, we completed the sale of our bio-energy
operations for $59 million in cash. During 2003, we
recognized a pre-tax loss on the sale of $5.4 million. We
recorded impairment charges totaling $195.7 million,
including $23 million related to goodwill, during 2002, to
reduce the carrying cost to our
112
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
estimate of fair value, less cost to sell, at that time. Both
the loss and impairment charges are included in (Impairments)
and gain (loss) on sales-net in the preceding table of
summarized results of discontinued operations. These operations
were part of the previously reported Petroleum Services segment.
On May 30, 2003, we completed the sale of natural gas
exploration and production properties in the Raton Basin in
southern Colorado and the Hugoton Embayment in southwestern
Kansas. This sale included all of our interests within these
basins. We recognized a $39.7 million pre-tax gain on the
sale during 2003. The gain is included in (Impairments) and gain
(loss) on sales-net in the preceding table of summarized results
of discontinued operations. These properties were part of the
Exploration & Production segment.
On May 16, 2003, we completed the sale of Texas Gas
Transmission Corporation for $795 million in cash and the
assumption by the purchaser of $250 million in existing
Texas Gas debt. We recorded a $109 million impairment
charge in 2003 reflecting the excess of the carrying cost of the
long-lived assets over our estimate of fair value based on our
assessment of the expected sales price pursuant to the purchase
and sale agreement. The impairment charge is included in
(Impairments) and gain (loss) on sales-net in the preceding
table of summarized results of discontinued operations. No
significant gain or loss was recognized on the subsequent sale.
Texas Gas was a segment within Gas Pipeline.
|
|
|
Midsouth Refinery and related assets |
On March 4, 2003, we completed the sale of our refinery and
other related operations located in Memphis, Tennessee for
$455 million in cash. We had previously written these
assets down by $240.8 million to their estimated fair value
less cost to sell at December 31, 2002. We recognized a
pre-tax gain on sale of $4.7 million in the first quarter
of 2003. During the second quarter of 2003, we recognized a
$24.7 million pre-tax gain on the sale of an earn-out
agreement we retained in the sale of the refinery. The 2002
impairment charge and subsequent gains are included in
(Impairments) and gain (loss) on sales-net in the preceding
table of summarized results of discontinued operations. These
operations were part of the previously reported Petroleum
Services segment.
On February 27, 2003, we completed the sale of our travel
centers for approximately $189 million in cash. We had
previously written these assets down by $146.6 million in
2002 and $14.7 million in 2001 to their then estimated fair
value less cost to sell at December 31, 2002. These
impairments are included in (Impairments) and gain (loss) on
sales-net in the preceding table of summarized results of
discontinued operations. We did not recognize a significant gain
or loss on the sale. These operations were part of the
previously reported Petroleum Services segment.
|
|
|
2002 completed transactions |
On November 15, 2002, we completed the sale of our Central
natural gas pipeline for $380 million in cash and the
assumption by the purchaser of $175 million in debt.
Impairment charges totaling $91.3 million during 2002 are
reflected in (Impairments) and gain (loss) on sales-net in the
preceding table of summarized results of discontinued
operations. Central was a segment within Gas Pipeline.
113
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
Mid-America and Seminole Pipelines |
On August 1, 2002, we completed the sale of our
98 percent interest in Mid-America Pipeline and
98 percent of our 80 percent ownership interest in
Seminole Pipeline for $1.2 billion. The sale generated net
cash proceeds of $1.15 billion. In the preceding table of
summarized results of discontinued operations, (Impairments) and
gain (loss) on sales-net includes a pre-tax gain of
$301.7 million during 2002 and an $11.4 million
reduction of the gain during 2003. These assets were part of the
Midstream segment.
On March 27, 2002, we completed the sale of our Kern River
pipeline for $450 million in cash and the assumption by the
purchaser of $510 million in debt. As part of the
agreement, $32.5 million of the purchase price was
contingent upon Kern River receiving a certificate from the FERC
to construct and operate a future expansion. We received the
certificate in July 2002, and recognized the contingent payment
plus interest as income from discontinued operations in 2002.
Included as a component of (Impairments) and gain (loss) on
sales-net in the preceding table of summarized results of
discontinued operations is a pre-tax loss of $6.4 million
for the year ended December 31, 2002. Kern River was a
segment within Gas Pipeline.
|
|
Note 3. |
Investing activities |
Investing income (loss) for the years ended December 31,
2004, 2003 and 2002, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Equity earnings*
|
|
$ |
49.9 |
|
|
$ |
20.3 |
|
|
$ |
73.0 |
|
Income (loss) from investments*
|
|
|
(35.5 |
) |
|
|
(25.3 |
) |
|
|
42.1 |
|
Impairments of cost-based investments
|
|
|
(28.5 |
) |
|
|
(35.0 |
) |
|
|
(12.1 |
) |
Loss provision for WilTel receivables
|
|
|
|
|
|
|
|
|
|
|
(268.7 |
) |
Interest income and other
|
|
|
62.1 |
|
|
|
113.2 |
|
|
|
52.6 |
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
48.0 |
|
|
$ |
73.2 |
|
|
$ |
(113.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
* |
Items also included in segment profit (see Note 18). |
Equity earnings for the year ended December 31, 2002,
includes a benefit of $27.4 million for a contractual
construction completion fee received by one of our equity
affiliates whose operations are accounted for under the equity
method of accounting. This equity affiliate served as the
general contractor on the Gulfstream pipeline project for
Gulfstream Natural Gas System (Gulfstream), an interstate
natural gas pipeline subject to FERC regulations and an equity
affiliate of ours. The fee paid by Gulfstream was for the early
completion during second-quarter 2002 of the construction of
Gulfstreams pipeline. It was capitalized by Gulfstream as
property, plant and equipment and is included in
Gulfstreams rate base to be recovered in future revenues.
Income (loss) from investments for the year ended
December 31, 2004 includes:
|
|
|
|
|
a $10.8 million additional impairment of our investment in
equity securities of Longhorn, which is included in our Other
segment; |
|
|
|
$6.5 million net unreimbursed Longhorn recapitalization
advisory fees, which are included in our Other segment; and |
114
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
a $16.9 million impairment of our equity investment in
Discovery Pipeline resulting from managements estimate of
fair value, which is included in our Midstream segment. |
Income (loss) from investments for the year ended
December 31, 2003 includes:
|
|
|
|
|
a $43.1 million impairment of our investment in equity and
debt securities of Longhorn which is included in our Other
segment; |
|
|
|
a $14.1 million impairment of our equity interest in Aux
Sable, which is included in our Power segment; |
|
|
|
a $13.5 million gain on the sale of stock in eSpeed Inc.,
which is included in our Power segment; and |
|
|
|
an $11.1 million gain on sale of our equity interest in
West Texas LPG Pipeline, L.P., which is included in our
Midstream segment. |
Income (loss) from investments for the year ended
December 31, 2002 includes:
|
|
|
|
|
a $58.5 million gain on sale of our investment in AB
Mazeikiu Nafta, a Lithuanian oil refinery, pipeline and terminal
complex, which is included in our Other segment; |
|
|
|
a $12.3 million write-off of Gas Pipelines investment
in a pipeline project which was cancelled in 2002; |
|
|
|
a $10.4 million net write-down pursuant to the sale of our
equity interest in Alliance Pipeline, a Canadian and
U.S. gas pipeline, which is included in our Gas Pipeline
segment; and |
|
|
|
an $8.7 million gain on sale of our general partner equity
interest in Northern Border Partners, L.P., which is included in
our Gas Pipeline segment. |
Impairments of cost-based investments for the year ended
December 31, 2004, includes a $20.8 million impairment
of our investment in an Indonesian toll road, primarily due to
increased uncertainty of the Indonesian economy.
Impairments of cost-based investments for the year ended
December 31, 2003, includes:
|
|
|
|
|
a $13.5 million impairment of our investment in ReserveCo,
a company holding phosphate reserves; and |
|
|
|
a $13.2 million impairment of our investment in Algar
Telecom S.A. |
The 2002 impairments of cost-based investments relate primarily
to various international investments.
For the year ending December 31, 2004, we did not perform
an impairment analysis for cost-based investments with a
carrying value of $16.4 million.
The loss provision for WilTel receivables in 2002 includes
pre-tax charges relating to the assessment of the recovery and
settlement of certain receivables and claims from WilTel. The
receivables and claims resulted from our performance on
$2.15 billion of guarantees and payment obligations,
amounts due from WilTel related to a deferred payment for
services and a minimum lease payment receivable from WilTel
related to WilTels headquarters building and other assets.
Interest income for the year ended December 31, 2003,
includes approximately $34 million of interest income at
Power as the result of certain FERC proceedings.
115
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Investments at December 31, 2004 and 2003, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
(Millions) | |
Equity method:
|
|
|
|
|
|
|
|
|
|
Gulfstream Natural Gas System, LLC 50%
|
|
$ |
726.1 |
|
|
$ |
730.8 |
|
|
Discovery Pipeline 50%
|
|
|
184.2 |
|
|
|
194.6 |
|
|
Longhorn Partners Pipeline, L.P. 21.3%
|
|
|
113.2 |
|
|
|
85.1 |
|
|
ACCROVEN 49.3%
|
|
|
62.0 |
|
|
|
67.1 |
|
|
Alliance Aux Sable 14.6%
|
|
|
45.6 |
|
|
|
42.8 |
|
|
Petrolera Entre Lomas S.A. 40.8%
|
|
|
44.9 |
|
|
|
41.5 |
|
|
Other
|
|
|
70.5 |
|
|
|
71.8 |
|
|
|
|
|
|
|
|
|
|
|
1,246.5 |
|
|
|
1,233.7 |
|
Cost method:
|
|
|
|
|
|
|
|
|
|
Various international funds
|
|
|
49.9 |
|
|
|
48.9 |
|
|
Algar Telecom S.A common and preferred stock
|
|
|
|
|
|
|
15.3 |
|
|
Indonesian toll road
|
|
|
2.1 |
|
|
|
23.7 |
|
|
Other
|
|
|
17.7 |
|
|
|
24.8 |
|
|
|
|
|
|
|
|
|
|
|
69.7 |
|
|
|
112.7 |
|
Advances to Longhorn Partners Pipeline, L.P.
|
|
|
|
|
|
|
117.2 |
|
|
|
|
|
|
|
|
|
|
$ |
1,316.2 |
|
|
$ |
1,463.6 |
|
|
|
|
|
|
|
|
During February 2004, we were a party to a recapitalization plan
completed by Longhorn. As a result of this plan, we sold a
portion of our equity investment in Longhorn for
$11.4 million, received $58 million in repayment of a
portion of our advances to Longhorn and converted the remaining
advances, including accrued interest, into preferred equity
interests in Longhorn. These preferred equity interests are
subordinate to the preferred interests held by the new
investors. No gain or loss was recognized on this transaction.
In December 2003, our Midstream subsidiary made an additional
$127 million investment in Discovery Pipeline that was
subsequently used by Discovery Pipeline to repay maturing debt.
All owners contributed amounts equal to their ownership
percentage so our 50 percent ownership in Discovery
remained unchanged.
Dividends and distributions received from companies carried on
the equity basis were $60 million, $21 million and
$81 million in 2004, 2003 and 2002, respectively. The
$27.4 million Gulfstream construction completion fee
described previously is included in the 2002 distributions.
Summarized financial position and results of operations of our
equity method investments are as follows:
Financial position at December 31, 2004 and 2003 is as
follows:
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
(Millions) | |
Current assets
|
|
$ |
345.1 |
|
|
$ |
281.7 |
|
Noncurrent assets
|
|
|
3,660.3 |
|
|
|
3,457.2 |
|
Current liabilities
|
|
|
357.4 |
|
|
|
325.3 |
|
Noncurrent liabilities
|
|
|
432.2 |
|
|
|
472.8 |
|
116
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Results of operations for the years ended December 31,
2004, 2003 and 2002 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Gross revenue
|
|
$ |
1,064.7 |
|
|
$ |
753.9 |
|
|
$ |
621.7 |
|
Operating income
|
|
|
185.0 |
|
|
|
109.7 |
|
|
|
148.6 |
|
Net income
|
|
|
107.8 |
|
|
|
12.6 |
|
|
|
177.4 |
|
|
|
|
Guarantees on behalf of investees |
We have guaranteed commercial letters of credit totaling
$17 million on behalf of ACCROVEN. These expire in January
2006, have no carrying value and are fully collateralized with
cash.
In connection with the construction of a joint venture pipeline
project, we guaranteed, through a put agreement, certain
portions of the joint ventures project financing in the
event of nonpayment by the joint venture. During the fourth
quarter of 2004, this project, and the associated guarantees
were terminated. We had not accrued any amounts related to this
guarantee.
We have provided guarantees on behalf of certain entities in
which we have an equity ownership interest. These generally
guarantee operating performance measures and the maximum
potential future exposure cannot be determined. There are no
expiration dates associated with these guarantees. No amounts
have been accrued at December 31, 2004.
117
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
Note 4. |
Asset sales, impairments and other accruals |
Significant gains or losses from asset sales, impairments and
other accruals included in Other (income) expense
net within segment costs and expenses for the years ended
December 31, 2004, 2003 and 2002, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Income) Expense | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Power
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of Jackson power contract
|
|
$ |
|
|
|
$ |
(188.0 |
) |
|
$ |
|
|
|
Commodity Futures Trading Commission settlement (see
Note 15)
|
|
|
|
|
|
|
20.0 |
|
|
|
|
|
|
California rate refund and other accrual adjustments
|
|
|
|
|
|
|
19.5 |
|
|
|
|
|
|
Impairment of goodwill
|
|
|
|
|
|
|
45.0 |
|
|
|
61.1 |
|
|
Impairment of generation facilities
|
|
|
|
|
|
|
44.1 |
|
|
|
44.7 |
|
|
Loss accruals and impairment of other power related assets
|
|
|
|
|
|
|
|
|
|
|
82.6 |
|
|
Guarantee loss accruals and write-offs
|
|
|
|
|
|
|
|
|
|
|
56.2 |
|
Gas Pipeline
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Write-off of previously-capitalized costs on an idled segment of
a pipeline
|
|
|
9.0 |
|
|
|
|
|
|
|
|
|
|
Write-off of software development costs due to cancelled
implementation
|
|
|
|
|
|
|
25.6 |
|
|
|
|
|
Exploration & Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss provision related to an ownership dispute
|
|
|
15.4 |
|
|
|
|
|
|
|
|
|
|
Net gain on sales of certain natural gas properties
|
|
|
|
|
|
|
(96.7 |
) |
|
|
(141.7 |
) |
Midstream Gas & Liquids
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of Gulf Liquids assets
|
|
|
2.5 |
|
|
|
108.7 |
|
|
|
|
|
|
Arbitration award on a Gulf Liquids insurance claim dispute
|
|
|
(93.6 |
) |
|
|
|
|
|
|
|
|
|
Gain on sale of the wholesale propane business
|
|
|
|
|
|
|
(16.2 |
) |
|
|
|
|
|
Impairment of Canadian olefin assets
|
|
|
|
|
|
|
|
|
|
|
78.2 |
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of blending assets
|
|
|
|
|
|
|
(9.2 |
) |
|
|
|
|
|
|
Environmental accrual related to the Augusta refinery facility
|
|
|
11.8 |
|
|
|
|
|
|
|
|
|
In June 2002, we announced our intent to exit the Power
business. As a result, Power pursued efforts to sell all or
portions of our power, natural gas, and crude and refined
products portfolios in the latter half of 2002 and in 2003.
Based on bids received in these sales efforts, we impaired
certain assets and projects in 2002. During 2003, we continued
our focus on exiting the Power business and, as a result,
impaired certain assets. In September 2004, our Board of
Directors approved the decision to retain Power and end our
efforts to exit that business (see Note 1).
California Rate Refund and Other Accrual Adjustments. In
addition to the $19.5 million charge included in other
(income) expense net within segment costs and
expenses for 2003, a $13.8 million charge is recorded
within costs and operating expenses. These two amounts, totaling
$33.3 million, are for California
118
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
rate refund liability and other accrual adjustments and relate
to power marketing activities in California during 2000 and
2001. See Note 15 for further discussion.
Goodwill. The fair value of the Power reporting unit used
to calculate the goodwill impairment loss in 2002 was based on
the estimated fair value of the trading portfolio inclusive of
the fair value of contracts with affiliates. In 2002, the
trading portfolio was reflected at fair value in the financial
statements and the affiliate contracts were not. The fair value
of the affiliate contracts was estimated using a discounted cash
flow model with natural gas pricing assumptions based on current
market information.
During 2003, we were pursuing a strategy of exiting the Power
business. Because of this strategy and the market conditions in
which this business operated, we evaluated Powers
remaining goodwill for impairment. In estimating the fair value
of the Power segment, we considered our derivative portfolio
which is carried at fair value on the balance sheet and our
non-derivative portfolio which is no longer carried at fair
value on the balance sheet. Because of the significant negative
fair value of certain of our non-derivative contracts, we may be
unable to realize our carrying value of this segment. As a
result, we recognized a $45 million impairment of the
remaining goodwill within Power during 2003.
Generation Facilities. The 2003 impairment relates to the
Hazelton generation facility. Fair value was estimated using
future cash flows based on current market information and
discounted at a risk adjusted rate. The 2002 impairment was
related to the Worthington generation facility. Fair value was
estimated based on expected proceeds from the sale of the
facility, which closed in first-quarter 2003.
Loss Accruals and Impairment of Other Power Related
Assets. The 2002 loss accruals and impairments of other
power related assets were recorded pursuant to reducing
activities associated with the distributive power generation
business.
Guarantee Loss Accruals and Write-Offs. The 2002
guarantee loss accruals and write-offs within Power of
$56.2 million includes accruals for commitments for certain
assets that were previously planned to be used in power
projects, write-offs associated with a terminated power plant
project and a $13.2 million reversal of loss accruals
related to the wind-down of our mezzanine lending business.
Impairment of Gulf Liquids Assets. During second-quarter
2003, our Board of Directors approved a plan authorizing
management to negotiate and facilitate a sale of the assets of
Gulf Liquids. We are currently negotiating purchase and sale
agreements related to the sale of these assets. We expect the
sale of these operations to close by the end of the second
quarter of 2005. We recognized impairment charges of
$2.5 million in the fourth quarter of 2004 and
$108.7 million during 2003 to reduce the carrying cost of
the long-lived assets to estimated fair value less costs to sell
the assets. We estimated fair value based on a
probability-weighted analysis of various scenarios including
expected sales prices, discounted cash flows and salvage
valuations. Prior to fourth-quarter 2004, the operations of Gulf
Liquids were included in discontinued operations (see
Note 12).
Arbitration award on a Gulf Liquids Insurance Claim
Dispute. Winterthur International Insurance Company
(Winterthur) issued policies to Gulf Liquids providing financial
assurance related to construction contracts. After disputes
arose regarding obligations under the construction contracts,
Winterthur disputed coverage resulting in arbitration between
Winerthur and Gulf Liquids. In July 2004, the arbitration panel
awarded Gulf Liquids $93.6 million, plus interest of
$9.6 million. Following the arbitration decision,
Winterthur filed a Petition to Vacate the Final Award in the New
York State court and Gulf Liquids filed a Cross-Petition to
Confirm the Final Award. Prior to the State courts ruling,
Winterthur agreed to the terms of the award and on
November 1, 2004, remitted the proceeds to us. As a result,
we recognized total income of approximately $103 million
related to the arbitration award in fourth-quarter 2004.
119
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Canadian Olefin Assets. The 2002 impairment is associated
with an olefin fractionation facility and reflects a reduction
of carrying cost to managements estimate of fair market
value, determined primarily from information available from
efforts to sell these assets.
Environmental accrual related to the Augusta refinery
facility. As a result of new information obtained in the
fourth quarter related to the Augusta refinery site, we have
accrued additional amounts for completion of work under a
current Administrative Order on Consent and reasonably estimated
remediation costs. Accruals may be adjusted as more information
from the site investigation becomes available (see Note 15).
|
|
Note 5. |
Provision (benefit) for income taxes |
The provision (benefit) for income taxes from continuing
operations includes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
11.0 |
|
|
$ |
(8.8 |
) |
|
$ |
(126.7 |
) |
|
State
|
|
|
(13.7 |
) |
|
|
(17.6 |
) |
|
|
27.5 |
|
|
Foreign
|
|
|
11.0 |
|
|
|
8.8 |
|
|
|
21.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.3 |
|
|
|
(17.6 |
) |
|
|
(77.8 |
) |
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
75.1 |
|
|
|
(17.0 |
) |
|
|
(161.9 |
) |
|
State
|
|
|
38.7 |
|
|
|
44.4 |
|
|
|
(58.4 |
) |
|
Foreign
|
|
|
9.2 |
|
|
|
(15.1 |
) |
|
|
7.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
123.0 |
|
|
|
12.3 |
|
|
|
(212.5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total provision (benefit)
|
|
$ |
131.3 |
|
|
$ |
(5.3 |
) |
|
$ |
(290.3 |
) |
|
|
|
|
|
|
|
|
|
|
Reconciliations from the provision (benefit) for income taxes
from continuing operations at the federal statutory rate to the
provision (benefit) for income taxes are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Provision (benefit) at statutory rate
|
|
$ |
78.6 |
|
|
$ |
(22.0 |
) |
|
$ |
(318.1 |
) |
Increases (reductions) in taxes resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State income taxes (net of federal benefit)
|
|
|
27.9 |
|
|
|
.5 |
|
|
|
(20.1 |
) |
|
Foreign operations net
|
|
|
6.1 |
|
|
|
3.5 |
|
|
|
81.6 |
|
|
Capital losses
|
|
|
|
|
|
|
(39.6 |
) |
|
|
(121.2 |
) |
|
Valuation allowance/expiration charitable contributions
|
|
|
13.8 |
|
|
|
|
|
|
|
|
|
|
Non-deductible impairment of goodwill
|
|
|
|
|
|
|
15.8 |
|
|
|
21.7 |
|
|
Income tax credits recapture
|
|
|
|
|
|
|
|
|
|
|
26.8 |
|
|
Other net
|
|
|
4.9 |
|
|
|
36.5 |
|
|
|
39.0 |
|
|
|
|
|
|
|
|
|
|
|
Provision (benefit) for income taxes
|
|
$ |
131.3 |
|
|
$ |
(5.3 |
) |
|
$ |
(290.3 |
) |
|
|
|
|
|
|
|
|
|
|
During 2004, the utilization of foreign tax credits reduced the
provision for income taxes by $12 million. Utilization of
foreign operating loss carryovers reduced the provision for
income taxes during 2003 by $19 million. The impact of
foreign operations on the effective tax rate increased during
2002 due to the
120
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
recognition of U.S. tax on foreign dividend distributions
and recording of a financial impairment on certain foreign
assets for which a valuation allowance was established.
Income (loss) from continuing operations before income taxes
includes $51 million of international income in 2004,
$9 million of international income in 2003 and
$38 million of international loss in 2002.
Significant components of deferred tax liabilities and assets as
of December 31, 2004 and 2003, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
(Millions) | |
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
$ |
2,356.5 |
|
|
$ |
2,118.8 |
|
|
Derivatives net
|
|
|
99.3 |
|
|
|
149.9 |
|
|
Investments
|
|
|
442.4 |
|
|
|
514.8 |
|
|
Other
|
|
|
201.8 |
|
|
|
195.8 |
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
3,100.0 |
|
|
|
2,979.3 |
|
|
|
|
|
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
|
Minimum tax credits
|
|
|
151.0 |
|
|
|
151.5 |
|
|
Accrued liabilities
|
|
|
171.5 |
|
|
|
208.7 |
|
|
Receivables
|
|
|
44.2 |
|
|
|
52.5 |
|
|
Federal carryovers
|
|
|
315.3 |
|
|
|
115.7 |
|
|
Foreign carryovers
|
|
|
54.1 |
|
|
|
46.2 |
|
|
Other
|
|
|
44.3 |
|
|
|
125.7 |
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
780.4 |
|
|
|
700.3 |
|
|
|
|
|
|
|
|
|
Valuation allowance
|
|
|
61.5 |
|
|
|
67.8 |
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
718.9 |
|
|
|
632.5 |
|
|
|
|
|
|
|
|
|
Overall net deferred tax liabilities
|
|
$ |
2,381.1 |
|
|
$ |
2,346.8 |
|
|
|
|
|
|
|
|
Valuation allowances at December 31, 2004 serve to reduce
the recognized tax benefit associated with charitable
contribution carryovers and foreign carryovers to an amount that
will, more likely than not, be realized. Valuation allowances at
December 31, 2003 serve to reduce the recognized tax
benefit associated with foreign asset impairments and foreign
carryovers to an amount that will, more likely than not, be
realized.
Undistributed earnings of certain consolidated foreign
subsidiaries at December 31, 2004, amounted to
approximately $88 million. No provision for deferred
U.S. income taxes has been made for these subsidiaries
because we intend to permanently reinvest such earnings in those
foreign operations.
Cash payments for income taxes (net of refunds) were
$8 million and $36 million in 2004 and 2002,
respectively. Cash refunds for income taxes (net of payments)
were $88 million in 2003.
At December 31, 2004, federal net operating loss carryovers
are $824 million, capital loss carryovers are
$13 million and charitable contribution carryovers are
$64 million. We do not expect to utilize $21 million
of charitable contribution carryovers prior to expiration in
2005. We expect to utilize the net operating loss carryovers
prior to expiration in 2022 through 2024, capital loss
carryovers prior to expiration in 2007 and the remaining
$43 million charitable contribution carryovers prior to
expiration in 2006 and 2007. We also do not expect to be able to
utilize $54 million of foreign deferred tax assets related
to carryovers.
121
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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 tax filing positions, we
record a liability for probable tax contingencies. In
association with this liability, we record an estimate of
related interest as a component of our current tax provision.
The impact of this accrual is included within Other
net in our reconciliation of the tax provision to the federal
statutory rate.
|
|
Note 6. |
Earnings (loss) per share |
Basic and diluted earnings (loss) per common share for the years
ended December 31, 2004, 2003 and 2002, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Dollars in millions, except per-share | |
|
|
amounts; shares in thousands) | |
Income (loss) from continuing operations
|
|
$ |
93.2 |
|
|
$ |
(57.5 |
) |
|
$ |
(618.4 |
) |
Convertible preferred stock dividends (see Note 12)
|
|
|
|
|
|
|
29.5 |
|
|
|
90.1 |
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations available to common
stockholders for basic and diluted earnings per share
|
|
$ |
93.2 |
|
|
$ |
(87.0 |
) |
|
$ |
(708.5 |
) |
|
|
|
|
|
|
|
|
|
|
Basic weighted-average shares(1)
|
|
|
529,188 |
|
|
|
518,137 |
|
|
|
516,793 |
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested deferred shares
|
|
|
2,631 |
|
|
|
|
|
|
|
|
|
|
Stock options
|
|
|
3,792 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted-average shares(1)
|
|
|
535,611 |
|
|
|
518,137 |
|
|
|
516,793 |
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per share from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
.18 |
|
|
$ |
(.17 |
) |
|
$ |
(1.37 |
) |
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$ |
.18 |
|
|
$ |
(.17 |
) |
|
$ |
(1.37 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
In October 2004, we issued approximately 33.1 million
shares of common stock in association with an exchange offer on
our FELINE PACS units (see Note 11). |
During fourth-quarter 2004 we reclassified the results of Gulf
Liquids from discontinued operations to continuing operations
(see Notes 1 and 2). As a result, both the basic and
diluted loss per common share from continuing operations
increased by $.17 and $.04 for the years ended December 31,
2003 and 2002, respectively.
Approximately 27.5 million and 16.5 million
weighted-average shares related to the assumed conversion of
convertible debentures, as well as the related interest, have
been excluded from the computation of diluted earnings per
common share for the years ended December 31, 2004 and
2003, respectively. Inclusion of these shares would have an
antidilutive effect on diluted earnings per common share. If no
other components used to calculate diluted earnings per common
share change, we estimate the assumed conversion of convertible
debentures would become dilutive and therefore be included in
diluted earnings per common share at an Income from continuing
operations applicable to common stock amount of
$198.1 million and $192.1 million for the years ended
December 31, 2004 and 2003, respectively.
For the year ended December 31, 2003, approximately
3.6 million weighted-average stock options, approximately
6.4 million weighted-average shares related to the assumed
conversion of 9.875 percent
122
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
cumulative convertible preferred stock and approximately
2.5 million weighted-average unvested deferred shares have
been excluded from the computation of diluted earnings per
common share as their inclusion would be antidilutive. The
unvested deferred shares will vest over the period from January
2005 to January 2008. The preferred stock was redeemed in June
2003.
For the year ended December 31, 2002, approximately 666,000
weighted-average stock options, approximately 11.3 million
weighted-average shares related to the assumed conversion of the
9.875 percent cumulative convertible preferred stock and
approximately 3.6 million weighted-average unvested
deferred shares have been excluded from the computation of
diluted earnings per common share as their inclusion would be
antidilutive.
The table below includes information related to options that
were outstanding at the end of each respective year but have
been excluded from the computation of diluted earnings per
common share due to the option exercise price exceeding the
fourth-quarter weighted-average market price of our common
shares.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
Options excluded (millions)
|
|
|
8.5 |
|
|
|
15.0 |
|
|
|
38.7 |
|
Weighted-average exercise prices of options excluded
|
|
|
$28.21 |
|
|
|
$22.77 |
|
|
|
$19.90 |
|
Exercise price ranges of options excluded
|
|
|
$14.61 - $42.29 |
|
|
|
$10.39 - $42.52 |
|
|
|
$2.27 - $42.52 |
|
Fourth-quarter weighted-average market price
|
|
|
$14.41 |
|
|
|
$9.76 |
|
|
|
$2.21 |
|
On February 16, 2005, we issued 10.9 million shares of
common stock to the holders of an equity forward contract
(FELINE PACS) in exchange for $25 cash per share (see
Note 12). These shares will be a component of basic
earnings per share in future periods.
|
|
Note 7. |
Employee benefit plans |
We provide pension benefits to substantially all eligible
employees through our noncontributory defined benefit pension
plans. 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 receive annuity payments, a lump sum payment or a
combination of lump sum and annuity payments. In addition to our
pension plans, we provide subsidized medical and life insurance
benefits (other postretirement benefits) to certain eligible
participants. Generally, employees hired after December 31,
1991, are not eligible for these benefits, except for
participants that were employees of Transco Energy Company on
December 31, 1995, and other defined participant groups.
Certain of these other postretirement benefit plans,
particularly the subsidized medical benefit plans, provide for
retiree contributions and contain other cost-sharing features
such as deductibles, copayments, and coinsurance. 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.
123
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table presents the changes in benefit obligations
and plan assets for pension benefits and other postretirement
benefits for the years indicated. It also presents a
reconciliation of the funded status of these benefit plans to
the amounts recorded in the Consolidated Balance Sheet at
December 31 of each year indicated. The annual measurement
date for our plans is December 31. Changes in the
obligations or assets of continuing plans associated with the
transfer of such obligations or assets in a sale or planned sale
reflected as discontinued operations have been reflected as
divestitures in the following tables.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement | |
|
|
Pension Benefits | |
|
Benefits | |
|
|
| |
|
| |
|
|
2004 | |
|
2003 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Millions) | |
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$ |
775.9 |
|
|
$ |
788.9 |
|
|
$ |
362.4 |
|
|
$ |
410.5 |
|
|
Service cost
|
|
|
24.0 |
|
|
|
25.5 |
|
|
|
3.2 |
|
|
|
6.2 |
|
|
Interest cost
|
|
|
50.5 |
|
|
|
52.7 |
|
|
|
18.8 |
|
|
|
24.1 |
|
|
Plan participants contributions
|
|
|
|
|
|
|
|
|
|
|
4.3 |
|
|
|
3.3 |
|
|
Curtailment
|
|
|
(2.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement benefits paid
|
|
|
(.4 |
) |
|
|
(6.1 |
) |
|
|
|
|
|
|
|
|
|
Benefits paid
|
|
|
(78.8 |
) |
|
|
(87.1 |
) |
|
|
(24.8 |
) |
|
|
(24.6 |
) |
|
Plan amendments
|
|
|
7.8 |
|
|
|
|
|
|
|
(75.5 |
) |
|
|
|
|
|
Divestiture
|
|
|
|
|
|
|
(.8 |
) |
|
|
|
|
|
|
(118.3 |
) |
|
Actuarial (gain) loss
|
|
|
116.3 |
|
|
|
2.8 |
|
|
|
(20.0 |
) |
|
|
61.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
|
893.0 |
|
|
|
775.9 |
|
|
|
268.4 |
|
|
|
362.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
|
706.3 |
|
|
|
592.9 |
|
|
|
152.7 |
|
|
|
193.9 |
|
|
Actual return on plan assets
|
|
|
69.6 |
|
|
|
155.8 |
|
|
|
13.2 |
|
|
|
36.1 |
|
|
Divestiture
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(70.2 |
) |
|
Employer contributions
|
|
|
138.8 |
|
|
|
50.8 |
|
|
|
13.5 |
|
|
|
14.2 |
|
|
Plan participants contributions
|
|
|
|
|
|
|
|
|
|
|
4.3 |
|
|
|
3.3 |
|
|
Benefits paid
|
|
|
(78.8 |
) |
|
|
(87.1 |
) |
|
|
(24.8 |
) |
|
|
(24.6 |
) |
|
Settlement benefits paid
|
|
|
(.4 |
) |
|
|
(6.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year
|
|
|
835.5 |
|
|
|
706.3 |
|
|
|
158.9 |
|
|
|
152.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status
|
|
|
(57.5 |
) |
|
|
(69.6 |
) |
|
|
(109.5 |
) |
|
|
(209.7 |
) |
Unrecognized net actuarial loss
|
|
|
295.3 |
|
|
|
195.5 |
|
|
|
23.7 |
|
|
|
44.5 |
|
Unrecognized prior service cost (credit)
|
|
|
4.7 |
|
|
|
(4.6 |
) |
|
|
(53.8 |
) |
|
|
1.5 |
|
Unrecognized transition obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid (accrued) benefit cost
|
|
$ |
242.5 |
|
|
$ |
121.3 |
|
|
$ |
(139.6 |
) |
|
$ |
(140.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
124
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Amounts recognized in the Consolidated Balance Sheet consist of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement | |
|
|
Pension Benefits | |
|
Benefits | |
|
|
| |
|
| |
|
|
2004 | |
|
2003 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Millions) | |
Prepaid benefit cost
|
|
$ |
251.0 |
|
|
$ |
164.4 |
|
|
$ |
|
|
|
$ |
|
|
Accrued benefit cost
|
|
|
(17.6 |
) |
|
|
(53.7 |
) |
|
|
(139.6 |
) |
|
|
(140.1 |
) |
Regulatory asset
|
|
|
1.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (before tax)
|
|
|
7.4 |
|
|
|
10.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid (accrued) benefit cost
|
|
$ |
242.5 |
|
|
$ |
121.3 |
|
|
$ |
(139.6 |
) |
|
$ |
(140.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The regulatory asset shown in the table above is the portion of
the additional minimum pension liability recognized by our FERC
regulated gas pipelines. As required by FERC accounting
guidelines, our FERC regulated gas pipelines are required to
record the effect of an additional minimum pension liability to
a regulatory asset instead of accumulated other comprehensive
income.
The 2004 actuarial loss of $116.3 million for our pension
plans included in the table of changes in benefit obligation
reflects the impact of changes in various actuarial assumptions
used to calculate the benefit obligation including the expected
type of benefit payment and discount rate.
The accumulated benefit obligation for our pension plans was
$823.4 million and $720.2 million at December 31,
2004 and 2003, respectively.
The projected benefit obligation and fair value of plan assets
for our pension plans with projected benefit obligation in
excess of plan assets were $381.2 million and
$305.3 million, respectively, at December 31, 2004,
and $335.0 million and $225.5 million, respectively,
at December 31, 2003. The accumulated benefit obligation
for pension plans with accumulated benefit obligations in excess
of plan assets was $17.6 million at December 31, 2004.
There were no assets for these plans at December 31, 2004.
The accumulated benefit obligation and fair value of plan assets
for our pension plans with accumulated benefit obligations in
excess of plan assets were $279.2 million and
$225.5 million, respectively, at December 31, 2003.
Net periodic pension and other postretirement benefit expense
for the years ended December 31, 2004, 2003 and 2002,
consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Components of net periodic pension expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$ |
24.0 |
|
|
$ |
25.5 |
|
|
$ |
32.5 |
|
|
Interest cost
|
|
|
50.5 |
|
|
|
52.7 |
|
|
|
59.3 |
|
|
Expected return on plan assets
|
|
|
(64.9 |
) |
|
|
(54.2 |
) |
|
|
(65.3 |
) |
|
Amortization of prior service credit
|
|
|
(1.5 |
) |
|
|
(2.5 |
) |
|
|
(1.6 |
) |
|
Recognized net actuarial loss
|
|
|
9.4 |
|
|
|
13.7 |
|
|
|
4.0 |
|
|
Regulatory asset amortization (deferral)
|
|
|
2.0 |
|
|
|
3.9 |
|
|
|
(1.2 |
) |
|
Settlement/curtailment expense
|
|
|
.1 |
|
|
|
.6 |
|
|
|
4.8 |
|
|
Special termination benefit cost
|
|
|
|
|
|
|
|
|
|
|
29.5 |
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension expense
|
|
$ |
19.6 |
|
|
$ |
39.7 |
|
|
$ |
62.0 |
|
|
|
|
|
|
|
|
|
|
|
125
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement Benefits | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Components of net periodic postretirement benefit expense
(income):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$ |
3.2 |
|
|
$ |
6.2 |
|
|
$ |
7.1 |
|
|
Interest cost
|
|
|
18.8 |
|
|
|
24.1 |
|
|
|
31.8 |
|
|
Expected return on plan assets
|
|
|
(12.4 |
) |
|
|
(13.0 |
) |
|
|
(18.9 |
) |
|
Amortization of transition obligation
|
|
|
2.7 |
|
|
|
2.7 |
|
|
|
4.1 |
|
|
Amortization of prior service cost
|
|
|
.6 |
|
|
|
.6 |
|
|
|
.2 |
|
|
Regulatory asset amortization
|
|
|
6.7 |
|
|
|
8.6 |
|
|
|
3.7 |
|
|
Settlement/curtailment expense (income)
|
|
|
|
|
|
|
(41.9 |
) |
|
|
13.5 |
|
|
Special termination benefit cost
|
|
|
|
|
|
|
|
|
|
|
1.5 |
|
|
|
|
|
|
|
|
|
|
|
Net periodic postretirement benefit expense (income)
|
|
$ |
19.6 |
|
|
$ |
(12.7 |
) |
|
$ |
43.0 |
|
|
|
|
|
|
|
|
|
|
|
The $41.9 million settlement/curtailment income in 2003 and
$13.5 million settlement/curtailment expense in 2002
included in net periodic postretirement benefit expense (income)
is included in Income (loss) from discontinued operations in the
Consolidated Statement of Operations due to the
settlement/curtailment directly resulting from the sale of the
operations included within discontinued operations.
The weighted-average assumptions utilized to determine benefit
obligations as of December 31, 2004 and 2003 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other | |
|
|
|
|
Postretirement | |
|
|
Pension Benefits | |
|
Benefits | |
|
|
| |
|
| |
|
|
2004 | |
|
2003 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
| |
Discount rate
|
|
|
5.86 |
% |
|
|
6.25 |
% |
|
|
5.75 |
% |
|
|
6.25 |
% |
Rate of compensation increase
|
|
|
5 |
|
|
|
5 |
|
|
|
N/A |
|
|
|
N/A |
|
The weighted-average assumptions utilized to determine net
pension and other postretirement benefit expense for the years
ended December 31, 2004, 2003 and 2002, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other | |
|
|
|
|
Postretirement | |
|
|
Pension Benefits | |
|
Benefits | |
|
|
| |
|
| |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Discount rate
|
|
|
6.25 |
% |
|
|
7 |
% |
|
|
7.5 |
% |
|
|
6.25 |
% |
|
|
7 |
% |
|
|
7 |
% |
Expected long-term rate of return on plan assets
|
|
|
8.5 |
|
|
|
8.5 |
|
|
|
8.5 |
|
|
|
8.5 |
|
|
|
7 |
|
|
|
7 |
|
Rate of compensation increase
|
|
|
5 |
|
|
|
5 |
|
|
|
5 |
|
|
|
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 and their respective expected benefit cash
flows. With the assistance of our third-party actuary, the plans
were analyzed and discount rates based on a yield curve
comprised of high quality corporate bonds published by a large
securities firm were matched to a highly correlated published
index of high quality corporate bonds. Based on an analysis
performed between each of the plans yield curve discount
rates and the index, a formula was developed to determine the
December 31, 2004, discount rates based upon the year-end
published index.
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
126
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Statement, and the capital market projections provided by our
independent investment consultant for the asset classifications
in which the portfolio is invested and the target weightings of
each asset classification.
The mortality assumptions used to determine the obligations for
our pension and other postretirement benefit plans are related
to the experience of the plans and to our third-party
actuarys best estimate of expected plan mortality. The
selected mortality tables are among the most recent tables
available.
The annual assumed rate of increase in the health care cost
trend rate for 2005 is 9 percent, and systematically
decreases to 5 percent by 2013.
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
|
|
$ |
3.7 |
|
|
$ |
(2.9 |
) |
Effect on postretirement benefit obligation
|
|
|
52.0 |
|
|
|
(41.4 |
) |
In December 2003, the Medicare Prescription Drug, Improvement,
and Modernization Act of 2003 (the Act) was signed into law. The
Act introduces a prescription drug benefit under Medicare
(Medicare Part D) as well as a federal subsidy to sponsors
of retiree health care benefit plans that provide a benefit that
is at least actuarially equivalent to Medicare Part D. Our
health care plans for retirees include prescription drug
coverage. In accordance with FSP No. FAS 106-1,
Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of
2003, the provisions of the Act were not reflected in any
measures of benefit obligations or other postretirement benefit
expense in the financial statements or accompanying notes until
further guidance was effective. In May 2004, the FASB issued FSP
No. FAS 106-2, Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003. Although final
guidance has not been issued, we believe the prescription drug
benefits included in our health care plans for retirees, prior
to the amendment of the plans discussed below, were actuarially
equivalent to Medicare Part D. In accordance with FSP
No. FAS 106-2, we reflected the effect of the subsidy
on the measurement of net periodic postretirement benefit
expense (income) in 2004. Net periodic postretirement benefit
expense (income) for the year ended December 31, 2004,
reflects a reduction of $3.4 million, including a decrease
in service cost of $.4 million and decrease in interest
cost of $2.7 million. The reduction in the benefit
obligation was approximately $43 million as of
January 1, 2004, and is included as a component of the
actuarial (gain) loss in the table of changes in benefit
obligation. We amended our plans in the fourth quarter of 2004
to coordinate and pay secondary to any part of Medicare,
including prescription drug benefits covered by Medicare
Part D. This amendment further decreased the benefit
obligation by $75.5 million and is reflected as a plan
amendment in the table of changes in benefit obligation as we
believe our plans are no longer actuarially equivalent to
Medicare Part D. The net reduction to the obligation as a
result of this amendment will be amortized as a reduction to net
periodic postretirement benefit expense (income) over the
average remaining years of service to full eligibility for
benefits.
The amount of postretirement benefit costs deferred as a net
regulatory asset at December 31, 2004 and 2003, is
$18 million and $24 million, respectively, and is
expected to be recovered through rates over approximately
7 years.
127
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Our pension plans weighted-average asset allocations at
December 31, 2004 and 2003, by asset category are as
follows:
|
|
|
|
|
|
|
|
|
|
|
Plan Assets at | |
|
|
December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
Equity securities
|
|
|
82 |
% |
|
|
82 |
% |
Debt securities
|
|
|
14 |
|
|
|
13 |
|
Other
|
|
|
4 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
Included in equity securities are investments in commingled
funds that invest entirely in equity securities and comprise
37 percent and 38 percent of the pension plans
weighted-average assets at December 31, 2004 and 2003,
respectively. Other assets, in the previous table, are comprised
primarily of cash and cash equivalents.
Our investment strategy for the assets within the pension plans
is to maximize investment returns with prudent levels of risk to
meet current and projected financial requirements of the pension
plans. These risks are evaluated, in part, from an asset-only
standpoint as to investment allocation, investment style and
manager selection. Additional risk perspectives are reviewed
considering the allocation of assets and the structure of the
plan liabilities and the combined effects on the plans. Our
investment policy for the pension plan assets includes a target
asset allocation. The target for equity securities is
84 percent and debt securities and other is 16 percent
at December 31, 2004.
Our other postretirement benefit plans weighted-average
asset allocations at December 31, 2004 and 2003, by asset
category are as follows:
|
|
|
|
|
|
|
|
|
|
|
Plan Assets at | |
|
|
December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
Equity securities
|
|
|
77 |
% |
|
|
74 |
% |
Debt securities
|
|
|
14 |
|
|
|
14 |
|
Other
|
|
|
9 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
Included in equity securities are investments in commingled
funds that invest entirely in equity securities and comprise
24 percent and 22 percent of the other postretirement
benefit plans weighted-average assets at December 31,
2004 and 2003, respectively. Other assets, in the previous
table, are comprised primarily of cash and cash equivalents, and
insurance contract assets.
Our investment strategy for the assets within the other
postretirement benefit plans is to maximize investment returns
with prudent levels of risk in a tax efficient manner to meet
current and projected financial requirements of the other
postretirement benefit plans. These risks are evaluated, in
part, from an asset-only standpoint as to investment allocation,
investment style and manager selection. Additional risk
perspectives are reviewed considering the allocation of assets
and the structure of the plan liabilities and the combined
effects on the plans. Our investment policy for the other
postretirement benefit plan assets includes a target asset
allocation. The target for equity securities is 80 percent
and debt securities and other is 20 percent at
December 31, 2004.
The following are the expected benefits to be paid 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
128
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
Other | |
|
|
Pension | |
|
Postretirement | |
|
|
Benefits | |
|
Benefits | |
|
|
| |
|
| |
|
|
(Millions) | |
2005
|
|
$ |
39.2 |
|
|
$ |
19.3 |
|
2006
|
|
|
39.1 |
|
|
|
20.6 |
|
2007
|
|
|
39.0 |
|
|
|
21.8 |
|
2008
|
|
|
38.8 |
|
|
|
22.6 |
|
2009
|
|
|
39.4 |
|
|
|
23.2 |
|
2010-2014
|
|
|
235.5 |
|
|
|
119.5 |
|
We expect to contribute approximately $42 million to our
pension plans and approximately $15 million to our other
postretirement benefit plans in 2005.
We also maintain defined contribution plans. Costs related to
continuing operations of $17 million, $18 million, and
$38 million were recognized for these plans in 2004, 2003
and 2002, respectively. In 2002, these costs included the cost
related to additional contributions to an employee stock
ownership plan resulting from the retirement of related external
debt.
Inventories at December 31, 2004 and 2003, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
(Millions) | |
Finished goods:
|
|
|
|
|
|
|
|
|
|
Refined products
|
|
$ |
.8 |
|
|
$ |
8.0 |
|
|
Natural gas liquids
|
|
|
63.2 |
|
|
|
40.4 |
|
|
|
|
|
|
|
|
|
|
|
64.0 |
|
|
|
48.4 |
|
|
|
|
|
|
|
|
Natural gas in underground storage
|
|
|
133.1 |
|
|
|
132.5 |
|
Materials, supplies and other
|
|
|
64.0 |
|
|
|
62.0 |
|
|
|
|
|
|
|
|
|
|
$ |
261.1 |
|
|
$ |
242.9 |
|
|
|
|
|
|
|
|
At December 31, 2004 and 2003, less than one percent of
inventories were stated at fair value. Inventories determined
using the LIFO cost method were approximately six percent and
ten percent of inventories at December 31, 2004 and 2003,
respectively. The remaining inventories were primarily
determined using the average-cost method.
If inventories valued on the LIFO cost method at
December 31, 2004 and 2003, were valued at current
replacement cost, the amounts would increase by $25 million
and $26 million, respectively.
129
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
Note 9. |
Property, plant and equipment |
Property, plant and equipment at December 31, 2004 and
2003, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
(Millions) | |
Cost:
|
|
|
|
|
|
|
|
|
|
Power
|
|
$ |
188.2 |
|
|
$ |
190.7 |
|
|
Gas Pipeline
|
|
|
8,140.3 |
|
|
|
7,949.1 |
|
|
Exploration & Production(1)
|
|
|
3,690.6 |
|
|
|
3,235.7 |
|
|
Midstream Gas & Liquids(1)
|
|
|
4,189.9 |
|
|
|
4,126.7 |
|
|
Other
|
|
|
243.8 |
|
|
|
250.2 |
|
|
|
|
|
|
|
|
|
|
|
16,452.8 |
|
|
|
15,752.4 |
|
Accumulated depreciation, depletion and amortization
|
|
|
(4,566.0 |
) |
|
|
(4,018.4 |
) |
|
|
|
|
|
|
|
|
|
$ |
11,886.8 |
|
|
$ |
11,734.0 |
|
|
|
|
|
|
|
|
|
|
(1) |
Certain assets above are currently pledged as collateral to
secure debt (see Note 11). |
Depreciation, depletion and amortization expense for property,
plant and equipment was $667.4 million in 2004,
$655.6 million in 2003 and $644.8 million in 2002.
Property, plant and equipment includes approximately
$218 million at December 31, 2004 and
$676 million at December 31, 2003 of construction in
progress which is not yet subject to depreciation. In addition,
property of Exploration & Production includes
approximately $561 million at December 31, 2004 and
$675 million at December 31, 2003 of capitalized costs
related to properties with unproven reserves not yet subject to
depletion. Additionally, property of Exploration &
Production includes approximately $1.5 billion (net of
approximately $276 million of accumulated amortization) of
developed and undeveloped leaseholds.
Commitments for construction and acquisition of property, plant
and equipment are approximately $26 million at
December 31, 2004.
Net property, plant and equipment includes approximately
$1.2 billion at December 31, 2004 and 2003, related to
amounts in excess of the original cost of the regulated
facilities within Gas Pipeline 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.
We adopted SFAS No. 143, Accounting for Asset
Retirement Obligations on January 1, 2003. As a
result, we recorded a liability of $33.4 million
representing the present value of expected future asset
retirement obligations at January 1, 2003, and an increase
to earnings of $1.2 million reflected as a cumulative
effect of a change in accounting principle. The asset retirement
obligation at December 31, 2004 and December 31, 2003
is $55 million and $39 million, respectively. The
increase in the obligation in 2004 is primarily due to new
assets placed in service and revised estimated retirement dates.
The obligations relate to producing wells, offshore platforms,
underground storage caverns and gas gathering well connections.
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 dismantle
offshore platforms, and to cap certain gathering pipelines at
the wellhead connection and remove any related surface
equipment. We have not recorded liabilities for pipeline
transmission assets, processing assets, and gas gathering
systems pipelines. A reasonable estimate of the fair value of
the retirement obligations for these
130
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
assets cannot be made as the remaining life of these assets is
not currently determinable. If the Statement had been in effect
at the beginning of 2002, the impact to our 2002 income from
continuing operations and net income would have been immaterial.
There would have been no impact on earnings per share.
|
|
Note 10. |
Accounts payable and accrued liabilities |
Under our cash-management system, certain subsidiaries
cash accounts reflect credit balances to the extent checks
written have not been presented for payment. Accounts payable
includes approximately $6 million of these credit balances
at December 31, 2004 and $27 million at
December 31, 2003.
On May 26, 2004, we were released from certain historical
indemnities, primarily related to environmental remediation, for
an agreement to pay $117.5 million (see Note 15). We
had previously deferred $113 million of a gain on sale
related to these indemnities. At the date of sale, the deferred
revenue and identified obligations related to the indemnities
totaled $102 million. At December 31, 2004, the
carrying value of this settlement is $74.8 million. We will
pay the balance in three installments of $27.5 million,
$20 million, and $35 million on July 1, 2005,
2006 and 2007, respectively.
We have provided guarantees in the event of nonpayment by our
previously owned communications subsidiary, WilTel, on certain
lease performance obligations that extend through 2042 and have
a maximum potential exposure of approximately $49 million
at December 31, 2004. Our exposure declines systematically
throughout the remaining term of WilTels obligations.
Accrued liabilities at December 31, 2004 and 2003, are as
follows:
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
(Millions) | |
Interest
|
|
$ |
238.2 |
|
|
$ |
269.7 |
|
Employee costs
|
|
|
151.3 |
|
|
|
153.6 |
|
Taxes other than income taxes
|
|
|
109.1 |
|
|
|
101.2 |
|
Net lease obligation
|
|
|
35.6 |
|
|
|
59.7 |
|
Guarantees and payment obligations related to WilTel
|
|
|
44.4 |
|
|
|
46.1 |
|
Deposits received from customers relating to energy risk
management and trading and hedging activities
|
|
|
17.7 |
|
|
|
25.8 |
|
Income taxes
|
|
|
4.0 |
|
|
|
6.2 |
|
Structured indemnity settlement
|
|
|
26.7 |
|
|
|
|
|
Other
|
|
|
364.7 |
|
|
|
325.6 |
|
|
|
|
|
|
|
|
|
|
$ |
991.7 |
|
|
$ |
987.9 |
|
|
|
|
|
|
|
|
131
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
Note 11. |
Debt, leases and banking arrangements |
Notes payable and long-term debt
Notes payable and long-term debt at December 31, 2004 and
2003, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- | |
|
|
|
|
Average | |
|
December 31, | |
|
|
Interest | |
|
| |
|
|
Rate(1) | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Secured notes payable
|
|
|
|
|
|
$ |
|
|
|
$ |
3.3 |
|
|
|
|
|
|
|
|
|
|
|
Long-term debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Secured long-term debt(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes, 6.62%-9.45%, payable through 2016
|
|
|
8.0 |
% |
|
$ |
219.7 |
|
|
$ |
243.7 |
|
|
|
Notes, adjustable rate, payable through 2016
|
|
|
4.6 |
% |
|
|
587.3 |
|
|
|
602.5 |
|
|
Unsecured long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debentures, 5.5%-10.25%, payable through 2033
|
|
|
7.1 |
% |
|
|
1,408.4 |
|
|
|
1,645.2 |
|
|
|
Notes, 5.935%-9.25%, payable through 2032
|
|
|
7.7 |
% |
|
|
5,671.3 |
|
|
|
9,404.3 |
|
|
|
Note, adjustable rate, due 2008
|
|
|
3.8 |
% |
|
|
75.0 |
|
|
|
|
|
|
|
Other, payable through 2007
|
|
|
6.0 |
% |
|
|
.3 |
|
|
|
79.3 |
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt, including current portion
|
|
|
|
|
|
|
7,962.0 |
|
|
|
11,975.0 |
|
|
Long-term debt due within one year
|
|
|
|
|
|
|
(250.1 |
) |
|
|
(935.2 |
) |
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
|
|
|
$ |
7,711.9 |
|
|
$ |
11,039.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
At December 31, 2004 |
|
(2) |
Includes $492.5 million and $497.5 million of
long-term debt secured by substantially all of the assets of
Williams Production RMT Company at December 31, 2004 and
2003. The value of these assets significantly exceeds the
outstanding debt. The remaining $314.5 million and
$348.7 million at December 31, 2004 and 2003,
respectively, of long-term debt is collateralized by certain
fixed assets of our Venezuelan subsidiary with a net book value
of $444.6 million and $466.3 million at
December 31, 2004 and 2003, respectively. |
Long-term debt for 2004 and 2003 includes $73.1 million and
$1.1 billion, respectively, of FELINE PACS, payable in 2007
associated with our FELINE PACS offering.
|
|
|
Recent significant events |
On February 25, our Exploration & Production
segment amended its $500 million secured variable rate
note. The amendment reduced the floating interest rate from the
London InterBank Offered Rate (LIBOR) plus
3.75 percent to LIBOR plus 2.5 percent. The amendment
also extended the maturity date from May 30, 2007 to
May 30, 2008. The amendment provides for an additional
reduction in the interest rate by 25 basis points, or
0.25 percent, if we meet certain credit-rating
requirements. The significant covenants were not altered by the
amendment.
On March 15, we retired $679 million of senior,
unsecured 9.25 percent notes. The amount represented the
outstanding balance remaining after the fourth-quarter 2003
tender that retired $721 million of the original
$1.4 billion balance.
132
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In June, we retired approximately $1.34 billion aggregate
principal amount of a specified series of our outstanding notes
and debentures. In May, we also repurchased approximately
$255 million of various notes with maturity dates ranging
from 2006 to 2011. In conjunction with these tendered notes and
debentures and related consents, and early retirements, we paid
premiums of approximately $79 million. The premiums, as
well as related fees and expenses together totaling
approximately $97 million, are recorded as early debt
retirement costs.
On July 20, WilPro Energy Services (PIGAP II) Limited,
one of our subsidiaries, received a notice of default from the
Venezuelan state oil company, Petroleos de Venezuela S.A.
(PDVSA), relating to certain operational issues alleging that
our subsidiary is not in compliance under a services agreement
with PDVSA. We do not believe there is a basis for such notice.
The notice of default from PDVSA could have resulted in an event
of default with respect to project loans totaling approximately
$208 million. On January 10, 2005, we obtained a
waiver from the lenders concerning the notice of default from
PDVSA. The waiver will immediately terminate if PDVSA takes any
action evidencing their intention to pursue any right or remedy
for the alleged event of default. To date, PDVSA has not taken
any action, nor given us any indication that they will take any
action, to pursue any such right or remedy relating to this
matter. Moreover, in February of 2005, PDVSA provided us with a
letter confirming that there is no current event of default
under the services agreement. Since there is no current event of
default, we will continue to classify this debt as non-current
on our balance sheet.
In September, we retired approximately $793 million of our
8.625 percent senior notes due 2010. In conjunction with
these tendered notes and related consents, we paid premiums of
approximately $134.5 million. The premiums, as well as
related fees and expenses, together totaling approximately
$154.7 million, are recorded as early debt retirement costs.
On October 18, we completed an offer to exchange up to
43.9 million of our FELINE PACS in the form of Income PACS
for one share of our common stock plus $1.47 in cash for each
unit. The exchange resulted in approximately 33.1 million
of the 44 million issued and outstanding units being
tendered and accepted for exchange. The exchange offer reduced
our 6.5 percent notes, due 2007, by approximately
$827 million and increased our common stock outstanding by
33.1 million shares. The effect of the exchange, including
a pre-tax charge for related expenses of approximately
$25 million, was recorded as early debt retirement costs in
the fourth quarter. Following the exchange and in connection
with the remarketing of the remaining senior notes, we retired
approximately $200 million additional notes on
November 16. A pre-tax charge for remarketing expenses of
approximately $5 million was recorded in the fourth
quarter. At December 31, 2004, approximately
$73 million of the original $1.1 billion note
obligation and 10.9 million equity forward contracts remain
outstanding. The remaining equity forward contracts were
exercised on February 16, 2005, and the remaining notes are
due on February 16, 2007. As a result of the
November 16, remarketing, the interest rate on the
remaining obligation was reset to 5.935 percent. See
Note 12 for additional information.
|
|
|
Revolving credit and letter of credit facilities |
In April 2004, we entered into two unsecured bank revolving
credit facilities totaling $500 million. These facilities
provide for both borrowings and issuing letters of credit, but
are used primarily for issuing letters of credit. At
December 31, 2004, letters of credit totaling
$472 million have been issued by the participating
financial institution under these facilities and no revolving
credit loans were outstanding. We are required to pay to the
bank fixed fees at a weighted-average rate of 3.64 percent
on the total committed amount of the facilities. In addition, we
pay interest on any borrowings at a fluctuating rate comprised
of either a base rate or LIBOR. We were able to obtain the
unsecured credit facilities because the funding bank syndicated
its associated credit risk into the institutional investor
market, which allows for the resale of certain restricted
securities to qualified institutional buyers. Upon the
occurrence of certain credit events, letters of credit
outstanding under the agreement become cash collateralized
creating a borrowing under the facilities.
133
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Concurrently the bank can deliver the facilities to the
institutional investors, whereby the investors replace the bank
as lender under the facilities. Upon such occurrence, we will
pay:
|
|
|
|
|
a fixed facility fee at a weighted average rate of
3.19 percent to the investors, |
|
|
|
interest on borrowings under the $400 million facility
equal to a fixed rate of 3.57 percent, and |
|
|
|
interest on borrowings under the $100 million facility at a
fluctuating LIBOR interest rate. |
To facilitate the syndication of these facilities, the bank
established trusts funded by the institutional investors. The
assets of the trusts serve as collateral to reimburse the bank
for our borrowings in the event the facilities are delivered to
the investors. Thus, we have no asset securitization or
collateral requirements under the new facilities. During
second-quarter 2004, use of these new facilities replaced
existing facilities and released a total of approximately
$500 million of restricted cash, restricted investments and
margin deposits which secured our previous $800 million
revolving and letter of credit facility.
In January 2005, these facilities were terminated and replaced
with two new facilities via an exchange offer and consent
solicitation carried out by the bank. The two new facilities
contain the same terms outlined above, but almost all of the
restrictive covenants and events of default in the previous
credit agreements were removed or made less restrictive. As a
result, as of January 20, 2005, the restrictive covenants
no longer limit the following:
|
|
|
|
|
certain payments, including investments and the payment of
quarterly dividends to no greater than $.05 per common
share; |
|
|
|
asset sales; |
|
|
|
the use of proceeds from permitted asset sales; |
|
|
|
transactions with affiliates; and |
|
|
|
the incurrence of additional indebtedness and issuance of
disqualified stock. |
On May 3, 2004, we entered into a new three-year,
$1 billion secured revolving credit facility which is
available for borrowings and letters of credit. The previous
$800 million revolver and letter of credit facility was
terminated. In August 2004, we expanded the credit facility by
an additional $275 million. At December 31, 2004,
letters of credit totaling $422 million have been issued by
the participating institutions under this facility and no
revolving credit loans were outstanding. Northwest Pipeline and
Transco have access to $400 million each under the facility. The
new facility is secured by certain Midstream assets, including
substantially all of our southwest Wyoming, Wamsutter,
San Juan Conventional, Manzanares and Torre Alta systems.
Additionally, the facility is guaranteed by WGP. Interest is
calculated based on a choice of two methods: a fluctuating rate
equal to the facilitating banks base rate plus an
applicable margin or a periodic fixed rate equal to LIBOR plus
an applicable margin. We are also required to pay a commitment
fee (currently .375 percent annually) based on the unused
portion of the facility. The applicable margins and commitment
fee are based on the relevant borrowers senior unsecured
long-term debt ratings. Significant financial covenants under
the credit agreement include the following.
|
|
|
|
|
Ratio of debt to capitalization no greater than
(i) 75 percent for the period June 30, 2004
through December 31, 2004, (ii) 70 percent for
the period after December 31, 2004 through
December 31, 2005, and (iii) 65 percent for the
remaining term of the agreement. At December 31, 2004, we
are in compliance with this covenant as our ratio of debt to
capitalization is approximately 61 percent. |
|
|
|
Ratio of debt to capitalization no greater than 55 percent
for Northwest Pipeline and Transco. |
|
|
|
Ratio of EBITDA to Interest, on a rolling four quarter basis
(or, in the first year, building up to a rolling four quarter
basis), no less than (i) 1.5 for the periods ending
September 30, 2004 through |
134
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
March 31, 2005, (ii) 2.0 for any period after
March 31, 2005 through December 31, 2005, and
(iii) 2.5 for the remaining term of the agreement. Through
December 31, 2004, we are in compliance with this covenant
as we exceed the compliance level by approximately
90 percent. |
|
|
|
Issuances and Retirements |
A summary of significant issuances and payments of long-term
debt for the year ended December 31, 2004, including the
retirements discussed above, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal | |
Issue/Terms |
|
Due Date | |
|
Amount | |
|
|
| |
|
| |
|
|
|
|
(Millions) | |
Issuances of long-term debt in 2004:
|
|
|
|
|
|
|
|
|
|
Floating rate senior unsecured notes
|
|
|
2008 |
|
|
$ |
75.0 |
|
Retirements/prepayments of long-term debt in 2004:
|
|
|
|
|
|
|
|
|
|
6.5% senior notes (FELINE PACS exchange offer)
|
|
|
2007 |
|
|
|
827.2 |
|
|
8.625% senior notes
|
|
|
2010 |
|
|
|
792.8 |
|
|
9.25% senior unsecured notes
|
|
|
2004 |
|
|
|
678.5 |
|
|
6.75% Putable Asset Term Securities
|
|
|
2006 |
|
|
|
370.3 |
|
|
6.5% unsecured notes
|
|
|
2006 |
|
|
|
251.4 |
|
|
6.25% unsecured debentures
|
|
|
2006 |
|
|
|
231.0 |
|
|
6.5% unsecured notes
|
|
|
2008 |
|
|
|
221.9 |
|
|
5.935% senior notes (FELINE PACS remarketing)
|
|
|
2007 |
|
|
|
199.7 |
|
|
7.55% unsecured notes
|
|
|
2007 |
|
|
|
118.8 |
|
|
6.625% unsecured notes
|
|
|
2004 |
|
|
|
127.5 |
|
|
7.25% unsecured notes
|
|
|
2009 |
|
|
|
85.0 |
|
|
Long-term debt collateralized by certain receivables
|
|
|
N/A |
|
|
|
78.7 |
|
|
7.125% unsecured notes
|
|
|
2011 |
|
|
|
60.0 |
|
|
Various notes, 2.86%-9.45%, including adjustable rate
|
|
|
2007-2016 |
|
|
|
46.7 |
|
Aggregate minimum maturities of long-term debt for each of the
next five years are as follows:
|
|
|
|
|
|
|
(Millions) | |
|
|
| |
2005
|
|
$ |
246.8 |
|
2006
|
|
|
119.0 |
|
2007
|
|
|
396.3 |
|
2008
|
|
|
715.6 |
|
2009
|
|
|
53.1 |
|
Cash payments for interest (net of amounts capitalized) were as
follows: 2004 $849 million; 2003
$1.3 billion; and 2002 $856 million.
Terms of certain of our subsidiaries borrowing
arrangements with lenders limit the transfer of funds to the
corporate parent. At December 31, 2004, approximately
$165 million of net assets of consolidated subsidiaries was
restricted. Of this amount, $91 million is reported as
restricted cash on our Consolidated Balance Sheet. In addition,
certain equity method investees borrowing arrangements and
foreign government
135
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
regulations limit the amount of dividends or distributions to
the corporate parent. Restricted net assets of equity method
investees was approximately $17.4 million at
December 31, 2004.
Future minimum annual rentals under noncancelable operating
leases as of December 31, 2004, are payable as follows:
|
|
|
|
|
|
|
(Millions) | |
|
|
| |
2005
|
|
$ |
194.5 |
|
2006
|
|
|
191.1 |
|
2007
|
|
|
187.6 |
|
2008
|
|
|
185.1 |
|
2009
|
|
|
181.5 |
|
Thereafter
|
|
|
1,411.7 |
|
|
|
|
|
Total
|
|
$ |
2,351.5 |
|
|
|
|
|
The above amounts include obligations of approximately
$2.17 billion related to a tolling agreement at Power that
is now accounted for as an operating lease as a result of
changes to the contract terms subsequent to our implementation
of EITF 01-8 (see Note 1). Under the tolling
agreement, Power has the exclusive right to capacity and fuel
conversion services as well as ancillary services associated
with electric generation facilities that are currently in
operation in southern California. Current annual rentals under
this tolling agreement are approximately $162 million with
approximately 13 years remaining on the agreement as of
December 31, 2004. These rentals are substantially offset
through year 2010 with income from sales and other transactions
made possible by the tolling agreement.
Total rent expense was $206 million in 2004,
$110 million in 2003 and $93 million in 2002. Included
in 2004 rent expense was $136 million at Power related
primarily to a tolling agreement, including $9 million of
contingent rentals which are primarily based on utilization of
the leased property or changes in the capacity of the power
generating facility. Income from sales and other transactions
made possible by the tolling agreement was approximately
$129 million in 2004, and includes $6 million of
contingent rental income.
|
|
Note 12. |
Stockholders equity |
Concurrent with the sale of Kern River to MidAmerican Energy
Holdings Company (MEHC) on March 27, 2002, we issued
approximately 1.5 million shares of 9.875 percent
cumulative convertible preferred stock to MEHC for
$275 million. The terms of the preferred stock allowed the
holder to convert, at any time, one share of preferred stock
into 10 shares of our common stock at $18.75 per
share. The preferred shares carried no voting rights and had a
liquidation preference equal to the stated value of
$187.50 per share plus any dividends accumulated and
unpaid. Dividends on the preferred stock were payable quarterly.
At the time the preferred stock was issued, the conversion price
was less than the market price of our common stock and thus
deemed beneficial to the purchaser. The benefit was recorded as
a noncash dividend of $69.4 million, which was a reduction
to our retained earnings with an offsetting amount recorded as
an increase to capital in excess of par value.
On June 10, 2003, we redeemed all of the outstanding
9.875 percent cumulative-convertible preferred shares for
approximately $289 million, plus $5.3 million for
accrued dividends. The $13.8 million of payments in excess
of carrying value of the shares was also recorded as a dividend.
These shares were repurchased with proceeds from a private
placement of $300 million of 5.5 percent junior
subordinated convertible debentures
136
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
due 2033. These notes, which are callable after seven years, are
convertible at the option of the holder into our common stock at
a conversion price of approximately $10.89 per share.
In January 2002, we issued $1.1 billion of 6.5 percent
notes payable in 2007 that were subject to remarketing in 2004.
Each note was bundled with an equity forward contract (together,
the FELINE PACS units) and sold in a public offering for
$25 per unit. The equity forward contract required the
holder of each note to purchase one share of our common stock
for $25 three years from issuance of the contract. On
September 17, 2004, we initiated an offer to exchange up to
43.9 million FELINE PACS units for one share of our common
stock plus $1.47 in cash for each unit. The offer resulted in
approximately 33.1 million of the 44 million issued
and outstanding units being tendered and accepted for exchange.
The exchange offer reduced our 6.5 percent notes, due 2007,
by approximately $827 million and increased our common
stock outstanding by 33.1 million shares. On
February, 16, 2005, the settlement date, the holders of the
remaining 10.9 million equity forward contracts purchased
one share of our common stock for $25.
We maintain a Stockholder Rights Plan, as amended and restated
on September 21, 2004, 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 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 |
The Williams Companies, Inc. 2002 Incentive Plan (the
Plan) was approved by stockholders on May 16,
2002, and amended and restated on May 15, 2003 and
January 23, 2004. The Plan provides for common-stock-based
awards to both employees and non-management directors. Upon
approval by the stockholders, all prior stock plans were
terminated resulting in no further grants being made from those
plans. However, awards outstanding in those prior plans remain
in those plans with their respective terms and provisions.
The Plan permits the granting of various types of awards
including, but not limited to, stock options, restricted stock
and deferred stock. Awards may be granted for no consideration
other than prior and future services or based on certain
financial performance targets being achieved. At
December 31, 2004, 49.7 million shares of our common
stock were reserved for issuance pursuant to existing and future
stock awards, of which 25.2 million shares were available
for future grants. At December 31, 2003, 56.2 million
shares of our common stock were reserved for issuance, of which
28.3 million were available.
Several of our prior stock plans allowed us to loan money to
participants to exercise stock options using stock certificates
as collateral. Effective November 14, 2001, we no longer
issue loans under the stock option loan programs. Loan holders
were offered a one-time opportunity in January 2002 to refinance
outstanding
137
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
loans at a market rate of interest commensurate with the
borrowers credit standing. The refinancing was in the form
of a full recourse note, with interest payable annually in cash
and a loan maturity date of December 31, 2005. We continue
to hold the collateral shares for certain borrowers and may
review any borrowers financial position at any time. The
variable rate of interest on the loans was determined at the
signing of the promissory note to be 1.75 percent plus the
current three-month London Interbank Offered Rate (LIBOR). The
rate is subject to change every three months beginning with the
first three-month anniversary of the note. The amount of loans
outstanding at December 31, 2004 and 2003, totaled
approximately $22 million (net of a $7 million
allowance) and $28 million (net of a $5 million
allowance), respectively.
Deferred shares are valued at the date of award. Deferred share
expense is recognized in the performance year or over the
vesting period, depending on the terms of the awards. Expense
related to forfeited shares is recognized in the year of the
forfeiture.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions, except per-share amounts) | |
Deferred shares granted
|
|
|
1.8 |
|
|
|
.2 |
|
|
|
2.7 |
|
Deferred shares issued
|
|
|
.9 |
|
|
|
1.3 |
|
|
|
.5 |
|
Weighted average fair value of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
deferred shares granted, per share
|
|
$ |
10.54 |
|
|
$ |
4.68 |
|
|
$ |
12.26 |
|
Deferred share expense
|
|
$ |
14 |
|
|
$ |
30 |
|
|
$ |
31 |
|
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 generally expire
ten years after grant.
On May 15, 2003, our shareholders approved a stock option
exchange program. Under this program, eligible employees were
given a one-time opportunity to exchange certain outstanding
options for a proportionately lesser number of options at an
exercise price to be determined at the grant date of the new
options. Surrendered options were cancelled June 26, 2003,
and replacement options were granted on December 29, 2003.
We did not recognize any expense pursuant to the stock option
exchange. However, for purposes of pro forma disclosures, we
recognized additional expense related to these new options. The
remaining pro forma expense on the cancelled options was
amortized through year-end 2004.
138
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following summary reflects stock option activity for our
common stock and related information for 2004, 2003 and 2002:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
|
|
Weighted- | |
|
|
|
Weighted- | |
|
|
|
Weighted- | |
|
|
|
|
Average | |
|
|
|
Average | |
|
|
|
Average | |
|
|
|
|
Exercise | |
|
|
|
Exercise | |
|
|
|
Exercise | |
|
|
Options | |
|
Options | |
|
Options | |
|
Price | |
|
Options | |
|
Price | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Millions) | |
|
|
|
(Millions) | |
|
|
|
(Millions) | |
|
|
Outstanding beginning of year
|
|
|
25.7 |
|
|
$ |
14.63 |
|
|
|
38.8 |
|
|
$ |
19.85 |
|
|
|
25.6 |
|
|
$ |
28.23 |
|
Granted
|
|
|
4.5 |
|
|
|
9.96 |
|
|
|
4.1 |
* |
|
|
9.76 |
|
|
|
15.8 |
|
|
|
6.64 |
|
Exercised
|
|
|
(5.5 |
) |
|
|
3.93 |
|
|
|
(.2 |
) |
|
|
5.86 |
|
|
|
(.5 |
) |
|
|
11.77 |
|
Canceled
|
|
|
(2.7 |
) |
|
|
22.35 |
|
|
|
(17.0 |
)** |
|
|
25.60 |
|
|
|
(2.1 |
) |
|
|
26.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding end of year
|
|
|
22.0 |
|
|
$ |
15.36 |
|
|
|
25.7 |
|
|
$ |
14.63 |
|
|
|
38.8 |
|
|
$ |
19.85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable end of year
|
|
|
17.1 |
|
|
$ |
16.87 |
|
|
|
12.3 |
|
|
$ |
24.23 |
|
|
|
21.7 |
|
|
$ |
27.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
Includes 3.9 million shares that were granted
December 29, 2003, under the stock option exchange program,
described above. |
|
|
** |
Includes 10.4 million shares that were cancelled on
June 26, 2003 under the stock option exchange program,
described above. |
The following summary provides information about options for our
common stock that are outstanding and exercisable at
December 31, 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options | |
|
|
Stock Options Outstanding | |
|
Exercisable | |
|
|
| |
|
| |
|
|
|
|
Weighted- | |
|
|
|
|
|
|
Weighted- | |
|
Average | |
|
|
|
Weighted- | |
|
|
|
|
Average | |
|
Remaining | |
|
|
|
Average | |
|
|
|
|
Exercise | |
|
Contractual | |
|
|
|
Exercise | |
Range of Exercise Prices |
|
Options | |
|
Price | |
|
Life | |
|
Options | |
|
Price | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Millions) | |
|
|
|
|
|
(Millions) | |
|
|
$2.27 to $5.40
|
|
|
5.2 |
|
|
$ |
2.95 |
|
|
|
7.7 years |
|
|
|
5.1 |
|
|
$ |
2.91 |
|
$6.96 to $9.93
|
|
|
4.4 |
|
|
|
9.90 |
|
|
|
8.7 years |
|
|
|
.2 |
|
|
|
9.35 |
|
$10.00 to $12.22
|
|
|
3.9 |
|
|
|
10.18 |
|
|
|
4.5 years |
|
|
|
3.5 |
|
|
|
10.19 |
|
$12.59 to $31.56
|
|
|
4.6 |
|
|
|
20.07 |
|
|
|
2.9 years |
|
|
|
4.4 |
|
|
|
20.29 |
|
$33.51 to $42.29
|
|
|
3.9 |
|
|
|
37.75 |
|
|
|
3.1 years |
|
|
|
3.9 |
|
|
|
37.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
22.0 |
|
|
$ |
15.36 |
|
|
|
5.5 years |
|
|
|
17.1 |
|
|
$ |
16.87 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The estimated fair value at date of grant of options for our
common stock granted in 2004, 2003 and 2002, using the
Black-Scholes option pricing model, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003* | |
|
2002 | |
|
|
| |
|
| |
|
| |
Weighted-average grant date fair value of options for our common
stock granted during the year
|
|
$ |
4.54 |
|
|
$ |
2.95 |
|
|
$ |
2.77 |
|
|
|
|
|
|
|
|
|
|
|
Assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend yield
|
|
|
0.4 |
% |
|
|
1 |
% |
|
|
1 |
% |
|
Volatility
|
|
|
50 |
% |
|
|
50 |
% |
|
|
56 |
% |
|
Risk-free interest rate
|
|
|
3.3 |
% |
|
|
3.1 |
% |
|
|
3.6 |
% |
|
Expected life (years)
|
|
|
5.0 |
|
|
|
5.0 |
|
|
|
5.0 |
|
139
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
* |
The 2003 weighted average fair value and assumptions do not
reflect options that were granted December 29, 2003, as
part of the stock option exchange program which is described
above. The fair value of these options is $1.58, which is the
difference in the fair value of the new options granted and the
fair value of the exchanged options. The assumptions used in the
fair value calculation of the new options granted were:
1) dividend yield of .40 percent; 2) volatility
of 50 percent; 3) weighted average expected remaining
life of 3.4 years; and 4) weighted average risk free
interest rate of 1.99 percent. |
Pro forma net income (loss) and earnings per share, assuming we
had applied the fair-value method of SFAS No. 123,
Accounting for Stock-Based Compensation, in
measuring compensation cost beginning with 1997 employee
stock-based awards is disclosed under Employee stock-based
awards in Note 1.
|
|
Note 14. |
Financial instruments, derivatives, guarantees and
concentration of credit risk |
|
|
|
Financial instruments fair value |
We used the following methods and assumptions in estimating our
fair-value disclosures for financial instruments:
Cash and Cash Equivalents and Restricted Cash: The
carrying amounts of cash equivalents reported in the balance
sheet approximate fair value due to the short-term maturity of
these instruments.
Notes and Other Non-current Receivables, Margin Deposits and
Deposits Received from Customers Relating to Energy Trading and
Hedging Activities: The carrying amounts reported in the
balance sheet approximate fair value as these instruments have
interest rates approximating market.
Restricted Investments: The 2003 restricted investments
consisted of short-term U.S. Treasury securities. Fair
value was determined using indicative year-end traded prices.
Advances to Affiliates: The 2003 carrying amounts
reported in the balance sheet approximated fair value as these
instruments were written down to estimated fair value based on
terms of a recapitalization plan (see Note 3).
Notes Payable: The carrying amounts of notes payable
approximated fair value due to the short-term maturity of these
instruments.
Long-Term Debt: The fair value of our publicly traded
long-term debt is valued using indicative year-end traded bond
market prices. Private debt is valued based on the prices of
similar securities with similar terms and credit ratings. At
December 31, 2004 and 2003, 89 percent and
92 percent, respectively, of our long-term debt was
publicly traded. We used the expertise of outside investment
banking firms to assist with the estimate of the fair value of
long-term debt.
Energy Derivatives: Energy derivatives include:
|
|
|
|
|
futures contracts, |
|
|
|
forward purchase and sale contracts, |
|
|
|
swap agreements, |
|
|
|
option contracts, and |
|
|
|
interest-rate swap agreements and futures contracts. |
Fair value of energy derivatives is determined based on the
nature of the transaction and the market in which transactions
are executed. Most of these transactions are executed in
exchange-traded or over-the-
140
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
counter markets for which quoted prices in active periods exist.
For contracts with lives exceeding the time period for which
quoted prices are available, we determined fair value by
estimating commodity prices during the illiquid periods. We
estimated commodity prices during illiquid periods by
incorporating information obtained from commodity prices in
actively quoted markets, prices reflected in current
transactions and market fundamental analysis.
Foreign Currency Derivatives: Fair value was determined
by discounting estimated future cash flows using forward foreign
exchange rates derived from the year-end forward exchange curve.
Interest-Rate Swaps: Fair value was determined by
discounting estimated future cash flows using forward-interest
rates derived from the year-end yield curve.
|
|
|
Carrying Amounts and Fair Values of Our Financial
Instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
Carrying | |
|
Fair | |
|
Carrying | |
|
Fair | |
Asset (Liability) |
|
Amount | |
|
Value | |
|
Amount | |
|
Value | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Millions) | |
Cash and cash equivalents
|
|
$ |
930.0 |
|
|
$ |
930.0 |
|
|
$ |
2,315.7 |
|
|
$ |
2,315.7 |
|
Restricted cash (current and noncurrent)
|
|
|
112.7 |
|
|
|
112.7 |
|
|
|
206.9 |
|
|
|
206.9 |
|
Notes and other noncurrent receivables
|
|
|
80.0 |
|
|
|
80.5 |
|
|
|
140.0 |
|
|
|
140.0 |
|
Investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost based investments
|
|
|
69.7 |
|
|
|
(a |
) |
|
|
112.7 |
|
|
|
(a |
) |
|
Restricted investments (current and noncurrent)
|
|
|
|
|
|
|
|
|
|
|
381.3 |
|
|
|
381.3 |
|
|
Advances to affiliates
|
|
|
|
|
|
|
|
|
|
|
117.2 |
|
|
|
117.2 |
|
Notes payable
|
|
|
|
|
|
|
|
|
|
|
(3.3 |
) |
|
|
(3.3 |
) |
Long-term debt, including current portion
|
|
|
(7,962.0 |
) |
|
|
(8,857.2 |
) |
|
|
(11,975.0 |
) |
|
|
(12,291.5 |
) |
Structured Indemnity settlement (see Note 15)
|
|
|
(74.8 |
) |
|
|
(74.8 |
) |
|
|
|
|
|
|
|
|
Margin deposits
|
|
|
131.7 |
|
|
|
131.7 |
|
|
|
553.9 |
|
|
|
553.9 |
|
Deposits received from customers relating to energy risk
management and trading and hedging activities
|
|
|
(17.7 |
) |
|
|
(17.7 |
) |
|
|
(25.8 |
) |
|
|
(25.8 |
) |
Guarantees
|
|
|
45.0 |
|
|
|
(b |
) |
|
|
46.8 |
|
|
|
(b |
) |
Energy derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy trading and non-trading derivatives
|
|
|
718.7 |
|
|
|
718.7 |
|
|
|
842.6 |
|
|
|
842.6 |
|
|
Energy commodity cash flow hedges
|
|
|
(328.8 |
) |
|
|
(328.8 |
) |
|
|
(295.8 |
) |
|
|
(295.8 |
) |
Foreign currency derivatives
|
|
|
|
|
|
|
|
|
|
|
(55.2 |
) |
|
|
(55.2 |
) |
Interest-rate swaps
|
|
|
|
|
|
|
|
|
|
|
(20.2 |
) |
|
|
(20.2 |
) |
Other derivatives
|
|
|
1.4 |
|
|
|
1.4 |
|
|
|
2.7 |
|
|
|
2.7 |
|
|
|
|
(a) |
|
These investments are primarily in non-publicly traded companies
for which it is not practicable to estimate fair value. |
|
(b) |
|
It is not practicable to estimate the fair value of these
financial instruments because of their unusual nature and unique
characteristics. |
141
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
Energy trading and non-trading derivatives not utilized in
hedging activities |
We have energy trading and non-trading derivatives that have not
been designated as or do not qualify as SFAS No. 133
hedges. As such, the net change in their fair value is
recognized in revenues in the Consolidated Statement of
Operations. Our Power segment has trading derivatives that
provide risk management services to our third-party customers
and non-trading derivatives that hedge or could possibly hedge
our long-term structured contract positions on an economic
basis. Certain of our non-trading derivatives became eligible to
be and were designated as SFAS No. 133 cash flow
hedges after our decision to retain our power business. Many of
these non-trading derivatives had an existing fair value prior
to their designation as cash flow hedges. In addition, our
Exploration & Production segment enters into natural
gas basis swap agreements that are not designated in a hedging
relationship under SFAS No. 133.
We also hold significant non-derivative energy-related contracts
in our Power trading and non-trading portfolios. These have not
been included in the financial instruments table above because
they do not qualify as financial instruments. See Note 1
regarding Energy commodity risk management and trading
activities for further discussion of the non-derivative
energy-related contracts.
|
|
|
Derivative contracts include the following: |
Futures Contracts: Futures contracts are commitments to
either purchase or sell a commodity at a future date for a
specified price and are generally settled in cash, but may be
settled through delivery of the underlying commodity.
Exchange-traded or over-the-counter markets providing quoted
prices in active periods are available. Where quoted prices are
not available, other market indicators exist for the futures
contracts we enter into. The fair value of these contracts is
based on quoted prices.
Swap Agreements and Forward Purchase and Sale Contracts:
Swap agreements require us to make payments to (or receive
payments from) counterparties based upon the differential
between a fixed and variable price or variable prices of energy
commodities for different locations. Forward contracts, which
involve physical delivery of energy commodities, contain both
fixed and variable pricing terms. Swap agreements and forward
contracts are valued based on prices of the underlying energy
commodities over the contract life and contractual or notional
volumes with the resulting expected future cash flows discounted
to a present value using a risk-free market interest rate.
Options: Physical and financial option contracts give the
buyer the right to exercise the option and receive the
difference between a predetermined strike price and a market
price at the date of exercise. These contracts are valued based
on option pricing models considering prices of the underlying
energy commodities over the contract life, volatility of the
commodity prices, contractual volumes, estimated volumes under
option and other arrangements and a risk-free market interest
rate.
Interest-Rate Derivatives: Interest-rate swap and futures
agreements, including those with the parent, were used to manage
the interest rate risk in Powers energy trading and
non-trading portfolio. Under swap agreements, Power paid a fixed
rate and received a variable rate on the notional amount of the
agreements. Financial futures contracts were commitments to
either purchase or sell a financial instrument, such as a
Eurodollar deposit, U.S. Treasury bond or
U.S. Treasury note, at a future date for a specified price.
These were generally settled in cash, but could have been
settled through delivery of the underlying instrument. The fair
value of these contracts was determined by discounting estimated
future cash flows using forward interest rates derived from
interest rate yield curves. The corporate parent determined the
level, term and nature of derivative instruments entered into
with external parties. These external derivative instruments did
not qualify for hedge accounting per SFAS 133; therefore,
changes in their fair value were reflected in earnings, the
effect of which is shown as interest rate swap loss in the
Consolidated Statement of Operations below operating income. We
terminated or liquidated all remaining interest-rate derivatives
in fourth quarter 2004.
142
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
We execute most of these transactions in exchange-traded or
over-the-counter markets for which quoted prices in active
periods exist. For contracts with terms that exceed the time
period for which actively quoted prices are available, we must
estimate commodity prices during the illiquid periods when
determining fair value. We estimate commodity prices during
illiquid periods utilizing internally developed valuations
incorporating information obtained from commodity prices in
actively quoted markets, quoted prices in less active markets,
prices reflected in current transactions and other market
fundamental analysis.
|
|
|
Energy commodity cash flow hedges |
We are exposed to market risk from changes in energy commodity
prices within our operations. We utilize derivatives to manage
our exposure to the variability in expected future cash flows
attributable to commodity price risk associated with forecasted
purchases of natural gas and electricity, capacity as well as
forecasted purchases and sales of electricity. These derivatives
have been designated as cash flow hedges.
Our Power segment sells electricity produced by our electric
generation facilities, obtained contractually through tolling
agreements or obtained through marketplace transactions at
different locations throughout the United States. We also buy
electricity and capacity to serve our full requirements
agreements in the Southeast. To reduce exposure to a decrease in
revenues and increase in costs from fluctuations in electricity
prices, we enter into fixed-price forward physical sales and
purchase contracts to fix the price of anticipated electricity
sales and electricity and capacity purchases, respectively.
Our electric generation facilities and tolling agreements
require natural gas for the production of electricity. To reduce
the exposure to increasing costs of natural gas due to changes
in market prices, we enter into natural gas futures contracts,
swap agreements and fixed-price forward physical purchases to
fix the prices of anticipated purchases of natural gas.
Powers cash flow hedges are expected to be highly
effective in achieving 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, changes in the creditworthiness of counterparties
and the hedging derivative contract having a fair value upon
designation.
Our Exploration & Production segment produces, buys and
sells natural gas at different locations throughout the United
States. To reduce exposure to a decrease in revenues from
fluctuations in natural gas market prices, we hedge price risk
by entering into natural gas futures contracts and swap
agreements to fix the price of anticipated sales and purchases
of natural gas. We also enter into basis swap agreements as part
of our overall natural gas price risk management program to
reduce the locational price risk associated with our producing
basins. Exploration & Productions cash flow
hedges are expected to be highly effective in achieving
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.
Changes in the fair value of our cash flow hedges are deferred
in other comprehensive income and are reclassified into revenues
in the same period or periods during which the hedged forecasted
purchases or sales affect earnings or when it is probable that
the hedged forecasted transaction will not occur either by the
end of the originally specified time period or within an
additional two-month period. Approximately $13 million of
net gains from hedge ineffectiveness is included in revenues in
the Consolidated Statement of Operations during 2004. Hedge
ineffectiveness in 2003 was immaterial. We discontinued hedge
accounting in 2003 for certain contracts when it became probable
that the related forecasted transactions would not occur. As a
result, we reclassified net losses of $5 million out of
accumulated other comprehensive income and into revenues in the
Consolidated Statement of Operations in 2003. For 2004 and 2003,
there were no derivative gains or losses excluded from the
assessment of hedge effectiveness. As of December 31, 2004,
we had hedged portions of future cash flows associated with
anticipated energy commodity purchases and sales for up to
143
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
8 years. Based on recorded values at December 31,
2004, approximately $124 million of net losses (net of
income tax benefits of $77 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, 2004. Due to the volatile nature of commodity
prices and changes in the creditworthiness of counterparties,
actual gains or losses realized in 2005 will likely differ from
these values. These gains or losses will offset net losses or
gains that will be realized in earnings from previous
unfavorable or favorable market movements associated with
underlying hedged transactions.
|
|
|
Foreign currency derivatives |
Until July 2004, we had an intercompany
Canadian-dollar-denominated note receivable that was exposed to
foreign-currency risk. We entered into a forward contract to fix
the U.S. dollar principal cash flows from this note. This
derivative was designated as a cash flow hedge and was expected
to be highly effective over the period of the hedge. Hedge
accounting was discontinued effective October 1, 2002
because the hedge was no longer expected to be highly effective.
All gains or losses subsequent to October 1, 2002, were
recognized in other income (expense) net below
operating income. Gains and losses from the change in fair value
of the derivatives prior to October 1, 2002, were deferred
in other comprehensive income (loss) and reclassified to other
income (expense) net below operating income as the
Canadian-dollar-denominated note receivable impacted earnings as
it was translated into U.S. dollars. The $2.4 million
of net losses (net of income tax benefits of $1.5 million)
deferred in other comprehensive income (loss) at
December 31, 2002, was reclassified into earnings during
2003. In 2002, there were no derivative gains or losses recorded
in the Consolidated Statement of Operations from hedge
ineffectiveness or from amounts excluded from the assessment of
hedge effectiveness, and no foreign currency hedges were
discontinued as a result of it becoming probable that the
forecasted transaction would not occur.
In addition to the guarantees and payment obligations discussed
elsewhere in these footnotes (see Notes 3 and 10), we have
issued guarantees and other similar arrangements with
off-balance sheet risk as discussed below.
In connection with the 1993 public offering of units in the
Williams Coal Seam Gas Royalty Trust (Royalty Trust), our
Exploration & Production segment entered into a gas
purchase contract for the purchase of natural gas in which the
Royalty Trust holds a net profits interest. Under this
agreement, we guarantee a minimum purchase price that the
Royalty Trust will realize in the calculation of its net profits
interest. We have an annual option to discontinue this minimum
purchase price guarantee and pay solely based on an index price.
The maximum potential future exposure associated with this
guarantee is not determinable because it is dependent upon
natural gas prices and production volumes. No amounts have been
accrued for this contingent obligation as the index price
continues to substantially exceed the minimum purchase price.
A foreign bank is a defendant in litigation related to a loan
they provided to us. We have repaid the loan and indemnified the
bank for legal fees and potential losses that may result from
this litigation. We are unable to determine the maximum amount
of future payments that we could be required to pay as it is
dependent upon the ultimate resolution of the claim. However, we
believe the probability is remote that a judgment will be made
against the bank that we will have to pay. We have accrued
$0.1 million at December 31, 2004, related to this
guarantee.
We are required by certain foreign lenders to ensure that the
interest rates received by them under various loan agreements
are not reduced by taxes by providing for the reimbursement of
any domestic taxes required to be paid by the foreign lender.
The maximum potential amount of future payments under these
indemnifications is based on the related borrowings, generally
continue indefinitely unless limited by the
144
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
underlying tax regulations, and have no carrying value. We have
never been called upon to perform under these indemnifications.
|
|
|
Concentration of credit risk |
|
|
|
Cash equivalents and restricted investments |
Our cash equivalents consist of high-quality securities placed
with various major financial institutions with credit ratings at
or above BBB by Standard & Poors or Baa1 by
Moodys Investors Service. Restricted investments consisted
of short-term U.S. Treasury Securities.
|
|
|
Accounts and notes receivable |
The following table summarizes concentration of receivables, net
of allowances, by product or service at December 31, 2004
and 2003:
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
(Millions) | |
Receivables by product or service:
|
|
|
|
|
|
|
|
|
|
Sale or transportation of natural gas and related products
|
|
$ |
859.0 |
|
|
$ |
793.9 |
|
|
Power sales and related services
|
|
|
441.9 |
|
|
|
704.9 |
|
|
Income taxes receivable
|
|
|
1.1 |
|
|
|
17.5 |
|
|
Other
|
|
|
120.8 |
|
|
|
96.9 |
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
1,422.8 |
|
|
$ |
1,613.2 |
|
|
|
|
|
|
|
|
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, Venezuela and Canada. Power customers include the
California Independent System Operator (ISO), the California
Department of Water Resources, other power marketers and
utilities located throughout the majority of the United States.
Other receivables in 2004 includes a $54.1 million
receivable from WilTel. We sold this receivable in January 2005,
for $54.6 million. Other receivables for 2003 include sales
or transportation of petroleum products. As a general policy,
collateral is not required for receivables, but customers
financial condition and credit worthiness are evaluated
regularly.
As of December 31, 2004, Power had approximately
$61 million of certain power receivables net of related
allowances from the ISO and the California Power Exchange
(compared to $177 million at December 31, 2003). We
believe that we have appropriately reflected the collection and
credit risk associated with receivables and derivative assets in
our Consolidated Balance Sheet and Statement of Operations at
December 31, 2004.
|
|
|
Derivative assets and liabilities |
We have a risk of loss as a result of counterparties not
performing pursuant to the terms of their contractual
obligations. Risk of loss can result from credit considerations
and the regulatory environment of the counterparty. 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.
145
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The concentration of counterparties within the energy and energy
trading industry impacts our overall exposure to credit risk in
that these counterparties are similarly influenced by changes in
the economy and regulatory issues. Additional collateral support
could include the following:
|
|
|
|
|
letters of credit, |
|
|
|
payment under margin agreements, |
|
|
|
guarantees of payment by credit worthy parties, and |
|
|
|
transfers of ownership interests in natural gas reserves or
power generation assets. |
We also enter into netting agreements to mitigate counterparty
performance and credit risk.
The gross credit exposure from our derivative contracts as of
December 31, 2004 is summarized below.
|
|
|
|
|
|
|
|
|
|
|
Investment | |
|
|
Counterparty Type |
|
Grade(a) | |
|
Total | |
|
|
| |
|
| |
|
|
(Millions) | |
Gas and electric utilities
|
|
$ |
556.4 |
|
|
$ |
609.4 |
|
Energy marketers and traders
|
|
|
1,185.7 |
|
|
|
3,268.3 |
|
Financial institutions
|
|
|
2,023.9 |
|
|
|
2,023.9 |
|
Integrated gas and oil
|
|
|
90.0 |
|
|
|
90.0 |
|
Other
|
|
|
5.6 |
|
|
|
21.1 |
|
|
|
|
|
|
|
|
|
|
$ |
3,861.6 |
|
|
|
6,012.7 |
|
|
|
|
|
|
|
|
Credit reserves
|
|
|
|
|
|
|
(26.4 |
) |
|
|
|
|
|
|
|
Gross credit exposure from derivatives(b)
|
|
|
|
|
|
$ |
5,986.3 |
|
|
|
|
|
|
|
|
We assess our credit exposure on a net basis. The net credit
exposure from our derivatives as of December 31, 2004 is
summarized below.
|
|
|
|
|
|
|
|
|
|
|
Investment | |
|
|
Counterparty Type |
|
Grade(a) | |
|
Total | |
|
|
| |
|
| |
|
|
(Millions) | |
Gas and electric utilities
|
|
$ |
93.4 |
|
|
$ |
119.8 |
|
Energy marketers and traders
|
|
|
454.9 |
|
|
|
613.3 |
|
Financial institutions
|
|
|
217.4 |
|
|
|
217.4 |
|
Other
|
|
|
1.1 |
|
|
|
1.6 |
|
|
|
|
|
|
|
|
|
|
$ |
766.8 |
|
|
|
952.1 |
|
|
|
|
|
|
|
|
Credit reserves
|
|
|
|
|
|
|
(26.4 |
) |
|
|
|
|
|
|
|
Net credit exposure from derivatives(b)
|
|
|
|
|
|
$ |
925.7 |
|
|
|
|
|
|
|
|
|
|
(a) |
We determine investment grade primarily using publicly available
credit ratings. We included counterparties with a minimum
Standard & Poors of BBB or
Moodys Investors Service rating of Baa3 in investment
grade. We also classify counterparties that have provided
sufficient collateral, such as cash, standby letters of credit,
parent company guarantees, and property interests, as investment
grade. |
|
|
|
(b) |
|
One counterparty within the California power market represents
more than ten percent of the derivative assets and is included
in investment grade. Standard & Poors and
Moodys Investors Service do not currently rate this
counterparty. We included this counterparty in the investment
grade column based upon contractual credit requirements. |
146
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In 2004 and 2003, there were no customers that exceeded
10 percent of our consolidated revenues. In 2002, eight of
Powers customers exceeded 10 percent of our revenues
with sales from each customer of $516.9 million,
$505.5 million, $482.5 million, $474.8 million,
$408.7 million, $379.2 million, $377.5 million
and $358.9 million, respectively. The revenues from these
customers in 2002 are net of cost of sales with the same
customer consistent with fair-value accounting (see
Note 1). The sum of these net revenues exceeds our total
revenues because there are additional customers with whom we
have negative net revenues (due to the costs from these
customers exceeding the revenues) which offset this sum.
Certain of our counterparties lack financial stability and
creditworthiness, which may adversely impact their ability to
perform under contracts. Revenues from one of Powers
counterparties, which has a credit rating below investment
grade, constitutes approximately five percent of Powers
gross revenues. Our exposure to this counterparty is mitigated
by the existence of a netting arrangement.
|
|
Note 15. |
Contingent liabilities and commitments |
|
|
|
Rate and regulatory matters and related litigation |
Our interstate pipeline subsidiaries have various regulatory
proceedings pending. As a result of rulings in certain of these
proceedings, a portion of the revenues of these subsidiaries has
been collected subject to refund. The natural gas pipeline
subsidiaries have accrued approximately $9 million for
potential refund as of December 31, 2004.
|
|
|
Issues resulting from California energy crisis |
Subsidiaries of our Power segment are 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 have been
challenged in various proceedings including those before the
Federal Energy Regulatory Commission (FERC). These challenges
include refund proceedings, California Independent System
Operator (ISO) fines, summer 2002 90-day contracts,
investigations of alleged market manipulation including
withholding, gas indices and other gaming of the market, new
long-term power sales to the State of California that were
subsequently challenged and civil litigation relating to certain
of these issues. We have entered into settlements with the State
of California (State Settlement), major California utilities
(Utilities Settlement), and others that have substantially
resolved each of these issues. However, certain issues remain
open at the FERC and for other non-settling parties, such as the
DOJ.
Although we have entered into the State Settlement and Utilities
Settlement which resolve the refund issues among the settling
parties, we have potential refund exposure to non-settling
parties (e.g., various California end users that have not agreed
to opt into the Utilities Settlement). As a part of the
Utilities Settlement, we funded escrow accounts that we
anticipate will satisfy any ultimate refund determinations in
favor of the non-settling parties. We are also owed interest
from counterparties in the California market during the refund
period for which we have recorded a receivable of approximately
$30 million at December 31, 2004. Collection of the
interest is subject to the conclusion of this proceeding. A
request for rehearing of the order approving the Utilities
Settlement is pending at the FERC. Therefore, we continue to
participate in the FERC refund case and related proceedings.
Challenges to virtually every aspect of the refund proceeding,
including the refund period, are now pending at the Ninth
Circuit Court of Appeals.
147
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
Summer 2002 90-day contracts |
On May 2, 2002, PacifiCorp filed a complaint with the FERC
against us seeking relief from rates contained in three separate
confirmation agreements between PacifiCorp and Power (known as
the Summer 2002 90-Day Contracts). PacifiCorp filed similar
complaints against three other suppliers. PacifiCorp alleged
that the rates contained in the contracts are unjust and
unreasonable. On June 26, 2003, the FERC affirmed the
administrative law judges initial decision dismissing the
complaints. PacifiCorp has appealed the FERCs order to the
United States Court of Appeals for the Ninth Circuit after the
FERC denied rehearing of its order on November 10, 2003.
|
|
|
Investigations of alleged market manipulation |
As a result of various allegations and FERC orders, in 2002 the
FERC initiated investigations of manipulation of the California
gas and power markets. As they related to us, these
investigations included economic and physical withholding,
so-called Enron Gaming Practices and gas index
manipulation.
Each of these FERC investigations of alleged market manipulation
was resolved pursuant to the Utilities Settlement that is
discussed above in Refund proceedings.
As also discussed below in Reporting of natural
gas-related information to trade publications, on
November 8, 2002, we received a subpoena from a federal
grand jury in Northern California seeking documents related to
our involvement in California markets. We have completed our
response to the subpoena. This subpoena is a part of the broad
United Sates Department of Justice (DOJ) investigation
regarding gas and power trading.
In February 2001, during the height of the California energy
crisis, we entered into a long-term power contract with the
State of California to assist in stabilizing its market. The
State of California later sought to rescind this contract.
Following settlement discussions between the State and us on the
contract issue as well as other state initiated proceedings and
allegations of market manipulation, we entered into the State
Settlement that includes renegotiated long-term energy
contracts. These contracts are made up of block energy sales,
dispatchable products and a gas contract. The State Settlement
does not extend to criminal matters or matters of willful fraud,
but did resolve civil complaints brought by the California
Attorney General against us and the State of Californias
refund claims that are discussed above. In addition, the State
Settlement resolved ongoing investigations by the States of
California, Oregon and Washington. Certain private class action
and other civil plaintiffs who have initiated class action
litigation against us and others in California based on
allegations against us with respect to the California energy
crisis also executed the State Settlement. On June 29,
2004, the court approved the State Settlement, making it
effective as to plaintiffs and terminating the class actions as
to us. A limited group did opt out of the State Settlement. An
appeal of the approval order is currently pending. Litigation by
non-California plaintiffs, or relating to reporting of natural
gas information to trade publications, as discussed below, will
continue. As of December 31, 2004, pursuant to the terms of
the State Settlement, we have transferred ownership of six
LM6000 gas powered electric turbines, have made three payments
totaling $87 million to the California Attorney General,
and have funded a $15 million fee and expense fund
associated with civil actions that are subject to the State
Settlement. An additional $60 million remains to be paid to
the California Attorney General (or his designee) over the next
five years, with the final payment of $15 million due on
January 1, 2010.
On February 5, 2005, Power received a tax assessment
letter, addressed to AES Redondo Beach, L.L.C. and Power, from
the city of Redondo Beach, California, in which the city
asserted that approximately
148
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
$33 million in back taxes and approximately
$39 million in interest and penalties are owed related to
natural gas used at the generating facility operated by AES
Redondo Beach. On the same date, Power was served with a
subpoena from the city related to the tax assessment. Under
Powers tolling agreement related to the Redondo Beach
generating facility, we believe that AES Redondo Beach is
responsible for taxes of the nature asserted by the city.
|
|
|
Reporting of natural gas-related information to trade
publications |
We disclosed on October 25, 2002, that certain of our
natural gas traders had reported inaccurate information to a
trade publication that published gas price indices. As noted
above, on November 8, 2002, we received a subpoena from a
federal grand jury in Northern California seeking documents
related to our involvement in California markets, including our
reporting to trade publications for both gas and power
transactions. We completed our response to the subpoena. On
December 17, 2004, a former trader with Power pled guilty
to manipulation of gas prices through misreporting to an
industry trade periodical. The DOJs investigation of us in
this matter is continuing and it is reasonably possible that
material penalties could result. However, a reasonable estimate
of such amount cannot be determined at this time. In addition,
the Commodity Futures Trading Commission (CFTC) has
conducted an investigation of us regarding this issue. On
July 29, 2003, we reached a settlement with the CFTC where
in exchange for $20 million, the CFTC closed its
investigation and we did not admit or deny allegations that we
had engaged in false reporting or attempted manipulation. Civil
suits based on allegations of manipulating the gas indices have
been brought against us and others in federal court in New York,
Tennessee, Washington, Oregon and California and in state court
in California.
|
|
|
Investigations related to natural gas storage
inventory |
We responded to a subpoena from the CFTC and inquiries from the
FERC related to investigations involving natural gas storage
inventory issues. Through some of our subsidiaries, we own and
operate natural gas storage facilities. On August 30, 2004,
the CFTC announced that it had concluded its investigation. The
FERC inquiries relate to the sharing of non-public data
concerning inventory levels and the potential uses of such data
in natural gas trading. The FERC investigation is continuing and
we are engaged in discussions with FERC staff regarding the
ultimate disposition of this matter.
On December 3, 2002, an administrative law judge at the
FERC issued an initial decision in Transcos general rate
case which, among other things, rejected the recovery of the
costs of Transcos Mobile Bay expansion project from its
shippers on a rolled-in basis and found that
incremental pricing for the Mobile Bay expansion project is just
and reasonable. The administrative law judges initial
decision is subject to review by the FERC. On March 26,
2004, the FERC issued an Order on Initial Decision in which it
reversed certain parts of the administrative law judges
holding and accepted Transcos proposal for rolled-in
rates. Power holds long-term transportation capacity on the
Mobile Bay expansion project. If the FERC had adopted the
decision of the administrative law judge on the pricing of the
Mobile Bay expansion project and also required that the decision
be implemented effective September 1, 2001, Power could
have been subject to surcharges of approximately
$59 million, excluding interest, through December 31,
2004, in addition to increased costs going forward. On
April 26, 2004, several parties, including Transco filed
requests for rehearing of the FERCs March 26, 2004
order. These requests are still pending.
We have outstanding claims against Enron Corp. and various of
its subsidiaries (collectively Enron) related to
Enrons bankruptcy filed in December 2001. In March 2002,
we sold $100 million of our claims
149
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
against Enron to a third party for $24.5 million. On
December 23, 2003, Enron filed objections to these claims.
Under the sales agreement, the purchaser of the claims may
demand repayment of the purchase price, plus interest assessed
at an annual rate of 7.5 percent, for that portion of the
claims still subject to objections beginning 90 days
following the initial objection. To date, the purchaser has not
demanded repayment.
Since 1989, our Transco subsidiary has had studies underway to
test certain of its facilities for the presence of toxic and
hazardous substances to determine to what extent, if any,
remediation may be necessary. Transco has responded to data
requests from the U.S. Environmental Protection Agency
(EPA) and state agencies regarding such potential
contamination of certain of its sites. Transco has identified
polychlorinated biphenyl (PCB) contamination in compressor
systems, soils and related properties at certain compressor
station sites. Transco has also been involved in negotiations
with the EPA and state agencies to develop screening, sampling
and cleanup programs. In addition, Transco commenced
negotiations with certain environmental authorities and other
programs concerning investigative and remedial actions relative
to potential mercury contamination at certain gas metering
sites. The costs of any such remediation will depend upon the
scope of the remediation. At December 31, 2004, Transco had
accrued liabilities of $23 million related to PCB
contamination, potential mercury contamination, and other toxic
and hazardous substances.
We also accrued environmental remediation costs for our natural
gas gathering and processing facilities, primarily related to
soil and groundwater contamination. At December 31, 2004,
we had accrued liabilities totaling approximately
$8 million for these costs.
Actual costs incurred for these matters will depend on the
actual number of contaminated sites identified, the amount and
extent of contamination discovered, the final cleanup standards
mandated by the EPA and other governmental authorities and other
factors.
In August 2004, the New Mexico Environment Department
(NMED) issued a Notice of Violation (NOV) to one of
our subsidiaries, Williams Field Services Company (WFS),
alleging various air permit violations primarily related to
WFSs alleged failure to control volatile organic compound
emissions from three conventional dehydrators in 2001. The NOV
specified that the maximum statutory penalty for such violations
is approximately $13.7 million. NMED and WFS are
negotiating a possible resolution to this matter and WFS
anticipates that any proposed penalty will be significantly
lower than the maximum statutory amount. Additionally, in August
2004, WFS discovered and self-disclosed to the NMED that WFS was
out of compliance with certain requirements of the operating
permit issued under Title V of the Clean Air Act Amendments
of 1990 at the Kutz gas processing plant. NMED and WFS
are also negotiating a possible resolution to this matter.
|
|
|
Former operations, including operations classified as
discontinued |
In connection with the sale of certain assets and businesses, we
have retained responsibility, through indemnification of the
purchasers, for environmental and other liabilities existing at
the time the sale was consummated, as described below.
In connection with the 1987 sale of the assets of Agrico
Chemical Company, we agreed to indemnify the purchaser for
environmental cleanup costs resulting from certain conditions at
specified locations to the extent such costs exceed a specified
amount. At December 31, 2004, we had accrued liabilities of
approximately $11 million for such excess costs.
150
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
We are also in discussions with defendants involved in two class
action damages lawsuits involving this former chemical
fertilizer business. Settlement among those defendants was
judicially approved in October 2004. We were not a named
defendant in the settled lawsuits, but have contractual
obligations to participate with the named defendants in the
ongoing environmental remediation. One defendant has filed a
Motion to Compel us to participate in arbitration regarding the
contractual obligations. A hearing was held on that Motion on
September 2, 2004 and the judge ordered the Motion to
Compel and subsequent issues severed from the class action. On
November 3, 2004, we removed the severed case to the United
States District Court in the Northern District of Florida in
Pensacola. Agrico filed its motion to remand on
November 22, 2004. We then filed a Motion to Dismiss on
January 21, 2005. A hearing on the Motion to Remand is set
for March 23, 2005.
As part of our June 17, 2003 sale of Williams Energy
Partners (see Note 2), we provided certain environmental
indemnities to the purchaser. On May 26, 2004, the parties
reached an agreement for buyout of certain indemnities in the
form of a structured cash settlement. The agreement releases us
from essentially all environmental indemnity obligations under
the June 2003 sale of Williams Energy Partners and two related
agreements. The agreement also transferred most third party
litigation matters related to Williams Energy Partners
assets to the purchaser.
At December 31, 2004, we had accrued environmental
liabilities totaling approximately $30 million related
primarily to our:
|
|
|
|
|
potential indemnification obligations to purchasers of our
former retail petroleum and refining operations; |
|
|
|
former propane marketing operations, bio-energy facilities,
petroleum products and natural gas pipelines; |
|
|
|
discontinued petroleum refining facilities; and |
|
|
|
exploration and production and mining operations. |
These costs include (1) certain conditions at specified
locations related primarily to soil and groundwater
contamination and (2) any penalty assessed on Williams
Refining & Marketing, LLC (Williams Refining)
associated with noncompliance with EPAs benzene waste
NESHAP regulations. In 2002, Williams Refining
submitted to the EPA a self-disclosure letter indicating
noncompliance with those regulations. This unintentional
noncompliance had occurred due to a regulatory interpretation
that resulted in under-counting the total annual benzene level
at Williams Refinings Memphis refinery. Also in 2002, the
EPA conducted an all-media audit of the Memphis refinery. On
August 25, 2004, Williams Refining and its new owner met
with the EPA and the DOJ to discuss alleged violations and
proposed penalties due to noncompliance issues identified in the
multi-media report, including the benzene NESHAP issue.
Discussion between the EPA, the DOJ and Williams Refining to
resolve the allegations of noncompliance are ongoing. In
connection with the sale of the Memphis refinery in March 2003,
there are certain indemnification obligations to the purchaser.
We were a plaintiff in litigation involving the environmental
investigation and subsequent cleanup of the Augusta refinery. In
April 2004, we received a court order to participate in
mediation before the end of June with the defendant to attempt
to reach a settlement prior to going to trial. The litigation
has been resolved and Williams Petroleum Services, LLC has
accrued additional amounts of $11.8 million for completion of
the work under the current Administrative Order on Consent and
reasonably anticipated remediation costs. Accruals may be
adjusted as more information from the site investigation becomes
available.
151
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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.
|
|
|
Summary of environmental matters |
Actual costs incurred 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 and other factors.
In connection with agreements to resolve take-or-pay and other
contract claims and to amend gas purchase contracts, Transco
entered into certain settlements with producers which may
require the indemnification of certain claims for additional
royalties which the producers may be required to pay as a result
of such settlements. Transco, through its agent, Power,
continues to purchase gas under contracts which extend, in some
cases, through the life of the associated gas reserves. Certain
of these contracts contain royalty indemnification provisions
that have no carrying value. Producers have received and may
receive other demands, which could result in claims pursuant to
royalty indemnification provisions. Indemnification for
royalties will depend on, among other things, the specific lease
provisions between the producer and the lessor and the terms of
the agreement between the producer and Transco. Consequently,
the potential maximum future payments under such indemnification
provisions cannot be determined.
As a result of these settlements, Transco has been sued by
certain producers seeking indemnification from Transco. Transco
is currently a defendant in one lawsuit in which a producer has
asserted damages, including interest calculated through
December 31, 2004, of approximately $10 million. On
July 11, 2003, at the conclusion of the trial, the judge
ruled in Transcos favor and subsequently entered a formal
judgment. However, the plaintiff continues to seek an appeal.
|
|
|
Will Price (formerly Quinque) |
On June 8, 2001, fourteen of our entities were named as
defendants in a nationwide class action lawsuit which had been
pending against other defendants, generally pipeline and
gathering companies, for more than one year. The plaintiffs
allege that the defendants, including us, have engaged in
mismeasurement techniques that distort the heating content of
natural gas, resulting in an alleged underpayment of royalties
to the class of producer plaintiffs. After the court denied
class action certification and while motions to dismiss for lack
of personal jurisdiction were pending, the court granted the
plaintiffs motion to amend their petition on July 29,
2003. The fourth amended petition, which was filed on
July 29, 2003, deletes all of our defendants except two
Midstream subsidiaries. All defendants intend to continue their
opposition to class certification.
In 1998, the DOJ informed us that Jack Grynberg, an individual,
had filed claims on behalf of himself and the federal
government, in the United States District Court for the District
of Colorado under the False Claims Act against us and certain of
our wholly owned subsidiaries. The claims sought an unspecified
amount of royalties allegedly not paid to the federal
government, treble damages, a civil penalty, attorneys
fees, and costs. In connection with our sale of Kern River and
Texas Gas, we agreed to indemnify the purchasers for any
liability relating to this claim, including legal fees. The
maximum amount of future payments that we could potentially be
required to pay under these indemnifications depends upon the
ultimate resolution of the claim and cannot currently be
determined. Grynberg has also filed claims against approximately
300 other energy
152
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
companies alleging that the defendants violated the False Claims
Act in connection with the measurement, royalty valuation and
purchase of hydrocarbons. On April 9, 1999, the DOJ
announced that it was declining to intervene in any of the
Grynberg qui tam cases, including the action filed in
federal court in Colorado against us. On October 21, 1999,
the Panel on Multi-District Litigation transferred all of the
Grynberg qui tam cases, including those filed against us,
to the federal court in Wyoming for pre-trial purposes.
Grynbergs measurement claims remain pending against us and
the other defendants; the court previously dismissed
Grynbergs royalty valuation claims. The defendants have
filed a number of joint motions to dismiss Grynbergs
claims on subject matter jurisdictional bases. Oral argument on
these motions has been set for March 17, 2005, and we
expect a decision in the second quarter of 2005.
On August 6, 2002, Jack J. Grynberg, and Celeste C.
Grynberg, Trustee on Behalf of the Rachel Susan Grynberg Trust,
and the Stephen Mark Grynberg Trust, served us and one of our
Exploration & Production subsidiaries with a complaint
in the state court in Denver, Colorado. The complaint alleges
that the defendants have used mismeasurement techniques that
distort the BTU heating content of natural gas, resulting in the
alleged underpayment of royalties to Grynberg and other
independent natural gas producers. The complaint also alleges
that defendants inappropriately took deductions from the gross
value of their natural gas and made other royalty valuation
errors. Under various theories of relief, the plaintiff is
seeking actual damages of between $2 million and
$20 million based on interest rate variations and punitive
damages in the amount of approximately $1.4 million
dollars. Our motion to stay the proceedings in this case based
on the pendency of the False Claims Act litigation discussed in
the preceding paragraph was granted in January 2003. In
September 2004, Grynberg moved to lift the stay and filed an
amended complaint against one of our Exploration &
Production subsidiaries. This subsidiary filed an answer in
January 2005, denying liability for the damages claimed.
Numerous shareholder class action suits have been filed against
us in the United States District Court for the Northern District
of Oklahoma. The majority of the suits allege that we and
co-defendants, WilTel Communications (WilTel), previously an
owned subsidiary known as Williams Communications, and certain
corporate officers, have acted jointly and separately to inflate
the stock price of both companies. Other suits allege similar
causes of action related to a public offering in early January
2002, known as the FELINE PACS offering. These cases were filed
against us, certain corporate officers, all members of our board
of directors and all of the offerings underwriters. These
cases have all been consolidated and an order has been issued
requiring separate amended consolidated complaints by our equity
holders and WilTel equity holders. The underwriter defendants
have requested indemnification from these cases. If granted,
costs incurred as a result of these indemnifications will not be
covered by our insurance policies. The amended complaint of the
WilTel securities holders was filed in September 2002, and the
amended complaint of our securities holders was filed in October
2002. This amendment added numerous claims related to Power. On
April 2, 2004, the purported class of our securities
holders filed a partial motion for summary judgment with respect
to certain disclosures made in connection with our public
offerings during the class period. The lead plaintiff
subsequently filed to withdraw from the proceeding and a new
process was held to determine the lead plaintiff. This process
has concluded and the Motion for Summary Judgment is now moot.
Derivative shareholder suits have been filed in state court in
Oklahoma, all based on similar allegations. The state court
approved motions to consolidate and to stay these Oklahoma suits
pending action by the federal court in the shareholder suits. We
have directors and officers insurance which we believe provides
coverage for these claims, but there can be no assurance that
the ultimate resolution of this litigation will not include some
amount outside of insurance.
In addition, four class action complaints have been filed
against us, the members of our Board of Directors and members of
our benefits and investment committees under the Employee
Retirement Income Security Act (ERISA) by participants in
our 401(k) plan. A motion to consolidate these suits has been
approved. In July 2003, the court dismissed us and our Board
from the ERISA suits, but not the members of
153
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
the benefits and investment committees to whom we might have an
indemnity obligation. If it is determined that we have an
indemnity obligation, we expect that any costs incurred will be
covered by our insurance policies. On June 7, 2004, the
Court granted plaintiffs request to amend their complaint
to add additional investment committee members and to again name
the Board of Directors. On December 21, 2004, the Court
denied the Plaintiffs Motion for Partial Summary Judgment
against the Director Defendants and denied the Motions to
Dismiss filed by the Directors and certain Committee Defendants.
On March 4, 2005, Plaintiffs filed a Third Amended
Complaint again seeking to add us as a defendant in this matter.
The U.S. Department of Labor is also independently
investigating our employee benefit plans.
|
|
|
Oklahoma securities investigation |
On April 26, 2002, the Oklahoma Department of Securities
issued an order initiating an investigation of us and WilTel
regarding issues associated with the spin-off of WilTel and
regarding the WilTel bankruptcy. We have no pending inquiries in
this investigation, but are committed to cooperate fully in the
investigation.
|
|
|
Federal Income Tax Litigation |
One of our wholly-owned subsidiaries, Transco Coal Gas Company,
is engaged in a dispute with the Internal Revenue Service (IRS)
regarding the recapture of certain income tax credits associated
with the construction of a coal gasification plant in North
Dakota by Great Plains Gasification Associates, in which Transco
Coal Gas Company was a partner. The IRS has taken alternative
positions that allege a disposition date for purposes of tax
credit recapture that is earlier than the position taken in the
partnership tax return. On August 23, 2001, we filed a
petition in the U.S. Tax Court to contest the adjustments
to the partnership tax return proposed by the IRS. Certain
settlement discussions have taken place since that date. During
the fourth quarter of 2004, we determined that a reasonable
settlement with the IRS could not be achieved. We filed a Motion
for Summary Judgment with the Tax Court, which was heard, and
denied, in January 2005. The matter was then tried before the
Tax Court in February 2005. We continue to believe that the
return position of the partnership is with merit. However, it is
reasonably possible that the Tax Court could render an
unfavorable decision that could ultimately result in estimated
income taxes and interest of up to approximately
$110 million in excess of the amount currently accrued.
One of our subsidiaries, Williams Alaska Petroleum, Inc.
(WAPI) is actively engaged in administrative litigation
being conducted jointly by the FERC and the Regulatory
Commission of Alaska (RCA) concerning the Trans-Alaska
Pipeline System (TAPS) Quality Bank. Primary issues being
litigated include the appropriate valuation of the naphtha,
heavy distillate, vacuum gas oil and residual product cuts
within the TAPS Quality Bank as well as the appropriate
retroactive effects of the determinations. Due to the sale of
WAPIs interests on March 31, 2004, no future Quality
Bank liability will accrue but we are responsible for any
liability that existed as of that date including potential
liability for any retroactive payments that might be awarded in
these proceedings for the period prior to March 31, 2004.
The FERC and RCA presiding administrative law judges rendered
their joint and individual initial decisions during the third
quarter of 2004. The initial decisions set forth methodologies
for determining the valuations of the product cuts under review
and also approved the retroactive application of the approved
methodologies for the heavy distillate and residual product
cuts. Based on our computation and assessment of ultimate ruling
terms that would be considered probable, we recorded an accrual
of approximately $134 million in the third quarter of 2004.
Interest on the Quality Bank accrual is being accrued each
quarter. Because the application of certain aspects of the
initial decisions are subject to interpretation, we have
calculated the reasonably possible impact of the decisions, if
fully adopted by the FERC and RCA, to result in additional
exposure to us of approximately $32 million more than we have
accrued at December 31, 2004. We filed a brief on
exceptions to the initial decisions to both the FERC and RCA on
November 16, 2004, and our reply briefs on February 1,
2005.
154
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Decisions from the Commissions will likely be issued before the
end of 2005. Settlement discussions have been initiated. Absent
the completion of any settlements, it is unlikely that we will
be required to make any payments with respect to this matter
until sometime after the Commission decisions.
|
|
|
Deepwater construction litigation |
In a lawsuit pending in federal court in Houston, Texas, Technip
Offshore, Inc. (Technip) is seeking approximately
$8.6 million from two of our subsidiaries. The suit alleges
that we breached a contract for the construction of deepwater
export pipelines connected to the Devils Tower Spar in the Gulf
of Mexico. We have filed counterclaims seeking $4.2 million
in liquidated delay damages. Each party has posted a letter of
credit covering the value of the claims pending against it.
|
|
|
Colorado royalty litigation |
On June 27, 2002, a royalty owner in the Piceance basin of
Colorado filed suit against one of our Exploration &
Production subsidiaries alleging that we breached our lease
agreements and violated the Colorado Deceptive Trade Practices
Act (CDTA) by making various deductions from his royalty
payments from 1996 to date. On August 2, 2004, the jury
returned its verdict in the amount of $4.1 million for the
plaintiff. The verdict included a finding under the CDTA which
could have potentially tripled the damage award. On
November 30, 2004, the court issued an order setting aside
the plaintiffs CDTA claims, but left intact the
$4.1 million award. We are appealing the judgment to the
Colorado Court of Appeals.
|
|
|
San Juan basin gas entitlements |
One of our Exploration & Production subsidiaries is
involved in a dispute with another joint interest owner in
multiple federal oil and gas units located in the San Juan
basin. The dispute involves various accounting issues relating
to payout determinations in these federal units and associated
claims for retroactive adjustment of entitlements to gas
production. We are engaged in discussions with the joint
interest owner regarding proper adjustment calculations, and we
have proposed to settle these disputes for approximately
$11.3 million plus interest of $3 million. We continue
to analyze additional claims made by the joint interest owner.
These additional claims total approximately $12 million.
|
|
|
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, environmental matters,
right of way and other representations that we have provided. At
December 31, 2004, 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 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.
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,
155
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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 materially adverse
effect upon our future financial position.
Power has entered into certain contracts giving it the right to
receive fuel conversion services as well as certain other
services associated with electric generation facilities that are
currently in operation throughout the continental United States.
At December 31, 2004, Powers estimated committed
payments under these contracts range from approximately
$394 million to $422 million annually through 2017 and
decline over the remaining five years to $57 million in
2022. Total committed payments under these contracts over the
next eighteen years are approximately $6.3 billion. Total
payments made under these contracts during 2004, 2003, and 2002
were $402 million, $394 million and $298 million,
respectively.
|
|
Note 16. |
Related party transactions |
|
|
|
Lehman Brothers Holdings, Inc. |
Lehman Brothers Inc. was a related party as a result of a
director that served on both our Board of Directors and Lehman
Brothers Holdings, Inc.s Board of Directors. On
May 20, 2004, this director retired from our Board of
Directors. In third-quarter 2002, RMT, a wholly owned
subsidiary, entered into a $900 million short-term Credit
Agreement dated July 31, 2002, with certain lenders
including a subsidiary of Lehman Brothers Inc. This debt
obligation was refinanced in second-quarter 2003. Included in
interest accrued on the Consolidated Statement of Operations for
2003 and 2002 are $199.4 million and $154.1 million,
respectively, of interest expense, including amortization of
deferred set up fees related to the RMT note. As of
December 31, 2003, the amount due to Lehman Brothers, Inc.,
related primarily to advisory fees was $1.8 million. In
addition, we paid $37.2 million and $39.6 million to
Lehman Brothers Inc. in 2003 and 2002, respectively, primarily
for underwriting fees related to debt and equity issuances as
well as strategic advisory and restructuring success fees. We
had no significant transactions with Lehman Brothers Holdings,
Inc. for the year ended December 31, 2004.
|
|
|
American Electric Power Company, Inc. |
American Electric Power Company, Inc. (AEP) is a related
party as a result of a director that serves on both our Board of
Directors and AEPs Board of Directors. Prior to 2003, our
Power segment engaged in forward and physical power and gas
trading activities with AEP. During 2002, AEP disputed a
settlement amount related to the liquidation of a trading
position with Power. Arbitration was initiated and in 2003 AEP
paid Power $90 million to resolve the dispute. There were
no trading activities with AEP in 2003. Net revenues from AEP
were $264.6 million in 2002. There were no significant
transactions with AEP for the year ended December 31, 2004.
ExxonMobil Corporation is a related party as a result of a
director that serves on both our Board of Directors and
ExxonMobil Corporations Board of Directors. Transactions
with ExxonMobil Corporation result primarily from the purchase
and sale of crude oil, refined products and natural gas liquids
in support of crude oil, refined products and natural gas
liquids trading activities as well as revenues generated from
gathering and processing activities. Aggregate revenues from
this customer, including those reported on a net basis in 2002,
were $178.9 million, $121.8 million and
$217.6 million in 2004, 2003 and 2002, respectively.
Aggregate purchases from this customer were $16.7 million,
$30.4 million and $15.6 million in 2004, 2003 and
2002, respectively. Amounts due from ExxonMobil were
$50.6 million and $40.0 million as of December 31,
156
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
2004, and 2003, respectively. There were no significant amounts
due to ExxonMobil at December 31, 2004 and 2003.
157
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
Note 17. |
Accumulated other comprehensive income (loss) |
The table below presents changes in the components of
accumulated other comprehensive income (loss).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) | |
|
|
| |
|
|
|
|
Unrealized | |
|
|
|
|
|
|
Appreciation | |
|
Foreign | |
|
Minimum | |
|
|
|
|
Cash Flow | |
|
(Depreciation) | |
|
Currency | |
|
Pension | |
|
|
|
|
Hedges | |
|
On Securities | |
|
Translation | |
|
Liability | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Millions) | |
Balance at December 31, 2001
|
|
$ |
370.2 |
|
|
$ |
.9 |
|
|
$ |
(23.8 |
) |
|
$ |
(2.2 |
) |
|
$ |
345.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2002 Change:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-income tax amount
|
|
|
(170.7 |
) |
|
|
5.3 |
|
|
|
(.1 |
) |
|
|
(27.3 |
) |
|
|
(192.8 |
) |
Income tax benefit (provision)
|
|
|
65.0 |
|
|
|
(1.9 |
) |
|
|
|
|
|
|
10.4 |
|
|
|
73.5 |
|
Minority interest in other comprehensive loss
|
|
|
.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
.4 |
|
Net realized loss in net loss (net of a $.7 million income
tax)
|
|
|
|
|
|
|
1.2 |
|
|
|
|
|
|
|
|
|
|
|
1.2 |
|
Net reclassification into earnings of derivative instrument
gains (net of a $119.2 million income tax)
|
|
|
(193.6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(193.6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(298.9 |
) |
|
|
4.6 |
|
|
|
(.1 |
) |
|
|
(16.9 |
) |
|
|
(311.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2002
|
|
|
71.3 |
|
|
|
5.5 |
|
|
|
(23.9 |
) |
|
|
(19.1 |
) |
|
|
33.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 Change:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-income tax amount
|
|
|
(408.8 |
) |
|
|
2.6 |
|
|
|
77.0 |
|
|
|
18.2 |
|
|
|
(311.0 |
) |
Income tax benefit (provision)
|
|
|
156.3 |
|
|
|
(1.0 |
) |
|
|
|
|
|
|
(6.9 |
) |
|
|
148.4 |
|
Net reclassification into earnings of derivative instrument
losses (net of a $9.7 million income tax benefit)
|
|
|
15.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15.6 |
|
Realized gains on securities reclassified into earnings (net of
a $5.3 million income tax)
|
|
|
|
|
|
|
(9.0 |
) |
|
|
|
|
|
|
|
|
|
|
(9.0 |
) |
Reclassification into earnings due to sale of Bio-energy
facilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.2 |
|
|
|
1.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(236.9 |
) |
|
|
(7.4 |
) |
|
|
77.0 |
|
|
|
12.5 |
|
|
|
(154.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2003
|
|
|
(165.6 |
) |
|
|
(1.9 |
) |
|
|
53.1 |
|
|
|
(6.6 |
) |
|
|
(121.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 Change:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-income tax amount
|
|
|
(460.9 |
) |
|
|
(2.4 |
) |
|
|
15.8 |
|
|
|
3.0 |
|
|
|
(444.5 |
) |
Income tax benefit (provision)
|
|
|
176.5 |
|
|
|
.9 |
|
|
|
|
|
|
|
(1.2 |
) |
|
|
176.2 |
|
Net reclassification into earnings of derivative instrument
losses (net of a $87.8 million income tax benefit)
|
|
|
141.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
141.7 |
|
Realized losses on securities reclassified into earnings (net of
a $2.1 million income tax)
|
|
|
|
|
|
|
3.4 |
|
|
|
|
|
|
|
|
|
|
|
3.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(142.7 |
) |
|
|
1.9 |
|
|
|
15.8 |
|
|
|
1.8 |
|
|
|
(123.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2004
|
|
$ |
(308.3 |
) |
|
$ |
|
|
|
$ |
68.9 |
|
|
$ |
(4.8 |
) |
|
$ |
(244.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
158
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
Available for sale securities |
During 2004, we received proceeds totaling $851.4 million
from the sale and maturity of available for sale securities. We
realized losses of $5.5 million from these transactions. As
of December 31, 2004, all available for sale securities
have matured or have been sold.
During 2003, we received proceeds totaling $370.5 million
from the sale and maturity of available for sale securities. We
realized gross gains and losses of $14.4 million and
$0.1 million, respectively, from these transactions. At
December 31, 2003, we held U.S. Treasury securities
with a fair value of $381.3 million. Gross unrealized
losses of $3 million on these securities are included in
Accumulated Other Comprehensive Income (Loss) at
December 31, 2003.
|
|
Note 18. |
Segment disclosures |
|
|
|
Segments and reclassification of operations |
Our reportable segments are strategic business units that offer
different products and services. The segments are managed
separately because each segment requires different technology,
marketing strategies and industry knowledge. Other primarily
consists of corporate operations and certain continuing
operations that were included within the previously reported
International and Petroleum Services segments.
Due in part to FERC Order 2004, management and decision-making
control of certain activities were transferred from our
Midstream segment. Certain regulated gas gathering assets were
transferred from our Midstream segment to our Gas Pipeline
segment effective June 1, 2004, and our equity method
investment in the Aux Sable gas processing plant and related
business was transferred from our Midstream segment to our Power
segment effective September 21, 2004. Consequently, the
results of operations were similarly reclassified. All periods
presented reflect these classifications.
|
|
|
Segments performance measurement |
We currently evaluate performance based on segment profit (loss)
from operations, which includes revenues from external and
internal customers, operating costs and expenses, depreciation,
depletion and amortization, equity earnings (losses) and income
(loss) from investments including gains/ losses on impairments
related to investments accounted for under the equity method.
The accounting policies of the segments are the same as those
described in Note 1, Summary of significant accounting
policies. Intersegment sales are generally accounted for at
current market prices as if the sales were to unaffiliated third
parties.
Power entered into intercompany interest rate swaps with the
corporate parent, the effect of which is included in
Powers segment revenues and segment profit (loss) as shown
in the reconciliation within the following tables. The results
of interest rate swaps with external counterparties are shown as
interest rate swap income (loss) in the Consolidated Statement
of Operations below operating income. We terminated all
interest-rate derivatives in fourth quarter 2004.
The majority of energy commodity hedging by certain of our
business units is done through intercompany derivatives with
Power which, in turn, enters into offsetting derivative
contracts with unrelated third parties. Power bears the
counterparty performance risks associated with unrelated third
parties. External Revenues of our Exploration &
Production segment includes third party oil and gas sales, more
than offset by transportation expenses and royalties due third
parties on intercompany sales.
159
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
$ |
12,167.8 |
|
|
$ |
293.5 |
|
|
$ |
12,461.3 |
|
|
2003
|
|
|
15,755.8 |
|
|
|
895.2 |
|
|
|
16,651.0 |
|
|
2002
|
|
|
3,207.9 |
|
|
|
226.6 |
|
|
|
3,434.5 |
|
Long-lived assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
$ |
12,149.0 |
|
|
$ |
762.0 |
|
|
$ |
12,911.0 |
|
|
2003
|
|
|
11,982.0 |
|
|
|
776.9 |
|
|
|
12,758.9 |
|
Long-lived assets are comprised of property, plant and
equipment, goodwill and other intangible assets.
160
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream | |
|
|
|
|
|
|
|
|
|
|
Gas | |
|
Exploration & | |
|
Gas & | |
|
|
|
|
|
|
|
|
Power | |
|
Pipeline | |
|
Production | |
|
Liquids | |
|
Other | |
|
Eliminations | |
|
Total | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Millions) | |
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
$ |
8,346.2 |
|
|
$ |
1,345.0 |
|
|
$ |
(84.0 |
) |
|
$ |
2,844.7 |
|
|
$ |
9.4 |
|
|
$ |
|
|
|
$ |
12,461.3 |
|
|
Internal
|
|
|
912.5 |
|
|
|
17.3 |
|
|
|
861.6 |
|
|
|
37.9 |
|
|
|
23.4 |
|
|
|
(1,852.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment revenues
|
|
|
9,258.7 |
|
|
|
1,362.3 |
|
|
|
777.6 |
|
|
|
2,882.6 |
|
|
|
32.8 |
|
|
|
(1,852.7 |
) |
|
|
12,461.3 |
|
Less intercompany interest rate swap loss
|
|
|
(13.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$ |
9,272.4 |
|
|
$ |
1,362.3 |
|
|
$ |
777.6 |
|
|
$ |
2,882.6 |
|
|
$ |
32.8 |
|
|
$ |
(1,866.4 |
) |
|
$ |
12,461.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit (loss)
|
|
$ |
76.7 |
|
|
$ |
585.8 |
|
|
$ |
235.8 |
|
|
$ |
549.7 |
|
|
$ |
(41.6 |
) |
|
$ |
|
|
|
$ |
1,406.4 |
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings (losses)
|
|
|
3.9 |
|
|
|
29.2 |
|
|
|
11.9 |
|
|
|
14.6 |
|
|
|
(9.7 |
) |
|
|
|
|
|
|
49.9 |
|
|
Loss from investments
|
|
|
|
|
|
|
(1.0 |
) |
|
|
|
|
|
|
(17.1 |
) |
|
|
(17.4 |
) |
|
|
|
|
|
|
(35.5 |
) |
|
Intercompany interest rate swap loss
|
|
|
(13.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss)
|
|
$ |
86.5 |
|
|
$ |
557.6 |
|
|
$ |
223.9 |
|
|
$ |
552.2 |
|
|
$ |
(14.5 |
) |
|
$ |
|
|
|
|
1,405.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General corporate expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(119.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,285.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to long-lived assets
|
|
$ |
1.0 |
|
|
$ |
300.1 |
|
|
$ |
445.4 |
|
|
$ |
91.3 |
|
|
$ |
6.0 |
|
|
$ |
|
|
|
$ |
843.8 |
|
Depreciation, depletion & amortization
|
|
$ |
20.1 |
|
|
$ |
264.4 |
|
|
$ |
192.3 |
|
|
$ |
178.4 |
|
|
$ |
13.3 |
|
|
$ |
|
|
|
$ |
668.5 |
|
2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
$ |
12,570.5 |
|
|
$ |
1,344.3 |
|
|
$ |
(36.3 |
) |
|
$ |
2,740.2 |
|
|
$ |
32.3 |
|
|
$ |
|
|
|
$ |
16,651.0 |
|
|
Internal
|
|
|
622.1 |
|
|
|
24.0 |
|
|
|
816.0 |
|
|
|
44.6 |
|
|
|
39.7 |
|
|
|
(1,546.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment revenues
|
|
|
13,192.6 |
|
|
|
1,368.3 |
|
|
|
779.7 |
|
|
|
2,784.8 |
|
|
|
72.0 |
|
|
|
(1,546.4 |
) |
|
|
16,651.0 |
|
Less intercompany interest rate swap loss
|
|
|
(2.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$ |
13,195.5 |
|
|
$ |
1,368.3 |
|
|
$ |
779.7 |
|
|
$ |
2,784.8 |
|
|
$ |
72.0 |
|
|
$ |
(1,549.3 |
) |
|
$ |
16,651.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit (loss)
|
|
$ |
135.1 |
|
|
$ |
555.5 |
|
|
$ |
401.4 |
|
|
$ |
197.3 |
|
|
$ |
(50.5 |
) |
|
$ |
|
|
|
$ |
1,238.8 |
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings (losses)
|
|
|
(4.9 |
) |
|
|
15.8 |
|
|
|
8.9 |
|
|
|
(.8 |
) |
|
|
1.3 |
|
|
|
|
|
|
|
20.3 |
|
|
Income (loss) from investments
|
|
|
(2.4 |
) |
|
|
0.1 |
|
|
|
|
|
|
|
20.1 |
|
|
|
(43.1 |
) |
|
|
|
|
|
|
(25.3 |
) |
|
Intercompany interest rate swap loss
|
|
|
(2.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss)
|
|
$ |
145.3 |
|
|
$ |
539.6 |
|
|
$ |
392.5 |
|
|
$ |
178.0 |
|
|
$ |
(8.7 |
) |
|
$ |
|
|
|
|
1,246.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General corporate expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(87.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,159.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to long-lived assets
|
|
$ |
1.0 |
|
|
$ |
517.4 |
|
|
$ |
241.5 |
|
|
$ |
255.0 |
|
|
$ |
2.5 |
|
|
$ |
|
|
|
$ |
1,017.4 |
|
Depreciation, depletion & amortization
|
|
$ |
31.5 |
|
|
$ |
274.6 |
|
|
$ |
173.9 |
|
|
$ |
157.7 |
|
|
$ |
19.7 |
|
|
$ |
|
|
|
$ |
657.4 |
|
2002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External
|
|
$ |
909.6 |
|
|
$ |
1,244.1 |
|
|
$ |
62.6 |
|
|
$ |
1,151.3 |
|
|
$ |
66.9 |
|
|
$ |
|
|
|
$ |
3,434.5 |
|
|
Internal
|
|
|
(994.8 |
)* |
|
|
57.1 |
|
|
|
797.8 |
|
|
|
32.4 |
|
|
|
57.2 |
|
|
|
50.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total segment revenues
|
|
|
(85.2 |
) |
|
|
1,301.2 |
|
|
|
860.4 |
|
|
|
1,183.7 |
|
|
|
124.1 |
|
|
|
50.3 |
|
|
|
3,434.5 |
|
Less intercompany interest rate swap loss
|
|
|
(141.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
141.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$ |
56.2 |
|
|
$ |
1,301.2 |
|
|
$ |
860.4 |
|
|
$ |
1,183.7 |
|
|
$ |
124.1 |
|
|
$ |
(91.1 |
) |
|
$ |
3,434.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment profit (loss)
|
|
$ |
(626.2 |
) |
|
$ |
535.8 |
|
|
$ |
508.6 |
|
|
$ |
172.2 |
|
|
$ |
14.1 |
|
|
$ |
|
|
|
$ |
604.5 |
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity earnings (losses)
|
|
|
(11.1 |
) |
|
|
88.4 |
|
|
|
3.7 |
|
|
|
19.0 |
|
|
|
(27.0 |
) |
|
|
|
|
|
|
73.0 |
|
|
Income (loss) from investments
|
|
|
(2.0 |
) |
|
|
(13.9 |
) |
|
|
|
|
|
|
|
|
|
|
58.0 |
|
|
|
|
|
|
|
42.1 |
|
|
Intercompany interest rate swap loss
|
|
|
(141.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(141.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income (loss)
|
|
$ |
(471.7 |
) |
|
$ |
461.3 |
|
|
$ |
504.9 |
|
|
$ |
153.2 |
|
|
$ |
(16.9 |
) |
|
$ |
|
|
|
|
630.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General corporate expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(142.8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operating income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
488.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other financial information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to long-lived assets
|
|
$ |
135.8 |
|
|
$ |
705.0 |
|
|
$ |
382.8 |
|
|
$ |
616.4 |
|
|
$ |
51.7 |
|
|
$ |
|
|
|
$ |
1,891.7 |
|
Depreciation, depletion & amortization
|
|
$ |
33.1 |
|
|
$ |
253.0 |
|
|
$ |
184.6 |
|
|
$ |
149.9 |
|
|
$ |
28.2 |
|
|
$ |
|
|
|
$ |
648.8 |
|
|
|
* |
Prior to January 1, 2003, Power intercompany cost of sales,
which are netted in revenues consistent with fair-value
accounting, exceed intercompany revenues. Beginning
January 1, 2003, Power intercompany cost of sales are no
longer netted in revenues due to the adoption of EITF Issue
No. 02-3 (see Note 1). |
161
THE WILLIAMS COMPANIES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets | |
|
Equity Method Investments | |
|
|
| |
|
| |
|
|
December 31, | |
|
December 31, | |
|
December 31, | |
|
December 31, | |
|
|
2004 | |
|
2003 | |
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
| |
|
| |
|
|
(Millions) | |
Power
|
|
$ |
8,204.1 |
|
|
$ |
8,732.9 |
|
|
$ |
45.6 |
|
|
$ |
42.8 |
|
Gas Pipeline
|
|
|
7,651.8 |
|
|
|
7,314.3 |
|
|
|
769.5 |
|
|
|
774.4 |
|
Exploration & Production
|
|
|
5,576.4 |
|
|
|
5,347.4 |
|
|
|
44.9 |
|
|
|
41.5 |
|
Midstream Gas & Liquids
|
|
|
4,211.7 |
|
|
|
4,050.4 |
|
|
|
273.3 |
|
|
|
289.9 |
|
Other(1)
|
|
|
3,584.0 |
|
|
|
6,928.7 |
|
|
|
113.2 |
|
|
|
85.1 |
|
Eliminations
|
|
|
(5,248.6 |
) |
|
|
(6,078.2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23,979.4 |
|
|
|
26,295.5 |
|
|
|
1,246.5 |
|
|
|
1,233.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net assets of discontinued operations(2)
|
|
|
13.6 |
|
|
|
726.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$ |
23,993.0 |
|
|
$ |
27,021.8 |
|
|
$ |
1,246.5 |
|
|
$ |
1,233.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
The decrease in Others total assets is primarily due to
cash payments on existing debt. |
|
(2) |
The decrease in net assets of discontinued operations is due to
the sale of our Canadian straddle plants during 2004. |
162
THE WILLIAMS COMPANIES, INC.
QUARTERLY FINANCIAL DATA
(Unaudited)
Summarized quarterly financial data are as follows (millions,
except per-share amounts). Certain amounts have been restated or
reclassified as described in Note 1 of Notes to
Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First | |
|
Second | |
|
Third | |
|
Fourth | |
|
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
|
| |
|
| |
|
| |
|
| |
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
3,070.0 |
|
|
$ |
3,051.9 |
|
|
$ |
3,375.2 |
|
|
$ |
2,964.2 |
|
Costs and operating expenses
|
|
|
2,690.9 |
|
|
|
2,661.4 |
|
|
|
2,855.9 |
|
|
|
2,543.5 |
|
Income (loss) from continuing operations
|
|
|
|
|
|
|
(18.5 |
) |
|
|
16.2 |
|
|
|
95.5 |
|
Net income (loss)
|
|
|
9.9 |
|
|
|
(18.2 |
) |
|
|
98.6 |
|
|
|
73.4 |
|
Basic earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
|
|
|
|
(.03 |
) |
|
|
.03 |
|
|
|
.17 |
|
|
Net income (loss)
|
|
|
.02 |
|
|
|
(.03 |
) |
|
|
.19 |
|
|
|
.13 |
|
Diluted earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
|
|
|
|
(.03 |
) |
|
|
.03 |
|
|
|
.17 |
|
|
Net income (loss)
|
|
|
.02 |
|
|
|
(.03 |
) |
|
|
.19 |
|
|
|
.13 |
|
|
2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
4,778.5 |
|
|
$ |
3,613.2 |
|
|
$ |
4,745.8 |
|
|
$ |
3,513.5 |
|
Costs and operating expenses
|
|
|
4,430.8 |
|
|
|
3,031.6 |
|
|
|
4,389.1 |
|
|
|
3,152.8 |
|
Income (loss) from continuing operations
|
|
|
(52.2 |
) |
|
|
50.0 |
|
|
|
18.0 |
|
|
|
(73.3 |
) |
Net income (loss)
|
|
|
(814.5 |
) |
|
|
269.7 |
|
|
|
106.3 |
|
|
|
(53.7 |
) |
Basic earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
(.12 |
) |
|
|
.06 |
|
|
|
.04 |
|
|
|
(.14 |
) |
|
Net income (loss)
|
|
|
(1.59 |
) |
|
|
.48 |
|
|
|
.21 |
|
|
|
(.10 |
) |
Diluted earnings (loss) per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
(.12 |
) |
|
|
.05 |
|
|
|
.03 |
|
|
|
(.14 |
) |
|
Net income (loss)
|
|
|
(1.59 |
) |
|
|
.47 |
|
|
|
.20 |
|
|
|
(.10 |
) |
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 2004 includes the following items
which are pre-tax:
|
|
|
|
|
$93.6 million income from Gulf Liquids insurance
arbitration award and related interest income of
$9.6 million at Midstream (see Note 4); |
|
|
|
$11.8 million expense related to an environmental accrual
for the Augusta refinery facility, included in Other (see
Note 4); |
|
|
|
$16.9 million impairment of our investment in Discovery
Pipeline at Midstream (see Note 3); and |
|
|
|
$29.5 million costs associated with the FELINE PACS
exchange and remarketing (see Note 11). |
Net income for third-quarter 2004 includes the following items
which are pre-tax:
|
|
|
|
|
$16.5 million reduction of revenue attributable to the
second quarter of 2004 as a result of Midstreams
correction of their revenue recognition methodology related to
the Devils Tower facility; |
163
THE WILLIAMS COMPANIES, INC.
QUARTERLY FINANCIAL DATA (Continued)
(Unaudited)
|
|
|
|
|
$155.1 million premiums, fees and expenses related to the
third-quarter 2004 cash tender offer and consent solicitations
(see Note 11); |
|
|
|
$15.7 million impairment of an international cost-based
investment, included at Other (see Note 3); |
|
|
|
$127.0 million loss from discontinued operations (see
Note 2); and |
|
|
|
$192.9 million gain from discontinued operations for
impairments and net gains on sales (see Note 2). |
Net loss for second-quarter 2004 includes the following items
which are pre-tax:
|
|
|
|
|
$9.0 million charge resulting from the write-off of
previously capitalized costs on an idled segment of a pipeline
at Gas Pipelines (see Note 4); |
|
|
|
$10.1 million benefit from the reversal of a default
reserve on good faith negotiations at Power; |
|
|
|
$11.3 million expense related to a loss provision regarding
an ownership dispute on prior period production at
Exploration & Production (see Note 4); |
|
|
|
$10.8 million impairment of our investment in Longhorn at
Other (see Note 3); |
|
|
|
$16.5 million increase in revenues related to the Devils
Tower facility subsequently reversed in third-quarter 2004 due
to a revenue recognition methodology correction at
Midstream; and |
|
|
|
$96.8 million premiums, fees and expenses related to the
second-quarter 2004 cash tender offer (see Note 11). |
Net income for first-quarter 2004 includes the following items
which are pre-tax:
|
|
|
|
|
$13.0 million charge resulting from the termination of a
non-derivative power sales contract at Power; |
|
|
|
$6.5 million net unreimbursed Longhorn recapitalization
advisory fees (see Note 3); |
|
|
|
$8.7 million income from discontinued operations (see
Note 2); and |
|
|
|
$6.9 million gain from discontinued operations for
impairments and net gains on sales (see Note 2). |
Net loss for fourth-quarter 2003 includes the following items
which are pre-tax:
|
|
|
|
|
$45.0 million impairment of goodwill at Power (see
Note 4); |
|
|
|
$44.1 million impairment of the Hazelton generation
facility at Power (see Note 4); |
|
|
|
$33.3 million California rate refund and other accrual
adjustments at Power; |
|
|
|
$19.9 million in unrealized gains on certain derivative
contracts that had previously not been recognized in 2003,
including approximately $10 million of revenue related to
the accounting treatment applied to certain derivative contracts
terminated in prior periods at Power (see Note 1); |
|
|
|
$16.2 million gain on sale of the wholesale propane
business at Midstream (see Note 4); |
|
|
|
$66.8 million of costs for the early retirement of debt
(see Note 11); |
|
|
|
$16.4 million impairment of the Gulf Liquids operations at
Midstream (see Note 4); and |
|
|
|
$32.5 million income from discontinued operations (see
Note 2). |
164
THE WILLIAMS COMPANIES, INC.
QUARTERLY FINANCIAL DATA (Continued)
(Unaudited)
Net income for third-quarter 2003 includes the following items
which are pre-tax:
|
|
|
|
|
$13.0 million gain on sale of a full requirements contract
at Power (see Note 4); |
|
|
|
$126.8 million positive valuation adjustment on a
terminated derivative contract at Power; |
|
|
|
$13.5 million gain on sale of marketable equity securities
at Power (see Note 3); |
|
|
|
$11.0 million gain on sale of equity interest in West Texas
LPG Pipeline, L.P. investment at Midstream (see Note 3); |
|
|
|
$20.3 million income from discontinued operations (see
Note 2); and |
|
|
|
$72.0 million gain from discontinued operations for
impairments and net gains on sales (see Note 2). |
Net income for second-quarter 2003 includes the following items
which are pre-tax:
|
|
|
|
|
$20 million CFTC settlement at Power (see Note 4); |
|
|
|
$175 million gain on sale of a full requirements contract
at Power (see Note 4); |
|
|
|
$25.5 million write-off of software development costs at
Gas Pipelines (see Note 4); |
|
|
|
$80.7 million correction, attributable to prior periods
relating to the accounting treatment previously applied to
certain third party derivative contracts during 2002 and 2001 at
Power (see Note 1); |
|
|
|
$12.4 million of revenue attributable to prior periods
relating to the accounting treatment previously applied to
certain third party derivative contracts during 2002 and 2001
and recorded prior to the $80.7 million correction in
second-quarter at Power (see Note 1); |
|
|
|
$94.1 million gain on the sale of certain natural gas
properties at Exploration & Production (see
Note 4); |
|
|
|
$42.4 million impairment of an investment in equity and
debt securities of Longhorn Partners Pipeline L.P. at Other (see
Note 3); |
|
|
|
$14.5 million in accelerated amortization of costs related
to the termination of the revolving credit agreement; |
|
|
|
$13.5 million impairment of cost based investment in
ReserveCo, a company holding phosphate reserves (see
Note 3); |
|
|
|
$92.6 million impairment of the Gulf Liquids operations at
Midstream (see Note 4); |
|
|
|
$33.3 million income from discontinued operations (see
Note 2); and |
|
|
|
$325.5 million gain from discontinued operations for
impairments and net gains on sales (see Note 2). |
Net loss for first-quarter 2003 includes the following items
which are pre-tax:
|
|
|
|
|
$13.7 million of revenue attributable to prior periods
relating to the accounting treatment previously applied to
certain third party derivative contracts during 2002 and 2001
and recorded prior to the $80.7 million correction in
second-quarter at Power (see Note 1); |
|
|
|
$12.0 million impairment of a cost based investment in
Algar Telecom S.A. at Other (see Note 3); |
|
|
|
$761.3 million after tax cumulative effect of change in
accounting principles related to the adoption of EITF 02-3
and SFAS No. 143 (see Note 1); |
165
THE WILLIAMS COMPANIES, INC.
QUARTERLY FINANCIAL DATA (Continued)
(Unaudited)
|
|
|
|
|
$111.8 million income from discontinued operations (see
Note 2); and |
|
|
|
$117.3 million loss from discontinued operations for
impairments and net losses on sales (see Note 2). |
166
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS DISCLOSURES
(Unaudited)
The following information pertains to our oil and gas producing
activities and is presented in accordance with
SFAS No. 69, Disclosures About Oil and Gas
Producing Activities. The information is required to be
disclosed by geographic region. We have significant oil and gas
producing activities primarily in the Rocky Mountain and
Mid-continent areas of the United States. Additionally, we have
oil and gas producing activities in Argentina and Venezuela.
However, proved reserves and revenues related to these
activities are approximately 6.7 percent and
5.2 percent, respectively, of our total international and
domestic oil and gas producing activities. The following
information relates only to the oil and gas activities in the
United States and includes the activities of those properties
that qualified for reporting as discontinued operations in the
Consolidated Statement of Operations.
Capitalized costs
|
|
|
|
|
|
|
|
|
|
|
As of December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
(Millions) | |
Proved properties
|
|
$ |
3,022.9 |
|
|
$ |
2,464.4 |
|
Unproved properties
|
|
|
569.7 |
|
|
|
682.5 |
|
|
|
|
|
|
|
|
|
|
|
3,592.6 |
|
|
|
3,146.9 |
|
Accumulated depreciation, depletion and amortization and
valuation provisions
|
|
|
(688.3 |
) |
|
|
(511.1 |
) |
|
|
|
|
|
|
|
Net capitalized costs
|
|
$ |
2,904.3 |
|
|
$ |
2,635.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized costs include the cost of equipment and facilities
for oil and gas producing activities. These amounts for 2004 and
2003 do not include approximately $1 billion of goodwill
related to the purchase of Barrett Resources Corp. (Barrett) in
2001. |
|
|
|
Proved properties include capitalized costs for oil and gas
leaseholds holding proved reserves; development wells and
related equipment and facilities (including uncompleted
development well costs); and successful exploratory wells and
related equipment and facilities. |
|
|
|
Unproved properties consist primarily of acreage related to
probable/possible reserves acquired through the Barrett
acquisition in addition to a small portion of unproved
exploratory acreage. |
Costs incurred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended | |
|
|
December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Acquisition
|
|
$ |
17.2 |
|
|
$ |
11.3 |
|
|
$ |
|
|
Exploration
|
|
|
4.5 |
|
|
|
7.1 |
|
|
|
15.5 |
|
Development
|
|
|
419.2 |
|
|
|
186.8 |
|
|
|
374.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
440.9 |
|
|
$ |
205.2 |
|
|
$ |
389.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred include capitalized and expensed items. |
|
|
|
Acquisition costs are as follows: The 2004 costs related to the
Huber-Edwards reserve acquisition in the San Juan Basin,
RBS, Vectra and Citrus reserve acquisitions in the Arkoma basin,
and Guthrie leasehold acquisition in the Powder River basin. The
2003 costs relates to the Smith, Contra, Tailwind acquisition
also in the Arkoma basis at the end of 2003. |
167
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS
DISCLOSURES (Continued)
(Unaudited)
|
|
|
|
|
Exploration costs 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. |
|
|
|
Development costs include costs incurred to gain access to and
prepare development well locations for drilling and to drill and
equip development wells. |
Results of operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
2002* | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues
|
|
$ |
599.9 |
|
|
$ |
611.9 |
|
|
$ |
683.0 |
|
|
Other revenues
|
|
|
137.3 |
|
|
|
168.8 |
|
|
|
189.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
737.2 |
|
|
|
780.7 |
|
|
|
872.0 |
|
|
|
|
|
|
|
|
|
|
|
Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
165.4 |
|
|
|
138.3 |
|
|
|
119.5 |
|
|
General & administrative
|
|
|
58.3 |
|
|
|
54.4 |
|
|
|
62.9 |
|
|
Exploration expenses
|
|
|
4.5 |
|
|
|
7.1 |
|
|
|
13.9 |
|
|
Depreciation, depletion & amortization
|
|
|
183.4 |
|
|
|
170.2 |
|
|
|
191.0 |
|
|
Property impairments
|
|
|
|
|
|
|
|
|
|
|
8.4 |
|
|
(Gains)/losses on sales of interests in oil and gas properties
|
|
|
0.1 |
|
|
|
(134.8 |
) |
|
|
(141.7 |
) |
|
Other expenses
|
|
|
115.2 |
|
|
|
102.1 |
|
|
|
109.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs
|
|
|
526.9 |
|
|
|
337.3 |
|
|
|
363.2 |
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
|
210.3 |
|
|
|
443.4 |
|
|
|
508.8 |
|
Provision for income taxes
|
|
|
(81.4 |
) |
|
|
(169.6 |
) |
|
|
(186.9 |
) |
|
|
|
|
|
|
|
|
|
|
Exploration and production net income
|
|
$ |
128.9 |
|
|
$ |
273.8 |
|
|
$ |
321.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
Certain amounts have been reclassified to conform to current
presentation. |
|
|
|
|
|
Results of operations for producing activities consist of all
related domestic activities within the Exploration &
Production reporting unit, including those operations that
qualified for presentation as discontinued operations within our
Consolidated Statement of Operations. Included above are the
pretax results of operations and gains on sales of assets,
reported as discontinued operations, of $60.2 million in
2003 and $11.9 million in 2002. Other expenses in 2004
includes a $16 million gain attributable to the sales of
securities, assicatied with a coal seam royalty trust, that were
purchased for resale. |
|
|
|
Oil and gas revenues consist primarily of natural gas production
sold to the Power subsidiary and includes the impact of
intercompany hedges. |
|
|
|
Other revenues and other expenses consist of activities within
the Exploration & Production segment that are not a
direct part of the producing activities. These non-producing
activities include acquisition and disposition of other working
interest and royalty interest gas and the movement of gas from
the wellhead to the tailgate of the respective plants for sale
to the Power subsidiary or third party purchasers. In addition,
other revenues include recognition of income from transactions
which transferred certain non-operating benefits to a third
party. |
168
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS
DISCLOSURES (Continued)
(Unaudited)
|
|
|
|
|
Production costs consist of costs incurred to operate and
maintain wells and related equipment and facilities used in the
production of petroleum liquids and natural gas. These costs
also include production related taxes other than income taxes,
and administrative expenses related to the production activity.
Excluded are depreciation, depletion and amortization of
capitalized acquisition, exploration and development costs. |
|
|
|
Exploration expenses include unsuccessful exploratory dry hole
costs, leasehold impairment, geological and geophysical expenses
and the cost of retaining undeveloped leaseholds. |
|
|
|
Depreciation, depletion and amortization includes depreciation
of support equipment. |
Proved reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Bcfe) | |
Proved reserves at beginning of period
|
|
|
2,703 |
|
|
|
2,834 |
|
|
|
3,178 |
|
|
Revisions
|
|
|
(70 |
) |
|
|
(5 |
) |
|
|
(87 |
) |
|
Purchases
|
|
|
24 |
|
|
|
38 |
|
|
|
|
|
|
Extensions and discoveries
|
|
|
521 |
|
|
|
412 |
|
|
|
385 |
|
|
Production
|
|
|
(191 |
) |
|
|
(186 |
) |
|
|
(211 |
) |
|
Sale of minerals in place
|
|
|
(1 |
) |
|
|
(390 |
) |
|
|
(431 |
) |
|
|
|
|
|
|
|
|
|
|
Proved reserves at end of period
|
|
|
2,986 |
|
|
|
2,703 |
|
|
|
2,834 |
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at end of period
|
|
|
1,348 |
|
|
|
1,165 |
|
|
|
1,368 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The SEC defines proved oil and gas reserves (Rule 4-10(a)
of Regulation S-X) as the estimated quantities of crude
oil, natural gas, and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty are
recoverable in future years from known reservoirs under existing
economic and operating conditions. Our 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 limited to those drilling units
offsetting productive units that are reasonably certain of
production when drilled or where it can be demonstrated with
certainty that there is continuity of production from the
existing productive formation. |
|
|
|
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). |
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 and the year-end prices and costs. The average year end
natural gas prices used in the following estimates were $5.08,
$5.28, and $3.85 per MMcfe at December 31, 2004, 2003
and 2002, respectively. Future income tax expenses have been
computed considering available carryforwards and credits and the
appropriate statutory tax rates. The discount rate of
10 percent is as prescribed by SFAS No. 69.
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
169
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS
DISCLOSURES (Continued)
(Unaudited)
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 $1,703 million of future
development costs, $421 million, $461 million and
$374 million are estimated to be spent in 2005, 2006 and
2007, respectively.
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, | |
|
|
| |
|
|
2004 | |
|
2003 | |
|
|
| |
|
| |
|
|
(Millions) | |
Future cash inflows
|
|
$ |
15,174 |
|
|
$ |
14,268 |
|
Less:
|
|
|
|
|
|
|
|
|
|
Future production costs
|
|
|
3,027 |
|
|
|
2,434 |
|
|
Future development costs
|
|
|
1,703 |
|
|
|
1,303 |
|
|
Future income tax provisions
|
|
|
3,744 |
|
|
|
3,858 |
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
6,700 |
|
|
|
6,673 |
|
Less 10 percent annual discount for estimated timing of
cash flows
|
|
|
3,553 |
|
|
|
3,324 |
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$ |
3,147 |
|
|
$ |
3,349 |
|
|
|
|
|
|
|
|
170
THE WILLIAMS COMPANIES, INC.
SUPPLEMENTAL OIL AND GAS
DISCLOSURES (Continued)
(Unaudited)
Sources of change in standardized measure of discounted
future net cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
| |
|
| |
|
|
(Millions) | |
Standardized measure of discounted future net cash flows
beginning of period
|
|
$ |
3,349 |
|
|
$ |
2,272 |
|
|
$ |
1,432 |
|
Changes during the year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of oil and gas produced, net of operating costs
|
|
|
(835 |
) |
|
|
(567 |
) |
|
|
(322 |
) |
|
Net change in prices and production costs
|
|
|
(306 |
) |
|
|
2,001 |
|
|
|
1,602 |
|
|
Extensions, discoveries and improved recovery, less estimated
future costs
|
|
|
787 |
|
|
|
901 |
|
|
|
546 |
|
|
Development costs incurred during year
|
|
|
419 |
|
|
|
187 |
|
|
|
374 |
|
|
Changes in estimated future development costs
|
|
|
(696 |
) |
|
|
(159 |
) |
|
|
(326 |
) |
|
Purchase of reserves in place, less estimated future costs
|
|
|
29 |
|
|
|
78 |
|
|
|
|
|
|
Sales of reserves in place, less estimated future costs
|
|
|
(3 |
) |
|
|
(855 |
) |
|
|
(611 |
) |
|
Revisions of previous quantity estimates
|
|
|
(90 |
) |
|
|
(11 |
) |
|
|
(123 |
) |
|
Accretion of discount
|
|
|
286 |
|
|
|
341 |
|
|
|
203 |
|
|
Net change in income taxes
|
|
|
182 |
|
|
|
(773 |
) |
|
|
(537 |
) |
Other
|
|
|
25 |
|
|
|
(66 |
) |
|
|
34 |
|
|
|
|
|
|
|
|
|
|
|
Net changes
|
|
|
(202 |
) |
|
|
1,077 |
|
|
|
840 |
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows end of
period
|
|
$ |
3,147 |
|
|
$ |
3,349 |
|
|
$ |
2,272 |
|
|
|
|
|
|
|
|
|
|
|
171
THE WILLIAMS COMPANIES, INC.
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ADDITIONS | |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Charged to | |
|
|
|
|
|
|
|
|
Beginning | |
|
Cost and | |
|
|
|
|
|
Ending | |
|
|
Balance | |
|
Expenses | |
|
Other | |
|
Deductions | |
|
Balance | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
(Millions) | |
Year ended December 31, 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts Accounts and notes
receivable(a)
|
|
$ |
112.2 |
|
|
$ |
(.8 |
) |
|
$ |
|
|
|
$ |
12.6 |
(c) |
|
$ |
98.8 |
|
|
Price-risk management credit reserves(a)
|
|
|
39.8 |
|
|
|
(12.8 |
)(e) |
|
|
(.6 |
) |
|
|
|
|
|
|
26.4 |
|
|
Processing plant major maintenance accrual(b)
|
|
|
4.1 |
|
|
|
1.6 |
|
|
|
|
|
|
|
|
|
|
|
5.7 |
|
Year ended December 31, 2003:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts Accounts and notes
receivable(a)
|
|
|
111.8 |
|
|
|
7.3 |
|
|
|
7.9 |
(g) |
|
|
14.8 |
(c) |
|
|
112.2 |
|
|
Price-risk management credit reserves(a)
|
|
|
250.4 |
|
|
|
2.6 |
(e) |
|
|
|
|
|
|
213.2 |
(f) |
|
|
39.8 |
|
|
Processing plant major maintenance accrual(b)
|
|
|
2.7 |
|
|
|
1.4 |
|
|
|
|
|
|
|
|
|
|
|
4.1 |
|
Year ended December 31, 2002:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts Accounts and notes
receivable(a)
|
|
|
251.8 |
|
|
|
22.4 |
|
|
|
|
|
|
|
162.4 |
(c) |
|
|
111.8 |
|
|
|
Other noncurrent assets(a)
|
|
|
103.2 |
|
|
|
256.0 |
|
|
|
1,720.0 |
(d) |
|
|
2,079.2 |
(c) |
|
|
|
|
|
Price-risk management credit reserves(a)
|
|
|
648.2 |
|
|
|
(397.8 |
)(e) |
|
|
|
|
|
|
|
|
|
|
250.4 |
|
|
Processing plant major maintenance accrual(b)
|
|
|
1.2 |
|
|
|
1.5 |
|
|
|
|
|
|
|
|
|
|
|
2.7 |
|
|
|
|
(a) |
|
Deducted from related assets. |
|
(b) |
|
Included in liabilities. |
|
(c) |
|
Represents balances written off, net of recoveries and
reclassifications. |
|
(d) |
|
Reflects a reclassification of amounts included in the liability
for Guarantees and payment obligations related to WilTel at
December 31, 2002. |
|
(e) |
|
Included in revenue. |
|
(f) |
|
Reflects cumulative effect of change in accounting principle
related to EITF 02-3 (see Note 1 of Notes to
Consolidated Financial Statements). |
|
(g) |
|
Reflects allowances for accounts receivable charged to costs and
expenses for a discontinued operation whose receivables were not
held for sale. |
172
|
|
Item 9. |
Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure |
None
|
|
Item 9A. |
Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation
of our disclosure controls and procedures (as defined in
Rules 13a-15(e) and 15(d) 15(e) of the
Securities Exchange Act of 1934) (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.
Our management, including our Chief Executive Officer and Chief
Financial Officer, does not expect that our 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.
Managements Report on Internal Control over Financial
Reporting
See Managements Report on Internal Control over
Financial Reporting set forth on page 88 in
Item 8, Financial Statements and Supplementary Data,
immediately following the audit reports of Ernst &
Young LLP.
Fourth Quarter 2004 Changes in Internal Control Over
Financial Reporting
Effective October 1, 2004, our Power business segment
elected to apply to certain of its derivatives hedge accounting
provisions of FAS 133 (see Note 14 of Notes to
Financial Statements). In connection with this application,
Power implemented certain changes to its processes and
established related internal controls.
There has been no material change in our Internal Controls,
other than those noted above, that occurred during the
registrants fourth fiscal quarter.
|
|
Item 9B. |
Other Information |
None.
PART III
|
|
Item 10. |
Directors and Executive Officers of the Registrant |
The information regarding our directors and nominees for
director required by Item 401 of Regulation S-K will
be presented under the headings Board of
Directors Board Committees, Election of
Directors, and Principal Accountant Fees and
Services in our Proxy Statement prepared for the
solicitation
173
of proxies in connection with our Annual Meeting of Stockholders
to be held May 19, 2005 (Proxy Statement), which
information is incorporated by reference herein.
Information regarding our executive officers required by
Item 401 of Regulation S-K is presented as
Item 4A herein and captioned 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 Compliance with
Section 16(a) of the Securities Exchange Act of 1934
in our Proxy Statement, which information is incorporated by
reference herein.
We have adopted a Code of Ethics that applies to our Chief
Executive Officer, Chief Financial Officer, and Controller, or
persons performing similar functions. The Code of Ethics,
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 Secretary at Williams, One Williams Center,
Suite 4100, 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 of Regulation S-K
regarding executive compensation will be presented under the
headings Board of Directors and Executive
Compensation and Other Information in our Proxy Statement,
which information is incorporated by reference herein.
Notwithstanding the foregoing, the information provided under
the headings Compensation Committee Report on Executive
Compensation and Stockholder Return Performance
Presentation in our Proxy Statement is not incorporated by
reference herein.
|
|
Item 12. |
Security Ownership of Certain Beneficial Owners and
Management |
The information regarding the security ownership of certain
beneficial owners and management required by Item 403 of
Regulation S-K will be presented under the headings
Security Ownership of Certain Beneficial Owners and
Management in our Proxy Statement, which information is
incorporated by reference herein.
174
EQUITY COMPENSATION STOCK PLANS
Securities authorized for issuance under equity compensation
plans
The following table provides information concerning our common
stock that may be issued upon the exercise of options, warrants
and rights under all of our existing equity compensation plans
as of December 31, 2004, including The Williams Companies,
Inc. 2002 Incentive Plan, The Williams Companies, Inc. 2001
Stock Plan, The Williams Companies, Inc. Stock Plan for
Non-Officer Employees, The Williams Companies, Inc. 1996 Stock
Plan, The Williams International Stock Plan, The Williams
Companies, Inc. 1996 Stock Plan for Non-Employee Directors, The
Williams Companies, Inc. 1988 Stock Option Plan for Non-Employee
Directors, The Williams Companies, Inc. 1990 Stock Plan and The
Williams Communications Stock Plan.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities | |
|
|
Number of Securities to | |
|
Weighted-Average | |
|
Remaining Available for Future | |
|
|
be Issued upon Exercise | |
|
Exercise Price of | |
|
Issuance Under Equity | |
|
|
of Outstanding Options, | |
|
Outstanding Options, | |
|
Compensation Plans | |
|
|
Warrants and | |
|
Warrants and | |
|
(Excluding Securities Reflected | |
Plan Category |
|
Rights(2) | |
|
Rights(3) | |
|
in the 1st Column of This Table) | |
|
|
| |
|
| |
|
| |
Equity Compensation plans approved by security holders
|
|
|
19,702,328 |
|
|
$ |
12.44 |
|
|
|
25,235,521 |
|
Equity Compensation plans not approved by security holders(1)
|
|
|
4,832,815 |
|
|
$ |
26.51 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
24,535,143 |
|
|
$ |
15.36 |
|
|
|
25,235,521 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
As described in Note 13 of our Notes to Consolidated
Financial Statements, these plans were terminated upon
shareholder approval of the 2002 Incentive Plan. Options
outstanding in these plans remain in the plans subject to their
terms. Those options generally expire 10 years after the
grant date. |
|
(2) |
Includes 2,530,844 shares of deferred stock. |
|
(3) |
Excludes the shares of deferred stock included in the
1st column of this table for which there is no
weighted-average price. |
|
|
Item 13. |
Certain Relationships and Related Transactions |
The information regarding certain relationships and related
transactions required by Item 404 of Regulation S-K
will be presented under the heading Certain Relationships
and Related Transactions in our Proxy Statement, which
information is incorporated by reference herein.
|
|
Item 14. |
Principal Accounting 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 Principal Accountant Fees and
Services in our Proxy Statement, which information is
incorporated by reference herein.
175
PART IV
|
|
Item 15. |
Exhibits, Financial Statement Schedules |
(a) 1 and 2.
|
|
|
|
|
|
|
|
|
Page | |
|
|
| |
Covered by report of independent auditors:
|
|
|
|
|
|
Consolidated statement of operations for each of the three years
ended December 31, 2004
|
|
|
91 |
|
|
Consolidated balance sheet at December 31, 2004 and 2003
|
|
|
92 |
|
|
Consolidated statement of stockholders equity for each of
the three years ended December 31, 2004
|
|
|
93 |
|
|
Consolidated statement of cash flows for each of the three years
ended December 31, 2004
|
|
|
94 |
|
|
Notes to consolidated financial statements
|
|
|
95 |
|
Not covered by report of independent auditors:
|
|
|
|
|
|
Quarterly financial data (unaudited)
|
|
|
163 |
|
|
Supplemental oil and gas disclosures (unaudited)
|
|
|
167 |
|
|
Schedule for each of the three years ended December 31,
2004:
|
|
|
|
|
|
|
II Valuation and qualifying accounts
|
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|
172 |
|
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
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Exhibit | |
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No. | |
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|
|
Description |
| |
|
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|
3.1 |
|
|
|
|
Restated Certificate of Incorporation, as supplemented. |
|
3.2* |
|
|
|
|
Restated By-laws (filed as Exhibit 3.1 to Form 8-K
filed September 21, 2004 ). |
|
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 as Exhibit 4.1 to Form S-3
filed September 8, 1997). |
|
4.2* |
|
|
|
|
Form of Floating Rate Senior Note (filed as Exhibit 4.3 to
Form S-3 filed September 8, 1997). |
|
4.3* |
|
|
|
|
Form of Fixed Rate Senior Note (filed as Exhibit 4.4 to
Form S-3 filed September 8, 1997). |
|
4.4* |
|
|
|
|
Fourth Supplemental Indenture between Williams and Bank One
Trust Company, N.A., as Trustee, dated as of January 17,
2001 (filed as Exhibit 4(j) to Form 10-K for the
fiscal year ended December 31, 2000). |
|
4.5* |
|
|
|
|
Fifth Supplemental Indenture between Williams and Bank One Trust
Company, N.A., as Trustee, dated as of January 17, 2001
(filed as Exhibit 4(k) to Form 10-K for the fiscal
year ended December 31, 2000). |
|
4.6* |
|
|
|
|
Sixth Supplemental Indenture dated January 14, 2002,
between Williams and Bank One Trust Company, National
Association, as Trustee (filed as Exhibit 4.1 to
Form 8-K filed January 23, 2002). |
|
4.7* |
|
|
|
|
Seventh Supplemental Indenture dated March 19, 2002,
between The Williams Companies, Inc. as Issuer and Bank One
Trust Company, National Association, as Trustee (filed as
Exhibit 4.1 to Form 10-Q filed May 9, 2002). |
176
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|
|
|
Exhibit | |
|
|
|
|
No. | |
|
|
|
Description |
| |
|
|
|
|
|
4.8* |
|
|
|
|
Eighth Supplemental Indenture dated as of June 3, 2002,
between The Williams Companies, Inc., as Issuer and Bank One
Trust Company, N.A., as Trustee (filed as Exhibit 4.8 to
Form 10-K for the fiscal year ended December 31, 2003). |
|
4.9* |
|
|
|
|
Ninth Supplemental Indenture dated June 10, 2003 between
The Williams Companies, Inc. as Issuer and JPMorgan Chase Bank
as Trustee (filed as Exhibit 4.1 to Form 10-Q filed
August 12, 2003). |
|
4.10* |
|
|
|
|
Tenth Supplemental Indenture dated as of August 17, 2004,
with respect to the Indenture dated as of November 10, 1997
between The Williams Companies, Inc. and JPMorgan Chase Bank (as
successor trustee to Bank One Trust Company, National
Association (successor to the First National Bank of Chicago))
(filed as Exhibit 99.2 for Form 8-K filed
August 17, 2004). |
|
4.11* |
|
|
|
|
Form of Senior Debt Indenture between Williams Holdings of
Delaware, Inc. and Citibank, N.A., as Trustee (filed as
Exhibit 4.1 to Williams Holdings of Delaware, Inc.s
Form 10-Q filed October 18, 1995). |
|
4.12* |
|
|
|
|
First Supplemental Indenture dated as of July 31, 1999,
among Williams Holdings of Delaware, Inc., Williams and
Citibank, N.A., as Trustee (filed as Exhibit 4(o) to
Form 10-K for the fiscal year ended December 31, 1999). |
|
4.13* |
|
|
|
|
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 as
Exhibit 4.4.1 to MAPCO Inc.s Amendment No. 1 to
Form S-3 dated February 25, 1997). |
|
4.14* |
|
|
|
|
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). |
|
4.15* |
|
|
|
|
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). |
|
4.16* |
|
|
|
|
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). |
|
4.17* |
|
|
|
|
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 as Exhibit 4(q) to
Form 10-K for the fiscal year ended December 31, 1999). |
|
4.18* |
|
|
|
|
Revised Form of Indenture between Barrett Resources Corporation,
as Issuer, and Bankers Trust Company, as Trustee, with respect
to Senior Notes including specimen of 7.55% Senior Notes
(filed as Exhibit 4.1 to Barrett Resources
Corporations Amendment No. 2 to Registration
Statement on Form S-3 filed February 10, 1997). |
|
4.19* |
|
|
|
|
First Supplemental Indenture dated 2001, between Barrett
Resources Corporation, as Issuer, and Bankers Trust Company, as
Trustee (filed as Exhibit 4.3 to Form 10-Q filed
November 13, 2001). |
|
4.20* |
|
|
|
|
Second Supplemental Indenture dated as of August 2, 2001,
among Barrett Resources Corporation, as Issuer, Resources
Acquisition Corp., The Williams Companies, Inc. and Bankers
Trust Company, as Trustee (filed as Exhibit 4.4 to
Form 10-Q filed November 13, 2001). |
|
4.21* |
|
|
|
|
Third Supplemental Indenture dated as of May 20, 2004 with
respect to the Indenture dated as of February 1, 1997
between Barrett Resources Corporation (predecessor-in-interest
to Williams Production RMT Company) and Deutsche Bank Trust
Company Americas (formerly known as Bankers Trust Company), as
trustee (filed as Exhibit 99.2 to Form 8-K filed
May 20, 2004). |
|
4.22* |
|
|
|
|
Form of Note (filed as Exhibit 4.2 and included in
Exhibit 4.1 to Form 8-K filed January 23, 2002). |
|
4.23* |
|
|
|
|
Purchase Contract Agreement dated January 14, 2002, between
Williams and JPMorgan Chase Bank, as Purchase Contract Agent
(filed as Exhibit 4.3 to Form 8-K filed
January 23, 2002). |
|
4.24* |
|
|
|
|
Form of Income PACS Certificate (filed as Exhibit 4.4 and
included in Exhibit 4.3 to Form 8-K filed
January 23, 2002). |
177
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|
|
Exhibit | |
|
|
|
|
No. | |
|
|
|
Description |
| |
|
|
|
|
|
4.25* |
|
|
|
|
Pledge Agreement dated January 14, 2002, among Williams,
Bank, as Purchase Contract Agent (filed as Exhibit 4.5 to
Form 8-K filed January 23, 2002). |
|
4.26* |
|
|
|
|
Remarketing Agreement dated January 14, 2002, among
Williams, JPMorgan Chase Bank, as Purchase Contract Agent, and
Merrill Lynch & Co., Merrill Lynch, Pierce,
Fenner & Smith Incorporated, as Remarketing Agent
(filed as Exhibit 4.6 to Form 8-K filed
January 23, 2002). |
|
4.27* |
|
|
|
|
Supplemental Remarketing Agreement dated as of November 4,
2004 by and among Williams, Merill Lynch & Co., Merrill
Lynch, Pierce, Fenner & Smith Incorporation, as
Remarketing Agent, and JPMorgan Chase Bank, as Purchase Contract
Agent (filed as exhibit 99.1 to Form 8-K filed
November 9, 2004). |
|
4.28* |
|
|
|
|
Indenture dated March 4, 2003, between Northwest Pipeline
Corporation and JP Morgan Chase Bank, as Trustee (filed as
Exhibit 4.1 to Form 10-Q filed May 13, 2003. |
|
4.29* |
|
|
|
|
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 as Exhibit 4.2 to Form 10-Q
filed August 12, 2003). |
|
4.30* |
|
|
|
|
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 as Exhibit 4.1
to Form 8-K filed September 21, 2004. |
|
10.1* |
|
|
|
|
The Williams Companies, Inc. Supplemental Retirement Plan
effective as of January 1, 1988 (filed as
Exhibit 10(iii)(c) to Form 10-K for the fiscal year
ended December 31, 1987). |
|
10.2* |
|
|
|
|
First Amendment to The Williams Companies, Inc. Supplemental
Retirement Plan effective as of April 1, 1988 (filed
as Exhibit 10.2 to Form 10-K for the fiscal year ended
December 31, 2003). |
|
10.3 |
|
|
|
|
Second Amendment to The Williams Companies, Inc. Supplemental
Retirement Plan effective as of January 1, 2002 and
January 1, 2003. |
|
10.4* |
|
|
|
|
The Williams Companies, Inc. 1988 Stock Option Plan for
Non-Employee Directors (filed as Exhibit A to the Proxy
Statement dated March 14, 1988). |
|
10.5* |
|
|
|
|
The Williams Companies, Inc. 1990 Stock Plan (filed as
Exhibit A to the Proxy Statement dated March 12,
1990). |
|
10.6* |
|
|
|
|
The Williams Companies, Inc. Stock Plan for Non-Officer
Employees (filed as Exhibit 10(iii)(g) to Form 10-K
for the fiscal year ended December 31, 1995). |
|
10.7* |
|
|
|
|
The Williams Companies, Inc. 1996 Stock Plan (filed as
Exhibit A to the Proxy Statement dated March 27,
1996). |
|
10.8* |
|
|
|
|
The Williams Companies, Inc. 1996 Stock Plan for Non-Employee
Directors (filed as Exhibit B to the Proxy Statement dated
March 27, 1996). |
|
10.9* |
|
|
|
|
Indemnification Agreement effective as of August 1, 1986,
among Williams, members of the Board of Directors and certain
officers of Williams (filed as Exhibit 10(iii)(e) to
Form 10-K for the year ended December 31, 1986). |
|
10.10* |
|
|
|
|
The Williams International Stock Plan (filed as
Exhibit 10(iii)(l) to Form 10-K for the fiscal year
ended December 31, 1998). |
|
10.11* |
|
|
|
|
Form of Stock Option Secured Promissory Note and Pledge
Agreement among Williams and certain employees, officers and
non-employee directors (filed as Exhibit 10(iii)(m) to
Form 10-K for the fiscal year ended December 31, 1998). |
|
10.12 |
|
|
|
|
Form of 2004 Deferred Stock Agreement among Williams and certain
employees and officers. |
|
10.13 |
|
|
|
|
Form of 2004 Performance-Based Deferred Stock Agreement among
Williams and executive officers. |
|
10.14* |
|
|
|
|
Form of Stock Option Agreement among Williams and certain
employees and officers (filed as Exhibit 99.1 to
Form 8-K filed March 2, 2005). |
|
10.15* |
|
|
|
|
Form of 2005 Deferred Stock Agreement among Williams and certain
employees and officers (filed as Exhibit 99.2 to
Form 8-K filed March 2, 2005). |
|
10.16* |
|
|
|
|
Form of 2005 Performance-Based Deferred Stock Agreement among
Williams and executive officers.(filed as Exhibit 99.3 to
Form 8-K filed March 2, 2005). |
178
|
|
|
|
|
|
|
Exhibit | |
|
|
|
|
No. | |
|
|
|
Description |
| |
|
|
|
|
|
10.17* |
|
|
|
|
The Williams Companies, Inc. 2001 Stock Plan (filed as
Exhibit 4.1 to Form S-8 filed August 1, 2001). |
|
10.18* |
|
|
|
|
The Williams Companies, Inc. 2002 Incentive Plan as amended and
restated effective as of January 23, 2004 (filed as
Exhibit 10.1 to Form 10-Q filed on August 5,
2004). |
|
10.19* |
|
|
|
|
Form of Change in Control Severance Agreement between the
Company and certain executive officers (filed as
Exhibit 10.12 to Form 10-Q filed November 14,
2002). |
|
10.20* |
|
|
|
|
Settlement Agreement, by and among the Governor of the State of
California and the several other parties named therein and The
Williams Companies, Inc. and Williams Energy
Marketing & Trading Company dated November 11,
2002 (filed as Exhibit 10.79 for Form 10-K for the
fiscal year ended December 31, 2002). |
|
10.21* |
|
|
|
|
U.S. $500,000,000 Term Loan Agreement among Williams
Production Holdings LLC, Williams Production RMT Company, as
Borrower, the Several Lenders from time to time parties thereto,
Lehman Brothers Inc. and Banc of America Securities LLC as Joint
Lead Arrangers, Citigroup USA, Inc. and JPMorgan Chase Bank, as
Co-Syndication Agents, Bank of America, N.A., as Documentation
Agent, and Lehman Commercial Paper Inc., as Administrative Agent
dated as of May 30, 2003 (filed as Exhibit 10.1 to
Form 10-Q filed August 12, 2003). |
|
10.22* |
|
|
|
|
The First Amendment to the Term Loan Agreement dated
February 25, 2004, between Williams Production Holdings,
LLC, Williams Production RMT Company, as Borrower, the several
financial institutions as lenders and Lehman Commercial Paper
Inc., as Administrative Agent dated as of May 30, 2003
(filed as Exhibit 10.3 to Form 10-Q filed May 6,
2004). |
|
10.23* |
|
|
|
|
Guarantee and Collateral Agreement made by Williams Production
Holdings LLC, Williams Production RMT Company and certain of its
Subsidiaries in favor of Lehman Commercial Paper Inc. as
Administrative Agent dated as of May 30, 2003 (filed as
Exhibit 10.2 to Form 10-Q filed August 12, 2003). |
|
10.24* |
|
|
|
|
U.S. $800,000,000 Credit Agreement dated as of June 6,
2003, among The Williams Companies, Inc., Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation, as
Borrowers, Citibank, N.A., as Administrative Agent and
Collateral Agent, Bank of America, N.A., as Syndication Agent,
JPMorgan Chase Bank, as documentation Agreement, Citibank, N.A.
and Bank of America, N.A. as Issuing Banks, the banks named
therein as Banks and Citigroup Global Markets Inc. and Banc of
America Securities LLC as Joint Lead Arrangers and Joint Book
Runners (filed as Exhibit 10.3 to Form 10-Q filed
August 12, 2003). |
|
10.25* |
|
|
|
|
Security Agreement dated as of June 6, 2003, among The
Williams Companies, Inc., as Grantor, Citibank, N.A., as
Collateral Agent and Citibank, N.A. as Securities Intermediary
(filed as Exhibit 10.4 to Form 10-Q filed
August 12, 2003). |
|
10.26* |
|
|
|
|
U.S. $1,000,000,000 Credit Agreement dated as of
May 3, 2004, among The Williams Companies, Inc., Northwest
Pipeline Corporation, Transcontinental Gas Pipeline Corporation,
as Borrowers, Citicorp USA, Inc., as Administrative Agent and
Collateral Agent, Citibank, N.A. and Bank of America, N.A., as
Issuing Banks, the banks named therein as Banks, Bank of
America, N.A., as Syndication Agent, JPMorgan Chase Bank, The
Bank of Nova Scotia, The Royal Bank of Scotland plc as
Co-Documentation Agents, Citigroup Global Markets Inc. and Banc
of America Securities LLC as Joint Lead Arrangers and Co-Book
Runners (filed as Exhibit 10.4 to Form 10-Q filed
May 6, 2004). |
|
10.27* |
|
|
|
|
Letter of Credit Commitment Increase Agreement dated
August 4, 2004, by and among The Williams Companies, Inc.,
Citicorp USA in its capacity as Agent under the Credit Agreement
dated as of May 3, 2004 among the Borrower, Northwest
Pipeline Corporation, Transcontinental Gas Pipe Line
Corporation, the Agent, the Collateral Agent, the Banks and
Issuing Banks party thereto and Citibank, N.A. and Bank of
America, N.A. (filed as Exhibit 10.1 to Form 10-Q
filed November 4, 2004). |
179
|
|
|
|
|
|
|
Exhibit | |
|
|
|
|
No. | |
|
|
|
Description |
| |
|
|
|
|
|
10.28* |
|
|
|
|
Revolving Credit Commitment Increase Agreement dated
August 4, 2004, by and among The Williams Companies, Inc.,
Citicorp USA in its capacity as Agent under the Credit Agreement
dated as of May 3, 2004 among the Borrower, Northwest
Pipeline Corporation, Transcontinental Gas Pipe Line
Corporation, the Agent, the Collateral Agent and the Banks and
Issuing Banks party thereto, the Issuing Banks and Citicorp USA,
Inc. (filed as Exhibit 10.2 to Form 10-Q filed
November 4, 2004). |
|
10.29 |
|
|
|
|
Amendment Agreement dated as of October 19, 2004 among The
Williams Companies, Inc., Northwest Pipeline Corporation,
Transcontinental Gas Pipeline Corporation, as Borrowers, the
banks, financial institutions and other institutional lenders
that are parties to the Credit Agreement dated as of May 3,
2004 among the Borrowers, the Banks, Citicorp USA, Inc., as
agent and Citibank, N.A. and Bank of America, N.A., as issuers
of letters of credit under the Credit Agreement, the Agent and
the Issuing Banks. |
|
10.30* |
|
|
|
|
Western Midstream Security Agreement dated as of May 3,
2004, among Williams Gas Processing Company, Williams Field
Services Company, Williams Gas Processing Wamsutter
Company as Grantors, in favor of Citicorp USA, Inc. as
Collateral Agents (filed as Exhibit 10.5 to Form 10-Q
filed May 6, 2004). |
|
10.31* |
|
|
|
|
Pledge Agreement dated as of May 3, 2004, by Williams Field
Services Group, Inc. in favor of Citicorp USA, Inc. as
Collateral Agent (filed as Exhibit 10.6 to Form 10-Q
filed May 6, 2004). |
|
10.32* |
|
|
|
|
Western Midstream Guaranty by Williams Gas Processing Company,
Williams Field Services Company, Williams Gas
Processing Wamsutter Company as Guarantors in favor
of Citicorp USA, Inc. as Collateral Agent (filed as
Exhibit 10.7 for Form 10-Q filed May 6, 2004). |
|
10.33* |
|
|
|
|
Pipeline Holdco Guaranty by Williams Gas Pipeline Company, LLC
as Guarantor in favor of Citicorp USA, Inc. as Collateral Agent
(filed as Exhibit 10.8 to Form 10-Q filed May 6,
2004). |
|
10.34* |
|
|
|
|
Amended and Restated U.S. $400,000,000 Five Year Credit
Agreement dated April 14, 2004 and amended January 20,
2005 among The Williams Companies, Inc., as Borrower, the
Initial Lenders named herein, as Initial Lenders , the Initial
Issuing Banks named herein, as Initial Issuing Banks and
Citibank, N.A, as Agent (filed as Exhibit 10.1 to
Form 8-K filed on January 26, 2005). |
|
10.35* |
|
|
|
|
Amended and Restated U.S. $100,000,000 Five Year Credit
Agreement dated April 26, 2004 and amended January 20,
2005 among The Williams Companies, Inc., as Borrower, the
Initial Lenders named herein, as Initial Lenders , the Initial
Issuing Banks named herein, as Initial Issuing Banks and
Citibank, N.A, as Agent (filed as Exhibit 10.2 to
Form 8-K filed on January 26, 2005). |
|
10.36* |
|
|
|
|
U.S. $400,000,000 Five Year Credit Agreement dated
January 20, 2005 among The Williams Companies, Inc., as
Borrower, the Initial Lenders named herein, as Initial Lenders,
the Initial Issuing Banks named herein, as Initial Issuing Banks
and Citibank, N.A, as Agent (filed as Exhibit 10.3 to
Form 8-K filed on January 26, 2005). |
|
10.37* |
|
|
|
|
U.S. $100,000,000 Five Year Credit Agreement dated
January 20, 2005 among The Williams Companies, Inc., as
Borrower, the Initial Lenders named herein, as Initial Lenders ,
the Initial Issuing Banks named herein, as Initial Issuing Banks
and Citibank, N.A, as Agent (filed as Exhibit 10.4 to
Form 8-K filed on January 26, 2005). |
|
10.38* |
|
|
|
|
New Omnibus Agreement among WEG Acquisitions, L.P., Williams
Energy Services, LLC, Williams Natural Gas Liquids, Inc. and The
Williams Companies, Inc. dated as of June 17, 2003 (filed
as Exhibit 10.9 to Form 10-Q filed August 12,
2003). |
|
10.39* |
|
|
|
|
Assumption Agreement dated June 17, 2003 by and between The
Williams Companies, Inc. and WEG Acquisitions, L.P. (filed as
Exhibit 10.10 to Form 10-Q filed August 12, 2003). |
|
10.40* |
|
|
|
|
Agreement for the Release of Certain Indemnification Obligations
dated as of May 26, 2004 by and among Magellan Midstream
Holdings, L.P., Magellan G.P. LLC and Magellan Midstream
Partners, L.P., on the one hand, and The Williams Companies,
Inc., Williams Energy Services, LLC, Williams Natural Gas
Liquids, Inc. and Williams GP LLC, on the other hand (filed as
Exhibit 10.6 to Form 10-Q filed August 5, 2004). |
180
|
|
|
|
|
|
|
Exhibit | |
|
|
|
|
No. | |
|
|
|
Description |
| |
|
|
|
|
|
10.41* |
|
|
|
|
Sale Agreement Relating to the Sale of the Interest of Williams
Energy (Canada), Inc. in the Cochrane, Empress II and
Empress V Straddle Plants dated as of July 8, 2004 between
Williams Energy (Canada), Inc. and 1024234 Alberta Ltd. (filed
as Exhibit 10.7 to Form 10-Q filed August 5,
2004). |
|
10.42* |
|
|
|
|
Master Professional Services Agreement dated as of June 1,
2004, by and between The Williams Companies, Inc. and
International Business Machines Corporation (filed as
Exhibit 10.2 to Form 10-Q filed August 5, 2004). |
|
10.43* |
|
|
|
|
Amendment No. 1 to the Master Professional Services
Agreement dated June 1, 2004, by and between The Williams
Companies, Inc. and International Business Machines Corporation
made as of June 1, 2004 (filed as Exhibit 10.3 to
Form 10-Q filed August 5, 2004). |
|
12 |
|
|
|
|
Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirements. |
|
14* |
|
|
|
|
Code of Ethics (filed as Exhibit 14 to Form 10-K for
the fiscal year ended December 31, 2003). |
|
20* |
|
|
|
|
Definitive Proxy Statement of Williams for 2005 (to be filed
with the Securities and Exchange Commission on or before
April 11, 2005). |
|
21 |
|
|
|
|
Subsidiaries of the registrant. |
|
23.1 |
|
|
|
|
Consent of Independent Registered Public Accounting Firm,
Ernst & Young LLP. |
|
23.2 |
|
|
|
|
Consent of Independent Petroleum Engineers and Geologists,
Netherland, Sewell & Associates, Inc. |
|
23.3 |
|
|
|
|
Consent of Independent Petroleum Engineers and Geologists,
Miller and Lents, LTD. |
|
24 |
|
|
|
|
Power of Attorney together with certified resolution. |
|
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. |
|
|
* |
Each such exhibit has heretofore been filed with the SEC as part
of the filing indicated and is incorporated herein by reference. |
(c) The financial statements of partially owned companies
are not presented herein since none of them individually, or in
the aggregate, constitute a significant subsidiary.
181
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) |
|
|
|
|
|
Brian K. Shore |
|
Attorney-in-fact |
Date: March 11, 2005
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the
dates indicated.
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|
|
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|
|
Signature |
|
Title |
|
Date |
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|
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/s/ Steven J. Malcolm
Steven
J. Malcolm |
|
President, Chief Executive Officer and Chairman of the Board
(Principal Executive Officer) |
|
March 11, 2005 |
|
/s/ Donald R. Chappel*
Donald
R. Chappel |
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Senior Vice President and Chief Financial Officer (Principal
Financial Officer) |
|
March 11, 2005 |
|
/s/ Gary R. Belitz*
Gary
R. Belitz |
|
Controller (Principal Accounting Officer) |
|
March 11, 2005 |
|
/s/ Hugh M. Chapman*
Hugh
M. Chapman |
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Director |
|
March 11, 2005 |
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/s/ William E. Green*
William
E. Green |
|
Director |
|
March 11, 2005 |
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/s/ Juanita H. Hinshaw*
Juanita
H. Hinshaw |
|
Director |
|
March 11, 2005 |
|
/s/ W.R. Howell*
W.R.
Howell |
|
Director |
|
March 11, 2005 |
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/s/ Charles M. Lillis*
Charles
M. Lillis |
|
Director |
|
March 11, 2005 |
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/s/ George A. Lorch*
George
A. Lorch |
|
Director |
|
March 11, 2005 |
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/s/ William G. Lowrie*
William
G. Lowrie |
|
Director |
|
March 11, 2005 |
|
/s/ Frank T. MacInnis*
Frank
T. MacInnis |
|
Director |
|
March 11, 2005 |
182
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Signature |
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Title |
|
Date |
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/s/ Janice D. Stoney*
Janice
D. Stoney |
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Director |
|
March 11, 2005 |
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/s/ Joseph H. Williams*
Joseph
H. Williams |
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Director |
|
March 11, 2005 |
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*By: |
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/s/ Brian K. Shore
Brian
K. Shore
Attorney-in-fact |
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March 11, 2005 |
183
INDEX TO EXHIBITS
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|
Exhibit | |
|
|
|
|
No. | |
|
|
|
Description |
| |
|
|
|
|
|
3.1 |
|
|
|
|
Restated Certificate of Incorporation, as supplemented. |
|
3.2* |
|
|
|
|
Restated By-laws (filed as Exhibit 3.1 to Form 8-K
filed September 21, 2004 ). |
|
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 as Exhibit 4.1 to Form S-3
filed September 8, 1997). |
|
4.2* |
|
|
|
|
Form of Floating Rate Senior Note (filed as Exhibit 4.3 to
Form S-3 filed September 8, 1997). |
|
4.3* |
|
|
|
|
Form of Fixed Rate Senior Note (filed as Exhibit 4.4 to
Form S-3 filed September 8, 1997). |
|
4.4* |
|
|
|
|
Fourth Supplemental Indenture between Williams and Bank One
Trust Company, N.A., as Trustee, dated as of January 17,
2001 (filed as Exhibit 4(j) to Form 10-K for the
fiscal year ended December 31, 2000). |
|
4.5* |
|
|
|
|
Fifth Supplemental Indenture between Williams and Bank One Trust
Company, N.A., as Trustee, dated as of January 17, 2001
(filed as Exhibit 4(k) to Form 10-K for the fiscal
year ended December 31, 2000). |
|
4.6* |
|
|
|
|
Sixth Supplemental Indenture dated January 14, 2002,
between Williams and Bank One Trust Company, National
Association, as Trustee (filed as Exhibit 4.1 to
Form 8-K filed January 23, 2002). |
|
4.7* |
|
|
|
|
Seventh Supplemental Indenture dated March 19, 2002,
between The Williams Companies, Inc. as Issuer and Bank One
Trust Company, National Association, as Trustee (filed as
Exhibit 4.1 to Form 10-Q filed May 9, 2002). |
|
4.8* |
|
|
|
|
Eighth Supplemental Indenture dated as of June 3, 2002,
between The Williams Companies, Inc., as Issuer and Bank One
Trust Company, N.A., as Trustee (filed as Exhibit 4.8 to
Form 10-K for the fiscal year ended December 31, 2003). |
|
4.9* |
|
|
|
|
Ninth Supplemental Indenture dated June 10, 2003 between
The Williams Companies, Inc. as Issuer and JPMorgan Chase Bank
as Trustee (filed as Exhibit 4.1 to Form 10-Q filed
August 12, 2003). |
|
4.10* |
|
|
|
|
Tenth Supplemental Indenture dated as of August 17, 2004,
with respect to the Indenture dated as of November 10, 1997
between The Williams Companies, Inc. and JPMorgan Chase Bank (as
successor trustee to Bank One Trust Company, National
Association (successor to the First National Bank of Chicago))
(filed as Exhibit 99.2 for Form 8-K filed
August 17, 2004). |
|
4.11* |
|
|
|
|
Form of Senior Debt Indenture between Williams Holdings of
Delaware, Inc. and Citibank, N.A., as Trustee (filed as
Exhibit 4.1 to Williams Holdings of Delaware, Inc.s
Form 10-Q filed October 18, 1995). |
|
4.12* |
|
|
|
|
First Supplemental Indenture dated as of July 31, 1999,
among Williams Holdings of Delaware, Inc., Williams and
Citibank, N.A., as Trustee (filed as Exhibit 4(o) to
Form 10-K for the fiscal year ended December 31, 1999). |
|
4.13* |
|
|
|
|
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 as
Exhibit 4.4.1 to MAPCO Inc.s Amendment No. 1 to
Form S-3 dated February 25, 1997). |
|
4.14* |
|
|
|
|
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). |
|
4.15* |
|
|
|
|
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). |
|
4.16* |
|
|
|
|
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). |
|
|
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|
|
Exhibit | |
|
|
|
|
No. | |
|
|
|
Description |
| |
|
|
|
|
|
4.17* |
|
|
|
|
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 as Exhibit 4(q) to
Form 10-K for the fiscal year ended December 31, 1999). |
|
4.18* |
|
|
|
|
Revised Form of Indenture between Barrett Resources Corporation,
as Issuer, and Bankers Trust Company, as Trustee, with respect
to Senior Notes including specimen of 7.55% Senior Notes
(filed as Exhibit 4.1 to Barrett Resources
Corporations Amendment No. 2 to Registration
Statement on Form S-3 filed February 10, 1997). |
|
4.19* |
|
|
|
|
First Supplemental Indenture dated 2001, between Barrett
Resources Corporation, as Issuer, and Bankers Trust Company, as
Trustee (filed as Exhibit 4.3 to Form 10-Q filed
November 13, 2001). |
|
4.20* |
|
|
|
|
Second Supplemental Indenture dated as of August 2, 2001,
among Barrett Resources Corporation, as Issuer, Resources
Acquisition Corp., The Williams Companies, Inc. and Bankers
Trust Company, as Trustee (filed as Exhibit 4.4 to
Form 10-Q filed November 13, 2001). |
|
4.21* |
|
|
|
|
Third Supplemental Indenture dated as of May 20, 2004 with
respect to the Indenture dated as of February 1, 1997
between Barrett Resources Corporation (predecessor-in-interest
to Williams Production RMT Company) and Deutsche Bank Trust
Company Americas (formerly known as Bankers Trust Company), as
trustee (filed as Exhibit 99.2 to Form 8-K filed
May 20, 2004). |
|
4.22* |
|
|
|
|
Form of Note (filed as Exhibit 4.2 and included in
Exhibit 4.1 to Form 8-K filed January 23, 2002). |
|
4.23* |
|
|
|
|
Purchase Contract Agreement dated January 14, 2002, between
Williams and JPMorgan Chase Bank, as Purchase Contract Agent
(filed as Exhibit 4.3 to Form 8-K filed
January 23, 2002). |
|
4.24* |
|
|
|
|
Form of Income PACS Certificate (filed as Exhibit 4.4 and
included in Exhibit 4.3 to Form 8-K filed
January 23, 2002). |
|
4.25* |
|
|
|
|
Pledge Agreement dated January 14, 2002, among Williams,
Bank, as Purchase Contract Agent (filed as Exhibit 4.5 to
Form 8-K filed January 23, 2002). |
|
4.26* |
|
|
|
|
Remarketing Agreement dated January 14, 2002, among
Williams, JPMorgan Chase Bank, as Purchase Contract Agent, and
Merrill Lynch & Co., Merrill Lynch, Pierce,
Fenner & Smith Incorporated, as Remarketing Agent
(filed as Exhibit 4.6 to Form 8-K filed
January 23, 2002). |
|
4.27* |
|
|
|
|
Supplemental Remarketing Agreement dated as of November 4,
2004 by and among Williams, Merill Lynch & Co., Merrill
Lynch, Pierce, Fenner & Smith Incorporation, as
Remarketing Agent, and JPMorgan Chase Bank, as Purchase Contract
Agent (filed as exhibit 99.1 to Form 8-K filed
November 9, 2004). |
|
4.28* |
|
|
|
|
Indenture dated March 4, 2003, between Northwest Pipeline
Corporation and JP Morgan Chase Bank, as Trustee (filed as
Exhibit 4.1 to Form 10-Q filed May 13, 2003. |
|
4.29* |
|
|
|
|
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 as Exhibit 4.2 to Form 10-Q
filed August 12, 2003). |
|
4.30* |
|
|
|
|
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 as Exhibit 4.1
to Form 8-K filed September 21, 2004. |
|
10.1* |
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|
The Williams Companies, Inc. Supplemental Retirement Plan
effective as of January 1, 1988 (filed as
Exhibit 10(iii)(c) to Form 10-K for the fiscal year
ended December 31, 1987). |
|
10.2* |
|
|
|
|
First Amendment to The Williams Companies, Inc. Supplemental
Retirement Plan effective as of April 1, 1988 (filed
as Exhibit 10.2 to Form 10-K for the fiscal year ended
December 31, 2003). |
|
10.3 |
|
|
|
|
Second Amendment to The Williams Companies, Inc. Supplemental
Retirement Plan effective as of January 1, 2002 and
January 1, 2003. |
|
10.4* |
|
|
|
|
The Williams Companies, Inc. 1988 Stock Option Plan for
Non-Employee Directors (filed as Exhibit A to the Proxy
Statement dated March 14, 1988). |
|
10.5* |
|
|
|
|
The Williams Companies, Inc. 1990 Stock Plan (filed as
Exhibit A to the Proxy Statement dated March 12,
1990). |
|
10.6* |
|
|
|
|
The Williams Companies, Inc. Stock Plan for Non-Officer
Employees (filed as Exhibit 10(iii)(g) to Form 10-K
for the fiscal year ended December 31, 1995). |
|
|
|
|
|
|
|
Exhibit | |
|
|
|
|
No. | |
|
|
|
Description |
| |
|
|
|
|
|
10.7* |
|
|
|
|
The Williams Companies, Inc. 1996 Stock Plan (filed as
Exhibit A to the Proxy Statement dated March 27,
1996). |
|
10.8* |
|
|
|
|
The Williams Companies, Inc. 1996 Stock Plan for Non-Employee
Directors (filed as Exhibit B to the Proxy Statement dated
March 27, 1996). |
|
10.9* |
|
|
|
|
Indemnification Agreement effective as of August 1, 1986,
among Williams, members of the Board of Directors and certain
officers of Williams (filed as Exhibit 10(iii)(e) to
Form 10-K for the year ended December 31, 1986). |
|
10.10* |
|
|
|
|
The Williams International Stock Plan (filed as
Exhibit 10(iii)(l) to Form 10-K for the fiscal year
ended December 31, 1998). |
|
10.11* |
|
|
|
|
Form of Stock Option Secured Promissory Note and Pledge
Agreement among Williams and certain employees, officers and
non-employee directors (filed as Exhibit 10(iii)(m) to
Form 10-K for the fiscal year ended December 31, 1998). |
|
10.12 |
|
|
|
|
Form of 2004 Deferred Stock Agreement among Williams and certain
employees and officers. |
|
10.13 |
|
|
|
|
Form of 2004 Performance-Based Deferred Stock Agreement among
Williams and executive officers. |
|
10.14* |
|
|
|
|
Form of Stock Option Agreement among Williams and certain
employees and officers (filed as Exhibit 99.1 to
Form 8-K filed March 2, 2005). |
|
10.15* |
|
|
|
|
Form of 2005 Deferred Stock Agreement among Williams and certain
employees and officers (filed as Exhibit 99.2 to
Form 8-K filed March 2, 2005). |
|
10.16* |
|
|
|
|
Form of 2005 Performance-Based Deferred Stock Agreement among
Williams and executive officers.(filed as Exhibit 99.3 to
Form 8-K filed March 2, 2005). |
|
10.17* |
|
|
|
|
The Williams Companies, Inc. 2001 Stock Plan (filed as
Exhibit 4.1 to Form S-8 filed August 1, 2001). |
|
10.18* |
|
|
|
|
The Williams Companies, Inc. 2002 Incentive Plan as amended and
restated effective as of January 23, 2004 (filed as
Exhibit 10.1 to Form 10-Q filed on August 5,
2004). |
|
10.19* |
|
|
|
|
Form of Change in Control Severance Agreement between the
Company and certain executive officers (filed as
Exhibit 10.12 to Form 10-Q filed November 14,
2002). |
|
10.20* |
|
|
|
|
Settlement Agreement, by and among the Governor of the State of
California and the several other parties named therein and The
Williams Companies, Inc. and Williams Energy
Marketing & Trading Company dated November 11,
2002 (filed as Exhibit 10.79 for Form 10-K for the
fiscal year ended December 31, 2002). |
|
10.21* |
|
|
|
|
U.S. $500,000,000 Term Loan Agreement among Williams
Production Holdings LLC, Williams Production RMT Company, as
Borrower, the Several Lenders from time to time parties thereto,
Lehman Brothers Inc. and Banc of America Securities LLC as Joint
Lead Arrangers, Citigroup USA, Inc. and JPMorgan Chase Bank, as
Co-Syndication Agents, Bank of America, N.A., as Documentation
Agent, and Lehman Commercial Paper Inc., as Administrative Agent
dated as of May 30, 2003 (filed as Exhibit 10.1 to
Form 10-Q filed August 12, 2003). |
|
10.22* |
|
|
|
|
The First Amendment to the Term Loan Agreement dated
February 25, 2004, between Williams Production Holdings,
LLC, Williams Production RMT Company, as Borrower, the several
financial institutions as lenders and Lehman Commercial Paper
Inc., as Administrative Agent dated as of May 30, 2003
(filed as Exhibit 10.3 to Form 10-Q filed May 6,
2004). |
|
10.23* |
|
|
|
|
Guarantee and Collateral Agreement made by Williams Production
Holdings LLC, Williams Production RMT Company and certain of its
Subsidiaries in favor of Lehman Commercial Paper Inc. as
Administrative Agent dated as of May 30, 2003 (filed as
Exhibit 10.2 to Form 10-Q filed August 12, 2003). |
|
10.24* |
|
|
|
|
U.S. $800,000,000 Credit Agreement dated as of June 6,
2003, among The Williams Companies, Inc., Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation, as
Borrowers, Citibank, N.A., as Administrative Agent and
Collateral Agent, Bank of America, N.A., as Syndication Agent,
JPMorgan Chase Bank, as documentation Agreement, Citibank, N.A.
and Bank of America, N.A. as Issuing Banks, the banks named
therein as Banks and Citigroup Global Markets Inc. and Banc of
America Securities LLC as Joint Lead Arrangers and Joint Book
Runners (filed as Exhibit 10.3 to Form 10-Q filed
August 12, 2003). |
|
|
|
|
|
|
|
Exhibit | |
|
|
|
|
No. | |
|
|
|
Description |
| |
|
|
|
|
|
10.25* |
|
|
|
|
Security Agreement dated as of June 6, 2003, among The
Williams Companies, Inc., as Grantor, Citibank, N.A., as
Collateral Agent and Citibank, N.A. as Securities Intermediary
(filed as Exhibit 10.4 to Form 10-Q filed
August 12, 2003). |
|
10.26* |
|
|
|
|
U.S. $1,000,000,000 Credit Agreement dated as of
May 3, 2004, among The Williams Companies, Inc., Northwest
Pipeline Corporation, Transcontinental Gas Pipeline Corporation,
as Borrowers, Citicorp USA, Inc., as Administrative Agent and
Collateral Agent, Citibank, N.A. and Bank of America, N.A., as
Issuing Banks, the banks named therein as Banks, Bank of
America, N.A., as Syndication Agent, JPMorgan Chase Bank, The
Bank of Nova Scotia, The Royal Bank of Scotland plc as
Co-Documentation Agents, Citigroup Global Markets Inc. and Banc
of America Securities LLC as Joint Lead Arrangers and Co-Book
Runners (filed as Exhibit 10.4 to Form 10-Q filed
May 6, 2004). |
|
10.27* |
|
|
|
|
Letter of Credit Commitment Increase Agreement dated
August 4, 2004, by and among The Williams Companies, Inc.,
Citicorp USA in its capacity as Agent under the Credit Agreement
dated as of May 3, 2004 among the Borrower, Northwest
Pipeline Corporation, Transcontinental Gas Pipe Line
Corporation, the Agent, the Collateral Agent, the Banks and
Issuing Banks party thereto and Citibank, N.A. and Bank of
America, N.A. (filed as Exhibit 10.1 to Form 10-Q
filed November 4, 2004). |
|
10.28* |
|
|
|
|
Revolving Credit Commitment Increase Agreement dated
August 4, 2004, by and among The Williams Companies, Inc.,
Citicorp USA in its capacity as Agent under the Credit Agreement
dated as of May 3, 2004 among the Borrower, Northwest
Pipeline Corporation, Transcontinental Gas Pipe Line
Corporation, the Agent, the Collateral Agent and the Banks and
Issuing Banks party thereto, the Issuing Banks and Citicorp USA,
Inc. (filed as Exhibit 10.2 to Form 10-Q filed
November 4, 2004). |
|
10.29 |
|
|
|
|
Amendment Agreement dated as of October 19, 2004 among The
Williams Companies, Inc., Northwest Pipeline Corporation,
Transcontinental Gas Pipeline Corporation, as Borrowers, the
banks, financial institutions and other institutional lenders
that are parties to the Credit Agreement dated as of May 3,
2004 among the Borrowers, the Banks, Citicorp USA, Inc., as
agent and Citibank, N.A. and Bank of America, N.A., as issuers
of letters of credit under the Credit Agreement, the Agent and
the Issuing Banks. |
|
10.30* |
|
|
|
|
Western Midstream Security Agreement dated as of May 3,
2004, among Williams Gas Processing Company, Williams Field
Services Company, Williams Gas Processing Wamsutter
Company as Grantors, in favor of Citicorp USA, Inc. as
Collateral Agents (filed as Exhibit 10.5 to Form 10-Q
filed May 6, 2004). |
|
10.31* |
|
|
|
|
Pledge Agreement dated as of May 3, 2004, by Williams Field
Services Group, Inc. in favor of Citicorp USA, Inc. as
Collateral Agent (filed as Exhibit 10.6 to Form 10-Q
filed May 6, 2004). |
|
10.32* |
|
|
|
|
Western Midstream Guaranty by Williams Gas Processing Company,
Williams Field Services Company, Williams Gas
Processing Wamsutter Company as Guarantors in favor
of Citicorp USA, Inc. as Collateral Agent (filed as
Exhibit 10.7 for Form 10-Q filed May 6, 2004). |
|
10.33* |
|
|
|
|
Pipeline Holdco Guaranty by Williams Gas Pipeline Company, LLC
as Guarantor in favor of Citicorp USA, Inc. as Collateral Agent
(filed as Exhibit 10.8 to Form 10-Q filed May 6,
2004). |
|
10.34* |
|
|
|
|
Amended and Restated U.S. $400,000,000 Five Year Credit
Agreement dated April 14, 2004 and amended January 20,
2005 among The Williams Companies, Inc., as Borrower, the
Initial Lenders named herein, as Initial Lenders , the Initial
Issuing Banks named herein, as Initial Issuing Banks and
Citibank, N.A, as Agent (filed as Exhibit 10.1 to
Form 8-K filed on January 26, 2005). |
|
10.35* |
|
|
|
|
Amended and Restated U.S. $100,000,000 Five Year Credit
Agreement dated April 26, 2004 and amended January 20,
2005 among The Williams Companies, Inc., as Borrower, the
Initial Lenders named herein, as Initial Lenders , the Initial
Issuing Banks named herein, as Initial Issuing Banks and
Citibank, N.A, as Agent (filed as Exhibit 10.2 to
Form 8-K filed on January 26, 2005). |
|
10.36* |
|
|
|
|
U.S. $400,000,000 Five Year Credit Agreement dated
January 20, 2005 among The Williams Companies, Inc., as
Borrower, the Initial Lenders named herein, as Initial Lenders,
the Initial Issuing Banks named herein, as Initial Issuing Banks
and Citibank, N.A, as Agent (filed as Exhibit 10.3 to
Form 8-K filed on January 26, 2005). |
|
|
|
|
|
|
|
Exhibit | |
|
|
|
|
No. | |
|
|
|
Description |
| |
|
|
|
|
|
10.37* |
|
|
|
|
U.S. $100,000,000 Five Year Credit Agreement dated
January 20, 2005 among The Williams Companies, Inc., as
Borrower, the Initial Lenders named herein, as Initial Lenders ,
the Initial Issuing Banks named herein, as Initial Issuing Banks
and Citibank, N.A, as Agent (filed as Exhibit 10.4 to
Form 8-K filed on January 26, 2005). |
|
10.38* |
|
|
|
|
New Omnibus Agreement among WEG Acquisitions, L.P., Williams
Energy Services, LLC, Williams Natural Gas Liquids, Inc. and The
Williams Companies, Inc. dated as of June 17, 2003 (filed
as Exhibit 10.9 to Form 10-Q filed August 12,
2003). |
|
10.39* |
|
|
|
|
Assumption Agreement dated June 17, 2003 by and between The
Williams Companies, Inc. and WEG Acquisitions, L.P. (filed as
Exhibit 10.10 to Form 10-Q filed August 12, 2003). |
|
10.40* |
|
|
|
|
Agreement for the Release of Certain Indemnification Obligations
dated as of May 26, 2004 by and among Magellan Midstream
Holdings, L.P., Magellan G.P. LLC and Magellan Midstream
Partners, L.P., on the one hand, and The Williams Companies,
Inc., Williams Energy Services, LLC, Williams Natural Gas
Liquids, Inc. and Williams GP LLC, on the other hand (filed as
Exhibit 10.6 to Form 10-Q filed August 5, 2004). |
|
10.41* |
|
|
|
|
Sale Agreement Relating to the Sale of the Interest of Williams
Energy (Canada), Inc. in the Cochrane, Empress II and
Empress V Straddle Plants dated as of July 8, 2004 between
Williams Energy (Canada), Inc. and 1024234 Alberta Ltd. (filed
as Exhibit 10.7 to Form 10-Q filed August 5,
2004). |
|
10.42* |
|
|
|
|
Master Professional Services Agreement dated as of June 1,
2004, by and between The Williams Companies, Inc. and
International Business Machines Corporation (filed as
Exhibit 10.2 to Form 10-Q filed August 5, 2004). |
|
10.43* |
|
|
|
|
Amendment No. 1 to the Master Professional Services
Agreement dated June 1, 2004, by and between The Williams
Companies, Inc. and International Business Machines Corporation
made as of June 1, 2004 (filed as Exhibit 10.3 to
Form 10-Q filed August 5, 2004). |
|
12 |
|
|
|
|
Computation of Ratio of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirements. |
|
14* |
|
|
|
|
Code of Ethics (filed as Exhibit 14 to Form 10-K for
the fiscal year ended December 31, 2003). |
|
20* |
|
|
|
|
Definitive Proxy Statement of Williams for 2005 (to be filed
with the Securities and Exchange Commission on or before
April 11, 2005). |
|
21 |
|
|
|
|
Subsidiaries of the registrant. |
|
23.1 |
|
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Consent of Independent Registered Public Accounting Firm,
Ernst & Young LLP. |
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23.2 |
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Consent of Independent Petroleum Engineers and Geologists,
Netherland, Sewell & Associates, Inc. |
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23.3 |
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Consent of Independent Petroleum Engineers and Geologists,
Miller and Lents, LTD. |
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24 |
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Power of Attorney together with certified resolution. |
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31.1 |
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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. |
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31.2 |
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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. |
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32 |
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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. |
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* |
Each such exhibit has heretofore been filed with the SEC as part
of the filing indicated and is incorporated herein by reference. |