WILLIAMS COMPANIES INC - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-4174

THE WILLIAMS COMPANIES, INC.
(Exact name of registrant as specified in its charter)

DELAWARE 73-0569878
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

ONE WILLIAMS CENTER, TULSA, OKLAHOMA 74172
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code:
918-573-2000

Securities registered pursuant to Section 12(b) of the Act:

Securities registered Pursuant to Section 12(g) of the Act: NONE

Indicate by check mark 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 [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

The aggregate market value of the registrant's voting and non-voting stock
held by non-affiliates as of the close of business on February 28, 2002, was
approximately $7,972,392,000.

The number of shares of the registrant's common stock held by
non-affiliates outstanding at February 28, 2002, was 516,012,427.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's Proxy Statement being prepared for the
solicitation of proxies in connection with the Annual Meeting of Stockholders of
Williams for 2002 are incorporated by reference in Part III.

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THE WILLIAMS COMPANIES, INC.

FORM 10-K

PART I

ITEM 1. BUSINESS

(a) GENERAL DEVELOPMENT OF BUSINESS

The Williams Companies, Inc. (Williams) was incorporated under the laws of
the State of Nevada in 1949 and was reincorporated under the laws of the State
of Delaware in 1987. The principal executive offices of Williams are located at
One Williams Center, Tulsa, Oklahoma 74172 (telephone (918) 573-2000).

On October 6, 1999, a former majority-owned subsidiary of Williams,
Williams Communications Group, Inc. (WCG), completed an initial public offering
by selling shares of its Class A common stock to the public. In separate private
placements, SBC Communications Inc., Intel Corporation and Telefonos de Mexico
S.A. de C.V. each purchased a portion of WCG's Class A common stock. On February
26, 2001, Williams and WCG entered into an agreement under which Williams
contributed an outstanding promissory note from WCG of approximately $975
million and certain other assets to WCG in exchange for 24,265,892 shares of
WCG's Class A common stock. Until the spinoff of WCG on April 23, 2001, Williams
owned 100 percent of WCG's outstanding Class B common stock, which gave Williams
approximately 98 percent of the voting power of WCG and approximately 86 percent
of the economic interest in WCG.

On March 30, 2001, Williams announced that its board of directors had
approved a tax-free distribution of 398,500,000 WCG Class A shares held by
Williams to its shareholders of record on April 9, 2001, in the form of a
dividend. Immediately prior to the distribution, 100 percent of the shares of
WCG's Class B common stock outstanding was converted into shares of Class A
common stock. On April 23, 2001, Williams completed the spinoff of WCG to its
shareholders, retaining approximately 4.9 percent of the outstanding Class A
common stock of WCG.

Also prior to the spinoff of WCG, Williams provided indirect credit support
for $1.4 billion of WCG's Note Trust Notes through a commitment to make
available proceeds of a Williams equity issuance in the event any one of the
following were to occur: (1) a WCG default; (2) downgrading of Williams' senior
unsecured debt by any of its credit rating agencies to below investment grade if
Williams' common stock closing price is below $30.22 for ten consecutive trading
days while such downgrade is in effect; or (3) to the extent proceeds from WCG's
refinancing or remarketing of certain structured notes prior to March 2004
produces proceeds of less than $1.4 billion.

On March 5, 2002, Williams received the requisite approvals on its consent
solicitation to amend the terms of the WCG Note Trust Notes. The amendment,
among other things, eliminates acceleration of the Notes due to a WCG bankruptcy
or a Williams credit rating downgrade. The amendment also affirms Williams'
obligations for all payments related to the WCG Note Trust Notes, which are due
March 2004, and allows Williams to fund such payments from any available
sources. With the exception of the March and September 2002 interest payments,
totaling $115 million, WCG remains indirectly obligated to reimburse Williams
for any payments Williams is required to make in connection with the WCG Note
Trust Notes.

On September 13, 2001, Williams purchased the WCG headquarters building and
other ancillary assets from WCG for $276 million. Williams then entered into
long-term lease arrangements under which WCG is the sole lessee of these assets.

On August 2, 2001, Williams completed its acquisition of Barrett Resources
Corporation of Denver, Colorado, following the approval of Barrett stockholders
at a special stockholder meeting held August 2, 2001. In the acquisition a
wholly owned subsidiary of Williams acquired all of the outstanding shares of
Barrett common stock (including the associated preferred stock purchase rights)
through a two-step transaction comprised of a cash tender offer for 16,730,502
of the Barrett shares, or approximately 50 percent of the Barrett shares then
outstanding, followed by a second step merger in which Barrett was merged with
and into a wholly owned subsidiary of Williams. In the merger, each outstanding
share, other than shares held by Williams or its subsidiaries, was converted
into the right to receive 1.767 shares of Williams' common stock.
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At the time of the merger, Barrett had total proved reserves of 1.9 trillion
cubic feet equivalent and equity production of 350 million cubic feet equivalent
per day. The Barrett merger established several new core areas in the Rockies
with development drilling programs in the Piceance, Raton and Powder River
basins. Other projects exist in the Uinta basin, Wind River basin, Mid-continent
area and the Gulf of Mexico.

On August 1, 2001, Kern River Gas Transmission Company filed an application
with the Federal Energy Regulatory Commission (FERC) to construct and operate an
expansion of its pipeline system that will provide an additional 906,626
dekatherms per day of firm transportation capacity to serve primarily power
generation demand in southern Nevada and California. The 2003 Expansion Project
will include installing 717 miles of pipeline, three new compressor stations,
upgrading, replacing or modifying six existing compressor stations, adding a net
total of 163,700 horsepower and upgrading five meter stations. Kern River
expects the FERC to issue a certificate by May 1, 2002, and plans to start
construction by June 2002. The estimated cost of the expansion is $1.26 billion
with a targeted in-service date of May 1, 2003. Kern River's customers will pay
for the cost of service of this expansion on an incremental basis.

Williams announced on December 19, 2001, its plans to take several steps to
strengthen its balance sheet in order to maintain its investment grade credit
rating. The steps of this plan include a $1 billion reduction in 2002 estimated
capital spending and the sale of certain non-core assets, the expected proceeds
of which total $250 million to $750 million. An additional step of the plan
included the sale, which was completed on January 14, 2002, of $1.1 billion of
publicly traded units, known as the Income PACS or FELINE PACS, that include a
senior debt security and an equity purchase contract. On February 4, 2002,
Williams announced that it plans to sell its Midwest petroleum products pipeline
and on-system terminals, which sale is in addition to, and more than doubles the
cash proceeds from, the balance sheet strengthening plan announced on December
19, 2001. A potential buyer of this pipeline system may be Williams Energy
Partners L.P., a subsidiary of Williams.

(b) FINANCIAL INFORMATION ABOUT SEGMENTS

See Part II, Item 8 -- Financial Statements and Supplementary Data.

(c) NARRATIVE DESCRIPTION OF BUSINESS

Williams, through Williams Energy Marketing & Trading Company, Williams Gas
Pipeline Company, LLC and Williams Energy Services, LLC, and their respective
subsidiaries, engages in the following types of energy-related activities:

- price risk management services and the purchase and sale, and arranging
of transportation or transmission, of energy and energy-related
commodities including natural gas and gas liquids, crude oil and refined
products and electricity;

- transportation and storage of natural gas and related activities through
the operation and ownership of five wholly owned interstate natural gas
pipelines, several pipeline joint ventures and a wholly owned liquefied
natural gas terminal;

- exploration, production and marketing of oil and gas through ownership of
3.2 trillion cubic feet equivalent of proved natural gas reserves
primarily located in the Rocky Mountain, Mid-Continent and Gulf Coast
regions of the United States;

- direct investments in international energy projects located primarily in
South America and Lithuania, investments in energy and infrastructure
development funds in Asia and South America and soda ash mining
operations in Colorado;

- natural gas gathering, treating and processing activities through
ownership and operation of approximately 11,200 miles of gathering lines,
10 natural gas treating plants and 18 natural gas processing plants
(three of which are partially owned) located in the United States and
Canada;

- natural gas liquids transportation through ownership and operation of
approximately 14,300 miles of natural gas liquids pipeline (4,770 miles
of which are partially owned);

- transportation of petroleum products and related terminal services
through ownership or operation of approximately 6,747 miles of petroleum
products pipeline and 39 petroleum products terminals;

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- light hydrocarbon/olefin transportation through 300 miles of pipeline in
Southern Louisiana;

- ethylene production through a 5/12 interest in a 1.3 billion pounds per
year facility in Geismar, Louisiana;

- production and marketing of ethanol and bio-products through operation
and ownership of two ethanol plants (one of which is partially owned) and
ownership of minority interests or investments in four other plants;

- refining of petroleum products through operation and ownership of two
refineries;

- retail marketing through 61 travel centers;

- petroleum products terminal services through the ownership and operation
of five marine terminals and 25 inland terminals that form a distribution
network for gasoline and other refined petroleum products throughout the
southeastern United States; and

- ammonia transportation and terminal services through ownership and
operation of an ammonia pipeline and terminals system that extends for
approximately 1,100 miles from Texas and Oklahoma to Minnesota.

Substantially all operations of Williams are conducted through
subsidiaries. Williams performs certain management, legal, financial, tax,
consultative, administrative and other services for its subsidiaries and at
December 31, 2001, employed approximately 1,500 employees at the corporate level
to provide these services. Williams' principal sources of cash are from external
financings, dividends and advances from its subsidiaries, investments, payments
by subsidiaries for services rendered and interest payments from subsidiaries on
cash advances. The amount of dividends available to Williams from subsidiaries
largely depends upon each subsidiary's earnings and operating capital
requirements. The terms of certain subsidiaries' borrowing arrangements limit
the transfer of funds to Williams.

To achieve organizational and operating efficiencies, Williams' energy
marketing and trading activities are primarily grouped together under its wholly
owned subsidiary, Williams Energy Marketing & Trading Company, its interstate
natural gas pipelines and pipeline joint venture investments are grouped
together under its wholly owned subsidiary, Williams Gas Pipeline Company, LLC
and the other energy operations are primarily grouped together under its wholly
owned subsidiary, Williams Energy Services, LLC. Item 1 of this report is
formatted to reflect this structure.

WILLIAMS ENERGY MARKETING & TRADING

Williams Energy Marketing & Trading Company, and its subsidiaries, is a
national energy services provider that buys, sells and transports a full suite
of energy and energy-related commodities, including power, natural gas, refined
products, natural gas liquids, crude oil, propane, liquefied natural gas,
liquefied petroleum gas and emission credits, primarily on a wholesale level,
serving over 652 customers. In addition, Energy Marketing & Trading provides and
procures risk management and other energy-related services through a variety of
financial instruments and structured transactions including exchange-traded
futures, as well as over-the-counter forwards, options, swap, tolling, load
serving and full requirements agreements and other derivatives related to
various energy and energy-related commodities. See Note 18 of Notes to
Consolidated financial statements for information on financial instruments and
energy trading activities. At December 31, 2001, Energy Marketing & Trading
employed approximately 1,000 employees.

During 2001, Energy Marketing & Trading marketed over 293,808 physical
gigawatt hours of power. As part of its approximately 15,000 megawatt power
supply portfolio, Energy Marketing & Trading has a mix of owned generation,
tolling agreements and supply resources through full requirements transactions
in support of its load obligations. Energy Marketing & Trading has entered into
a number of long-term agreements at December 31, 2001, to market capacity of
electric generation facilities (either existing or to be constructed at various
locations throughout the United States) totaling approximately 7,600 megawatts
(Alabama -- 846 megawatts; California -- 3,954 megawatts; Louisiana -- 750
megawatts; New Jersey -- 832 megawatts; Pennsylvania -- 700 megawatts;
Michigan -- 550 megawatts). Energy Marketing & Trading also has an additional
approximately 2,700 megawatts in planned tolling projects to be sited at various
locations within the
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United States. A portion of this supply, for which has been contracted, is in
the construction and development stages. On certain contracts, the
counterparties have not started construction and are currently negotiating
development and environmental permits. Under these tolling arrangements, Energy
Marketing & Trading supplies fuel for conversion to electricity and markets
capacity, energy and ancillary services related to the generating facilities
owned and operated by various counterparties. Approximately 5,400 megawatts of
electric generation capacity available through these tolling arrangements
located in California, Louisiana and Pennsylvania are operational, with the
balance expected to come online by year-end 2002. Energy Marketing & Trading
also has entered into several agreements to provide full requirements services
for a number of customers whose supply resources are being managed with
approximately 2,600 megawatts of load in the United States, including
transactions in Indiana, Pennsylvania and Georgia. Additionally, Energy
Marketing & Trading has marketing rights for the energy and capacity from three
natural gas-fired electric generating plants owned by affiliated companies and
located near Bloomfield, New Mexico (60 megawatts); in Hazleton, Pennsylvania
(63 megawatts to be expanded to 162 in 2002); and near Worthington, Indiana (170
megawatts). Energy Marketing & Trading's primary power customers include
utilities, municipalities, cooperatives, governmental agencies and other power
marketers.

Energy Marketing & Trading markets natural gas throughout North America
with total physical volumes averaging 3.4 billion cubic feet per day in 2001.
Beginning in 2000, Energy Marketing & Trading's natural gas marketing operations
focused on activities that facilitate and/or complement the group's power
portfolio. Energy Marketing & Trading's natural gas customers include local
distribution companies, utilities, producers, industrials and other gas
marketers.

In 2001, Energy Marketing & Trading provided supply, distribution and
related risk management services to petroleum producers, refiners and end-users
in the United States and various international regions. During 2001, Energy
Marketing & Trading's total physical crude oil and petroleum products marketed
exceeded 240,600 barrels per day. During 2001, Energy Marketing & Trading also
marketed natural gas liquids with total physical volumes averaging 287,200
barrels per day.

Operating Statistics

The following table summarizes marketing and trading volumes for the
periods indicated (natural gas volumes for 1999 include sales by the retail gas
and electric business, which has now been divested):

REGULATORY MATTERS

Energy Marketing & Trading's business is subject to a variety of laws and
regulations at the local, state and federal levels. At the federal level,
important regulatory agencies include the Federal Energy Regulatory Commission
(regarding energy commodity transportation and wholesale trading) and the
Commodity Futures Trading Commission (regarding various over-the-counter
derivative transactions and exemptions and exclusions from the Commodity
Exchange Act). Electricity markets, particularly in California, continue to be
subject to numerous and wide-ranging regulatory proceedings and investigations,
regarding among other things, market structure, behavior of market participants
and market prices. Energy Marketing & Trading may be liable for partial refunds
as a part of these regulatory actions. Energy Marketing & Trading is also the
subject of related state and federal investigations and Civil actions. Each of
these matters is discussed in more detail in Note 19 of the Notes to
Consolidated Financial Statements.

Management believes that Energy Marketing & Trading's activities are
conducted in substantial compliance with the marketing affiliate rules of FERC
Order 497. Order 497 imposes certain nondiscrimina-

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tion, disclosure and separation requirements upon interstate natural gas
pipelines with respect to their natural gas trading affiliates. Energy Marketing
& Trading has taken steps to ensure it does not share employees or officers with
affiliated interstate natural gas pipelines and does not receive information
from affiliated interstate natural gas pipelines that is not also available to
unaffiliated natural gas trading companies.

COMPETITION

Energy Marketing & Trading's operations directly compete with large
independent energy marketers, marketing affiliates of regulated pipelines and
utilities and natural gas producers. The financial trading business competes
with other energy-based companies offering similar services as well as certain
brokerage houses. This level of competition contributes to a business
environment of constant pricing and margin pressure.

OWNERSHIP OF PROPERTY

The primary assets of Energy Marketing & Trading are its term contracts,
employees, related systems and technological support. In addition, through
subsidiaries, Energy Marketing & Trading owns an approximately 170 megawatt
gas-fired generating facility located near Worthington, Indiana.

ENVIRONMENTAL

Electricity generation facilities that are subject to tolling or other
agreements are subject to various environmental laws and regulations, including
laws and regulations regarding emissions. Facility availability may be affected
by these laws and regulations.

WILLIAMS GAS PIPELINE

Williams' interstate natural gas pipeline group, comprised of Williams Gas
Pipeline Company, LLC and its subsidiaries (WGP), owns and operates a combined
total of approximately 27,500 miles of pipelines with a total annual throughput
of approximately 3,800 trillion British Thermal Units of natural gas and
peak-day delivery capacity of approximately 17 billion cubic feet of gas. WGP
consists of Transcontinental Gas Pipe Line Corporation (Transco), Northwest
Pipeline Corporation (Northwest Pipeline), Kern River Gas Transmission Company
(Kern River), Texas Gas Transmission Corporation (Texas Gas) and Williams Gas
Pipelines Central, Inc. (Central). WGP also holds interests in joint venture
interstate and intrastate natural gas pipeline systems.

WGP has combined certain administrative functions, such as information
services, technical services and finance, of its operating companies in an
effort to lower costs and increase efficiency. Although a single management team
manages both Northwest Pipeline and Kern River and a single management team
manages both Texas Gas and Central, each of these operating companies operates
as a separate legal entity. At December 31, 2001, WGP employed approximately
3,400 employees.

WGP's transmission and storage activities are subject to regulation by the
FERC under the Natural Gas Act of 1938 and under the Natural Gas Policy Act of
1978, and, as such, their 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 considered jurisdictional for which
certificates are required under the Natural Gas Act of 1938. 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, which regulates safety
requirements in the design, construction, operation and maintenance of
interstate natural gas pipelines.

As a result of Williams' merger with MAPCO Inc. in 1998, Williams acquired
an approximate 4.8 percent investment interest in Alliance Pipeline. On December
31, 1999, Williams acquired an additional 9.8 percent interest in Alliance
Pipeline. Alliance Pipeline consists of two segments, a Canadian segment and a
United States segment. Alliance Pipeline operates an approximate 1,800-mile
natural gas pipeline system
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extending from northeast British Columbia to the Chicago, Illinois area market
center, where it interconnects with the North American pipeline grid. On
September 17, 1998, the FERC granted a certificate of public convenience and
necessity for the United States portion of the Alliance Pipeline system, and on
December 3, 1998, the National Energy Board (NEB) of Canada granted a
certificate of public convenience and necessity for the Canadian portion.
Construction began in the spring of 1999 and the pipeline was placed in service
on December 1, 2000. Total cost of the Alliance pipeline system was in excess of
$3 billion. At December 31, 2001, Williams' investment in Alliance Pipeline was
approximately $185 million.

In February 2001, subsidiaries of Duke Energy and Williams completed their
joint acquisition of The Coastal Corporation's 100 percent ownership interest in
Gulfstream Natural Gas System, L.L.C., and announced that they are proceeding
with the development of the Gulfstream project in lieu of their jointly owned
Buccaneer Gas Pipeline Company, L.L.C. gas pipeline project. The Gulfstream
project will consist of a new natural gas pipeline system extending from the
Mobile Bay area in Alabama to markets in Florida. On February 22, 2001, the FERC
issued an order authorizing the construction and operation of the Gulfstream
project, and in June 2001 construction commenced on the project. On December 28,
2001, Gulfstream filed an application with the FERC to allow Gulfstream to phase
the construction of the approved facilities such that a portion of the project
will be placed into service on June 1, 2002 and the remainder on or about June
1, 2003. The estimated capital cost of the project is approximately $1.6
billion, of which Williams' portion is approximately $800 million.

In June 2000, two wholly owned subsidiaries of WGP purchased 100 percent of
the partnership interests in Cove Point LNG Limited Partnership (Cove Point).
The Cove Point liquefied natural gas (LNG) facility is located in Calvert
County, Maryland, and is currently utilized to provide firm peaking services and
firm and interruptible transportation services. On January 30, 2001, Cove Point
filed an application with the FERC to construct certain new facilities and to
reactivate and operate existing facilities and to provide LNG tanker discharging
services on a firm and interruptible basis to shippers importing LNG. On October
12, 2001, the FERC issued an order granting Cove Point the authorization to
reactivate its existing LNG terminal, to expand the facility, and to construct a
fifth storage tank as proposed. Cove Point accepted the certificate on October
18, 2001. On December 19, 2001, the FERC issued an order affirming its October
12 decision. Cove Point proposes to reactivate the LNG import and terminal
facilities by the fall of 2002 and to construct and place in service the new LNG
storage tank by early 2004. The total estimated cost of the project is
approximately $142 million. Cove Point and three shippers have executed 20-year
agreements for 100 percent of the 750,000 dekatherms per day of firm LNG
discharging services that will be created by the proposed reactivation project.

On April 24, 2001, Georgia Strait Crossing Pipeline LP, a joint venture of
WGP and BC Hydro, filed applications with the FERC and the NEB to construct and
operate a new pipeline that will provide 95,700 dekatherms per day of firm
transportation capacity from Sumas, Washington to Vancouver Island, British
Columbia. The Georgia Strait project will include installing 85 miles of
pipeline, a 10,302 horse power compression station and two meter stations.
Georgia Strait Crossing Pipeline anticipates the FERC to issue a certificate
approving the project by July 2002 and the NEB to issue a certificate approving
the project by February 2003. Construction is expected to begin in the fall of
2003. The estimated cost of the total Georgia Strait project is approximately
$166 million, with WGP's share being 50 percent of such amount. The targeted
in-service date is November 2004.

On June 29, 2001, Western Frontier Pipeline Company, LLC, a wholly owned
subsidiary of WGP, completed a binding open season for parties interested in
subscribing for firm natural gas transportation service on its proposed
expansion project. On October 24, 2001, Western Frontier filed an application
with the FERC to construct and operate the Western Frontier Pipeline, which will
consist of a 400-mile, 30-inch diameter pipeline and 30,000 horsepower of
compression designed to transport up to 540,000 dekatherms of natural gas per
day from the Cheyenne Hub in northeastern Colorado to Williams' Central pipeline
in southwest Kansas and the Oklahoma panhandle. The open season resulted in
precedent agreements for 365,000 dekatherms per day of firm transportation
service. The project's target in-service date has been delayed one year to
November 1, 2004, and work is being done with prospective shippers to further
define the market for and scope of this project. The estimated cost of the
project is approximately $365 million.
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Segment revenues and segment profit for WGP are reported in Note 22 of
Notes to Consolidated Financial Statements herein.

A business description of the principal companies in the interstate natural
gas pipeline group follows.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

Transco is an interstate natural gas transportation company that owns and
operates a 10,400-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., an affiliated company.

Pipeline System and Customers

At December 31, 2001, Transco's system had a mainline delivery capacity of
approximately 4.0 billion cubic feet of natural gas per day from its production
areas to its primary markets. Using its Leidy Line and market-area storage
capacity, Transco can deliver an additional 3.0 billion cubic feet of natural
gas per day for a system-wide delivery capacity total of approximately 7.0
billion cubic feet of natural gas per day. Excluding the production area
facilities operated by Williams Field Services Group, Inc., an affiliate,
Transco's system is composed of approximately 7,200 miles of mainline and branch
transmission pipelines, 44 transmission compressor stations and six storage
locations. Transmission compression facilities at a sea level-rated capacity
total approximately 1.4 million horsepower.

Transco's major natural gas transportation customers are public utilities
and municipalities that provide service to residential, commercial, industrial
and electric generation end users. Shippers on Transco's system include public
utilities, municipalities, intrastate pipelines, direct industrial users,
electrical generators, gas marketers and producers. One customer accounted for
approximately 11.5 percent of Transco's transportation and storage revenues in
2001. No other customer accounted for more than ten percent of Transco's total
revenues in 2001. Transco's firm transportation agreements are generally
long-term agreements with various expiration dates and account for the major
portion of Transco's business. Additionally, Transco offers interruptible
transportation and storage services under short-term agreements.

Transco has natural gas storage capacity in five underground storage fields
located on or near its pipeline system and/or market areas and operates three of
these storage fields. Transco also has storage capacity in a liquefied natural
gas (LNG) storage facility and operates the facility. The total top gas storage
capacity available to Transco and its customers in such storage fields and LNG
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, a LNG storage
facility with 4 billion cubic feet of storage capacity. Storage capacity permits
Transco's customers to inject gas into storage during the summer and off-peak
periods for delivery during peak winter demand periods.

Expansion Projects

On May 13, 1998, Transco filed an application with the FERC for approval to
construct and operate mainline and Leidy Line facilities (MarketLink) to create
an additional 676 million cubic feet per day of firm transportation capacity to
serve increased demand in the mid-Atlantic and south Atlantic regions of the
United States by a targeted in-service date of November 1, 2000, at an estimated
cost of $529 million. On December 17, 1999, the FERC issued an interim order
giving Transco conditional approval for MarketLink. Transco filed for rehearing
of the interim order and, on April 26, 2000, the FERC issued an order on
rehearing that authorized Transco to proceed with the MarketLink project subject
to certain conditions. On May 23, 2000, Transco filed a letter with the FERC
accepting the MarketLink certificate. On September 20, 2000, Transco filed an
application to amend the certificate of public convenience and necessity issued
in this proceeding to enable Transco to (a) phase the construction of the
MarketLink project to satisfy phased in-
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service dates requested by the project shippers, and (b) redesign the recourse
rate based on the phased construction of the project. On December 13, 2000, the
FERC issued an order permitting Transco to construct the MarketLink project in
phases as proposed. Phase 1 of the project, which provides approximately 160
million cubic feet per day of additional firm transportation service, was placed
into service in December 2001. Phase 2 of the project will consist of 126
million cubic feet per day of additional firm service with an expected
in-service date of November 1, 2002. The FERC's December 13, 2000, order
required Transco to file executed contracts fully subscribing the remaining
capacity of the project (approximately 390 million cubic feet per day) by April
13, 2001. Transco accepted the amended certificate on December 21, 2000. Certain
parties filed with the FERC requests for rehearing of the December 13, 2000
order, and on February 12, 2001, the FERC denied the requests. On April 3, 2001,
Transco filed a motion requesting that the FERC clarify that Transco could
construct Phase 3 of the MarketLink project that consisted of less than all of
the remaining certificated MarketLink facilities after the construction of
Phases 1 and 2, and that Transco could file by May 1 a report identifying the
certificated facilities to be constructed in Phase 3 and a revised project
recourse rate. On April 13, 2001, Transco filed firm service agreements with 5
shippers for 205 million cubic feet per day of capacity as required by the
December 13, 2000 order approving the phasing of the project. On April 26, 2001,
the FERC issued an order denying Transco's pending motion for clarification and
stating that Phase 3 of the MarketLink project must consist of all the remaining
certificated facilities. The order stated that as of April 13, 2001 the
certificate authority to construct additional MarketLink capacity in excess of
the 286 million cubic feet per day to be constructed as Phases 1 and 2 expired,
but that Transco could file a new application to serve the contracts filed on
April 13, 2001. On June 19, 2001, Transco submitted an application for the Leidy
East project discussed below, which incorporates a portion of the Phase 3
markets and facilities.

Transco filed an application with the FERC on June 19, 2001, to construct
and operate the Leidy East project, which will provide an additional 126 million
cubic feet per day of firm natural gas transportation service from Leidy,
Pennsylvania to the northeastern United States. Project facilities include
approximately 31 miles of pipeline looping and 3,400 horsepower of uprated
compression. On October 24, 2001, the FERC issued an order approving the
project. Construction is scheduled to begin in March 2002. The proposed in-
service date for the project is November 1, 2002. The capital cost of the
project is approximately $98 million.

In March 1997, as amended in December 1997, Independence Pipeline Company
filed an application with the FERC for approval to construct and operate a new
pipeline consisting of approximately 400 miles of 36-inch pipe from ANR Pipeline
Company's (ANR) existing compressor station at Defiance, Ohio to Transco's
facilities at Leidy, Pennsylvania. The Independence Pipeline project is proposed
to provide approximately 916 million cubic feet per day of firm transportation
capacity by an anticipated in-service date of November 2002. Independence is
owned equally by wholly-owned subsidiaries of Transco, ANR and National Fuel Gas
Company. The estimated cost of the project is $678 million, and Transco's equity
contributions are estimated to be approximately $68 million based on its
expected one-third ownership interest in the project. On December 17, 1999, the
FERC gave conditional approval for the Independence Pipeline project, subject to
Independence filing long-term, executed contracts with nonaffiliated shippers
for at least 35 percent of the capacity of the project. Independence Pipeline
filed for rehearing of the interim order. On April 26, 2000, the FERC issued an
order denying rehearing and requiring that Independence Pipeline submit by June
26, 2000, agreements with nonaffiliated shippers for at least 35 percent of the
capacity of the project. Independence Pipeline met this requirement, and on July
12, 2000, the FERC issued an order granting the necessary certificate
authorizations on August 11, 2000 for the Independence Pipeline project. On
September 28, 2000, the FERC issued an order denying all requests for rehearing
and requests for reconsideration of the Independence certificate order filed by
various parties. On November 1, 2001, Independence filed a letter with the FERC
requesting an extension of the in service date for the project to November 2004
and an extension of time until November 2003 to submit the final environmental
Implementation Plan required by the FERC's order approving the project.

On April 3, 2000, Transco filed an application with the FERC for its
Sundance Expansion project, which will create approximately 228 million cubic
feet per day of additional firm transportation capacity from Transco's Station
65 in Louisiana to delivery points in Georgia, South Carolina and North
Carolina. On March 29, 2001, the FERC issued an order authorizing Transco to
construct and operate the project and

8

Transco accepted the order on April 6, 2001. Approximately 38 miles of new
pipeline loop along the existing mainline system is being installed along with
approximately 33,000 horsepower of new compression and modifications to existing
compressor stations in Georgia, South Carolina and North Carolina. The project
has a target in-service date of May 2002 and an estimated cost of approximately
$134 million.

On September 25, 2001, Transco filed with the FERC an amendment to its
certificate application for its Momentum Expansion project to redesign and
downsize the project to reflect the termination of two shippers from the project
and certain additional capacity subscribed by two other shippers. As amended,
the project is proposed to create approximately 347 million cubic feet per day
of additional firm transportation capacity on Transco's pipeline system from
Station 65 in Louisiana to Station 165 in Virginia. The revised project
facilities include approximately 64 miles of pipeline looping and 45,000
horsepower of compression. The revised capital cost of the project is estimated
to be approximately $197 million. On February 14, 2002, the FERC issued an order
authorizing Transco to construct and operate the project. The project has a
targeted in-service date of May 1, 2003.

Transco held an open season in February 2001 for an expansion of the
Trenton-Woodbury line, which runs from Transco's mainline at Station 200 in
eastern Pennsylvania, around the metropolitan Philadelphia area and southern New
Jersey area, to Transco's mainline near Station 205. As a result of the open
season, precedent agreements are being negotiated for a total of 49 million
cubic feet per day of incremental firm transportation capacity. Transco plans to
file for FERC approval of the project in the first quarter of 2002. The target
in-service date for the project is November 1, 2003. The project will require
approximately 6 miles of looping at a capital cost of approximately $20 million.

Transco completed an open season on July 18, 2001, for the Cornerstone
Expansion project, an expansion of Transco's mainline system from Station 65 in
Louisiana to Station 165 in Virginia. The project has a target in-service date
May 1, 2004. Transco plans to begin the process for seeking FERC approval in the
second quarter of 2002. The capital cost of the project will depend on the level
of firm market commitment received.

Transco completed an open season on September 7, 2001, for the South
Virginia Line Expansion project, a proposed expansion on Transco's pipeline
system from Station 165 in Virginia to Hertford County, North Carolina. The
project has a target in-service date of May 1, 2005. The capital cost of the
project will depend on the level of firm market commitment received.

On July 21, 2000, Cross Bay Pipeline Company, L.L.C. (Cross Bay), a limited
liability company formed between subsidiaries of Transco, Duke Energy and
KeySpan Energy, filed an application with the FERC for approval of a gas
pipeline project which would increase natural gas deliveries into the New York
City metropolitan area by replacing and uprating pipeline facilities and
installing compression to expand the capacity of Transco's existing Lower New
York Bay Extension by approximately 121 million cubic feet per day. On November
8, 2001, the FERC issued an order authorizing the Cross Bay project, subject to
certain conditions. On December 5, 2001, the Cross Bay owners elected not to
accept the certificate issued by the FERC and decided not to proceed with the
Cross Bay project, which resulted in the dissolution of Cross Bay. A wholly
owned subsidiary of Transco had a 37.5 percent ownership interest in Cross Bay.
Transco's investment in this project was not significant.

On December 1, 2001, Transco transferred certain of its offshore Texas
facilities, which assets are not regulated by the FERC, to subsidiaries of
Williams Field Services Group, Inc. pursuant to orders granted by the FERC in
Docket Nos. CP01-32 and CP01-34. The facilities had a net book value of
approximately $3 million.

9

Operating Statistics

The following table summarizes transportation data for the periods
indicated (in trillion British Thermal Units):

Transco's 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 in 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 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, 2001, Northwest Pipeline's system, having a mainline
delivery capacity of approximately 2.9 billion cubic feet of natural gas per
day, was composed of approximately 4,100 miles of mainline and branch
transmission pipelines and 43 compressor stations having sea level-rated
capacity of approximately 343,000 horsepower.

In 2001, Northwest Pipeline transported natural gas for a total of 148
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 2001
accounted for approximately 15.4 percent and 13.7 percent, respectively, of its
total operating revenues. No other customer accounted for more than ten percent
of total operating revenues in 2001. Northwest Pipeline's firm transportation
agreements are generally long-term agreements with various expiration dates and
account for the major portion of Northwest Pipeline's business. Additionally,
Northwest Pipeline offers interruptible and short-term firm transportation
service.

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
liquefied natural gas storage facility in Washington that provides a
needle-peaking service for its system. These storage facilities have an
aggregate delivery capacity of approximately 1.3 billion cubic feet of gas per
day.

10

Expansion Projects

On August 29, 2001, Northwest Pipeline filed an application with the FERC
to construct and operate an expansion of its pipeline system that will provide
an additional 175,000 dekatherms per day of capacity to its transmission system
in Wyoming and Idaho in order to reduce reliance on displacement capacity. The
Rockies Expansion Project will include installing 91 miles of pipeline loop,
upgrades or modifications to five compressor stations for a total increase of
24,924 horsepower. Northwest reached a settlement agreement with the majority of
its firm shippers to support roll-in of the expansion costs into its existing
rates. Northwest expects the FERC to issue a certificate by September 2002.
Northwest plans to start construction by April 2003. The estimated cost of the
expansion project is approximately $154 million and the targeted completion date
is October 31, 2003.

On October 3, 2001, Northwest Pipeline filed an application with the FERC
to construct and operate an expansion of its pipeline system that will provide
276 million cubic feet per day of firm transportation capacity to serve new
power generation demand in western Washington. The Evergreen Expansion Project
will include installing 28 miles of pipeline loop, upgrading, replacing or
modifying five compressor stations and adding a net total of 67,000 horsepower
of compression. Northwest expects the FERC to issue a certificate by July 2002
and plans to start construction by August 2002. The estimated cost of the
expansion project is approximately $197 million with a targeted in-service date
of June 2003. The customers will pay for the cost of service of this expansion
on an incremental basis.

On October 3, 2001, Northwest Pipeline filed an application with the FERC
to construct and operate an expansion of its pipeline system that will provide
an additional 57,000 dekatherms per day of capacity to its transmission system
from Stanfield, Oregon to Washougal, Washington. The Columbia Gorge Project will
include upgrading, replacing or modifying five existing compressor stations,
adding a net total of 24,430 horsepower of compression. The Columbia Gorge
Project was filed as part of the Evergreen Expansion Project to reduce reliance
on displacement capacity. Northwest reached a settlement with the majority of
its firm shippers to support roll-in of 88 percent of the expansion costs with
the remainder to be allocated to the Evergreen Project. Northwest expects the
FERC to issue a certificate by July 2002 and plans to start construction by
April 2003. The estimated cost of the expansion project is approximately $43
million with a targeted in-service date of October 31, 2003.

On May 11, 2001, Northwest Pipeline filed an application with the FERC to
construct and operate a lateral pipeline that will provide 161,500 dekatherms
per day of firm transportation capacity to serve a new power generation plant.
The Grays Harbor Lateral project will include installing 49 miles of 20-inch
pipeline, adding 4,700 horsepower at an existing compressor station, and a new
meter station. Northwest expects the FERC to issue a certificate by April 15,
2002 and plans to start construction by June 2002. The estimated cost of the
lateral project is approximately $75 million with a targeted in-service date of
November 2002. The customer will pay for the cost of service of the lateral on
an incremental rate basis.

Operating Statistics

The following table summarizes transportation data for the periods
indicated (in trillion British Thermal Units):

KERN RIVER GAS TRANSMISSION COMPANY

Kern River is an interstate natural gas transportation company that owns
and operates a natural gas pipeline system extending from Wyoming through Utah
and Nevada to California. Gas transported on the Kern River pipeline is used in
enhanced oil recovery operations in the heavy oil fields in California. Gas is
also transported to other natural gas consumers in Utah, southern Nevada and
southern California for use in the

11

production of electricity, cogeneration of electricity and steam and other
applications. The system commenced operations in February 1992.

Pipeline System and Customers

At December 31, 2001, Kern River's system was composed of approximately 926
miles of mainline and branch transmission pipelines and five compressor stations
having a mainline designed delivery capacity of approximately 835 million cubic
feet of natural gas per day. The pipeline system interconnects with the pipeline
facilities of another pipeline company at Daggett, California. From the point of
interconnection, Kern River and the other pipeline company have a common
219-mile pipeline, which is owned as tenants in common and is designed to
accommodate the combined throughput of both systems. This common facility has a
designed delivery capacity of 1.235 billion cubic feet of natural gas per day.
Kern River currently has a design capacity of 835 million cubic feet of natural
gas per day while the other pipeline has a design capacity of 400 million cubic
feet of natural gas per day.

In 2001, Kern River transported natural gas for customers in California,
Nevada and Utah. Kern River transported natural gas for use in enhanced oil
recovery operations in the heavy oil fields in California and transported to
other natural gas consumers in Utah, southern Nevada and southern California for
use in the production of electricity, cogeneration of electricity and steam and
other applications. At December 31, 2001, Kern River had a total of 29
customers. The three largest customers of Kern River in 2001 accounted for
approximately 20.4 percent, 13.3 percent and 11.4 percent, respectively, of its
total operating revenues. No other customer accounted for more than ten percent
of total operating revenues in 2001. Kern River transports natural gas for
customers under firm long-term transportation agreements totaling approximately
835 million cubic feet of natural gas per day and under various interruptible,
short-term firm and seasonal firm transportation agreements.

Expansion Projects

On April 6, 2001, Kern River received a FERC certificate to construct and
operate an expansion of its pipeline, known as the California Action Project, to
provide an additional 114,000 dekatherms per day of limited term transportation
capacity from July 1, 2001, through April 30, 2002, and an additional 21,000
dekatherms per day of limited term transportation from July 1, 2001, through
April 30, 2003. Temporary facilities will be removed and the permanent
facilities will be used as part of the facilities needed to satisfy the 124,500
dekatherms per day of firm transportation contracts initially signed as a part
of the Kern River 2002 Expansion Project. The cost of the expansion project was
$81.3 million and was placed in service on July 1, 2001. The customers will pay
for the cost of service of this expansion on an incremental rate basis.

On July 26, 2001, Kern River received a FERC certificate to construct and
operate an expansion of its pipeline, known as the Kern River Amended 2002
Expansion Project, to provide an additional 10,500 dekatherms per day of
long-term firm transportation capacity from Wyoming to markets in California.
Kern River started construction on October 9, 2001. The project will make
permanent the California Action Project facilities which includes the
construction of three new compressor stations. An additional compressor at an
existing facility in Wyoming will be installed as well as restaging a compressor
in Utah and upgrading two-meter stations. The estimated cost of the project
excluding the permanent California Action Project facilities is $31.5 million
with a targeted in-service date of May 1, 2002. The customers will pay for the
cost of the service of this expansion on a rolled-in basis.

On July 18, 2001, Kern River filed an application with the FERC to
construct and operate a lateral pipeline that will provide 282,000 dekatherms
per day of firm transportation capacity to serve a new power generation plant.
The High Desert Lateral will include installing 32 miles of 24-inch pipeline and
two meter stations. Kern River expects the FERC to issue a certificate by May 1,
2002, and plans to start construction by June 2002. The estimated cost of the
lateral project is approximately $29 million with a targeted in-service date of
September 2002. The customer will pay for the cost of the service of the lateral
line on an incremental rate basis.

12

On August 1, 2001, Kern River filed an application with the FERC to
construct and operate an expansion of its pipeline system that will serve an
additional 902,626 dekatherms per day of firm transportation capacity to serve
primarily power generation demand in southern Nevada and California. The 2003
Expansion Project will include installing 717 miles of loop pipeline, three new
compressor stations, upgrading, replacing or modifying six existing compressor
stations, adding a net total of 163,700 horsepower and upgrading five-meter
stations. Kern River expects the FERC to issue a certificate by May 1, 2002, and
plans to start construction by June 2002. The estimated cost of the expansion is
$1.27 billion with a targeted in-service date of May 1, 2003. The customers will
pay for the cost of service of this expansion on an incremental basis.

Operating Statistics

The following table summarizes transportation data for the periods
indicated (in trillion British Thermal Units):

TEXAS GAS TRANSMISSION CORPORATION

Texas Gas is an interstate natural gas transportation company that owns and
operates a natural gas pipeline system extending from the Louisiana Gulf Coast
area and eastern Texas and running generally north and east through Louisiana,
Arkansas, Mississippi, Tennessee, Kentucky, Indiana and into Ohio, with smaller
diameter lines extending into Illinois. Texas Gas' direct market area
encompasses eight states in the South and Midwest, and includes the Memphis,
Tennessee; Louisville, Kentucky; Cincinnati and Dayton, Ohio; and Indianapolis,
Indiana metropolitan areas. Texas Gas also has indirect market access to the
Northeast through interconnections with unaffiliated pipelines.

Pipeline System and Customers

At December 31, 2001, Texas Gas' system, having a mainline delivery
capacity of approximately 2.8 billion cubic feet of natural gas per day, was
composed of approximately 5,900 miles of mainline, storage and branch
transmission pipelines and 31 compressor stations having a sea level-rated
capacity totaling approximately 556,000 horsepower.

In 2001, Texas Gas transported natural gas to customers in Louisiana,
Arkansas, Mississippi, Tennessee, Kentucky, Indiana, Illinois and Ohio, and
indirectly to customers in the Northeast. Texas Gas transported gas for 105
distribution companies and municipalities for resale to residential, commercial
and industrial end users. Texas Gas provided transportation services to
approximately 15 industrial customers located along its system. At December 31,
2001, Texas Gas had transportation contracts with approximately 560 shippers.
Transportation shippers include distribution companies, municipalities,
intrastate pipelines, direct industrial users, electrical generators, gas
marketers and producers. The largest customer of Texas Gas in 2001 accounted for
approximately 13.9 percent of its total operating revenues. No other customer
accounted for more than ten percent of total operating revenues in 2001. Texas
Gas' firm transportation and storage agreements are generally long-term
agreements with various expiration dates and account for the major portion of
Texas Gas's business. Additionally, Texas Gas offers interruptible
transportation, short-term firm transportation and storage services under
agreements that are generally shorter term.

Texas Gas owns and operates gas storage reservoirs in nine underground
storage fields located on or near its system or market areas. The storage
capacity of Texas Gas' certificated storage fields is approximately 178 billion
cubic feet of natural gas. Texas Gas' storage gas is used in part to meet
operational balancing needs on its system, to meet the requirements of Texas
Gas' firm and interruptible storage customers and to meet the requirements of
Texas Gas' No-Notice transportation service, which allows Texas Gas' customers
to temporarily draw from Texas Gas' storage gas to be repaid in-kind during the
following summer season. A

13

small amount of storage gas is also used to provide Summer No-Notice (SNS)
transportation service, designed primarily to meet the needs of summer-season
electrical power generation facilities. SNS customers may temporarily draw from
Texas Gas' storage gas in the summer, to be repaid during the same summer
season. A large portion of the natural gas delivered by Texas Gas to its market
area is used for space heating, resulting in substantially higher daily
requirements during winter months.

Operating Statistics

The following table summarizes transportation data for the periods
indicated (in trillion British Thermal Units):

WILLIAMS GAS PIPELINES CENTRAL, INC.

Central is an interstate natural gas transportation company that owns and
operates a natural gas pipeline system located in Colorado, Kansas, Missouri,
Nebraska, Oklahoma, Texas and Wyoming. The system serves customers in seven
states, including major metropolitan areas in Kansas and Missouri, its chief
market areas.

Pipeline System and Customers

At December 31, 2001, Central's system, having a mainline delivery capacity
of approximately 2.3 billion cubic feet of natural gas per day, was composed of
approximately 6,000 miles of mainline and branch transmission and storage
pipelines and 43 compressor stations having a sea level-rated capacity totaling
approximately 226,000 horsepower.

In 2001, Central transported natural gas to customers in Colorado, Kansas,
Missouri, Nebraska, Oklahoma, Texas and Wyoming. At December 31, 2001, Central
had transportation contracts with approximately 175 shippers serving
approximately 530 cities and towns and 222 industrial customers.

In 2001, approximately 58 percent of Central's total operating revenues
were generated from gas transportation services to Central's two largest
customers, Kansas Gas Service Company, a division of Oneok, Inc. (approximately
28 percent), and Missouri Gas Energy Company (approximately 30 percent). Kansas
Gas Service Company sells or resells gas to residential, commercial and
industrial customers principally in certain major metropolitan areas of Kansas.
Missouri Gas Energy Company sells or resells gas to residential, commercial and
industrial customers principally in certain major metropolitan areas of
Missouri. No other customer accounted for more than ten percent of operating
revenues in 2001.

Central's firm transportation agreements have various expiration dates
ranging from one to 20 years, with the majority expiring in three to eight
years. Additionally, Central offers interruptible transportation services under
shorter term agreements.

Central operates eight underground storage fields with an aggregate natural
gas storage capacity of approximately 43 billion cubic feet and an aggregate
delivery capacity of approximately 1.2 billion cubic feet of natural gas per
day. Central's customers inject gas into these fields when demand is low and
withdraw it to supply their peak requirements. During periods of peak demand,
approximately two-thirds of the firm gas delivered to customers is supplied from
these storage fields. Storage capacity enables Central's system to operate more
uniformly and efficiently during the year.

14

Operating Statistics

The following table summarizes transportation data for the periods
indicated (in trillion British Thermal Units):

REGULATORY MATTERS

Each of the interstate natural gas pipeline companies discussed above has
various regulatory proceedings pending. Each company establishes its rates
primarily through the FERC's 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 FERC determines the allowed rate of return 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, the interstate
natural gas pipeline companies have collected a portion of their revenues
subject to refund. See Note 19 of Notes to Consolidated Financial Statements for
the amount accrued for potential refund at December 31, 2001.

Each of the interstate natural gas pipeline companies that were formerly
gas supply merchants have undertaken the reformation of its respective gas
supply contracts. None of the pipeline companies have any pending supplier
take-or-pay, ratable-take or minimum-take claims, which are material to Williams
on a consolidated basis. For information on outstanding issues with respect to
contract reformation, gas purchase deficiencies and related regulatory issues,
see Note 19 of Notes to Consolidated Financial Statements.

COMPETITION

The FERC continues to regulate each of Williams' interstate natural gas
pipeline companies pursuant to the Natural Gas Act and the Natural Gas Policy
Act of 1978. Competition for natural gas transportation has intensified in
recent years due to customer access to other pipelines, rate competitiveness
among pipelines, customers' desire to have more than one transporter 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. WGP does not anticipate any significant financial impact from "capacity
turnback". WGP anticipates that it will be able to remarket most future capacity
subject to 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. States,
including New York, New Jersey, Pennsylvania, Maryland, Georgia, Delaware,
Virginia, California, Wyoming, Kentucky and Indiana, are currently at various
points in the process

15

of unbundling services at local distribution companies. Management expects the
implementation of these changes to encourage greater competition in the natural
gas marketplace.

OWNERSHIP OF PROPERTY

Each of Williams' interstate natural gas pipeline companies generally owns
its facilities in fee, with certain portions, such as certain offshore
facilities, being held jointly with third parties. However, a substantial
portion of each pipeline company's facilities is constructed and maintained
pursuant to rights-of-way, easements, permits, licenses or consents on and
across properties owned by others. Compressor stations, with appurtenant
facilities, are located in whole or in part either on lands owned or on sites
held under leases or permits issued or approved by public authorities. The
storage facilities are either owned or contracted under long-term leases or
easements.

ENVIRONMENTAL MATTERS

Each interstate natural gas pipeline is subject to the National
Environmental Policy Act and federal, state and local laws and regulations
relating to environmental quality control. Management believes 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 the pipeline companies could
recover most of the cost of these expenditures in their rates. For this reason,
management believes that compliance with applicable environmental requirements
by the interstate pipeline companies is not likely to have a material effect
upon Williams' 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 Management's Discussion and Analysis of
Financial Condition and Results of Operations and "Environmental Matters" in
Note 19 of Notes to Consolidated Financial Statements.

WILLIAMS ENERGY SERVICES

Williams Energy Services, LLC (Williams Energy) is comprised of five major
business units: Exploration & Production, International, Midstream Gas &
Liquids, Petroleum Services and Williams Energy Partners L.P. Williams Energy,
through its subsidiaries, engages in energy exploration and production
activities by owning 3.2 trillion cubic feet equivalent of proved natural gas
reserves located primarily in New Mexico, Wyoming and Colorado; directly invests
in international energy projects located primarily in South America and
Lithuania and invests in energy and infrastructure development funds in Asia and
Latin America; partially owns a soda ash mining operation in Colorado; and owns
or operates approximately 11,200 miles of gathering pipelines (including certain
gathering lines owned by Transco but operated by Midstream Gas & Liquids),
approximately 14,300 miles of natural gas liquids pipelines (4,770 of which are
partially owned), 10 natural gas treating plants, 18 natural gas processing
plants (three of which are partially owned) located in the United States and
Canada, 69 petroleum products terminals, two ethanol production facilities (one
of which is partially owned), two refineries, 89 convenience stores/travel
centers, approximately 6,747 miles of petroleum products pipeline and
approximately 1,100 miles of ammonia pipeline. At December 31, 2001, Williams
Energy, through its subsidiaries, employed approximately 6,870 employees.

Segment revenues and segment profit for Williams Energy's business units
are reported in Note 22 of Notes to Consolidated Financial Statements herein.

A business description of each of Williams Energy's business units follows.

EXPLORATION & PRODUCTION

Williams Energy, through its wholly owned subsidiaries Williams Production
Company and Williams Production RMT Company in its Exploration & Production unit
(E&P), owns and operates producing natural gas leasehold properties in the
United States. In addition, E&P is exploring for oil and natural gas.

16

Acquisitions

On August 2, 2001, Williams Production RMT Company completed its
acquisition of Barrett Resources Corporation of Denver, Colorado, through a
merger. At the time of the merger, Barrett had total proved reserves of 1.9
trillion cubic feet equivalent and equity productions of 350 million cubic feet
equivalent per day. The merger established several new core areas in the Rockies
with development drilling programs in the Piceance, Raton and Powder River
basins. Other projects exist in the Uinta basin, Wind River basin, Mid-
continent area and the Gulf of Mexico.

Oil and Gas Properties

E&P's properties are located primarily in the Rocky Mountains and Gulf
Coast areas. Rocky Mountain properties are located in New Mexico, Wyoming and
Colorado. Gulf Coast properties are located in Louisiana and east and south
Texas.

Gas Reserves and Wells

At December 31, 2001, 2000 and 1999, E&P had proved developed natural gas
reserves of 1,599 billion cubic feet equivalent, 603 billion cubic feet
equivalent and 548 billion cubic feet equivalent, respectively, and proved
undeveloped reserves of 1,579 billion cubic feet equivalent, 599 billion cubic
feet equivalent and 504 billion cubic feet equivalent, respectively. Of E&P's
total proved reserves, 21 percent are located in the San Juan Basin of Colorado
and New Mexico, 26 percent are located in Wyoming and 46 percent are located in
Colorado outside of the San Juan Basin. No major discovery or other favorable or
adverse event has caused a significant change in estimated gas reserves since
year end 2001. E&P has not filed any information with any other federal
authority or agency with respect to its estimated total proved reserves at
December 31, 2001.

At December 31, 2001, the gross and net developed leasehold acres owned by
E&P totaled 1,025,119 and 515,295, respectively, and the gross and net
undeveloped acres owned were 3,852,811 and 2,424,763, respectively. At December
31, 2001, E&P owned interests in 9,846 gross producing wells (4,252 net) on its
leasehold lands.

Operating Statistics

The following tables summarize drilling activity for the periods indicated:

The majority of E&P's natural gas production is currently being sold to
Energy Marketing & Trading at spot market prices. Additionally, E&P has entered
into derivative contracts with Energy Marketing & Trading that hedge
approximately 79 percent of projected 2002 natural gas production. Energy
Marketing & Trading then enters into offsetting derivative contracts with
unrelated third parties. Approximately 75 percent of production in 2001 was
hedged. The total net production sold during 2001, 2000 and 1999 was 130.7
billion cubic feet equivalent, 65.6 billion cubic feet equivalent and 57.9
billion cubic feet equivalent, respectively. The average production costs
including production taxes per million cubic feet of gas produced were $.61,
$.57 and

17

$.46, in 2001, 2000 and 1999, respectively. The average wellhead sales price per
million cubic feet was $3.13, $2.67 and $1.48, respectively, for the same
periods.

In 1993, E&P 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. Williams 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,
Williams sold its trust units as part of a Section 29 tax credit transaction, in
which Williams retained an option to repurchase the units. Williams registered
the units with the SEC and has been repurchasing the units and reselling the
units on the open market from time to time. As of February 18, 2002, Williams'
option to repurchase totaled 3,308,791 units.

INTERNATIONAL

Williams International Company, through subsidiaries, has made direct
investments in energy projects primarily in South America and Lithuania and
continues to explore and develop additional projects for international
investments. Williams International also has investments in energy and
infrastructure development funds in Asia and South America and a soda ash mining
operation in Colorado.

El Furrial. Williams International owns a 67 percent interest in a venture
near the El Furrial field in eastern Venezuela that constructed, owns and
operates medium and high pressure gas compression facilities for Petroleos de
Venezuela S.A. (PDVSA), the state owned petroleum corporation of Venezuela.

The medium pressure facility has compression capacity of 130 million cubic
feet per day of raw natural gas from 100 to 1,200 p.s.i.g. for delivery into a
natural gas processing plant owned by PDVSA. The high pressure facility has
compression capacity of 650 million cubic feet per day of processed natural gas
from 1,100 to 7,500 p.s.i.g. for injection into PDVSA's El Furrial producing
field.

Jose Terminal. Through a long-term operations and maintenance agreement, a
consortium, in which Williams International owns 45 percent, operates the PDVSA,
Eastern Venezuela crude oil storage and shiploading terminal. Operations began
in the second quarter of 1999, and volumes have averaged 500,000 barrels per
day. Crude oil exports shipped through this offshore facility are expected to
generate approximately 30 percent of Venezuela's forecasted revenues. PDVSA
expects to significantly increase the terminal's volume and capacity, currently
800,000 barrels per day, during the next several years.

Pigap II. In April 1999, a consortium in which Williams International owns
70 percent entered into an agreement with PDVSA Petroleo y Gas, S.A., to
develop, design, construct, operate, maintain and own a high pressure natural
gas injection facility and related infrastructure to take gas, process it and
deliver it for injection for secondary recovery of oil from the Santa
Barbara/Pirital oil fields located in North Monogas, Venezuela for an initial
term of 20 years. Williams International commenced construction in February
2000. Initial operations began in August 2001. The facility is now fully
operational. Performance tests have been completed and approved by PDVSA to 75
percent of capacity. The plant is currently being tested at 100 percent of
capacity. Maximum capacity is 1.4 billion cubic feet per day.

Accroven. Williams International acquired by purchase from TCPL
International Limited and TC International Limited and owns 49.25 percent of
Accroven, the Eastern Venezuela project which built, owns and operates two 400
million cubic feet per day natural gas liquids extraction plants, a 50,000
barrel per day natural gas liquids fractionation plant and associated storage
and refrigeration facilities for PDVSA. Operations commenced in June 2001. The
facility is fully operational with all performance tests completed and approved
to 100 percent of capacity.

AB Mazeikiu Nafta. In October 1999 Williams acquired a 33 percent
ownership interest and the right to operate AB Mazeikiu Nafta (MN). MN consists
of a 320,000 barrel per day refinery, which as of February 28, 2002 was refining
140,000 barrels per day, a 720,000 barrel per day crude oil and refined product
pipeline systems within Lithuania and a 160,000 barrel per day crude export
facility on the Baltic Sea. Williams took over the operation of these assets in
October 1999.

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In September of 2000, MN signed an agreement with Yukos Oil Company to
transport 80,000 barrels per day through the Butinge terminal. Additionally, MN
has entered into multiple short-term supply agreements for the supply of crude
oil to the refinery. MN is currently in negotiations with Russian producers for
a long-term 80,000-barrel per day refinery supply agreement.

Apco Argentina. Williams International owns approximately a 70 percent
interest in Apco Argentina Inc., an oil and gas exploration and production
company with operations in Argentina, whose securities are traded on the NASDAQ
stock market. Apco Argentina's principal business is its 47.6 percent interest
in the Entre Lomas concession in southwest Argentina. It also owns a 45 percent
interest in the Canadon Ramirez concession and a 1.5 percent interest in the
Acambuco concession.

American Soda L.L.P. -- Sodium Mineral Resource Investment. American Soda
L.L.P. is a partnership based in the Piceance Creek Basin of western Colorado
for the purpose of engaging in the exploration, development, mining and
marketing of soda ash and sodium bicarbonate in an efficient and environmentally
responsible manner. This facility has capacities of approximately one million
tons of soda ash per year and 150,000 tons of sodium bicarbonate per year. The
project is included in International's portfolio because it exports a
significant portion of the soda ash production through the United States
producer export-marketing consortium, American Natural Soda Ash Company. Soda
ash is used in the manufacture of glass, chemicals, paper and detergents. Sodium
bicarbonate, more commonly known as baking soda, is used in animal feed,
pharmaceutical products, food additives, water treatment, cleaning products and
fire extinguishers. As a result of higher than expected construction costs and
implementation difficulties, a $170 million impairment charge on the facility
was recorded in the fourth-quarter of 2001.

MIDSTREAM GAS & LIQUIDS

Williams Energy, through Williams Field Services Group, Inc. and its
subsidiaries, Williams Energy (Canada), Inc. and its subsidiaries, Williams
Natural Gas Liquids, Inc. and its subsidiaries and Williams Midstream Natural
Gas Liquids, Inc. (collectively Midstream), owns and operates natural gas
gathering, processing and treating facilities, and natural gas liquids
transportation, fractionation and storage facilities in northwestern New Mexico,
southwestern Colorado, southwestern Wyoming, eastern Utah, northwestern
Oklahoma, Kansas, northern Missouri, eastern Nebraska, Iowa, southern Minnesota,
Tennessee, central Alberta and western British Columbia, Canada and also in
areas offshore and onshore in Texas, Alabama, Mississippi and Louisiana.
Midstream also operates gathering facilities owned by Transcontinental Gas Pipe
Line Corporation, an affiliated interstate natural gas pipeline company, that
are currently regulated by the FERC.

Expansion Projects

In 2001, Midstream continued to expand its Gulf Coast operations with the
November completion of an onshore gas processing facility and the mid-2002
scheduled completion of deepwater gathering and transportation facilities, each
of which is leased by Midstream. Midstream's deepwater expansion efforts
continued with agreements to gather and transport oil and natural gas production
from Kerr-McGee Corporation's deepwater developments in the Nansen and Boomvang
areas in the Western Gulf of Mexico. In order to provide these services to
Kerr-McGee and other future prospects, a 137-mile gathering system was
constructed to move gas and oil produced by the Nansen and Boomvang prospects.
In November 2001, the newly-constructed cryogenic plant located near Markham,
Texas was placed into operation. The 300 million cubic feet per day plant
processes the gas flows generated from the East Breaks infrastructure. Midstream
leases each of these facilities. The lease terms include a five-year base term
including the construction phase and can be renewed for another five-year term.

Midstream also signed agreements to provide infrastructure for Dominion
Exploration & Production, Inc. and Pioneer Natural Resources Company deepwater
projects located in the Devils Tower field in the Gulf of Mexico. Terms of the
agreement call for Midstream to construct and own a floating production
facility, a 90-mile gas pipeline and a 120-mile oil pipeline to handle
production from the Devils Tower field. Midstream intends to use the facilities
to provide production-handling services to surrounding fields. The project is

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scheduled to become operational in June 2003. Midstream's Mobile Bay plant will
process the gas and recover NGL's, which will then be transported to the Baton
Rouge fractionator via the Tri-States and Wilprise pipelines.

The Redwater Olefins fractionation facility located adjacent to the
existing Redwater Fractionation Facility near Edmonton, Alberta, is nearing
completion. The new facility is scheduled to be in service in the first quarter
2002 and include feed storage, feed treatment, fractionation, product storage,
product treatment and rail loading. The new olefins facility will be an integral
part of Midstream's existing McMurray-Redwater System, which involves the
recovery of hydrocarbon liquids from the offgas produced at a third party
facility near Ft. McMurray, Alberta.

Customers and Operations

Facilities owned and/or operated by Midstream consist of approximately
11,200 miles of gathering pipelines (including certain gathering lines owned by
Transco but operated by Midstream), 10 natural gas treating plants, 18 natural
gas processing plants (three of which are partially owned), and approximately
14,300 miles of natural gas liquids pipeline, of which approximately 4,770 miles
are partially owned. The aggregate daily inlet capacity is approximately 9.0
billion cubic feet for the gathering systems and 12.2 billion cubic feet for the
gas processing, treating and dehydration facilities. Midstream's pipeline
operations provide customers with one of the nation's largest natural gas
liquids transportation systems, while gathering and processing customers have
direct access to interstate pipelines, including affiliated pipelines, which
provide access to multiple markets.

During 2001, Midstream gathered gas for 255 customers, processed gas for 93
customers and provided transportation to 87 customers. The largest customer
accounted for approximately 14 percent of total gathered volumes, and the two
largest processing customers accounted for 19 percent and 16 percent,
respectively, of processed volumes. The largest transportation customers
accounted for 17 percent of transportation volumes. No other customer accounted
for more than ten percent of gathered, processed or transported volumes.
Williams Canada sold NGLs to 10 customers, three of which individually represent
over ten percent of Canadian NGL sales. Midstream's gathering and processing
agreements with large customers are generally long-term agreements with various
expiration dates. These long-term agreements account for the majority of the gas
gathered and processed by Midstream. The natural gas liquids transportation
contracts are tariff-based and generally short-term in nature with some
long-term contracts for system-connected processing plants. The Canadian NGL
sales contracts are typically long-term in nature and are based on
cost-of-service or flat fee arrangements.

Acquisitions

Midstream continues to realign its assets to focus on providing producer
services in significant growth basins. In order to strengthen its strategic
position in the Gulf Coast offshore production areas, Midstream acquired a
series of Gulf Coast pipelines in 2001 that included the Black Marlin Pipeline,
Green Canyon Gathering System and the Tarpon Transmission System. In January
2002, Midstream announced an asset swap with Duke Energy Field Services that
will increase its ownership in the Wyoming area in exchange for its assets in
the Hugoton Basin. Terms of the agreement include Midstream receiving Duke's 34
percent ownership interest in the Echo Spring processing plant and related
gathering systems near Wamsutter, Wyoming. Midstream currently owns the
remaining 66 percent ownership interest in the Wamsutter assets. In exchange,
Duke will receive Midstream's Oklahoma Hugoton gathering system, and the Baker,
Hobart Ranch and South Bishop gas processing plants located in the Texas and
Oklahoma panhandle area. The transaction is expected to close in the first
quarter of 2002.

In January 2002, Midstream sold various gas gathering and processing assets
located in south Texas. These assets included a sour gas treatment plant and
gathering lines near Tilden, an inactive gas processing plant in Bee County and
Midstream's 76 percent interest in the Webb Duval gathering system. In addition,
the sale of 492 miles of Transco transmission lines in far southern Texas is
expected to close in the third quarter of 2002.

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Operating Statistics

The following table summarizes gathering, processing, natural gas liquid
sales and transportation volumes for the periods indicated. The information
includes operations attributed to facilities owned by Transco but operated by
Midstream.

- ---------------

* Partial year (acquired October 11, 2000)

PETROLEUM SERVICES

Williams Energy, through wholly owned subsidiaries in its Petroleum
Services unit, owns and operates a petroleum products pipeline system, an
ethylene plant and olefin pipeline, 39 petroleum products terminals (some of
which are partially owned), two ethanol production plants (one of which is
majority owned), two refineries and 89 convenience stores/travel centers, and
provides services and markets products related thereto. In 2001, no one customer
accounted for ten percent of Petroleum Services' total revenues.

Transportation

A subsidiary in the Petroleum Services unit, Williams Pipe Line Company,
owns and operates a petroleum products pipeline system that covers an 11-state
area extending from Oklahoma to North Dakota, Minnesota and Illinois. The system
is operated as a common carrier offering transportation and terminalling
services on a nondiscriminatory basis under published tariffs. The system
transports refined products and liquified petroleum gases. On February 4, 2002,
Williams announced that it plans to sell this pipeline system and its on-system
terminals. Williams Energy Partners L.P. is a potential purchaser of this
pipeline system.

At December 31, 2001 the system includes approximately 6,747 miles of
pipeline in various sizes up to 16 inches in diameter. The system includes 77
pumping stations, 26.5 million barrels of storage capacity and 39 delivery
terminals. The terminals are equipped to deliver refined products into tank
trucks and tank rail cars. The maximum number of barrels that the system can
transport per day depends upon the operating balance achieved at a given time
between various segments of the system. Because the balance is dependent upon
the mix of products to be shipped and the demand levels at the various delivery
points, the exact capacity of the system cannot be stated. In 2001, total system
shipments averaged 647,000 barrels per day.

The operating statistics set forth below relate to the system's operations
for the periods indicated:

Williams and its subsidiary, Longhorn Enterprises of Texas, Inc. (LETI),
own a total 32.1 percent interest in Longhorn Partners Pipeline, LP, a joint
venture formed to construct and operate a refined products

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pipeline from Houston, Texas, to El Paso, Texas. Pipeline construction is
substantially complete pending regulatory and environmental approvals, and
operations are expected to commence after receiving such approvals in mid-2002.
Williams Pipe Line has designed and constructed and will operate the pipeline,
and Williams Pipe Line and LETI have contributed a total of approximately $105
million and loaned approximately $32 million to the joint venture.

On June 30, 2000, a subsidiary in the Petroleum Services unit purchased an
interest in the Trans-Alaska Pipeline System from Mobil Alaska Pipeline Company
for $32.5 million. Petroleum Services' interest consists of 3.0845 percent of
the pipeline and the Valdez crude terminal. Petroleum Services' share of the
crude oil deliveries for 2001 was approximately 14.0 million barrels.

Olefins

Petroleum Services owns and operates an approximate 42 percent interest in
a 1.3 billion pounds per year ethylene plant near Geismar, Louisiana. Williams
Energy Marketing & Trading provides feedstocks to the olefins facility and
markets the Williams share of the ethylene produced from the facility through a
tolling arrangement with Petroleum Services. The olefins facility is supported
by pipeline and storage assets owned by Williams Midstream Gas & Liquids.
Midstream owns and operates a 215-mile light hydrocarbon transportation system
and operates and has partial ownership in an 85-mile olefin pipeline and storage
network, which connects, either directly or indirectly, most major natural gas
liquids producers and olefin consumers in Louisiana.

Feedstock processed and ethylene produced by the olefin facility, which was
acquired in March 1999, noted below represents Williams approximate 42 percent
interest:

Bio-Energy

Williams Bio-Energy, LLC, is engaged in the production and marketing of
ethanol. Williams Bio-Energy owns and operates two ethanol plants (one of which
is partially owned) for which corn is the principal feedstock. The Pekin,
Illinois, plant has an annual production capacity of 100 million gallons of
fuel-grade and industrial ethanol and also produces various coproducts and
bio-products. Bio-products, mainly flavor enhancers, produced at the Pekin plant
are marketed primarily to food processing companies. The Aurora, Nebraska, plant
(in which Williams Bio-Energy owns an approximate 77 percent interest) has an
annual production capacity of 30 million gallons. In late 2000, Williams
Bio-Energy acquired a minority interest in two affiliate plants in South Dakota
and made equity investments in two other plants in Minnesota and Iowa totaling
approximately 40 million gallons of annual ethanol production capacity produced
primarily from corn. In addition, Williams Bio-Energy obtained marketing rights
to 100 percent of the ethanol output of the four plants. Williams Bio-Energy
also markets ethanol produced by third parties. In 2001, Williams Bio-Energy
entered into marketing agreements to market all of the ethanol produced by
Heartland Grain Fuels, L.P., Minnesota Energy, Sunrise Energy and Tri-State
Ethanol Company, LLC.

The sales volumes set forth below include ethanol produced by third parties
as well as by Williams Bio-Energy for the periods indicated:

Refining

Petroleum Services, through subsidiaries in its unit, owns and operates two
petroleum products refineries: the North Pole, Alaska refinery and the Memphis,
Tennessee refinery. The financial results of the North Pole refinery and the
Memphis refinery may be significantly impacted by changes in market prices for
crude oil and

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refined products. Petroleum Services cannot predict the future of crude oil and
product prices or their impact on its financial results.

The North Pole Refinery includes the refinery located at North Pole, Alaska
and a terminal facility at Anchorage, Alaska. The refinery, the largest in the
state, is located approximately two miles from its supply point for crude oil,
the Trans-Alaska Pipeline System (TAPS). The refinery's processing capability is
approximately 215,000 barrels per day. At maximum crude throughput, the refinery
can produce up to 70,000 barrels per day of retained refined products. These
products are jet fuel, gasoline, diesel fuel, heating oil, fuel oil, naphtha and
asphalt. These products are marketed in Alaska, Western Canada and the Pacific
Rim principally to wholesale, commercial, industrial and government customers
and to Petroleum Services' retail petroleum group.

Barrels processed and transferred by the North Pole Refinery per day are
noted below:

The North Pole Refinery's crude oil is purchased from the state of Alaska
or is purchased or received on exchanges from crude oil producers. The refinery
has two long-term agreements with the state of Alaska for the purchase of
royalty oil, both of which are scheduled to expire on December 31, 2003. The
agreements provide for the purchase of up to 56,000 barrels per day
(approximately 80 percent of the refinery's supply needs for retained
production) of the state's royalty share of crude oil produced from Prudhoe Bay,
Alaska. These volumes, along with crude oil either purchased or received under
exchange agreements from crude oil producers or other short-term supply
agreements with the state of Alaska, are utilized as throughput for the
refinery. Approximately 30 percent of the throughput is refined, retained and
sold as finished product and the remainder of the throughput is returned to the
TAPS and either delivered to repay exchange obligations or sold.

The Memphis Refinery, which includes three petroleum products terminals, is
the only refinery in the state of Tennessee and has a throughput capacity of
approximately 175,000 barrels per day. Petroleum Services commissioned a 36,000
barrel per day continuous catalyst regeneration reformer in May 2000. The
reformer enables the refinery to produce in greater volumes premium gasoline to
be delivered in the mid-South region of the United States.

The Memphis Refinery produces gasoline, low sulfur diesel fuel, jet fuel,
K-1 kerosene, refinery-grade propylene, No. 6 fuel oil, propane and elemental
sulfur. In 2001, these products were exchanged or marketed primarily in the
Mid-South region of the United States to wholesale customers, such as industrial
and commercial consumers, jobbers, independent dealers and other
refiner/marketers. Through January 2001, Williams' Energy Marketing & Trading
unit marketed the refinery's products. Petroleum Services began marketing the
refinery's products directly in February 2001.

The Memphis Refinery has access to crude oil from the Gulf Coast via common
carrier pipeline and by river barges. In addition to domestic crude oil, the
Memphis Refinery receives and processes certain foreign crudes. The Memphis
Refinery's purchase contracts are generally short-term agreements.

Average daily barrels processed and transferred by the Memphis Refinery are
noted below:

Retail Petroleum

Petroleum Services, primarily under the brand names "Williams
TravelCenters" and "Williams Express," is engaged in the retail marketing of
gasoline, diesel fuel, other petroleum products, convenience merchandise and
restaurant and fast food items. On May 31, 2001, Petroleum Services sold 198
MAPCO Express convenience stores to Delek -- The Israel Fuel Corporation
Limited. At December 31, 2001, the retail petroleum group operated 61 interstate
TravelCenter locations and 28 Williams Express convenience stores in Alaska. The
TravelCenter sites consist of 35 modern facilities providing gasoline and diesel
fuel,

23

merchandise and restaurant offerings for both traveling consumers and
professional drivers, and 15 locations providing fuel and merchandise. The
convenience store sites are primarily concentrated in the vicinities of
Nashville and Memphis, Tennessee and Anchorage and Fairbanks, Alaska. All of the
motor fuel sold by Williams TravelCenters and convenience stores is supplied
either by exchanges, directly from either the Memphis or North Pole Refineries
or through Williams Energy Marketing & Trading.

Convenience merchandise, restaurants and fast food accounted for
approximately 60 percent of the retail petroleum group's gross margins in 2001.
Gasoline and diesel sales volumes for the periods indicated are noted below:

WILLIAMS ENERGY PARTNERS L.P.

In October 2000, Williams formed Williams Energy Partners L.P. (WEP), a
wholly owned partnership, to acquire, own and operate a diversified portfolio of
energy assets, concentrated around the storage, transportation and distribution
of refined petroleum products and ammonia. On October 30, 2000, WEP filed with
the Securities and Exchange Commission a registration statement on Form S-1
related to an initial public offering of common units. In February 2001,
4,600,000 common units, representing approximately 40 percent of the total
outstanding units, were sold to the public. Williams currently owns
approximately 60 percent of the partnership including its general partner
interest. WEP's common units trade on the New York Stock Exchange under the
symbol WEG.

WEP's asset portfolio includes five marine petroleum product terminal
facilities with an aggregate storage capacity of approximately 18 million
barrels, 25 inland terminals with an aggregate storage capacity of 4.7 million
barrels and an ammonia pipeline and terminals system that extends for
approximately 1,100 miles from Texas and Oklahoma to Minnesota. Williams Energy
Marketing & Trading is WEP's largest terminal customer accounting for
approximately 9.5 percent of WEP's terminal revenues for 2001.

REGULATORY MATTERS

International. AB Mazeikiu Nafta is regulated by the Government of the
Republic of Lithuania. The four primary ministries that interact on the day to
day activities of MN are the Ministry of Economy, the Ministry of
Transportation, the Ministry of Environment and the Ministry of Finance. These
Ministries provide governmental regulations regarding the operation of the
refinery, transportation of crude oil and refined products through the pipeline
and terminal system, and financial reporting of MN. In addition the Ministry of
Economy controls MN's Board of Directors and Supervisory Council.

Midstream. In May 1994, after reviewing its legal authority in a Public
Comment Proceeding, the FERC determined that while it retains some regulatory
jurisdiction over gathering and processing performed by interstate pipelines,
pipeline-affiliated gathering and processing companies are outside its authority
under the Natural Gas Act. An appellate court has affirmed the FERC's
determination, and the United States Supreme Court has denied requests for
certiorari. As a result of these FERC decisions, some of the individual states
in which Midstream conducts its operations have considered whether to impose
regulatory requirements on gathering companies. Kansas, Oklahoma and Texas
currently regulate gathering activities using complaint mechanisms under which
the state commission may resolve disputes involving an individual gathering
arrangement. Other states may also consider whether to impose regulatory
requirements on gathering companies.

In February 1996, Midstream and Transco filed applications with the FERC to
spindown all of Transco's gathering facilities to Midstream. The FERC
subsequently denied the request in September 1996. Midstream and Transco sought
rehearing in October 1996. In August 1997, Midstream and Transco filed a second
request for expedited treatment of the rehearing request. The FERC denied
rehearing on June 14, 2001. On July 26, 2001, Midstream and Transco filed an
appeal of the orders with the Circuit Court of Appeals for the District

24

of Columbia. In February 1998, Midstream and Transco filed separate applications
to spindown an onshore gathering system located in Texas, the Tilden/McMullen
gathering system, which was also one of the subjects of the pending rehearing
request. In May 1999, the FERC approved the spindown application only for the
facilities upstream of the Tilden treating plant. The transfer of ownership of
these facilities occurred in April 2000. As a result of a court appeal reversing
and remanding the FERC's decision that the offshore system of Sea Robin pipeline
were transmission facilities regulated by FERC under the Natural Gas Act, in
June 1999, the FERC issued an order in the Sea Robin remand proceeding finding
that the upstream portions of the Sea Robin system are nonjurisdictional
gathering but the downstream portion is regulated transmission. In July 2000,
the FERC affirmed that determination and denied rehearing requests. Appeals are
pending in the District of Columbia Circuit Court of Appeals. In April 2000, the
FERC issued "Regulations under the Outer Continental Shelf Lands Act Governing
the Movement of Natural Gas on Facilities on the Outer Continental Shelf," which
require most non-interstate natural gas pipelines located on the Outer
Continental Shelf to post prices, terms and conditions of service. Williams and
other parties appealed the Rule, challenging FERC's authority to issue it. On
January 11, 2002, the United States District Court for the District of Columbia
granted William's motion for summary judgment and permanently enjoined the FERC
from enforcing that rule. In November 2000, Midstream and Transco filed
applications with the FERC to spindown two of Transco's offshore gathering
facilities to Midstream (the North Padre system and the Central Texas system).
Transco and Midstream explained that it was the first in a series of spindown
filings designed to be consistent with the current policy under the Sea Robin
reformulated test. Subsequently, Midstream and Transco filed to spindown the
North High Island/West Cameron system and the Central Louisiana system. This
series of spindown filings will generally request the spindown of smaller
systems than originally proposed in the 1996 filings, but Transco and Midstream
have stated that they reserve their rights to continue pursuit of the original
spindown proposals. The FERC granted the proposed spindown of the North Padre
Island system and the Central Texas system on July 25, 2001. A rehearing order
was issued on December 19, 2001, which maintained the July 25th order's
determination on the function of the facilities, but did not require Transco to
change its rates before the transfer of facilities. The FERC granted only part
of the proposed spindowns for the North High Island/West Cameron system on July
25, 2001 and on the Central Louisiana system on August 31, 2001. On December 19,
2001, the FERC issued orders on rehearing in both proceedings, maintaining its
previous determination that only some of the proposed facilities function as
non-jurisdictional gathering. On January 7, 2002 Midstream filed an appeal of
each of the orders, the North High Island/West Cameron order and the Central
Louisiana order, with the Circuit Court of Appeals for the District of Columbia.
On January 9, 2002, Midstream and Transco moved to consolidate those two appeals
with the pending appeal of the comprehensive spindown that had been filed July
26, 2001.

Midstream's natural gas liquids group is subject to various federal, state,
and local environmental and safety laws and regulations. Midstream's pipeline
operations are subject to the provisions of the Hazardous Liquid Pipeline Safety
Act. In addition, the tariff rates, shipping regulations, and other practices of
the Mid-America, Rio Grande, Seminole, Wilprise and Tri-States pipelines are
regulated by the FERC pursuant to the provisions of the Interstate Commerce Act
applicable to interstate common carrier petroleum and petroleum products
pipelines. Both of these statutes require the filing of reasonable and
nondiscriminatory tariff rates and subject Midstream to certain other
regulations concerning its terms and conditions of service. The Mid-America, Rio
Grande, Seminole, Wilprise and Tri-States 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.

Midstream's Canadian natural gas group's assets, except for the Taylor to
Boundary Lake Pipeline, are regulated provincially. The Alberta-based assets are
regulated by the Alberta Energy & Utilities Board (AEUB) and Alberta
Environment, while the British Columbia-based assets are regulated by B.C. Oil
and Gas Commission and the British Columbia Ministry of Environment, Lands and
Parks. The regulatory system for Alberta oil and gas industry incorporates a
large measure of self-regulation, meaning 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
25

consequences. The British Columbia Oil and Gas Commission operates in a slightly
different manner than the AEUB, with more emphasis placed on pre-construction
criteria and the submission of post-construction documentation, as well as
periodic inspections. Only one asset is subject to federal regulation, under the
jurisdiction of the NEB. The Taylor to Boundary Lake Pipeline, which is Leg
Number 2 of the NGL Gathering System, is regulated by the National Energy Board
as a Group 2 inter-provincial pipeline between B.C. and Alberta. While Group 2
regulated companies are required to post a toll and tariff for the facilities
they operate, they are regulated on a "complaint only" basis and need only to
employ standard uniform accounting procedures, rather than the more onerous
Group 1 NEB-mandated accounting and reporting requirements.

Petroleum Services. Williams Pipe Line, as an interstate common carrier
pipeline, is subject to the provisions and regulations of the Interstate
Commerce Act. Under this Act, Williams Pipe Line is required, among other
things, to establish just, reasonable and nondiscriminatory rates, to file its
tariffs with the FERC, to keep its records and accounts pursuant to the Uniform
System of Accounts for Oil Pipeline Companies, to make annual reports to the
FERC and to submit to examination of its records by the audit staff of the FERC.
Authority to regulate rates, shipping rules and other practices and to prescribe
depreciation rates for common carrier pipelines is exercised by the FERC. The
Department of Transportation, as authorized by the 1995 Pipeline Safety
Reauthorization Act, is the oversight authority for interstate liquids
pipelines. Williams Pipe Line is also subject to the provisions of various state
laws applicable to intrastate pipelines.

Environmental regulations and changing crude oil supply patterns continue
to affect the refining industry. The industry's response to environmental
regulations and changing supply patterns will directly affect volumes and
products shipped on the Williams Pipe Line system. Environmental Protection
Agency regulations, driven by the Clean Air Act, require refiners to change the
composition of fuel manufactured. A pipeline's ability to respond to the effects
of regulation and changing supply patterns will determine its ability to
maintain and capture new market shares. Williams Pipe Line has successfully
responded to changes in diesel fuel composition and product supply and has
adapted to new gasoline additive requirements. Reformulated gasoline regulations
have not yet significantly affected Williams Pipe Line. Williams Pipe Line will
continue to attempt to position itself to respond to changing regulations and
supply patterns but cannot predict how future changes in the marketplace will
affect its market areas.

Williams Energy Partners L.P. The Surface Transportation Board, a part of
the United States Department of Transportation, has jurisdiction over interstate
pipeline transportation of ammonia. Ammonia transportation rates must be
reasonable, and a pipeline carrier may not unreasonably discriminate among its
shippers. In determining a reasonable rate, the Surface Transportation Board
will consider, among other factors, the effect of the rate on the volumes
transported by that carrier, the carrier's revenue needs and the availability of
other economic transportation alternatives. Because in some instances WEP
transports ammonia between two terminals in the same state, its pipeline
operations are subject to regulation by the state regulatory authorities in
Iowa, Nebraska, Oklahoma and Texas.

COMPETITION

Exploration & Production. Williams Energy's E&P unit competes with a wide
variety of independent producers as well as integrated oil and gas companies for
markets for its production. E&P has three general phases of operations:
acquiring oil and gas properties, developing non-producing properties and
operating producing properties. In the process of acquiring minerals, the
primary methods of competition are on acquisition price and terms such as
duration of the mineral lease, the amount of the royalty payment and special
conditions related to rights to use the surface of the land under which the
mineral interest lies. In the process of developing non-producing properties,
E&P does not face significant competition. In the operating phase, the primary
method of competition involves operating efficiencies related to the cost to
produce the hydrocarbons from the reservoir. The majority of Williams Energy's
ownership interests in exploration and production properties are held as working
interests in oil and gas leaseholds.

Midstream. Williams Energy competes for gathering and processing business
with interstate and intrastate pipelines, producers and independent gatherers
and processors. Numerous factors impact any given

26

customer's 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. Competition for the natural gas liquids pipelines include other
pipelines, tank cars, trucks, barges, local sources of supply (refineries,
gasoline plants and ammonia plants) and other sources of energy such as natural
gas, coal, oil and electricity. Factors that influence customer transportation
decisions include rate, location, nature of service and timeliness of delivery.

Petroleum Services. Williams Pipe Line operates without the protection of
a federal certificate of public convenience and necessity that might preclude
other entrants from providing like service in its area of operations. Further,
Williams Pipe Line must plan, operate and compete without the operating
stability inherent in a broad base of contractually obligated or
owner-controlled usage. Because Williams Pipe Line is a common carrier, its
shippers need only meet the requirements set forth in its published tariffs in
order to avail themselves of the transportation services offered by Williams
Pipe Line.

Competition exists from other pipelines, refineries, barge traffic,
railroads and tank trucks. Competition is affected by trades of products or
crude oil between refineries that have access to the system and by trades among
brokers, traders and others who control products. These trades can result in the
diversion from the Williams Pipe Line system of volume that might otherwise be
transported on the system. Shorter, lower revenue hauls may also result from
these trades. Williams Pipe Line also is exposed to interfuel competition
whereby an energy form shipped by a liquids pipeline, such as heating fuel, is
replaced by a form not transported by a liquids pipeline, such as electricity or
natural gas. While Williams Pipe Line faces competition from a variety of
sources throughout its marketing areas, the principal competition is other
pipelines. A number of pipeline systems, competing on a broad range of price and
service levels, provide transportation service to various areas served by the
system. The possible construction of additional competing products or crude oil
pipelines, conversions of crude oil or natural gas pipelines to products
transportation, changes in refining capacity, refinery closings, changes in the
availability of crude oil to refineries located in its marketing area or
conservation and conversion efforts by fuel consumers may adversely affect the
volumes available for transportation by Williams Pipe Line.

Williams Bio-Energy's fuel ethanol operations compete in local, regional
and national fuel additive markets with other ethanol products and other fuel
additive producers, such as refineries and methyl tertiary butyl ether (MTBE)
producers. MTBE has been banned in California effective January 1, 2003, and in
other states due to ground water contamination problems. Williams Bio-Energy's
other products compete in global markets against a variety of competitors and
substitute products.

The principal competitive forces affecting Williams Energy's refining
businesses are feedstock costs, refinery efficiency, refinery product mix and
product distribution. Some of Memphis Refinery's competitors can process sour
crude, and accordingly, are more flexible in the crudes that they can process.
Williams Energy has limited crude oil reserves and does not engage in crude oil
exploration, and it must therefore obtain its crude oil requirements from
unaffiliated sources. Williams Energy believes that it will be able to obtain
adequate crude oil and other feedstocks at generally competitive prices for the
foreseeable future.

The principal competitive factors affecting Williams Energy's retail
petroleum business are location, product price and quality, appearance and
cleanliness of stores and brand-name identification. Competition in the
convenience store industry is intense. Within the travel center industry,
Williams TravelCenters strives to be a market leader in customer service to the
local consumer, traveling consumer and professional driver.

Williams Energy's gathering and processing facilities and natural gas
liquids pipelines are owned in fee. Midstream Gas & Liquids constructs and
maintains gathering and natural gas liquids pipeline systems pursuant to
rights-of-way, easements, permits, licenses, and consents on and across
properties owned by others. The compressor stations and gas processing and
treating facilities are located in whole or in part on lands owned by
subsidiaries of Williams Energy or on sites held under leases or permits issued
or approved by public authorities.

Williams Energy owns its petroleum pipeline system in fee. However, a
substantial portion of the system is operated, constructed and maintained
pursuant to rights-of-way, easements, permits, licenses or consents on

27

and across properties owned by others. The terminals, pump stations and all
other facilities of the system are located on lands owned in fee or on lands
held under long-term leases, permits or contracts. The North Pole Refinery is
located on land leased from the state of Alaska under a long-term lease
scheduled to expire in 2025 and renewable at that time by Williams Energy. The
Anchorage, Alaska terminal is located on land leased from the Alaska Railroad
Corporation under two long-term leases. The Memphis Refinery is located on land
owned by Williams Energy. Williams Energy management believes its assets are in
such a condition and maintained in such a manner that they are adequate and
sufficient for the conduct of business.

Williams Energy Partners L.P. WEP competes with other independent terminal
operators as well as integrated oil companies on the basis of terminal location
and versatility, services provided and price. Its competition from independent
operators primarily comes from distribution companies with marketing and trading
arms, independent terminal operators and refining and marketing companies.

WEP competes primarily with ammonia shipped by rail carriers, but it has a
distinct advantage over rail carriers because ammonia is a gas under normal
atmospheric conditions and must be either placed under pressure or cooled to -33
degrees Celsius to be shipped or stored. WEP also competes to a limited extent
in the areas served by the far northern segment of their ammonia pipeline and
terminals system with the other United States ammonia pipeline, which originates
on the Gulf Coast and transports domestically produced and imported ammonia.

ENVIRONMENTAL MATTERS

Williams Energy is subject to various international, federal, state and
local laws and regulations relating to environmental quality control. Management
believes that Williams Energy's operations are in substantial compliance with
existing environmental legal requirements. Management expects that compliance
with existing environmental legal requirements will not have a material adverse
effect on the capital expenditures, earnings and competitive position of
Williams Energy. See Note 19 of Notes to Consolidated Financial Statements.

The International unit must comply with the environmental laws of the
country in which its assets are located. For example, Mazeikiu Nafta, a refinery
located in Lithuania, must comply with its Permit for Use of Natural Resources
issued by the government.

Groundwater monitoring and remediation are ongoing at both refineries and
air and water pollution control equipment is operating at both refineries to
comply with applicable regulations. The Clean Air Act Amendments of 1990
continue to impact Williams Energy's refining businesses through a number of
programs and provisions. The provisions include Maximum Achievable Control
Technology rules, which are being developed for the refining industry, controls
on individual chemical substances, new operating permit rules and new fuel
specifications to reduce vehicle emissions. The provisions impact other
companies in the industry in similar ways and are not expected to adversely
impact Williams Energy's competitive position.

Williams Energy and its subsidiaries also accrue environmental remediation
costs for its natural gas gathering and processing facilities, natural gas
liquids pipelines and storage facilities, petroleum products pipelines, retail
petroleum and refining operations and for certain facilities related to former
propane marketing operations primarily related to soil and groundwater
contamination. In addition, Williams Energy owns a discontinued petroleum
refining facility that is being evaluated for potential remediation efforts. At
December 31, 2001, Williams Energy and its subsidiaries had accrued liabilities
totaling approximately $43 million. Williams Energy accrues receivables related
to environmental remediation costs based upon an estimate of amounts that will
be reimbursed from state funds for certain expenses associated with underground
storage tank problems and repairs.

WEG's operation of terminals and associated facilities in connection with
the storage and transportation of crude oil and other liquid hydrocarbons,
together with its operation of an ammonia pipeline, are subject to stringent and
complex laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. As an owner or
lessee and operator of these facilities, WEG must comply with these laws and
regulations at the federal, state and local levels. Failure to comply with these

28

laws and regulations may result in the assessment of administrative, civil and
criminal penalties, imposition of remedial actions, and issuance of injunctions
or construction bans or delays on ongoing operations.

OTHER INFORMATION

Williams believes that it has adequate sources and availability of raw
materials and commodities to assure the continued supply of its services and
products for existing and anticipated business needs. Williams' 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 bodies. Each of the pipeline systems has ongoing capital requirements
for efficiency and mandatory improvements, with expansion opportunities also
necessitating periodic capital outlays.

At December 31, 2001, Williams and its subsidiaries had approximately
12,433 full-time employees, of whom approximately 883 were represented by unions
and covered by collective bargaining agreements. Williams' employees are jointly
employed by Williams and one of its subsidiaries. Williams considers its
relations with its employees to be generally good.

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this report, excluding historical information,
include forward-looking statements -- statements that discuss Williams' expected
future results based on current and pending business operations. Williams makes
these forward-looking statements in reliance on the safe harbor protections
provided under the Private Securities Litigation Reform Act of 1995.

Forward-looking statements can be identified by words such as
"anticipates," "believes," "expects," "planned," "scheduled" or similar
expressions. Although Williams believes 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.

Events in 2001 significantly impacted the risk environment all businesses
face and raised a level of uncertainty in the capital markets that has
approached that which lead to the general market collapse of 1929. Beliefs and
assumptions as to what constitutes appropriate levels of capitalization and
fundamental value have changed abruptly. The collapse of Enron combined with the
meltdown of the telecommunications industry are both new realities that have had
and will likely continue to have specific impacts on all companies, including
Williams.

Following Enron's collapse, the credit rating agencies reacted by
substantially shifting the financial criteria that companies must meet in order
to support an investment grade credit rating. This change in criteria resulted
in, among other things, the need for Williams to increase its equity by reducing
its capital spending to a level that allows surplus cash to be generated and to
issue new public equity. In addition, the credit rating agencies began to view
credit rating downgrade triggers in financial structures as capable of producing
an unpredictable event risk, so Williams committed to take action to eliminate
credit rating triggers from certain of its financial structures. While Williams
responded constructively to these new standards implemented by the credit rating
agencies, there is no assurance that the credit rating agencies will not change
the standards for maintaining an investment grade credit rating again in the
future. The probability of the credit rating agencies changing the standards for
maintaining an investment grade credit rating is high if the market remains
unsettled or if additional Enron-like events occur.

The meltdown in the telecommunications and dot-com industry sectors
combined with the Enron collapse caused lenders to become more conservative with
respect to the credit exposure they were willing to take with regard to any
company, including Williams. In some extreme cases, lenders sought ways to avoid
honoring previous lending commitments or to restructure outstanding loans both
by taking legal action and by creating credit or liquidity issues for companies
by taking advantage of the heightened sensitivity of the markets to such issues.
Williams can provide no assurance that its lenders will not respond in the same
manner.

29

The equity markets have also become much more volatile and perception plays
a much more important role in short-term market fluctuations than fundamentals.
There is a pronounced downward bias in the markets. The hint of uncertainty or
negative news regarding a company results in an abrupt loss of value in that
company's stock. While markets have experienced such pressure before for limited
periods of time, there is no assurance that the current uncertainty and negative
bias will be temporary in nature.

Like its peers, business transactions in each of Williams' businesses, but
especially in Williams' Energy Marketing & Trading business, will likely require
greater credit assurances, both to be given from and received by Williams' to
satisfy credit support requirements. If Williams' credit ratings were to decline
below investment grade, its ability to participate in the Energy Marketing &
Trading business could be significantly limited. Alternate credit support would
be required under certain existing agreements and would be necessary to support
future transactions. Without an investment grade rating, Williams would be
required to fund margining requirements pursuant to industry standard derivative
agreements with cash, letters of credit or other negotiable instruments. At
December 31, 2001, the total notional amounts that would require such funding,
in the event of a credit rating decline of Williams to below investment grade,
is approximately $500 million, before consideration of offsetting positions and
margin deposits from the same counterparties. Under extreme circumstances, the
level of credit quality and assurances necessary to support the Energy Marketing
& Trading business may reach a point that makes it impractical for Williams to
continue to pursue the Energy Marketing & Trading business. In addition, the
FERC's regulatory response to the events of 2001, including the California power
crisis and Enron's bankruptcy, may make it impossible for Williams to conduct
its Energy Marketing & Trading business along side its interstate natural gas
pipelines business, which is subject to the FERC's direct jurisdiction.

A direct result of the highly-charged political environment caused by the
Enron bankruptcy and the various perceived improper activities engaged in by
Enron may be the proliferation of laws or regulations that could have a
significant impact on the future conduct of all businesses. This proliferation
of new laws and regulations may rival the laws and regulations that resulted
from the Great Depression. These new laws and regulations could be mandated at
the federal level through the legislature or federal agencies such as the
Securities and Exchange Commission or Department of Labor, or from state
legislatures and agencies. These new rules and regulations could, for example,
cause companies to reexamine its employee benefit and compensation plans. More
specifically, companies may determine that the risks of maintaining their 401(k)
savings plans outweigh the benefits of the 401(k) savings plan to their
employees. Other legislative and regulatory responses to the events of 2001
could increase the legal risk of participating on the board or acting as a
senior officer of a publicly traded company impairing companies' ability to
attract highly qualified individuals for these important positions. Under
extreme circumstances, new laws and regulations which result from the events of
2001 could result in Williams adopting a risk avoidance strategy in pursuing its
business which would impair its ability to make investments in the business that
would provide growth for its shareholders and optimal service levels for its
current and potential customers. At a minimum, Williams expects the cost of
doing business to increase and the need to operate under more conservative
financial structures as permanent outcomes of the current environment.

In addition to the collapse of Enron and the meltdown of the
telecommunications industry, the security of our country has been challenged. It
has been reported that terrorists may be targeting domestic energy facilities.
While Williams is taking appropriate steps to increase the security of its
energy assets, there is no assurance that Williams can completely secure its
assets because it is impossible to completely protect against such an attack.

While Williams believes that it has the capacity to deal constructively
with each of these possible impacts of the events of 2001, it is clear that a
dramatic new level of uncertainty has been introduced. That uncertainty makes it
impossible for Williams to predict outcomes with respect to any of these impacts
with any meaningful level of confidence.

30

In addition to the factors discussed above, the following are important
factors that could cause actual results to differ materially from any results
projected, forecasted, estimated or budgeted:

- Changes in general economic conditions in the United States and changes
in the industries in which Williams conducts business;

- Changes in federal or state laws and regulations to which Williams is
subject, including tax, environmental and employment laws and
regulations;

- The cost and effects of legal and administrative claims and proceedings
against Williams or its subsidiaries;

- Conditions of the capital markets Williams utilizes to access capital to
finance operations;

- The ability to raise capital in a cost-effective way;

- The effect of changes in accounting policies;

- The ability to manage rapid growth;

- The ability to control costs;

- The ability of each business unit to successfully implement key systems,
such as order entry systems and service delivery systems;

- Changes in foreign economies, currencies, laws and regulations, and
political climates, especially in Canada, Argentina, Brazil, Venezuela
and Lithuania, where Williams has made direct investments;

- The impact of future federal and state regulations of business
activities, including allowed rates of return, the pace of deregulation
in retail natural gas and electricity markets, and the resolution of
other regulatory matters discussed herein;

- Fluctuating energy commodity prices;

- The ability of Williams to develop expanded markets and product offerings
as well as their ability to maintain existing markets;

- The ability of Williams and its subsidiaries to obtain governmental and
regulatory approval of various expansion projects;

- The ability of customers of the energy marketing and trading business to
obtain governmental and regulatory approval of various projects,
including power generation projects;

- Future utilization of pipeline capacity, which can depend on energy
prices, competition from other pipelines and alternative fuels, the
general level of natural gas and petroleum product demand, decisions by
customers not to renew expiring natural gas transportation contracts, and
weather conditions;

- The accuracy of estimated hydrocarbon reserves and seismic data;

- The ability to successfully integrate any newly acquired businesses; and

- Global and domestic economic repercussions from terrorist activities and
the government's response thereto.

(d) FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

See Item 1(c) for a description of Williams' international activities. See
Note 22 for amounts of revenue and long-lived assets attributable to
international activities.

31

ITEM 2. PROPERTIES

See Item 1(c) for a description of the locations and general character of
the material properties of Williams and its subsidiaries.

ITEM 3. LEGAL PROCEEDINGS

For information regarding certain proceedings pending before federal
regulatory agencies, see Note 19 of Notes to Consolidated Financial Statements.
Williams is also subject to other ordinary routine litigation incidental to its
businesses.

Environmental matters. Since 1989, Texas Gas and Transco have had studies
under way to test certain of their 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 regarding such potential
contamination of certain of its sites. The costs of any such remediation will
depend upon the scope of the remediation. At December 31, 2001, these
subsidiaries had accrued liabilities totaling approximately $33 million for
these costs.

Certain Williams' subsidiaries, including Texas Gas and Transco have been
identified as potentially responsible parties (PRP) 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. Although no assurances can be
given, Williams does not believe that these obligations or the PRP status of
these subsidiaries will have a material adverse effect on its financial
position, results of operations or net cash flows.

Transco, Texas Gas and Central have identified polychlorinated biphenyl
(PCB) contamination in air compressor systems, soils and related properties at
certain compressor station sites. Transco, Texas Gas and Central have also been
involved in negotiations with the EPA and state agencies to develop screening,
sampling and cleanup programs. In addition, negotiations with certain
environmental authorities and other programs concerning investigative and
remedial actions relative to potential mercury contamination at certain gas
metering sites have been commenced by Central, Texas Gas and Transco. As of
December 31, 2001, Central had accrued a liability for approximately $9 million,
representing the current estimate of future environmental cleanup costs to be
incurred over the next six to ten years. Texas Gas and Transco likewise had
accrued liabilities for these costs, which are included in the $33 million
liability mentioned above. Actual costs incurred will depend 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 July 1999, Transco received a letter stating that the DOJ, at the
request of the EPA, intends to file a civil action against Transco arising from
its waste management practices at Transco's compressor stations and metering
stations in 11 states from Texas to New Jersey. Transco, the EPA and the DOJ
agreed to settle this matter by signing a Consent Decree that provides for a
civil penalty of $1.4 million.

Williams Energy and its subsidiaries also accrue environmental remediation
costs for its natural gas gathering and processing facilities, petroleum
products pipelines, retail petroleum and refining operations and for certain
facilities related to former propane marketing operations primarily related to
soil and groundwater contamination. In addition, Williams Energy owns a
discontinued petroleum refining facility that is being evaluated for potential
remediation efforts. At December 31, 2001, Williams Energy and its subsidiaries
had accrued liabilities totaling approximately $43 million. Williams Energy
accrues receivables related to environmental remediation costs based upon an
estimate of amounts that will be reimbursed from state funds for certain
expenses associated with underground storage tank problems and repairs. At
December 31, 2001, Williams Energy and its subsidiaries had accrued receivables
totaling $1 million.

Williams Field Services (WFS), a subsidiary of Williams Energy, received a
Notice of Violation (NOV) from the EPA in February 2000. WFS received a
contemporaneous letter from the DOJ indicating that DOJ will also be involved in
the matter. The NOV alleged violations of the Clean Air Act at a gas processing
plant. WFS, the EPA and the DOJ agreed to settle this matter for a penalty of
$850,000. In the course of
32

investigating this matter, WFS discovered a similar potential violation at the
plant and disclosed it to the EPA and the DOJ. In December 2001, the EPA, DOJ
and WFS agreed to settle this self-reported matter by signing a Consent Decree
that provides for a civil penalty of $950,000.

In connection with the 1987 sale of the assets of Agrico Chemical Company,
Williams 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, 2001, Williams had
approximately $10 million accrued for such excess costs. The actual costs
incurred will depend on the actual amount and extent of contamination
discovered, the final cleanup standards mandated by the EPA or other
governmental authorities, and other factors.

On July 2, 2001, the EPA issued an information request asking for
information on oil releases and discharges in any amount from Williams'
pipelines, pipeline systems and pipeline facilities used in the movement of oil
or petroleum products, during the period July 1, 1998, through July 2, 2001. In
November 2001, Williams furnished its response.

Other legal matters. In connection with agreements to resolve take-or-pay
and other contract claims and to amend gas purchase contracts, Transco and Texas
Gas each 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. As a result of such
settlements, Transco is currently defending three lawsuits brought by producers.
In one of the cases, a jury verdict found that Transco was required to pay a
producer damages of $23.3 million including $3.8 million in attorneys' fees. In
addition, through December 31, 2001, post judgment interest was approximately
$10.5 million. Transco's appeals have been denied by the Texas Court of Appeals
for the First District of Texas, and on April 2, 2001, the company filed an
appeal to the Texas Supreme Court. On February 21, 2002, the Texas Supreme Court
denied Transco's petition for review. As a result, Transco recorded a pre-tax
charge to income for the year ended December 31, 2001, in the amount of $37
million representing management's estimate of the effect of this ruling. Transco
plans to request rehearing of the court's decision. In the other cases,
producers have asserted damages, including interest calculated through December
31, 2001, of approximately $16.3 million. Producers have received and may
receive other demands, which could result in additional claims. Indemnification
for royalties will depend on, among other things, the specific lease provisions
between the producer and the lessor and the terms of the settlement between the
producer and either Transco or Texas Gas. Texas Gas may file to recover 75
percent of any such additional amounts it may be required to pay pursuant to
indemnities for royalties under the provisions of Order 528.

On June 8, 2001, 14 Williams entities were named as defendants in a
nationwide class action lawsuit which has been pending against other defendants,
generally pipeline and gathering companies, for more than one year. The
plaintiffs allege that the defendants, including the Williams defendants, have
engaged in mismeasurement techniques that distort the heating content of natural
gas, resulting in an alleged underpayment of royalties to the class of producer
plaintiffs. In September 2001, the plaintiffs voluntarily dismissed two of the
14 Williams entities named as defendants. In November 2001, Williams, along with
other Coordinating Defendants, filed a motion to dismiss under Rules 9b and 12b
of the Kansas Rules of Civil Procedure. In January 2002, most of the Williams
defendants, along with a group of Coordinating Defendants, filed a motion to
dismiss for lack of personal jurisdiction. The court has not yet ruled on these
motions. In the next several months, the Williams entities will join with other
defendants in contesting certification of the plaintiff class.

In 1998, the DOJ informed Williams that Jack Grynberg, an individual, had
filed claims in the United States District Court for the District of Colorado
under the False Claims Act against Williams and certain of its wholly owned
subsidiaries including Central, Kern River, Northwest Pipeline, WGP, Transco,
Texas Gas, WFS and Williams Production Company. Mr. Grynberg has also filed
claims against approximately 300 other energy companies and alleges that the
defendants violated the False Claims Act in connection with the measurement and
purchase of hydrocarbons. The relief sought is an unspecified amount of
royalties allegedly not paid to the federal government, treble damages, a civil
penalty, attorneys' fees, and costs. 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 against the Williams entities in the United States District Court
for the District of Colorado. On

33

October 21, 1999, the Panel on Multi-District Litigation transferred all of the
Grynberg qui tam cases, including those filed against Williams, to the United
States District Court for the District of Wyoming for pre-trial purposes.
Motions to dismiss the complaints, filed by various defendants, including
Williams, were denied on May 18, 2001.

Between November 2000 and May 2001, class actions were filed on behalf of
San Diego ratepayers against California power generators and traders including
Williams Energy Marketing & Trading Company, a subsidiary of Williams. These
lawsuits concern the increase in power prices in California during the summer of
2000 through the winter of 2000-01. The suits claim that the defendants acted to
manipulate prices in violation of the California antitrust and business practice
statutes and other state and federal laws. Plaintiffs are seeking injunctive
relief as well as restitution, disgorgement, appointment of a receiver, and
damages, including treble damages. These cases have been consolidated before the
San Diego County Superior Court. Numerous other state and federal investigations
regarding California power prices are also underway that involve Williams Energy
Marketing & Trading Company.

Since January 29, 2002, Williams is aware of numerous shareholder class
action suits that have been filed in the United States District Court for the
Northern District of Oklahoma. The majority of the suits allege that Williams
and co-defendants, 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. This case was filed against
Williams, certain corporate officers, all members of the Williams board of
directors and all of the offerings' underwriters. Williams does not anticipate
any immediate action by the Court in these actions. In addition, class action
complaints have been filed against Williams and the members of its board of
directors under the Employee Retirement Income Security Act by participants in
Williams' 401(k) plan based on similar allegations.

Summary

While no assurances may be given, Williams, based on advice of counsel,
does not believe 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 have a materially
adverse effect upon Williams' future financial position, results of operations
or cash flow requirements.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not applicable.

34

EXECUTIVE OFFICERS OF WILLIAMS

The names, ages, positions and earliest election dates of the executive
officers of Williams are:

Except for Mr. Johnson, all of the above officers have been employed by
Williams or its subsidiaries as officers or otherwise for more than five years
and have had no other employment during the period. Prior to joining Williams,
Mr. Johnson held various officer positions with Amoco Corporation for more than
five years.

Mr. Keith E. Bailey resigned as Chief Executive Officer of Williams on
January 20, 2002, but continues to serve as the Chairman of the Board.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Williams' common stock is listed on the New York and Pacific Stock
exchanges under the symbol "WMB." At the close of business on December 31, 2001,
Williams had approximately 15,017 holders of record of its Common Stock. The
high and low closing sales price ranges (composite transactions) and dividends
declared by quarter for each of the past two years are as follows:

Terms of certain subsidiaries' borrowing arrangements limit transfer of
funds to Williams. These terms have not impeded, nor are they expected to
impede, Williams' ability to meet its cash flow needs.

35

ITEM 6. SELECTED FINANCIAL DATA

The following financial data as of December 31, 2001 and 2000 and for the
three years ended December 31, 2001 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 the Company's financial records.
Certain amounts below have been restated or reclassified (see Note 1).
Information concerning significant trends in the financial condition and results
of operations is contained in Management's Discussion & Analysis of Financial
Condition and Results of Operations on pages 37 through 69 of this report.

- ---------------

(1) See Note 1 for discussion of change in management of certain operations,
previously conducted by Energy Marketing & Trading, that were transferred to
Petroleum Services. The sales activity which was transferred was previously
reported on a "net" basis and is now reported on a "gross" basis. Also in
1998, there was a change in the reporting of certain marketing activities
from a "gross" basis to a "net" basis consistent with fair value accounting.

(2) See Note 4 for discussion of write-downs of certain Williams Communications
Group, Inc. (WCG) related assets in 2001 and see Note 5 for discussion of
asset sales, impairments and other accruals in 2001, 2000 and 1999. Income
from continuing operations in 1997 includes a $66 million pre-tax gain on
the sale of Williams' interest in the natural gas liquids and condensate
reserves in the West Panhandle field in Texas.

(3) See Note 3 for the discussion of the 2001, 2000 and 1999 losses from
discontinued operations. The loss from discontinued operations for 1998 and
1997 relates to the operations of WCG and the sale of the MAPCO coal
business.

(4) See Note 7 for discussion of the 1999 extraordinary gain. The extraordinary
loss for 1998 and 1997 relates to redemption of higher interest rate debt.

(5) See Note 2 for discussion of the 2001 issuance of common stock for the
Barrett acquisition, Note 3 for discussion of the WCG spinoff and Note 16
for discussion of Williams' January 2001 common stock issuance. See Note 3
for discussion of the 1999 issuance of subsidiary's common stock.

36

ITEM 7. MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

RECENT EVENTS

Since the fourth quarter 2001 events surrounding the Enron bankruptcy
filing, Williams has been engaged in various discussions with investors,
analysts, rating agencies and financial institutions regarding the liquidity
implications of such to the business strategy of Williams' energy trading
activities. More recently, Williams has also been evaluating its contingent
obligations regarding guarantees and payment obligations with respect to certain
financial obligations of Williams Communications Group, Inc. (WCG) because of
uncertainty regarding its ability to perform. In addition, WCG has also
announced that it is considering reorganizing under Chapter 11 bankruptcy laws.
Both of these situations have resulted in rating agencies issuing statements in
February 2002 confirming investment grade ratings, but with certain negative
implications. Williams has announced that it is committed to strengthen its
balance sheet and retain investment grade ratings and has taken significant
steps since the first of the year to ensure that this occurs. Williams has a
substantial and diverse asset base that provides strong support for its credit.

Following is a summary of the steps that are in progress which Williams
believes will strengthen its balance sheet and ensure retention of its
investment grade ratings.

- A $1 billion reduction in planned capital expenditures

- Generate proceeds from sales of assets during 2002

- Initiation of action to eliminate ratings triggers on certain obligations
and contingencies that do not appear as debt on the Consolidated Balance
Sheet, including the guarantees and payment obligations for WCG's debt

- A $50 million reduction from the company's cost structure pursuant to
right-sizing the organization as an energy-only business

Each of these are discussed in more detail within the Liquidity and Other
sections that follow.

GENERAL

On March 30, 2001, the board of directors of Williams approved a tax-free
spinoff of Williams' communications business, WCG, to Williams' shareholders. On
April 23, 2001, Williams distributed 398.5 million shares, or approximately 95
percent of the WCG common stock held by Williams, to holders of record of
Williams common stock. As a result, the consolidated financial statements
reflect WCG as discontinued operations.

In December 2001 and January 2002, the Securities and Exchange Commission
(SEC) issued statements regarding disclosures by companies within their
Management's Discussion & Analysis of Financial Condition and Results of
Operations for 2001. In those statements, the SEC cited certain items that
companies should consider including in the 2001 Form 10-Ks, including
identification of critical accounting policies and expanded disclosure of
certain liquidity matters, certain energy trading activities and transactions
similar to related party activities. The following discussions include items
that the SEC has encouraged companies to disclose.

Unless otherwise indicated, the following discussion and analysis of
results of operations, financial condition and liquidity relates to the
continuing operations of Williams and should be read in conjunction with the
consolidated financial statements and notes thereto included in Item 8.

CRITICAL ACCOUNTING POLICIES & ESTIMATES

Our financial statements reflect the selection and application of
accounting policies which require management to make significant estimates and
assumptions. We believe that the following are some of the more critical
judgment areas in the application of our accounting policies that currently
affect our financial condition and results of operations.

37

Revenue Recognition -- Gas Pipeline

Most of Gas Pipeline's businesses are regulated by the Federal Energy
Regulatory Commission (FERC). The FERC regulatory processes and procedures
govern the tariff rates that the Gas Pipeline subsidiaries are permitted to
charge customers for natural gas sales and services, including the interstate
transportation and storage of natural gas. Accordingly, certain revenues are
collected by Gas Pipeline which may be subject to refunds upon final orders in
pending rate cases with the FERC. In recording estimates of refund obligations,
Gas Pipeline takes into consideration Gas Pipeline's and other third-parties
regulatory proceedings, advice of counsel and estimated total exposure, as
discounted and risk weighted, as well as collection and other risks. At December
31, 2001, approximately $96 million was recorded as subject to refund,
reflecting management's estimate of amounts invoiced to customers that may
ultimately require refunding. Currently, certain of the Gas Pipeline
subsidiaries are involved in rate case proceedings. Depending on the results of
these proceedings, the actual amounts allowed to be collected from customers
could differ from management's estimate.

Revenue Recognition -- Energy Marketing & Trading

Energy Marketing & Trading has energy risk management and trading
operations that enter into energy contracts to provide price-risk management
services to its customers. Energy and energy-related contracts utilized in
energy risk management trading activities are recorded at fair value with the
net change in fair value of those contracts representing unrealized gains and
losses recognized in income currently. The fair value of energy and
energy-related contracts is determined based on the nature of the transaction
and the market in which transactions are executed. Certain contracts are
executed in markets exchange traded or over-the-counter where quoted prices in
active markets exist. Transactions are also executed in exchange-traded or
over-the-counter markets for which market prices may exist however, the market
may be inactive and price transparency is limited. Transactions are also
executed for which quoted market prices are not available. Determining fair
value for certain contracts involves complex assumptions and judgments when
estimating prices at which market participants would transact if a market
existed for the contract or transaction.

Certain energy-related contracts such as transportation, storage, load
servicing and tolling arrangements require Energy Marketing & Trading to assess
whether these contracts are executory service arrangements or leases pursuant to
Statement of Financial Accounting Standards (SFAS) No. 13, "Accounting for
Leases." Energy-related contracts that are determined to be executory contracts
are accounted for at fair value. Currently, Williams does not account for any of
the energy-related contracts as leases. There currently is not extensive
authoritative guidance for determining when an arrangement is a lease or an
executory service arrangement. As a result, Williams assesses each of its
energy-related contracts and makes the determination based on the substance of
each contract focusing on factors such as physical and operational control of
the related asset, risks and rewards of owning, operating and maintaining the
related asset and other contractual terms. The issue of whether contracts such
as these energy-related contracts are an executory contract or a lease is
currently being discussed by the Financial Accounting Standards Board's Emerging
Issues Task Force. The discussions surrounding this issue are in the early
stages of development and any consensus reached on these issues could ultimately
impact Williams' accounting for these contracts.

Additional discussion of the accounting for energy and energy-related
contracts at fair value is included in Note 1 of the Notes to Consolidated
Financial Statements and pages 53 through 59 of Management's Discussion &
Analysis of Financial Condition and Results of Operations.

Valuation of Deferred Tax Assets

Williams is required to assess the ultimate realization of deferred tax
assets generated from the basis difference in certain investments and
businesses. This assessment takes into consideration tax planning strategies,
including assumptions regarding the availability and character of future taxable
income. At December 31, 2001, Williams maintains $173.3 million of valuation
allowances for deferred tax assets from basis differences in investments for
which the ultimate realization of the tax asset may be dependent on the
availability of future capital gains. The ultimate amount of deferred tax assets
realized could be materially

38

different from those recorded, as influenced by potential changes in federal
income laws and the circumstances upon the actual realization of related tax
assets.

Impairment of Long-Lived Assets

Williams evaluates the long-lived assets, including other intangibles and
related goodwill, of identifiable business activities for impairment when events
or changes in circumstances indicate, in management's judgment, that the
carrying value of such assets may not be recoverable. In addition to those
long-lived assets for which impairment charges were recorded (see Note 5),
others were reviewed for which no impairment was required under a "held for use"
computation. These computations utilized judgments and assumptions inherent in
management's estimate of undiscounted future cash flows to determine
recoverability of an asset. It is possible that a computation under a "held for
sale" situation for certain of these long-lived assets could result in a
significantly different assessment because of market conditions, specific
transaction terms and a buyer's different viewpoint of future cash flows.

Contingent Liabilities

Williams establishes reserves for estimated loss contingencies when it is
management's assessment 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 different facts or information become known or
circumstances change that affect the previous assumptions with respect to the
likelihood or amount of loss. Reserves for contingent liabilities are based upon
management's assumptions and estimates, advice of legal counsel or other third
parties regarding the probable outcomes of the matter. Should the outcome differ
from the assumptions and estimates, revisions to the estimated reserves for
contingent liabilities would be required.

RESULTS OF OPERATIONS

CONSOLIDATED OVERVIEW

The following table and discussion is a summary of Williams' consolidated
results of operations. The results of operations by segment are discussed in
further detail beginning on page 42.

39

2001 vs. 2000

Consolidated Overview. Williams' revenues increased $1.4 billion, or 15
percent, due primarily to higher gas and electric power trading and services
margins, a full year of Canadian operations within Midstream Gas & Liquids
acquired in fourth-quarter 2000, higher petroleum products revenues, higher
natural gas sales prices and revenues from Barrett Resources Corporation
(Barrett) acquired in third-quarter 2001. In addition, the revenue increase
includes the $582 million effect of reporting certain revenues net of the
related costs in 2000 related to sales activity surrounding certain terminals.
The revenues related to the sales activity around certain terminals are reported
"gross" subsequent to the transfer of management over the sales activity from
Energy Marketing & Trading to Petroleum Services effective February 2001 (see
Note 1 of the Notes to Consolidated Financial Statements). Partially offsetting
these increases was a decrease of $283 million in revenues related to the 198
convenience stores sold in May 2001, $116 million decrease in domestic natural
gas liquids revenues and the effect in 2000 of a $74 million reduction of Gas
Pipeline's rate refund liabilities.

Segment costs and expenses increased $1.2 billion, or 16 percent, due
primarily to higher petroleum product costs, costs for a full year of Canadian
operations acquired in fourth-quarter 2000, operating costs associated with
Barrett acquired in third-quarter 2001 and the impact of reporting certain sales
activity costs net with related revenues in 2000 (discussed above).
Additionally, the increase reflects a $170 million impairment charge related to
the Colorado soda ash mining facility within International. These increases were
partially offset by a $286 million decrease in costs as a result of the sale of
198 convenience stores in May 2001 and the $75.3 million gain on the sale of
these convenience stores.

Operating income increased $244.0 million, or 11 percent, due primarily to
higher gas and electric power service margins, the $75.3 million pre-tax gain on
the sale of the convenience stores in May 2001, higher margins at refining and
marketing operations, increased realized natural gas sales prices, the impact of
Barrett and the effect in 2000 of $63.8 million in guarantee loss accruals and
impairment charges at Energy Marketing & Trading. Partially offsetting these
increases were lower per-unit natural gas liquids margins at Midstream Gas &
Liquids, the $170 million impairment charge within International, the $74
million effect in 2000 of reduction to rate refund liabilities and approximately
$41 million of impairment charges and loss accruals within Energy Services.
Included in operating income are general corporate expenses which increased
$27.1 million, or 28 percent, due primarily to an increase in advertising costs
(which includes a branding campaign of $12 million) and higher charitable
contributions.

Interest accrued -- net increased $87.7 million, or 13 percent, due
primarily to the $72 million effect of higher borrowing levels offset by the $48
million effect of lower average interest rates, $19 million in interest expense
related to an unfavorable court decision involving Transcontinental Gas Pipe
Line (Transco), a $14 million increase in interest expense related to deposits
received from customers relating to energy risk management and trading and
hedging activities, a $14 million increase in amortization of debt expense and a
$4 million increase in interest expense on rate refund liabilities. The increase
in long-term debt includes the $1.1 billion of senior unsecured debt securities
issued in January 2001 and $1.5 billion of long-term debt securities issued in
August 2001 related to the cash portion of the Barrett acquisition.

Investing income decreased $304.5 million, due primarily to fourth-quarter
2001 charges for a $103 million provision for doubtful accounts related to the
minimum lease payments receivable from WCG, an $85 million provision for
doubtful accounts related to a $106 million deferred payment for services
provided to WCG and a $25 million write-down of the remaining investment basis
in WCG common stock (see Note 3). In addition, the decrease also reflects a
$94.2 million charge in third-quarter 2001, representing declines in the value
of certain investments, including $70.9 million related to Williams' investment
in WCG and $23.3 million related to losses from other investments, which were
deemed to be other than temporary (see Note 4). In addition, the decrease in
investing income reflects a $13 million decrease in dividend income due to the
sale of the Ferrellgas Partners L.P. (Ferrellgas) senior common units in
second-quarter 2001. The decreases to investing income (loss) were slightly
offset by increased interest income of $17 million related to margin deposits.
Preferred returns and minority interest in income of consolidated subsidiaries
increased $9.5 million, or 16 percent, due primarily to preferred returns of
Snow Goose LLC, formed in December 2000, and minority interest in income of
Williams Energy Partners L.P., partially offset by a $10 million decrease of

40

preferred returns related to the second-quarter 2001 redemption of Williams
obligated mandatorily redeemable preferred securities of Trust.

Other income (expense) -- net increased $28 million due primarily to a $12
million increase in capitalization of interest on internally generated funds
related to various capital projects at certain FERC regulated entities and $6
million lower losses from the sales of receivables to special purpose entities
(see Note 18).

The provision for income taxes is comparable for both years. The effective
income tax rate for 2001 is greater than the federal statutory rate due
primarily to valuation allowances associated with the investing losses, for
which no tax benefits were provided plus the effects of state income taxes. The
effective income tax rate for 2000 is greater than the federal statutory rate
due primarily to the effects of state income taxes.

Loss from discontinued operations for 2001 includes a $1.17 billion
after-tax charge related to accruals for contingent obligations related to
guarantees and payment obligations related to WCG and a $147.5 million after-tax
loss from operations of WCG (see Note 3). The $441.1 million loss from
discontinued operations for 2000 represents the after-tax losses from the
operations of WCG.

2000 vs. 1999

Consolidated Overview. Williams' revenues increased $3 billion, or 45
percent, due primarily to higher revenues from natural gas and electric power
services, increased petroleum products and natural gas liquids average sales
prices and sales volumes and the contribution from Canadian operations within
Midstream Gas & Liquids acquired in fourth-quarter 2000. Partially offsetting
these increases were lower fleet management, retail natural gas, electric and
propane revenues following the 1999 sales of these businesses.

Segment costs and expenses increased $1.9 billion, or 35 percent, due
primarily to higher costs related to increased petroleum products and natural
gas liquids average purchase prices and volumes purchased and costs related to
the Canadian operations acquired in fourth-quarter 2000. Also contributing to
the increases were higher variable compensation levels associated with improved
performance and higher impairment charges and guarantee loss accruals at Energy
Marketing & Trading. Partially offsetting these increases were lower fleet
management, retail natural gas, electric and propane costs following the sales
of these businesses in 1999.

Operating income increased $1.0 billion, or 89 percent, primarily
reflecting improved natural gas and electric power services margins and higher
per-unit natural gas liquids margins at Midstream Gas & Liquids, increased
transportation demand revenues and the net effect of reductions to rate refund
liabilities in 2000 over 1999, partially offset by higher variable compensation
levels and the higher impairment charges and guarantee loss accruals in 2000.
Included in operating income are general corporate expenses, which increased
$20.3 million, or 26 percent, and include $15.2 million and $9.0 million in 2000
and 1999, respectively, of general corporate costs that would have otherwise
been allocated to discontinued operations.

Interest accrued -- net increased $103.4 million, or 19 percent, due
primarily to the $71 million effect of higher borrowing levels combined with the
$49 million effect of higher average interest rates. These increases reflect the
higher levels of short-term borrowing towards the end of 2000. Investing income
(loss) increased $81 million due primarily to $33 million higher interest
income, $28 million from higher net earnings from equity investments and $18
million higher dividend income associated primarily with the Ferrellgas senior
common units.

Preferred returns and minority interest in income of consolidated
subsidiaries increased $19.8 million. The change is due primarily to the
preferred returns related to Williams obligated mandatorily redeemable preferred
securities of Trust issued in December 1999.

The provision for income taxes increased $399.1 million primarily due to
higher pre-tax income. The effective income tax rate in 2000 and 1999 exceeds
the federal statutory rate due primarily to the effects of state income taxes.

41

Loss from discontinued operations includes the results of WCG in 2000 and
1999. WCG's losses in 2000 include a $323.9 million estimated pre-tax loss on
disposal of a WCG segment that installs and maintains communications equipment
and network services. In January 2001, WCG approved a plan for the disposal of
its Solutions segment. Excluding the loss on disposal, WCG's pre-tax loss
decreased $19.6 million as compared to 1999. Revenues increased over 1999 due
primarily to growth in voice and data services partially offset by lower dark
fiber revenue. WCG's expenses increased due primarily to the growth of network
operations and infrastructure. WCG had increased operating losses as a result of
providing customer services prior to completion of the new network, higher
depreciation and network lease expense as the network is brought into service
and higher selling, general and administrative expenses including costs
associated with infrastructure growth and improvement. WCG also had higher
interest expense as a result of increased debt levels in support of continued
expansion and new projects. WCG's increased operating losses were substantially
offset by higher investing income including a $214.7 million gain from the
conversion of WCG's common stock investment in Concentric Network Corporation
for common stock of XO Communications, Inc. (formerly Nextlink Communications,
Inc.) pursuant to a merger of those companies in June 2000, net gains totaling
$93.7 million from the sale of certain marketable equity securities, a $16.5
million gain on the sale of a portion of the investment in ATL-Algar Telecom
Leste S.A. (ATL) and higher interest income. These were partially offset by
$34.5 million of losses related to write-downs of certain cost basis and equity
investments.

The $65.2 million 1999 extraordinary gain results from the sale of
Williams' retail propane business (see Note 7).

Williams is organized into three industry groups: Energy Marketing &
Trading, Gas Pipeline and Energy Services (includes Exploration & Production,
International, Midstream Gas & Liquids, Petroleum Services, and Williams Energy
Partners). Williams evaluates performance based upon segment profit (loss) from
operations (see Note 22). The following discussions relate to the results of
operations of Williams' segments.

ENERGY MARKETING & TRADING

2001 vs. 2000

Energy Marketing & Trading's revenues increased by $299.2 million or 19
percent in 2001, due to a $411 million increase in risk management and trading
revenues, partially offset by a $112 million decrease in non-trading revenues.

The $411 million increase in risk management and trading revenues results
primarily from an increase in risk management activities surrounding Energy
Marketing & Trading's power tolling portfolio. As further discussed in Note 18
of the Notes to Consolidated Financial Statements, power tolling agreements
provide Energy Marketing & Trading the right, but not the obligation, to call on
the counterparty to convert natural gas to electricity at a predefined heat
conversion rate. Energy Marketing & Trading benefited from higher natural gas
and electric power services margins through the first quarter of 2001 from power
tolling agreements previously recognized in 2000. Energy Marketing & Trading,
through its origination of new contracts, executed several offsetting positions
throughout the year to mitigate declines in these margins that occurred
subsequent to the first quarter 2001. These new contracts consisted of full
requirements, load serving and power supply agreements and typically have terms
of up to 15 years (see Note 18). Execution of these contracts has the effect of
reducing the risk of future changes in natural gas and power prices within the
portfolio and also provides further insight into the prices for which third
parties are willing to exchange in illiquid periods. This additional insight
provides better information for the valuation of other existing contracts which
generally has the effect of increasing the value recognized on these existing
contracts. Subsequent to the

42

execution of these origination transactions, natural gas and power prices
declined dramatically. As a result of Energy Marketing & Trading's management
strategies, this reduction had minimal impact to the overall portfolio fair
value. Also contributing to the increase in the risk management and trading
revenues during 2001 is an increase in successful forward natural gas financial
trading.

Through a variety of energy commodity and derivative contracts, Energy
Marketing & Trading has credit exposure to Enron and certain of its subsidiaries
which have sought protection from creditors under Chapter 11 of the U.S.
Bankruptcy Code. During fourth-quarter 2001, Energy Marketing & Trading recorded
a reduction in trading revenues of approximately $130 million through the
valuation of contracts with Enron. Approximately $91 million of this reduction
in value was recorded pursuant to events immediately proceeding and following
Enron's announced bankruptcy. At December 31, 2001, Williams has reduced its
exposure to accounts receivable from Enron, net of margin deposits, to expected
recoverable amounts.

Additional discussion of the accounting for energy risk management and
trading activities at fair value is included in Note 1 of the Notes to
Consolidated Financial Statements and pages 53 through 59 of Management's
Discussion & Analysis of Financial Condition and Results of Operations.

The $112 million decrease in non-trading revenues is due primarily to
declining prices on ethane and lower ethylene volumes and prices related to
marketing of products of a petrochemical plant acquired by Williams in early
1999. These decreases were partially offset by a $4 million increase in
non-trading power services revenues.

Costs and operating expenses decreased by $95 million, or 32 percent, due
primarily to lower ethane, propane, and olefin prices in 2001, partially offset
by higher cost of sales and operating expenses relating to the non-trading power
services activities. These variances are associated with the corresponding
changes in non-trading revenues discussed above.

Other (income) expense -- net in 2000 includes $47.5 million in guarantee
loss accruals and impairment charges (see Note 5), a $16.3 million impairment of
assets related to a distributed power generation business, and a $12.4 million
gain on the sale of certain natural gas liquids contracts. Included in 2001, is
a $13.3 million impairment of assets related to a terminated expansion project.

Segment profit increased $263.6 million due primarily to the $411 million
higher trading revenues discussed above and the effect of the $63.8 million of
guarantee loss accruals and impairment charges in 2000. Partially offsetting
these increases were $141 million higher selling, general and administrative
costs, $27 million lower margins from non-trading natural gas liquids
operations, a $23.3 million loss from the write-downs of marketable equity
securities and a cost-based investment (see Note 4), the $13.3 million
impairment of assets related to a terminated expansion project, and the $12.4
million effect of the 2000 gain on sale of certain natural gas liquids
contracts. The higher selling, general and administrative costs primarily
reflect $40 million of higher variable compensation levels associated with
improved operating performance, increased outside service costs, increased costs
as a result of additional staff, as well as $13 million of increased charitable
contributions to state universities, and $19 million of costs related to a
European trading and marketing office in London which began operations in 2001.

2000 vs. 1999

Energy Marketing & Trading's revenues increased $910.3 million, or 137
percent, due to a $1,071 million increase in trading revenues partially offset
by a $161 million decrease in non-trading revenues. The $1,071 million increase
in trading revenues is due primarily to higher natural gas and electric power
services margins. The higher gas and electric power services margins reflect the
benefit of price volatility and increased demand for ancillary services,
primarily in the western region of the United States, expanded price risk
management services including higher structured transactions margins, increased
overall market demand and increased trading volumes. The increased trading
volumes and price risk management services reflect the expansion of the power
trading portfolio to include an additional 2,350 megawatts from contracts giving
Energy Marketing & Trading the right to market combined capacity from three
power generating plants which were signed in late 1999 and early 2000. At
December 31, 2000, Energy Marketing & Trading had rights to

43

market 7,000 megawatts of electric generation capacity for periods ranging from
15 to 20 years. Of the 7,000 megawatts, approximately 4,000 megawatts are from
facilities in California.

The $161 million decrease in non-trading revenues is due primarily to $226
million lower revenues following the sale of retail natural gas, electric and
propane businesses in 1999, partially offset by $19 million higher revenues from
a distributed power generation business that was transferred from Petroleum
Services during 2000 and $33 million higher natural gas liquids revenues
resulting from higher average sales prices and volumes attributable to marketing
the products of a petrochemical plant that was acquired by Williams in early
1999.

Costs and operating expenses decreased $129 million, or 30 percent, due
primarily to lower natural gas, electric and propane cost of sales and operating
expenses of $112 million and $91 million, respectively, partially offset by $20
million higher cost of sales and operating expenses relating to the distributed
power generation business and $25 million higher natural gas liquids cost of
sales attributable to the petrochemical plant. These variances are associated
with the corresponding changes in non-trading revenues discussed above.

Other (income) expense -- net changed unfavorably from income of $23
million in 1999 to expense of $48 million in 2000. The expense for 2000 includes
$47.5 million of guarantee loss and impairment accruals (see Note 5) and a $16.3
million impairment of assets to fair value based on expected net proceeds
related to management's decision and commitment to sell its distributed power
generation business. Partially offsetting these 2000 charges was a $12.4 million
gain on the sale of certain natural gas liquids contracts. Other (income)
expense -- net in 1999 includes a $22.3 million gain on the sale of retail
natural gas and electric operations.

Segment profit increased $903.9 million, from $104 million in 1999 to
$1,007.9 million in 2000, due primarily to $1,073 million higher trading margins
primarily related to natural gas and electric power services. Partially
offsetting the higher margins were $66 million higher selling, general and
administrative costs, the $47.5 million guarantee loss and impairment accruals,
the $16.3 million impairment of the distributed power generation business, the
$22.3 million gain in 1999 on sale of retail natural gas and electric operations
and a $23 million lower contribution from retail natural gas, electric and
propane following the sale of those businesses in 1999. The higher selling,
general and administrative costs primarily reflect higher variable compensation
levels associated with improved operating performance, partially offset by $40
million of selling, general and administrative costs related to the retail
natural gas, electric and propane businesses sold in 1999.

Potential Impact of California Power Regulation and Litigation

At December 31, 2001, Energy Marketing & Trading had net accounts
receivable recorded of approximately $388 million for power sales to the
California Independent System Operator and the California Power Exchange
Corporation (CPEC). While the amount recorded reflects management's best
estimate of collectibility, future events or circumstances could change those
estimates. In March and April of 2001, two California power-related entities,
the CPEC and Pacific Gas and Electric Company (PG&E), filed for bankruptcy under
Chapter 11. On September 20, 2001, PG&E filed a reorganization plan as part of
its Chapter 11 bankruptcy proceeding that seeks to pay all of its creditors in
full. California utility regulators agreed on October 2, 2001, to a settlement
in which a Edison International unit, Southern California Edison, will repay its
back debt out of existing rates by 2005. The agreement settles a federal-court
lawsuit in which the utility sought to force the California Public Utilities
Commission to raise rates and allows the utility to recover an estimated $3
billion in back debt. Both the reorganization plan and the settlement agreement
are subject to current challenges, further legal proceedings and regulatory
approvals. Williams does not believe its credit exposure to these utilities will
result in a materially adverse effect on its results of operations or financial
condition.

As discussed in Rate and Regulatory Matters and Related Litigation in Note
19 of the Notes to Consolidated Financial Statements, the FERC and the DOJ have
issued orders or initiated actions which involve Williams Energy Marketing &
Trading related to California and the western states electric power industry. In
addition to these federal agency actions, a number of federal and state
initiatives addressing the issues of the California electric power industry are
also ongoing and may result in restructuring of various
44

markets in California and elsewhere. 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 the wholesale price
increases resulted from the exercise of market power and collusion of the power
generators and sellers, such as Williams. These allegations have resulted in
multiple state and federal investigations as well as the filing of class-action
lawsuits in which Williams is a named defendant (see Other Legal Matters in Note
19). Most of these initiatives, investigations and proceedings are in their
preliminary stages and their likely outcome cannot be estimated. There can be no
assurance that these initiatives, investigations and proceedings will not have
an adverse effect on Williams' results of operations or financial condition.

GAS PIPELINE

2001 vs. 2000

Gas Pipeline's revenues decreased $130.4 million, or 7 percent, due
primarily to the effect of a $74 million reduction of rate refund liabilities in
2000 following the settlement of prior rate proceedings, $72 million lower gas
exchange imbalance settlements (offset in costs and operating expenses), $15
million lower recovery of tracked costs which are passed through to customers
(offset in general and administrative expenses), and $10 million lower
transportation revenues at Texas Gas due primarily to turnback capacity
remarketed at discounted rates and for shorter contracted terms. Partially
offsetting these decreases were $25 million higher gas transportation demand
revenues as a result of new expansion projects and new rates on the Transco
system and the California Action Project on the Kern River system and $9 million
higher revenues from a liquefied natural gas storage facility acquired in June
2000.

Costs and operating expenses decreased $66 million, or 7 percent, due
primarily to the $72 million lower gas exchange imbalance settlements (offset in
revenues), $15 million resulting from the FERC's approval for recovery of fuel
costs incurred in prior periods by Transco, and $6 million of accruals for gas
exchange imbalances in 2000. Partially offsetting these decreases was $36
million in higher depreciation expense due to increased property, plant &
equipment placed into service during 2001, which includes $16 million
attributable to the California Action Project.

General and administrative costs decreased $22 million resulting primarily
from lower tracked costs which are passed through to customers (offset in
revenues) and costs in 2000 related to the headquarters consolidation of two of
the gas pipelines, partially offset by higher charitable contributions.

Other (income) expense -- net for the year ended December 31, 2001, within
segment costs and expenses includes a $27.5 million pre-tax gain from the sale
of Williams' limited partnership interest in Northern Border Partners L.P. and a
$3 million insurance settlement in 2001 for storage gas losses. Also included is
an $18 million charge resulting from an unfavorable court decision in one of
Transco's royalty claims proceedings (an additional $19 million is included in
interest expense).

Segment profit decreased $21.4 million due primarily to the lower revenues
discussed previously, partially offset by the lower costs and operating
expenses, the items discussed previously in other (income) expense -- net, a $19
million increase in equity investment earnings from pipeline joint venture
projects and the lower general and administrative expenses. The increase in
equity investment earnings reflects $13 million from new projects which are
primarily comprised of interest capitalized on internally generated funds as
allowed by the FERC and a $6 million increase from earnings on existing
projects.

45

2000 vs. 1999

Gas Pipeline's revenues increased $56.6 million, or 3 percent, due
primarily to $74 million of rate refund liability reductions associated mainly
with a favorable FERC order received in March 2000 by Transco related to the
rate-of-return and capital structure issues in a regulatory proceeding. Revenues
also increased due to $68 million higher gas exchange imbalance settlements
(offset in costs and operating expenses), $23 million higher transportation
demand revenues at Transco and $14 million higher storage revenues. Partially
offsetting these increases were $66 million of reductions to rate refund
liabilities in 1999 by four of the gas pipelines resulting primarily from second
and fourth-quarter 1999 regulatory proceedings and $57 million lower
reimbursable costs passed through to customers (offset in costs and operating
expenses).

Segment profit increased $44.2 million, or 6 percent, due to $23 million
higher transportation demand revenues at Transco, $18 million higher equity
investment earnings from pipeline joint venture projects, the $8 million net
effect of rate refund liability reductions discussed above and $3 million lower
general and administrative expenses. The lower general and administrative costs
reflect lower professional services costs associated with year 2000 compliance
work, efficiencies realized from the headquarters consolidation of two of the
pipelines and other cost reduction initiatives and the effect of a $2.3 million
accrual in 1999 for damages associated with two pipeline ruptures in the
northwest, partially offset by expenses related to the headquarters
consolidation and higher charitable contributions in 2000. Partially offsetting
the segment profit increases were $10 million higher depreciation expense
primarily due to increased property, plant and equipment, and $6 million of
accruals for gas exchange imbalances.

ENERGY SERVICES

EXPLORATION & PRODUCTION

2001 vs. 2000

Exploration & Production's revenues increased $285.4 million, or 97
percent, due primarily to $263 million higher production revenues including $119
million from increased net realized prices for production (including the effect
of hedge positions) and $144 million associated with an increase in net volumes
from production. Approximately $115 million of the $144 million increase relates
to volumes associated with Barrett, which became a consolidated entity on August
2, 2001. Approximately 75 percent of production in 2001 was hedged. Exploration
& Production has entered into contracts that hedge approximately 79 percent of
projected 2002 natural gas production. These hedges are entered into with Energy
Marketing & Trading which in turn, enters into offsetting derivative contracts
with unrelated third parties. Energy Marketing & Trading bears the counterparty
performance risks associated with unrelated third parties. During 2001, a
portion of the external derivative contracts were with Enron, which filed for
bankruptcy in December 2001. As a result, the contracts were effectively
liquidated as a result of contractual terms about bankruptcy and Energy
Marketing & Trading recorded estimated charges for the credit exposure. Under
accounting guidance, the other comprehensive income related to a terminated
contract remains in accumulated other comprehensive income and is recognized as
the underlying volumes are produced. At December 31, 2001, approximately $80
million related to Enron was reflected in accumulated other comprehensive
income. Energy Marketing & Trading has entered into derivative contracts to
replace those contracts that were terminated during the year. At December 31,
2001, the contracted future hedges are at prices that averaged above the spot
market, resulting in an unrealized gain of $331 million (including the $80
million previously discussed) reflected in other comprehensive income. Revenues
from gas management activities increased $14 million. Gas management revenues
consist primarily of marketing activities within the Exploration & Production
segment that are not a direct part of the results of operations for producing
activities. Those non-producing activities include

46

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 Energy Marketing & Trading or third parties.

Segment costs and operating expenses increased $138 million, including a
$22 million increase in selling, general and administrative expense. Segment
costs and operating expenses increased due primarily to costs related to Barrett
operations, comprised primarily of depreciation, depletion and amortization,
lease operating expenses and gas management costs. In addition to the increase
as a result of the Barrett acquisition, the higher segment costs and operating
expenses reflect $10 million higher lease operating expenses, $8 million higher
depreciation, depletion and amortization expenses and $6 million higher
production-related taxes. Other income (expense) -- net in 2000 includes a $6
million impairment charge for certain gas producing properties. The charge
represented the impairment of these held for sale assets to fair value based on
expected net proceeds. These properties were sold in March 2001.

Segment profit increased $156.3 million due primarily to the higher
production revenues in excess of costs. A major portion of this increase can be
attributed to the Barrett acquisition. In addition, segment profit included $9
million in equity earnings from the 50 percent investment in Barrett held by
Williams for the period from June 11, 2001 through August 2, 2001.

2000 vs. 1999

Exploration & Production's revenues increased $104.1 million, or 55
percent, due primarily to $65 million from increased average natural gas sales
prices (net of the effect of hedge positions), $35 million associated with
increases in both company-owned production volumes and marketing volumes from
the Williams Coal Seam Gas Royalty Trust and royalty interest owners and an $8
million contribution in first-quarter 2000 of oil and gas properties acquired in
April 1999. Exploration & Production hedged approximately 50 percent of
production in 2000.

Other (income) expense -- net in 2000 includes a $6 million impairment
charge relating to management's decision to sell certain gas producing
properties. The charge represents the impairment of the assets to fair value
based on expected net proceeds. Other (income) expense -- net in 1999 includes a
$14.7 million gain from the sale of certain interests in gas producing
properties which contributed $2 million to segment profit in 1999 and a $7.7
million gain from the sale of certain other properties.

Segment profit increased $22.6 million, or 57 percent, due primarily to the
higher revenues discussed previously, partially offset by $43 million higher gas
purchase costs related to the marketing of natural gas from the Williams Coal
Seam Gas Royalty Trust and royalty interest owners, $22 million of gains on
sales of assets in 1999, $10 million higher production-related taxes and the $6
million impairment charge in 2000.

INTERNATIONAL

2001 vs. 2000

International's revenues increased $54.9 million, or 53 percent, due
primarily to $32 million of revenue from a new gas compression facility in
Venezuela which began operations in August 2001 and $21 million of revenue from
Colorado soda ash mining operations which began production in fourth-quarter
2000.

Costs and operating expenses increased $61 million, due primarily to $52
million related to soda ash mining operations and $13 million related to the new
gas compression facility in Venezuela.

In fourth-quarter 2001, a $170 million impairment charge was recorded
related to the Colorado soda ash mining operations. The facility experienced
higher than expected construction costs and implementation

47

difficulties through December 2001. As a result, an impairment of the assets
based on management's estimate of the fair value was recorded in fourth-quarter
2001. Management's estimate was based on the present value of discounted future
cash flows. In addition, management engaged an outside business consulting firm
during fourth-quarter 2001 to provide further information to be utilized in
management's estimation. Future events and the use of different judgments and/or
assumptions could result in the recognition of a different level of impairment
charge.

Segment profit decreased $186.9 million and is substantially related to the
$170 million impairment of the soda ash mining facility mentioned above as well
as additional losses from soda ash mining operations of $31 million, both of
which are attributable to the operational and implementation complications since
production began in late 2000. Equity losses increased $11 million due to an $8
million increase in equity losses from the Lithuanian refinery, pipeline and
terminal investment and $6 million lower equity earnings from an Argentina oil
and gas investment, partially offset by $3 million of equity earnings on an
investment in a natural gas liquids (NGL) extraction and processing joint
venture acquired in 2001. The Lithuanian refinery, pipeline and terminal
investment continued to be challenged by a lack of market-priced crude oil
supplies in the first-half of 2001. Additionally, a decrease in refinery crack
spreads on the world market significantly contributed to the losses in 2001.
Slightly offsetting these losses was an $18 million increase from a new
Venezuelan gas compression facility which began operations in third-quarter
2001.

2000 vs. 1999

International's revenues increased $31.6 million, or 44 percent, due
primarily to $17 million higher Venezuelan gas compression revenues reflecting
higher volumes in 2000 following operational problems experienced in
first-quarter 1999 and $11 million of higher revenues from oil and gas
exploration operations in Argentina.

Costs and operating expenses increased $18 million due primarily to $8
million related to soda ash mining operations which began in fourth-quarter
2000, $5 million higher costs related to a Venezuelan gas compression facility
and $3 million higher costs from oil and gas exploration operations in
Argentina.

Segment profit increased $18 million due primarily to $14 million from
increased operating income from Venezuelan gas compression operations, $8
million higher operating income from oil and gas exploration operations in
Argentina and $5 million lower international equity investment losses, partially
offset by a $7 million operating loss related to soda ash mining operations. The
$5 million lower international equity investment losses reflect the change in
accounting for an equity investment to a cost basis investment following a
reduction of management influence and higher equity earnings from a South
American equity investment. Partially offsetting these increases to equity
earnings were higher equity losses from a Lithuanian refinery, pipeline and
terminal investment acquired in fourth-quarter 1999, which continued to be
challenged in obtaining market-priced crude oil supplies and had not yet
consummated any long-term contracts.

MIDSTREAM GAS & LIQUIDS

2001 vs. 2000

Midstream Gas & Liquids' revenues increased $407.7 million, or 27 percent,
due primarily to $564 million in revenues for the first three quarters of 2001
from Canadian operations that were acquired in October 2000. The $564 million of
increased revenues from Canadian operations consists primarily of $270 million
of natural gas liquids sales from processing activities, $205 million of natural
gas liquids sales from fractionation activities, and $81 million of processing
revenues. Canadian revenues decreased $57 million for the comparable periods of
2001 and 2000 due primarily to natural gas liquids product sales price decline.

48

Domestic natural gas liquids revenues decreased $116 million including $78
million from 15 percent lower volumes sold and $38 million due to lower average
natural gas liquids sales prices. The 15 percent decrease in volumes sold is due
primarily to less favorable processing economics. Domestic gathering revenues
increased $11 million due primarily to higher volumes related to recent asset
acquisitions in the Gulf Coast area.

Costs and operating expenses increased $456 million to $1.6 billion, due
primarily to $549 million of costs and operating expenses related to the
Canadian operations for the first three quarters of 2001 and $26 million higher
domestic general operating and maintenance cost, partially offset by $58 million
lower Canadian costs and operating expenses for the comparable periods of 2001
and 2000 due to lower shrink gas replacement costs, $38 million lower domestic
shrink gas replacement costs, the effect in 2000 of $12 million of losses
associated with certain propane storage transactions and $6 million lower
domestic power costs related to the natural gas liquids pipelines.

General and administrative expenses decreased $2 million, or 2 percent, due
primarily to $12 million of reorganization and early retirement costs incurred
in 2000, substantially offset by $11 million of general and administrative
expenses related to the Canadian operations for the first three quarters of
2001.

Included in other (income) expense -- net within segment costs and expenses
for 2001 is $13.8 million of impairment charges related to management's 2001
decisions and commitments to sell certain south Texas non-regulated gathering
and processing assets. The $13.8 million in impairment charges represent the
impairment of the assets to fair value based on expected proceeds from the
sales. These sales closed during first-quarter 2002.

Segment profit decreased $76.3 million, or 26 percent, due primarily to $54
million from lower average per-unit domestic natural gas liquids margins and $22
million from decreased domestic natural gas liquids volumes sold, $26 million
higher domestic operating and maintenance costs, $13.8 million due to the
impairment charge discussed above and $13 million higher losses from equity
investments. Partially offsetting these decreases to segment profit were $14
million lower domestic general and administrative expenses, $11 million higher
domestic gathering revenues, $12 million of losses associated with certain
propane storage transactions during 2000 and $6 million lower domestic power
costs related to the natural gas liquids pipelines.

2000 vs. 1999

Midstream Gas & Liquids' revenues increased $484.3 million, or 47 percent,
due primarily to $267 million higher natural gas liquids sales from processing
activities and $183 million in revenues from Canadian operations purchased in
October 2000. The liquids sales increase reflects $172 million from a 49 percent
increase in average natural gas liquids sales prices and $95 million from a 37
percent increase in volumes sold. The increase in natural gas liquids sales
volumes result from improved liquids market conditions in 2000 and a full year
of results from a plant that became operational in June 1999. The $183 million
of revenues from the Canadian operations consist primarily of $165 million in
natural gas liquids sales and $15 million of processing revenues. In addition,
revenues increased due to $25 million higher natural gas liquids pipeline
transportation revenues associated with increased shipments following improved
market conditions and the completion of the Rocky Mountain liquids pipeline
expansion in November 1999.

Costs and operating expenses increased $412 million, or 60 percent, due
primarily to the $183 million of expenses related to the Canadian operations,
$147 million higher liquids fuel and replacement gas purchases, $17 million
higher power costs related to the natural gas liquids pipeline, $17 million in
higher gathering and processing fuel costs due to increased natural gas prices
and a full year of operation for two processing facilities, $15 million higher
transportation, fractionation, and marketing expenses related to the higher
natural gas liquid sales, $14 million higher depreciation expense, and $12
million of losses associated with certain propane storage transactions.

General and administrative expenses increased $11 million, or 11 percent,
due primarily to $12 million of reorganization costs and $3 million associated
with the Canadian operations purchased in 2000. The $12 million of
reorganization costs relate to the reorganization of Midstream's operations
including the consolidation in Tulsa of certain support functions previously
located in Salt Lake City and Houston. In

49

connection with this, Williams offered certain employees enhanced retirement
benefits under an early retirement incentive program in first-quarter 2000, and
incurred severance, relocation and other exit costs.

Segment profit increased $74 million, or 33 percent, due primarily to $81
million from higher per-unit natural gas liquids margins, $24 million from
increased natural gas liquids volumes sold, $8 million lower equity investment
losses mainly from the Discovery Pipeline project and $6 million from the
natural gas liquids pipeline. Partially offsetting these increases to segment
profit were $14 million higher depreciation expense, $17 million higher
gathering and processing fuel costs, $12 million of propane storage losses and
$11 million higher general and administrative expenses.

PETROLEUM SERVICES

Effective February 2001, management of refined product sales activities
surrounding certain terminals throughout the United States was transferred to
Petroleum Services from Energy Marketing & Trading (see Note 1). The sales
activity was previously included in the trading portfolio of Energy Marketing &
Trading and was therefore reported net of related cost of sales along with other
refined product trading gains and losses within Energy Marketing & Trading prior
to February 2001. After the transfer of management of these activities to
Petroleum Services, these sales activities are reported "gross" within the
Petroleum Services segment. Energy Marketing & Trading's revenues for the year
ended December 31, 2000 includes approximately $582 million for both the sales
and cost of sales related to this activity.

2001 vs. 2000

Petroleum Services' revenues increased $802.9 million, or 17 percent, and
includes an increase to Petroleum Services' total revenues of $184 million as a
result of lower intra-segment sales, which are eliminated, by refining and
marketing to the travel centers/convenience stores. Additionally, revenues
increased due to $596 million higher refining and marketing revenues partially
offset by $60 million lower travel center/convenience store sales. The $596
million increase in refining and marketing revenues includes the $582 million
impact discussed above and $340 million resulting from a 9 percent increase in
refined product volumes sold, partially offset by $325 million from 8 percent
lower average refined product sales prices. The $60 million decrease in travel
center/convenience store sales reflects $223 million increase in revenues
related to travel centers and Alaska convenience stores offset by a $283 million
decrease in revenues related to the 198 convenience stores sold in May 2001. The
$223 million increase in revenues of the travel centers and Alaska convenience
stores reflects $243 million from a 31 percent increase in gasoline and diesel
sales volumes and $41 million higher merchandise sales, partially offset by $61
million lower average diesel and gasoline sales prices. During 2001, Williams
opened 12 travel centers. Previously announced plans to add 12 additional stores
were deferred while a focus is placed on improving operating efficiencies and
profitability at existing stores. In addition, revenues increased due to $99
million higher bio-energy sales reflecting increases in ethanol volumes sold and
average ethanol sales prices and $28 million higher revenues from Williams' 3.1
percent undivided interest in Trans-Alaska Pipeline System (TAPS) acquired in
late June 2000. Slightly offsetting these increases were $15 million lower
revenues related to the petrochemical plant (Olefins) due to a plant turnaround
in first-quarter 2001 and curtailed production.

Costs and operating expenses increased $757 million, or 18 percent, and
include a $184 million increase in costs due to lower intra-segment purchases,
which are eliminated. Additionally costs and operating expenses increased due to
$526 million higher refining and marketing costs, partially offset by $29
million lower travel center/convenience store costs. The $526 million increase
in refining and marketing costs includes the $582 million impact of the transfer
of management from Energy Marketing & Trading to Petroleum Services discussed
above, a $296 million increase in the cost of refined product purchased for
resale and $17 million

50

increase in other operating costs at the refineries, partially offset by a $369
million decrease from lower crude supply cost and other per unit cost of sales
from the refineries. The refining and marketing costs include the impact of
price risk management activities that are used to manage the economic exposure
of fluctuations in commodity prices of crude oil and refined products. The $29
million decrease in travel center/convenience store costs reflects a $282
million decrease in costs related to the 198 convenience stores sold in May
2001, partially offset by a $253 million increase in costs related to travel
centers and Alaska convenience stores. The $253 million increase in costs for
the travel centers and Alaska convenience stores reflect $230 million from
increased diesel and gasoline sales volumes, $60 million from higher store
operating costs and $26 million higher merchandise costs, partially offset by
$63 million lower gasoline and diesel purchase prices. In addition, costs and
operating expenses increased due to $95 million higher bio-energy costs of
sales.

Included in other (income) expense -- net within segment costs and expenses
for 2001, is a $75.3 million gain from the sale of 198 convenience stores,
primarily in the Tennessee metropolitan areas of Memphis and Nashville. Also
included in other (income) expense -- net within segment costs and expenses in
2001 is a total of $14.7 million in loss accruals and impairment charges related
to certain travel centers. This amount includes the estimated liability
associated with the residual value guarantee of certain travel centers under an
operating lease and the impairment of certain other travel centers to fair value
based on management's estimate. Assessments for potential impairments are done
on a store by store basis. Also included in other (income) expense -- net within
segment costs and expenses in 2001 and 2000 are impairment charges of $12.1
million and $11.9 million, respectively, related to an end-to-end mobile
computing systems business. The impairment charges result from management's
decision in 2000 to sell certain of its end-to-end mobile computing systems and
represents the impairment of the assets to fair value based on expected net
sales proceeds, as revised. Other (income) expense -- net within segment costs
and expenses in 2000 also included a $7 million write-off of a retail software
system.

Segment profit increased $111.1 million, or 63 percent, due primarily to an
increase of $71 million from refining and marketing operations and $17 million
from Williams interest in TAPS acquired in late June 2000. In addition, segment
profit increased due to a $75.3 million gain on the sale of convenience stores
in May 2001. Partially offsetting these increases were a $32 million increase in
operating losses from the travel centers and Alaska convenience stores, the
$14.7 million in loss accruals and impairment charges related to certain travel
centers and $17 million lower operating profit from activities at the
petrochemical plant as revenues decreased due to plant turnaround and curtailed
production without a corresponding decrease in cost.

2000 vs. 1999

Petroleum Services' revenues increased $1,617.2 million, or 54 percent, due
primarily to $1,376 million higher refinery revenues (including $240 million
higher intra-segment sales to the travel centers/convenience stores which are
eliminated) and $455 million higher travel center/convenience store sales. The
$1,376 million increase in refinery revenues reflects $1,113 million from 59
percent higher average refined product sales prices and $263 million from a 16
percent increase in refined product volumes sold. The increase in refined
product volumes sold follows refinery expansions and improvements in mid-to-late
1999 and May 2000 which increased capacity. The $455 million increase in travel
center/convenience store sales reflects $260 million from 32 percent higher
average gasoline and diesel sales prices, $171 million primarily from a 64
percent increase in diesel sales volumes and $24 million higher merchandise
sales. The increase in diesel sales volumes and the higher merchandise sales
reflect the opening of eight new travel centers since fourth-quarter 1999.
Slightly offsetting these increases were $91 million lower fleet management
revenues following the sale of a portion of such operations in late 1999, $21
million lower distribution revenues due to a reduction of a propane trucking
operation and $16 million lower pipeline construction revenues following
substantial completion of the Longhorn pipeline project.

In December 2000, Williams signed an agreement to sell 198 of its
convenience stores, primarily in the Tennessee metropolitan areas of Memphis and
Nashville. Revenues related to these convenience stores for 2000 and 1999 were
$466 million and $453 million, respectively. The sale closed in May 2001.

51

Costs and operating expenses increased $1,568 million, or 58 percent, due
primarily to $1,349 million higher refining costs and $470 million higher travel
center/convenience store costs (including $240 million higher intra-segment
purchases from the refineries which are eliminated). The $1,349 million increase
in refining costs reflects $1,088 million from higher crude supply costs and
other related per-unit cost of sales, $221 million associated with increased
volumes sold and $40 million higher operating costs at the refineries. The $470
million increase in travel center/convenience store costs includes $273 million
from higher average gasoline and diesel purchase prices, $159 million primarily
from increased diesel sales volumes and $38 million higher store operating
costs. Slightly offsetting these increases were $101 million lower fleet
management operating costs following the sale of a portion of such operations in
late 1999, $18 million lower cost of distribution activities following a
reduction of a propane trucking operation and $14 million lower pipeline
construction costs following substantial completion of the Longhorn pipeline
project.

Other (income) expense -- net for 2000 includes a $11.9 million impairment
charge related to end-to-end mobile computing systems and a $7 million write-off
of a retail software system. The impairment charge results from management's
decision to sell certain of its end-to-end mobile computing systems and
represents the impairment of the assets to fair value based on expected net
sales proceeds. The primary component in other (income) expense -- net for 1999
was a $6.5 million favorable effect of settlement of transportation pipeline
rate case issues.

Segment profit increased $18 million, or 11 percent, due primarily to $42
million from increased refined product volumes sold and $25 million from
increased per-unit refinery margins, partially offset by $40 million higher
operating costs at the refineries. In addition, segment profit increased $18
million from bio-energy operations primarily reflecting increased ethanol sales
prices and volumes, $10 million from the absence of certain fleet management
losses in 2000, $8 million from Williams' interest in the TAPS acquired in late
June 2000 and $8 million from activities at the petrochemical plant acquired in
March 1999. Partially offsetting these increases to segment profit were a $6
million lower contribution from transportation activities and a lower
contribution from the travel centers/convenience stores which had $38 million
higher operating costs partially offset by a $24 million increase in gross
profit on merchandise sales. In addition, segment profit in 2000 was decreased
by $6 million higher selling, general and administrative expense and the $25
million unfavorable change in other (income) expense -- net discussed
previously.

WILLIAMS ENERGY PARTNERS

2001 vs. 2000

Williams Energy Partners' revenues increased $12.7 million due primarily to
the acquisition of a marine terminal facility in September 2000 and higher
revenues and rates from the storage of petroleum products at the Gulf Coast
marine facilities. Segment profit decreased $4.8 million due primarily to higher
operating costs related to the marine facilities discussed above and higher
general and administrative expenses.

2000 vs. 1999

Williams Energy Partners' revenues increased $29.9 million due primarily to
the acquisition of three Gulf Coast marine facilities in August 1999, one inland
terminal in March 2000, and another marine terminal in September 2000. Operating
costs and selling, general and administrative expenses increased $18.1 million
and $6.3 million respectively, due to the five terminals acquired above. Segment
profit increased $5.5 million due primarily to the profit generated from the new
terminals.

52

FAIR VALUE OF ENERGY RISK MANAGEMENT AND TRADING ACTIVITIES

As more thoroughly described in Note 1 of the Notes to Consolidated
Financial Statements, energy and energy-related contracts are valued at fair
value and, with the exception of certain commodity inventories, are recorded in
current and noncurrent energy risk management and trading assets and liabilities
in the Consolidated Balance Sheet. Fair value of energy and energy-related
contracts is determined based on the nature of the transaction and market in
which transactions are executed. Certain transactions are executed in
exchange-traded or over-the-counter markets for which quoted prices in active
periods exist. Transactions are also executed in exchange-traded or
over-the-counter markets for which quoted market prices may exist, however, the
market may be inactive and price transparency is limited. Certain transactions
are executed for which quoted market prices are not available.

METHODS OF ESTIMATING FAIR VALUE

Quoted prices in active markets

Quoted market prices for varying periods in active markets are readily
available for valuing forward contracts, futures contracts, swap agreements and
purchase and sales transactions in the commodity markets in which Energy
Marketing & Trading transacts. These prices reflect the economic and regulatory
conditions that currently exist in the market place and are subject to change in
the near term due to changes in future market conditions. The availability of
quoted market prices in active markets varies between periods and commodities
based upon changes in market conditions.

Quoted prices and other external factors in less active markets

For contracts or transactions extending into periods for which actively
quoted prices are not available, Energy Marketing & Trading estimates energy
commodity prices in these illiquid periods by incorporating information about
commodity prices in actively quoted markets, quoted prices in less active
markets, and other market fundamental analysis. While an active market may not
exist for the entire period, quoted prices can generally be obtained for natural
gas and power through 2008, crude and refined products through 2004, and natural
gas liquids through 2003. Prices reflected in current transactions executed by
Energy Marketing & Trading are used to further validate the estimates of these
prices.

Models and other valuation techniques

Contracts for which quoted market prices are not available primarily
include transportation, storage, full requirements, load serving and power
tolling contracts (energy-related contracts). A description of these contracts
is included in Note 18 of the Notes to Consolidated Financial Statements. Energy
Marketing & Trading estimates fair value using models and other valuation
techniques that reflect the best available information under the circumstances.
The valuation techniques incorporate option pricing theory, statistical and
simulation analysis, present value concepts incorporating risk from uncertainty
of the timing and amount of estimated cash flows and specific contractual terms.
Factors utilized in the valuation techniques include quoted energy commodity
market prices, estimates of energy commodity market prices in the absence of
quoted market prices, the risk-free market discount rate, volatility factors
underlying the positions, estimated correlation of energy commodity prices,
contractual volumes, estimated volumes, liquidity of the market in which the
contract is transacted and a risk premium that market participants would
consider in their determination of fair value. Although quoted market prices are
not available for these energy-related contracts themselves, quoted market
prices for the underlying energy commodities are a significant component in the
valuation of these contracts.

Each of the methods discussed above also include counterparty performance
and credit consideration in the estimation of fair value.

53

The chart below reflects the fair value of Energy Marketing & Trading's
energy risk management and trading contracts at December 31, 2001 by valuation
methodology and the year in which the recorded fair value is expected to be
realized.

- ---------------

(1) A significant portion of the value expected to be realized relates to a
contract within the California power market. The terms of this contract
provide for the sale of power at prices ranging from $62.50 to $87.00 per
megawatt hour over a ten-year period at variable volumes up to 1,400
megawatts per hour.

(2) Quoted market prices of the underlying commodities are a significant factor
in the estimate of fair value.

(3) Approximately $1.1 billion of the value expected to be realized through 2010
has been managed in a manner whereby offsetting fixed price energy and
energy-related contracts mitigate the exposure to changes in fair value
resulting from future changes in commodity prices.

SIGNIFICANT ESTIMATES AND ASSUMPTIONS USED IN THE VALUATION ESTIMATION PROCESS

Estimates of fair value for long-term energy and energy-related contracts
are most significantly impacted by management's estimates and assumptions in the
illiquid periods. However, the impact of these estimates and assumptions on the
fair value of contracts is reduced to the extent Energy Marketing & Trading has
managed the portfolio by executing offsetting fixed price energy and
energy-related contracts to mitigate exposure in the portfolio to changes in
fair value resulting from future changes in commodity prices.

The most significant estimates and assumptions include:

- Estimates of natural gas and power market prices in illiquid periods;

- Estimates of volatility and correlation of natural gas and power prices;

- Estimates of risk inherent in estimating cash flows; and

- Estimates and assumptions regarding counterparty performance and credit
considerations.

Estimates of natural gas and power market prices in illiquid periods

Natural gas and power prices are the most significant commodity prices
impacting the fair value of Energy Marketing & Trading contracts at December 31,
2001. In estimating natural gas and power prices during illiquid periods, Energy
Marketing & Trading includes factors such as quoted market prices, prices of
current market transactions and market fundamental analysis. Market fundamental
analysis incorporates the most recent market data from industry publications,
regulatory publications, existing and forecasted electricity generation
capacity, natural gas reserve data, alternative fuel source availability,
weather patterns and other indicative information supporting supply and demand
relationships. These estimated market prices are highly dependent upon actively
quoted market prices for natural gas and power, current economic and regulatory
conditions, as well as, information supporting future conditions that would
affect the supply and demand relationships.

54

As new information is obtained about market prices during illiquid periods,
Energy Marketing & Trading incorporates this information in its estimates of
market prices. Such new information includes additional executed transactions
extending into these periods. These transactions give insight into the market
prices for which market participants are willing to buy or sell in arms-length
transactions.

Estimation of volatility and correlation of natural gas and power prices

Volatility of natural gas and power prices represents a significant
assumption in the determination of fair value of contracts that contain
optionality and whose fair value is estimated using option-pricing models.
Correlation of natural gas and power prices represents a significant assumption
in the determination of fair value of contracts that contain optionality and
involve multiple commodities and whose fair value is estimated using
option-pricing models. Volatility and correlation can be implied from option
based market transactions during periods when quoted market prices exist for
natural gas and power. Volatility and correlation is estimated in periods during
which quoted market prices are not available through quantitative analysis of
historical volatility patterns of the commodities, expected future changes in
estimated natural gas and power prices, and market fundamental analysis.
Estimates of volatility and correlation significantly impact the estimation of
fair value for all periods in which the contract is valued using option-pricing
models.

Estimates of risk inherent in estimating cash flows

Risk inherent in estimating cash flows represents the uncertainty of events
occurring in the future which could ultimately affect the realization of cash
flows. Energy Marketing & Trading estimates the risk active market participants
would include in the price exchanged in an arms-length transaction in the
estimation of fair value for each contract. Energy Marketing & Trading estimates
risk utilizing the capital asset pricing theory in the estimation of fair value
of energy-related contracts. The capital asset pricing theory considers that
investors require a higher return for contracts perceived to embody higher risk
of uncertainty in the market. This risk is most significant in illiquid periods
and markets. Factors affecting the estimate of risk include liquidity of the
market in which the contract is executed, ability to transact in future periods,
existence of similar transactions in the market, uncertainty of timing and
amounts of cash flows, and market fundamental analysis.

Estimates and assumptions regarding counterparty performance and credit
considerations

Energy Marketing & Trading includes in its estimate of fair value for all
contracts an assessment of the risk of counterparty non-performance. Such
assessment considers the credit rating of each counterparty as represented by
public rating agencies such as Standard & Poor's and Moody's Investor's Service,
the inherent default probabilities within these ratings, the regulatory
environment that the contract is subject to, as well as the terms of each
individual contract.

55

The counterparties associated with assets from energy trading and
price-risk management activities as of December 31, 2001, are summarized as
follows:

- ---------------

(a) "Investment Grade" is primarily determined using publicly available credit
ratings along with consideration of cash, standby letters of credit, parent
company guarantees, and property interests, including oil and gas reserves.
Included in "Investment Grade" are counterparties with a minimum Standard &
Poor's and Moody's Investor's Service rating of BBB- or Baa3, respectively.

(b) One counterparty within the California power market represents greater than
ten percent of assets from energy risk management and trading activities
and is included in "investment grade." Standard & Poor's and Moody's
Investor's Service do not rate this counterparty. This counterparty has
been included in the "investment grade" column as a result of the manner in
which it was established by the State of California.

As further discussed in Note 19 of the Notes to Consolidated Financial
Statements, the electricity markets in California continue to be subject to
numerous and wide-ranging regulatory proceedings and investigations, regarding
among other things, market structure, behavior of market participants and market
prices. Energy Marketing & Trading has considered counterparty performance as a
result of ongoing issues in the California power industry that could result in a
restructuring of the California markets. The risk of non-performance surrounding
this issue is updated as new information regarding the status of these issues
occurs.

CONTROLS AROUND VALUATION ESTIMATION PROCESS

Information used in determining the significant estimates and assumptions
utilized in the determination of fair value of energy-related contracts is
derived from market fundamental analysis. Interpreting this data requires
judgement and Energy Marketing & Trading recognizes that others in the market
place might interpret this data differently. It is reasonably possible that
different interpretations of this data could result in a different estimation of
fair value in periods for which estimates and assumptions are significant
components of estimating fair value. In estimating fair value, Energy Marketing
& Trading considers how we believe others in the market place would interpret
this information in order to further validate that the estimates and assumptions
used in estimating fair value provides the best estimate of the amount that
active market participants would exchange in an arms-length transaction. Once
offsetting contracts are entered into to mitigate commodity price risk, the
reliance on management's assumptions and estimates utilized in the estimation of
the fair value of each contract becomes less significant. However, the
assumptions and estimates surrounding counterparty performance and credit are
still an integral component in the estimation of fair value for these contracts.
Energy Marketing & Trading enhances its valuation techniques, models and
significant estimates and assumptions as better information about the markets in
which Energy Marketing & Trading transacts becomes available.

Energy Marketing & Trading maintains a control environment surrounding the
operational and valuation processes through its trading policy, credit policy,
and general controls involved in the daily operations of the business. These
policies provide limits on the types of transactions that can be executed,
including term of the contract, the volumetric size of the contract and
commodities underlying the contract. The policies also provide limits on the
amount of credit extended to a single counterparty, the gross value at risk of
the overall
56

portfolio and the maximum daily loss permitted within the portfolio. These
policies have been approved by Williams' Board of Directors and are administered
through the Williams Risk Management Committee consisting of Energy Marketing &
Trading's Risk Control Officer and other members of Williams' senior management.
The Risk Control Officer is responsible for Energy Marketing & Trading's Risk
Control Group who monitors the compliance with these policies and controls on a
daily basis. The Risk Control Group reports instances in which limits are
exceeded or other significant exceptions to the policies occur to members of the
Risk Management Committee. A notification of noncompliance also includes a plan
to remedy the exception in order to bring the portfolio back into the approved
limits and standards.

Energy Marketing & Trading's Risk Control Group also performs validations
of the valuation techniques, models and significant estimates and assumption on
a quarterly basis in order to provide additional assurance that the estimates of
fair value provide the best determination of how others in the market might
value the contracts. Validations include functions such as comparing third party
market quotes against estimated prices, comparing contractual terms to those
input into the models, reviewing the market fundamental analysis for
reasonableness and recalculating the significant computations.

MANAGEMENT OF RISK IN PORTFOLIO

Energy Marketing & Trading manages the risk assumed from providing energy
risk management services to its customers. This risk results from exposure to
energy commodity prices, volatility and correlation of commodity prices, the
portfolio position of the contracts, liquidity of the market in which the
contract is transacted, interest rates, and counterparty performance and credit.
Energy Marketing & Trading actively seeks to diversify its portfolio in managing
the commodity price risk in the transactions that it executes in various markets
and regions by executing offsetting contracts to manage the commodity price risk
in accordance with parameters established in its trading policy. As of December
31, 2001, approximately $1.1 billion of the value expected to be realized
through 2010 has been managed in a manner whereby fixed-price energy and
energy-related contracts mitigate the exposure in the portfolio to changes in
fair value resulting from future changes in commodity prices.

Risks surrounding counterparty performance and credit could ultimately
impact the amount and timing of the cash flows expected to be realized. Energy
Marketing & Trading continually assesses this risk and has credit protection
within various agreements to call on additional collateral support in the event
of changes in the creditworthiness of the counterparty. Additional collateral
support could include letters of credit, payment under margin agreements,
guarantees of payment by creditworthy parties, or in some instances, transfers
of the ownership interest in natural gas reserves or power generation assets. In
addition, Energy Marketing & Trading enters into netting agreements to mitigate
counterparty performance and credit risk. Credit default swaps may also be used
to manage the counterparty credit exposure in the energy risk management and
trading portfolio. Under these agreements, Energy Marketing & Trading pays a
fixed rate premium for a notional amount of risk coverage associated with
certain credit events on a referenced obligation. The covered credit events are
bankruptcy, obligation acceleration, failure to pay, and restructuring.

Energy Marketing & Trading, through Williams, also enters into interest
rate swaps to mitigate the associated interest rate risk from the fair value of
the long dated energy and energy-related contracts by fixing the interest rate
inherent in the portfolio of contracts. At December 31, 2001, Energy Marketing &
Trading had executed interest rate swaps to offset potential interest rate
changes for approximately $1 billion of the expected future cash flows in its
portfolio.

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CHANGES IN FAIR VALUE DURING 2001

The following table reflects the changes in fair value between December 31,
2000 and 2001.

The following table reconciles the changes in fair value of energy risk
management and trading contracts during 2001 to energy risk management trading
revenues for the period ending December 31, 2001.

- ---------------

(1) Represents the change in fair value of energy and energy-related contracts
outstanding at December 31, 2000 that were realized during 2001, as well as,
contracts entered into during 2001 and settled prior to December 31, 2001.

(2) Reflects only revenues from energy risk management and trading activities
accounted for on a fair value basis. This amount excludes approximately $176
million of non-trading related revenues accounted for on an accrual basis.

Changes in fair value during 2001 include the realization of cash flows on
contracts outstanding at December 31, 2000 that were expected to be realized
during 2001. These amounts may have differed from the values that were actually
realized during 2001 due to changes in market prices and other factors that
occurred during 2001 prior to the realization of those cash flows.

During 2001, Energy Marketing & Trading recognized revenues resulting from
the execution of new long-term contracts providing for energy price risk
management services to customers. See Energy Marketing & Trading's 2001 Results
of Operations for a discussion of the type of contracts executed during the
year. The fair value of new contracts at the time they are executed reflect the
prices negotiated in long-term contracts which includes the premium Energy
Marketing & Trading receives for managing the energy price risk of its
customers. Additionally, as further discussed in Note 1 of the Notes to
Consolidated Financial Statements, Energy Marketing & Trading does not recognize
revenue on contracts until all requirements for revenue recognition have been
achieved. As a result, the fair value of these contracts at the time they were
executed is likely to differ from the fair value of the contracts at the time
they were initially recorded in the financial statements due to changes in
market prices and other factors which may have occurred during such period.

Energy Marketing & Trading continuously evaluates the valuation techniques
and models used in estimating fair value and modifies and implements new
valuation techniques based upon emerging financial theory in order to provide a
better estimate of fair value.

58

A component of the fair value of energy risk management and trading assets
and liabilities includes the amount of cash received and cash paid for premiums
on option contracts. Premiums for options contracts impact energy trading
revenues over the life of the option contract. At December 31, 2001,
approximately $881 million of the net energy risk management and trading assets
and liabilities included cash payments for premiums on option contracts
purchased by Energy Marketing & Trading in excess of cash received for options
sold.

Changes attributable to market movements reflect the change in fair value
of contracts resulting from changes in quoted market prices of commodities,
interest rates, volatility and correlation of commodity prices. This also
includes improvements in the estimates and assumptions Energy Marketing &
Trading uses in estimating fair value based upon new information and data
available in the marketplace. The most significant component of these changes
during 2001 occurred during the first quarter and prior to the execution of
certain offsetting contracts mitigating the exposure in the portfolio to changes
in fair value from future changes in commodity prices.

FINANCIAL CONDITION AND LIQUIDITY

LIQUIDITY

Williams considers its liquidity to come from both internal and external
sources. Certain of those sources are available to Williams (parent) and certain
of its subsidiaries. Williams' unrestricted sources of liquidity, which Williams
believes can be utilized without limitation under existing loan covenants,
consist primarily of the following:

- Available cash equivalent investments of $1.1 billion at December 31,
2001, as compared to $854 million at December 31, 2000.

- $700 million available under Williams' $700 million bank-credit facility
at December 31, 2001, as compared to $350 million at December 31, 2000.

- $769 million available under Williams' $2.2 billion commercial paper
program (or the related bank-credit facility) at December 31, 2001, as
compared to $4 million at December 31, 2000 under a $1.7 billion
commercial paper program.

- Cash generated from operations.

- Short-term uncommitted bank lines of credit may also be used in managing
liquidity.

The availability of borrowings under Williams' $700 million bank-credit
facility and Williams' $2.2 billion bank credit facility which supports the $2.2
billion commercial paper program is subject to specified conditions, which
Williams believes are currently met. These conditions include compliance with
the financial covenants and ratios as defined in the agreements (see Note 13),
absence of default as defined in the agreements, and continued accuracy of
representations and warranties made in the agreements.

At December 31, 2001, Williams had a $2.5 billion shelf registration
statement effective with the SEC to issue a variety of debt or equity
securities. Subsequent to the issuance of the $1.1 billion of FELINE PACS in
January 2002 as discussed below, the remaining availability on the shelf
registration is approximately $300 million, because Williams registered both the
FELINE PACS and the related common stock to be issued subsequently. In addition,
there are other outstanding registration statements filed with the SEC for
Northwest Pipeline, Texas Gas Transmission and Transcontinental Gas Pipe Line
(each a wholly owned subsidiary of Williams). At March 1, 2002, approximately
$450 million of shelf availability remains under these outstanding registration
statements and may be used to issue a variety of debt securities. Interest rates
and market conditions will affect amounts borrowed, if any, under these
arrangements. Williams believes additional financing arrangements, if required,
can be obtained on reasonable terms.

Terms of certain borrowing agreements limit transfer of funds to Williams
from its subsidiaries. The restrictions have not impeded, nor are they expected
to impede, Williams ability to meet its cash requirements in the future.

59

During 2002, Williams expects to fund capital and investment expenditures,
debt payments and working-capital requirements of its continuing operations
through (1) cash generated from operations, (2) the use of the available portion
of Williams' $700 million bank-credit facility, (3) commercial paper (or the
related bank-credit facility), (4) short-term uncommitted bank lines, (5)
private borrowings, (6) sale or disposal of existing businesses and/or (7) debt
or equity public offerings.

Credit Ratings

Williams maintains certain preferred interest and debt obligations that
contain provisions requiring accelerated payment of the related obligations or
liquidation of the related assets in the event of specified levels of declines
in Williams' credit ratings given by Moody's Investor's Service, Standard &
Poor's and Fitch Ratings (rating agencies). Performance by Williams under these
terms include potential acceleration of debt payment and redemption of preferred
interests totaling $816 million at December 31, 2001.

During the fourth quarter of 2001, Williams announced its intentions to
eliminate its exposure to the "ratings trigger" clauses incorporated in the
above agreements. At the time of this filing, negotiations had commenced with
the respective financial institutions with an objective of completing such
changes during the first half of 2002.

At December 31, 2001, Williams' credit ratings were above "trigger" levels
by a range of two or more levels. On February 1, 2002, Williams' credit ratings
were maintained by each of the rating agencies, although Standard & Poor's
placed Williams on "negative watch." On February 27, 2002, Moody's Investor's
Service confirmed the investment grade rating of Williams and changed the
outlook from stable to negative. On February 28, 2002, Fitch Ratings affirmed
its investment grade rating of Williams and also changed the outlook from stable
to negative. Standard & Poor's also announced it was maintaining its previous
rating from February 1, 2002.

In addition to the factors noted above, Williams' energy marketing and
trading business relies upon the investment grade rating of Williams senior
unsecured long-term debt to satisfy credit support requirements of many
counterparties. If Williams' credit ratings were to decline below investment
grade, its ability to participate in energy marketing and trading activity could
be significantly limited. Alternate credit support would be required under
certain existing agreements and would be necessary to support future
transactions. Without an investment grade rating, Williams would be required to
fund margining requirements pursuant to industry standard derivative agreements
with cash, letters of credit or other negotiable instruments. At December 31,
2001, the total notional amounts that could require such funding, in the event
of a credit rating decline of Williams to below investment grade, is
approximately $500 million, before consideration of offsetting positions and
margin deposits from the same counterparties.

At December 31, 2001, Williams maintained the following credit ratings on
its senior unsecured long-term debt, which are considered to be investment
grade:

Moody's Investor's Service.................................. Baa2
Standard & Poor's........................................... BBB
Fitch Ratings............................................... BBB

Off-Balance Sheet Financing Arrangements and Guarantees of Debt or Other
Commitments to Third Parties

During 2000, Williams entered into operating lease agreements with two
special purpose entities (SPE's) and provides a financial guarantee to a third
SPE. The operating lease agreements are with respect to certain Williams travel
center stores, offshore oil and gas pipelines and an onshore gas processing
plant (see Note 13), while the guarantee is with respect to gas turbines under
construction. The SPE's are not consolidated by Williams since their equity is
provided by non-related parties. The sole purpose of these entities is to
facilitate financing for construction and acquisition of the related assets. The
only assets of the SPE's are the constructed or acquired assets, which serve as
collateral for the SPE's liabilities, which are in the form of financing
obligations. The lease terms include a five-year base term with a renewal option
for an additional

60

five-year term. The funding obligations, if any, of Williams with respect to
these entities occurs solely through the lease commitments and the financial
guarantee. Williams has an option to purchase the leased assets during the lease
terms at amounts approximating the lessor's cost and has an option to acquire
the gas turbines at actual cost of construction. For the operating leases,
Williams provides residual value guarantees equal to 85 percent of the lessor's
cost on the completed travel center stores and 89.9 percent of the lessor's
cost, less the present value of actual lease payments, on the offshore oil and
gas pipelines and the onshore gas processing plant. The financial guarantee with
respect to the gas turbines is also a residual value guarantee equal to a
maximum of 89.9 percent of the actual cost of construction. In the event that
Williams does not exercise its purchase option, Williams expects the fair market
value of the covered assets to substantially reduce its obligation under the
residual value guarantees. If these SPE's were consolidated into Williams'
Consolidated Balance Sheet at December 31, 2001, they would increase assets and
long-term debt by approximately $364 million.

Williams provides a guarantee of approximately $127 million towards project
financing of energy assets owned and operated by an entity in which Williams
owns an interest of 50 percent. This obligation or guarantee is not consolidated
in Williams' balance sheet as Williams does not maintain a controlling interest
in the entity and therefore follows equity accounting for its interest.
Performance on the guarantees generally would occur upon a failure of payment by
the financed entity or certain events of default related to the guarantors.
These events of default primarily relate to bankruptcy and/or insolvency of the
guarantors. At December 31, 2001, there were no events of default by the
guarantors or delinquent payments by the financed entity with respect to the
project financings.

Williams is a party to a put agreement arising from its sale of Ferrellgas
senior common units in April 2001 (see Note 4) whereby the purchaser's lenders
can require Williams to repurchase the units upon certain events of default by
the purchaser or the failure or default by the seller (Williams) under any of
its debt obligations greater than $60 million. The total outstanding under the
put agreement at December 31, 2001 was $99.6 million. Williams' contingent
obligation reduces as purchaser's payments are made to the lender. The
purchaser's agreement is for a five year term, expiring December 30, 2005. The
put agreement represents a contingent liability and is not reflected on
Williams' balance sheet. At December 31, 2001, there have been no events of
default and the purchaser has performed as required under payment terms with the
lender.

For each of the Williams' guarantees discussed above, Williams has
currently assessed that its future performance under each of the agreements as
less than probable for purposes of SFAS No. 5, "Accounting for Contingencies."
This assessment is based on information available at December 31, 2001 affirming
there are no events of default on behalf of Williams as a guarantor and none of
the related entities are delinquent with respect to the supported obligations.

Williams has agreements to sell, on an ongoing basis, certain of its
accounts receivable to qualified special-purpose entities ("QSPE"). Under these
agreements, Williams is able to sell up to $450 million of accounts receivables.
These QSPEs are not consolidated; however, if these QSPEs were consolidated at
December 31, 2001, assets and debt would increase by $420 million.

WCG Separation

Since the initial equity offering by WCG in October 1999, the sources of
liquidity for WCG had been separate from Williams' sources of liquidity. The
reduction to Williams' stockholders' equity as a result of the separation in
April 2001 was approximately $2.0 billion. Williams, with respect to shares of
WCG's common stock that Williams retained, has committed to the Internal Revenue
Service (IRS) to dispose of all of the WCG shares that it retains as soon as
market conditions allow, but in any event not longer than five years after the
spinoff. As part of a separation agreement and subject to a favorable ruling by
the IRS that such a limitation is not inconsistent with any ruling issued to
Williams regarding the tax-free treatment of the spinoff, Williams has agreed
not to dispose of the retained WCG shares for three years from the date of
distribution and must notify WCG of an intent to dispose of such shares.
However, on February 28, 2002, Williams filed with the IRS a request to withdraw
its request for a ruling that the agreement between Williams and WCG that
Williams would not transfer any retained WCG stock for a three-year period from
the spinoff would not

61

be inconsistent with the favorable tax-free treatment ruling issued to Williams.
Williams represented in the withdrawal request that it had abandoned its intent
to make the lock-up effective, thereby making the ruling request moot. For
further discussion of separation agreements and potential tax exposure as a
result of the WCG separation, see Note 3 of the Notes to Consolidated Financial
Statements.

Additionally, Williams, prior to the spinoff and in an effort to strengthen
WCG's capital structure, entered into an agreement under which Williams
contributed an outstanding promissory note from WCG of approximately $975
million and certain other assets, including a building under construction and a
commitment to complete the construction. In return, Williams received 24.3
million newly issued common shares of WCG.

Williams, prior to the spinoff, provided indirect credit support for $1.4
billion of WCG's Note Trust Notes through a commitment to make available
proceeds of a Williams equity issuance or other permitted redemption sources in
the event any one of the following were to occur: (1) a WCG default; (2)
downgrading of Williams' senior unsecured debt to Ba1 or below by Moody's
Investor's Service, BB or below by Standard & Poor's, or BB+ or below by Fitch
Ratings if Williams' common stock closing price is below $30.22 for ten
consecutive trading days while such downgrade is in effect; or (3) to the extent
proceeds from WCG's refinancing or remarketing of the WCG Note Trust Notes prior
to March 2004 produces proceeds of less than $1.4 billion.

On March 5, 2002, Williams received the requisite approvals on its consent
solicitation to amend the terms of the WCG Note Trust Notes. The amendment,
among other things, eliminates acceleration of the Notes due to a WCG bankruptcy
or a Williams credit rating downgrade. The amendment also affirms Williams'
obligations for all payments due with respect to the WCG Note Trust Notes, which
are due March 2004, and allows Williams to fund such payments from any available
sources. With the exception of the March and September 2002 interest payments,
totaling $115 million, WCG remains indirectly obligated to reimburse Williams
for any payments Williams is required to make in connection with the WCG Note
Trust Notes.

Williams has provided a guarantee of WCG's obligations under a 1998
transaction in which WCG entered into an operating lease agreement covering a
portion of its fiber-optic network. The total cost of the network assets covered
by the lease agreement is $750 million. The lease term initially totaled five
years and, if renewed, could extend to seven years. WCG has an option to
purchase the covered network assets during the lease term at an amount
approximating lessor's cost. On March 6, 2002, a representative of WCG notified
Williams that WCG intends to issue a notice so as to be able to purchase the
assets in the immediate future. As a result of an agreement between Williams and
WCG's revolving credit facility lenders, if Williams gains control of the
network assets covered by the lease, Williams may be obligated to return the
assets to WCG and the obligation of WCG to compensate Williams for such property
may be subordinated to the interests of WCG's revolving credit facility lenders
and may not mature any earlier than one year after the maturity of WCG's
revolving credit facility.

Williams has also provided guarantees on certain performance obligations of
WCG totaling approximately $57 million.

In third-quarter 2001, Williams purchased the Williams Technology Center
and other ancillary assets (Technology Center) and three corporate aircraft from
WCG for $276 million which represents the approximate actual cost of
construction of the Williams Technology Center and the acquisition cost of the
ancillary assets and aircraft. Williams then entered into long-term lease
arrangements under which WCG is the sole lessee of the Technology Center and
aircraft (see Note 13). As a result of this transaction, Williams' Consolidated
Balance Sheet includes $28.8 million in current accounts and notes receivable
and $137.2 million in noncurrent other assets and deferred charges, net of
allowance of $103.2 million, relating to amounts due from WCG. Additionally,
receivables include amounts due from WCG of approximately $27 million at
December 31, 2001 which includes a $21 million deferred payment (net of
allowance of $85 million) for services provided to WCG due March 15, 2002. In
February 2002, the deferred payment for services provided to WCG was extended to
September 15, 2002.

62

Recent disclosures and announcements by WCG, including WCG's recent
announcement that it might seek to reorganize under the U.S. Bankruptcy Code,
have resulted in Williams concluding that it is probable that it will not fully
realize the $375 million of receivables from WCG at December 31, 2001 nor
recover its remaining $25 million investment in WCG common stock. In addition,
Williams has determined that it is probable that it will be required to perform
under the $2.21 billion of guarantees and payment obligations discussed above.
Other events that have affected Williams' assessment include the credit
downgrades of WCG, the bankruptcy of a significant competitor announced on
January 28, 2002, and public statements by WCG regarding an ongoing
comprehensive review of its bank secured credit arrangements. As a result of
these factors, Williams, using the best information available at the time and
under the circumstances, has developed an estimated range of loss related to its
total WCG exposure. Management utilized the assistance of external legal counsel
and an external financial and restructuring advisor in making estimates related
to its guarantees and payment obligations and ultimate recovery of the
contractual amounts receivable from WCG. At this time, management believes that
no loss within the range is more probable than another. Accordingly, Williams
has recorded the $2.05 billion minimum amount of the range of loss which is
reported in the Consolidated Statement of Operations as a $1.84 billion pre-tax
charge to discontinued operations and a $213 million pre-tax charge to
continuing operations. Williams recognized a related deferred tax benefit in the
Consolidated Statement of Operations of $742.5 million ($68.9 million in
continuing operations and $673.6 million in discontinued operations). The
ultimate amount of tax benefit realized could be different from the deferred tax
benefit recorded, as influenced by potential changes in federal income tax laws
and the circumstances upon the actual realization of the tax benefits from WCG's
balance sheet restructuring program.

The charge to discontinued operations of $1.84 billion includes the minimum
amount of the estimated range of loss from performance on $2.21 billion of
guarantees and payment obligations and approximately $16 million in expenses.
With the exception of the interest on the Note Trust Notes and the expenses,
Williams has assumed for purposes of this estimated loss that it will become an
unsecured creditor of WCG for all or part of the amounts paid under the
guarantees and payment obligations. However, it is probable that Williams will
not be able to recover a significant portion of the receivables. The estimated
loss from the performance of the guarantees and payment obligations is based on
the overall estimate of recoveries on amounts receivable discussed below. Due to
the amendment of the WCG Note Trust Notes discussed above, $1.1 billion of the
accrued loss will be classified as a long-term liability in the Consolidated
Balance Sheet.

The charge to continuing operations of $213 million includes estimated
losses from an assessment of the recoverability of carrying amounts of the $106
million deferred payment for services provided to WCG, the $269 million minimum
lease payments receivable from WCG, and a remaining $25 million investment in
WCG common stock. The $85 million provision on the deferred payment is based on
the overall estimate of recoveries on amounts receivable using the same
assumptions on collectibility as discussed below. The $103 million provision on
the minimum lease payments receivable is based on an estimate of the fair value
of the leased assets. The $25 million write-off of the WCG investment is based
on management's assessment of realization as a result of WCG's balance sheet
restructuring program.

The estimated range of loss assumes that Williams, as a creditor of WCG,
will recover only a portion of its claims against WCG. Such claims include a
$2.21 billion receivable from performance on guarantees and payment obligations
and a $106 million deferred payment for services provided to WCG. With the
assistance of external legal counsel and an external financial and restructuring
advisor, and considering the best information available at the time and under
the circumstances, management developed a range of loss on these receivables
with a minimum loss of 80 percent on claims in a bankruptcy of WCG. Estimating
the range of loss as a creditor involves making complex judgments and
assumptions about uncertain outcomes. The actual loss may ultimately differ from
the recorded loss due to changes in numerous factors, which include, but are not
limited to, the future demand for telecommunications services and the state of
the telecommunications industry, WCG's individual performance, and the nature of
the restructuring of WCG's balance sheet. There could be additional losses
recognized in the future, a portion of which may be reflected as discontinued
operations.

63

The minimum amount of loss in the range is estimated based on recoveries
from a successful reorganization process under Chapter 11 of the U.S. Bankruptcy
Code. Recoveries after a successful reorganization process depend, among other
things, on the impact of a bankruptcy on WCG's financial performance and WCG's
ability to continue uninterrupted business services to its customers and to
maintain relationships with vendors. To estimate recoveries of the unsecured
creditors, Williams estimated an enterprise value of WCG using a present value
analysis and reduced the enterprise value by the level of secured debt which may
exist in WCG's restructured balance sheet. In its estimate of WCG's enterprise
value, Williams considered a range of cash flow estimates based on information
from WCG and from other external sources. Future cash flow projections are
valued using discount rates ranging from 17 percent to 25 percent. The range of
cash flows is based on different scenarios related to the growth, if any, of
WCG's revenues and the impact that a bankruptcy may have on revenue growth. The
range of discount rates considers WCG's assumed restructured capital structure
and the market return that equity investors may require to invest in a
telecommunications business operating in the current distressed industry
environment. The range of loss also considers recoveries based on transaction
values from recent telecommunications restructurings and from a liquidation of
WCG's assets.

Should WCG go into bankruptcy under Chapter 7 of the U.S. Bankruptcy Code,
recoveries under a liquidation include factors such as the nature of WCG's
assets, the value of operating assets in a distressed telecommunications market,
the cost of liquidation, operating losses during the period of liquidation, the
length of liquidation period and claims of creditors superior to those of
Williams' unsecured claims.

Significant items reflected as discontinued operations in the Consolidated
Statement of Cash Flows include the following:

- In 2000, WCG issued $1 billion in long-term debt obligations consisting
of $575 million in 11.7 percent notes due 2008 and $425 million in 11.875
percent notes due 2010. In October 1999, WCG completed an initial public
equity offering, private equity offerings and public debt offerings that
yielded total net proceeds of approximately $3.5 billion. The initial
public equity offering yielded net proceeds of approximately $738 million
(see Note 3). In concurrent investments by SBC Communications Inc., Intel
Corporation and Telefonos de Mexico, additional shares of common stock
were privately sold for proceeds of $738.5 million. Concurrent with these
equity transactions, WCG issued high-yield public debt of approximately
$2 billion. Proceeds from the 1999 equity and debt transactions were used
to repay WCG's 1999 borrowings under an interim short-term bank-credit
facility and the $1.05 billion bank-credit agreement. The remaining
proceeds from the 1999 transactions and the 2000 debt proceeds were used
to fund 2000 WCG's operating losses, continued construction of WCG's
national fiber-optic network and other capital and investment expansion
opportunities. During 2000, WCG received net proceeds of approximately
$240.5 million from the issuance of five million shares of 6.75 percent
redeemable cumulative preferred stock.

- Capital expenditures of WCG, primarily for the construction of the
fiber-optic network, were $3.4 billion in 2000, $1.7 billion in 1999 and
$304 million in 1998.

- In 1999, WCG paid $265 million in cash to increase its investment in ATL
(a Brazilian telecommunications business).

OPERATING ACTIVITIES

Cash provided by continuing operating activities was: 2001 -- $1.8
billion; 2000 -- $594 million; and 1999 -- $1.5 billion. The 2001 $517.1 million
decrease in margin deposits is due primarily to lower deposits required by
counterparties related to trading activities at Energy Marketing & Trading. The
2001 $201.4 million increase in other current assets is due primarily to
increases associated with current derivative assets. The 2001 increase in other
assets and deferred charges of $455.0 million is due primarily to the increases
associated with noncurrent derivative assets and the minimum lease payments
receivable (net of an allowance for doubtful accounts) due from WCG related to
the long-term lease arrangement with WCG (see Note 3). The increase in
derivative assets reflects the impact of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," which requires these contracts
to be recorded at fair value.
64

FINANCING ACTIVITIES

Net cash provided by financing activities of continuing operations was:
2001 -- $2.0 billion; 2000 -- $2.0 billion; and 1999 -- $880 million. Long-term
debt proceeds, net of principal payments, were $1.9 billion, $235 million and
$682 million, during 2001, 2000 and 1999, respectively. Notes payable payments,
net of notes payable proceeds, were $801 million in 2001. Notes payable
proceeds, net of notes payable payments were $1.5 billion and $210 million
during 2000 and 1999, respectively. The increase in net new borrowings during
2001, 2000 and 1999 reflects borrowings to fund capital expenditures,
investments and acquisitions of businesses.

The proceeds from issuance of Williams common stock in 2001 reflect $1.3
billion in net proceeds from approximately 38 million shares of common stock
issued by Williams in January 2001 in a public offering at $36.125 per share.
Additionally, the proceeds from issuance of Williams common stock in 2001, 2000
and 1999 reflect exercise of stock options under the plans providing for
common-stock-based awards to employees and to non-employee directors.

Dividends paid on common stock increased $75.2 million in 2001 reflecting
an increase in the number of shares outstanding and an increase in the per share
dividends. The number of shares increased due primarily to the 38 million shares
issued in January 2001 and the 29.6 million shares issued in the Barrett
acquisition. Third-quarter 2001 and fourth-quarter 2001 dividends increased to
18 cents per share and 20 cents per share, respectively, up from the quarterly
dividend of 15 cents per share in 2000.

Proceeds from sale of limited partners units of consolidated partnership
reflect an initial public offering of Williams Energy Partners L.P. (WEP), a
wholly owned partnership which owns and operates a diversified portfolio of
energy assets, of approximately 4.6 million common units at $21.50 per unit for
net proceeds of approximately $92 million. The initial public offering
represents 40 percent of the units, and Williams retained a 60 percent interest
in the partnership, including its general partner interest.

In December 2001, Williams received net proceeds of $95.3 million from sale
of a non-controlling preferred interest in Piceance Production Holdings LLC to
an outside investor (see Note 14). During 2000, Williams received net proceeds
totaling $546.8 million from the sale of a limited liability company member
interest to an outside investor (see Note 14).

In April 2001, Williams redeemed the Williams obligated mandatorily
redeemable preferred securities of Trust holding only Williams indentures for
$194 million. Proceeds from the sale of the Ferrellgas senior common units held
by Williams were used for this redemption. In 1999, Williams received proceeds
of $175 million from the sale of the Williams obligated mandatorily redeemable
preferred securities.

In connection with the Barrett acquisition, Williams' Consolidated Balance
Sheet includes $150 million of 7.55 percent notes due 2007, which are debt
obligations guaranteed by Williams (parent). For further discussion of the
Barrett Resources Corporation acquisition, see Note 2.

Long-term debt at December 31, 2001 was $9.5 billion, compared with $6.8
billion at December 31, 2000 and $7.2 billion at December 31, 1999. At December
31, 2001 and 2000, $844 million and $800 million, respectively, of current debt
obligations were classified as noncurrent obligations based on Williams' intent
and ability to refinance on a long-term basis. The 2001 increase in long-term
debt is due primarily to the $1.1 billion of senior unsecured debt securities
issued in January 2001 and the $1.5 billion of long-term debt securities issued
in August 2001 primarily to replace $1.2 billion borrowed under a $1.5 billion
short-term agreement originated in June 2001 related to the cash portion of the
Barrett acquisition. The long-term debt to debt-plus-equity ratio (including
consolidated WCG debt for 2000 and 1999) was 61.1 percent at December 31, 2001,
compared to 63.7 percent and 62.3 percent at December 31, 2000 and 1999,
respectively. If short-term notes payable and long-term debt due within one year
were included in the calculations, these ratios would be 66.4 percent, 70.5
percent and 65.9, respectively. Additionally, the long-term debt to debt plus
equity as calculated for covenants under certain debt agreements was 61.5
percent at December 31, 2001.

In January 2002, Williams issued 44 million publicly traded units, more
commonly known as FELINE PACS, that include a senior debt security and an equity
purchase contract. The debt has a term of five years,

65

and the equity purchase contract will require the company to deliver Williams
common stock to holders after three years based on a previously agreed rate. Net
proceeds from this issuance were approximately $1.1 billion (see Note 23).

INVESTING ACTIVITIES

Net cash used by investing activities of continuing operations was:
2001 -- $3.5 billion; 2000 -- $2.3 billion; and 1999 -- $2.0 billion. Capital
expenditures of Energy Marketing & Trading, primarily to construct power
generation plants, were $104 million in 2001, $64 million in 2000 and $83
million in 1999. Capital expenditures of Energy Services, primarily to carry out
drilling programs and acquire, expand and modernize gathering and processing
facilities, terminals and refineries, were $931 million in 2001, $813 million in
2000 and $1.3 billion in 1999. Capital expenditures of Gas Pipeline, primarily
to expand deliverability into the east and west coast markets and upgrade
current facilities, were $855 million in 2001, $512 million in 2000 and $360
million in 1999. Budgeted capital expenditures and investments for continuing
operations for 2002 are estimated to be approximately $3.2 billion, including
expansion and modernization of pipeline systems, gathering and processing
facilities, refineries and international investment activities. Williams stated
in December 2001 that it had reduced its planned 2002 capital expenditure
program in an effort to maintain its investment grade rating. Additional
reductions may be necessary to maintain its investment grade rating, however,
Williams will evaluate other alternatives in order to maintain their capital
expenditure program including sales of additional assets.

On June 11, 2001, Williams acquired 50 percent of Barrett's outstanding
common stock in a cash tender offer of $73 per share for a total of
approximately $1.2 billion. On August 2, 2001, Williams completed the
acquisition of Barrett by issuing 29.6 million shares of Williams common stock
in exchange for the remaining Barrett shares.

The increase in investments is due primarily to the development of
Williams' joint interest in the Gulfstream project. The increase in proceeds
received from disposition of investments and other assets reflects Williams'
sale of the Ferrellgas senior common units to an affiliate of Ferrellgas for
proceeds of $199 million in April 2001 and the sale of certain convenience
stores for approximately $150 million in May 2001. The purchase of assets
subsequently leased to seller reflects Williams' purchase of the Williams
Technology Center, other ancillary assets and three corporate aircraft for $276
million.

In October 2000, Williams acquired various energy-related operations in
Canada for approximately $540 million. Included in the purchase were interests
in several NGL extraction and fractionation plants, NGL transportation pipeline
and storage facilities, and a natural gas processing plant.

During 1999, Williams purchased a business which includes a petrochemical
plant and natural gas liquids transportation, storage and other facilities for
$163 million in cash. Also during 1999, Williams made various cash investments
and advances totaling $347 million including a $75 million equity investment in
and a $75 million loan to AB Mazeikiu Nafta, Lithuania's national oil company,
$78 million in various natural gas and petroleum products pipeline joint
ventures, and other joint ventures and investments. In addition, Williams made
$139 million of investments in the Alliance natural gas pipeline and processing
plant during 1999 of which $93.5 million was financed with a note payable which
was paid in 2000. In December 1999, Williams sold its retail propane business to
Ferrellgas for $268.7 million in cash and $175 million in senior common units of
Ferrellgas.

66

COMMITMENTS

The table below summarizes some of the more significant contractual
obligations and commitments by period. This table does not include obligations
related to guarantees or payment obligations related to WCG (see Note 3).

- ---------------

(1) Amount relates to that invested by an outside investor for which the end of
the initial priority return period is shown.

(2) Energy Marketing & Trading has entered into certain contracts giving
Williams the right to receive fuel conversion services as well as certain
other services associated with electric generation facilities that are
either currently in operation or are to be constructed at various locations
throughout the continental United States. These contracts are included at
fair value within energy risk management and trading assets and liabilities.

Additionally, at December 31, 2001, commitments for construction and
acquisition of property, plant and equipment are approximately $771 million. At
December 31, 2001, commitments for additional investments in Gulfstream
Pipeline, LLC, certain international cost investments and advances to Longhorn
Partners Pipeline, L.P. are $233 million.

RECENTLY ISSUED ACCOUNTING STANDARDS AND POTENTIAL NEW ACCOUNTING STANDARDS

See Note 1 for a discussion of SFAS No. 141, "Business Combinations," SFAS
No. 142, "Goodwill and Other Intangible Assets," SFAS No. 143, "Accounting for
Asset Retirement Obligations" and SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets."

The accounting for Energy Marketing & Trading's energy-related contracts,
which include contracts such as transportation, storage, load servicing and
tolling agreements, requires Williams to assess whether certain of these
contracts are executory service arrangements or leases pursuant to SFAS No. 13,
"Accounting for Leases." There currently is not extensive authoritative guidance
for determining when an arrangement is a lease or an executory service
arrangement. As a result, Williams assesses each of its energy-related contracts
and makes the determination based on the substance of each contract focusing on
factors such as physical and operational control of the related asset, risks and
rewards of owning, operating and maintaining the related asset and other
contractual terms. The Emerging Issues Task Force of the Financial Accounting
Standards Board is in the preliminary stage of addressing Issue No. 01-8,
"Determining Whether an Arrangement is a Lease," and has assigned the Issue to a
Working Group for further consideration. As the Issue is in the preliminary
phase, the outcome and related impact to Williams is not yet determinable.

EFFECTS OF INFLATION

Williams' cost increases in recent years have benefited from relatively low
inflation rates during that time. Approximately 43 percent of Williams'
property, plant and equipment is at Gas Pipeline and approximately 55 percent is
at Energy Services. Approximately 87 percent of Gas Pipeline's and 60 percent of
Energy Services' property, plant and equipment has been acquired or constructed
since 1995, a period of relatively low

67

inflation. Approximately 17 percent of Energy Services' increase was the result
of the 2001 Barrett acquisition. 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, Williams believes it will be
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 the ability to recover such increased costs. Within
Energy Services, operating costs are influenced to a greater extent by specific
price changes in oil and gas and related commodities than by changes in general
inflation. Crude, refined product, natural gas and natural gas liquids prices
are particularly sensitive to OPEC production levels and/or the market
perceptions concerning the supply and demand balance in the near future.

ENVIRONMENTAL

Williams is a participant in certain environmental activities in various
stages involving assessment studies, cleanup operations and/or remedial
processes. The sites, some of which are not currently owned by Williams (see
Note 19), are being monitored by Williams, other potentially responsible
parties, the U.S. Environmental Protection Agency (EPA), or other governmental
authorities in a coordinated effort. In addition, Williams maintains an active
monitoring program for its continued remediation and cleanup of certain sites
connected with its refined products pipeline activities. Williams has both joint
and several liability in some of these activities and sole responsibility in
others. Current estimates of the most likely costs of such cleanup activities
are approximately $98 million, all of which is accrued at December 31, 2001.
Williams expects to seek recovery of approximately $42 million of the accrued
costs through future natural gas transmission rates. Williams will fund these
costs from operations and/or available bank-credit facilities. Estimates of the
most likely costs of cleanup are generally based on completed assessment
studies, preliminary results of studies or other similar cleanup operations. At
December 31, 2001, 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.

Williams is 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.
Williams is also subject to certain states' regulations. In September 1998, the
EPA promulgated rules designed to mitigate the migration of ground-level ozone
in certain states. Williams estimates that capital expenditures necessary to
install emission control devices over the next five years to comply with rules
will be between $186 million and $206 million. The actual costs incurred will
depend on the final implementation plans developed by each state to comply with
these regulations. In December 1999, standards promulgated by the EPA for
tailpipe emissions and the content of sulfur in gasoline were announced.
Williams estimates that capital expenditures necessary to bring its two
refineries into compliance over the next five years will be approximately $385
million. The actual costs incurred will depend on the final implementation
plans. In addition to the above mentioned capital expenditures pertaining to the
Clean Air Act and amendments, estimated future capital expenditures as of
December 31, 2001, for various compliance issues across the company are
approximately $202 million.

On July 2, 2001, the EPA issued an information request asking for
information on oil releases and discharges in any amount from Williams'
pipelines, pipeline systems, and pipeline facilities used in the movement of oil
or petroleum products, during the period July 1, 1998 through July 2, 2001. In
November 2001, Williams furnished its response.

In July 1999, Transco received a letter stating that the U.S. Department of
Justice (DOJ), at the request of the EPA, intends to file a civil action against
Transco arising from its waste management practices at Transco's compressor
stations and metering stations in 11 states from Texas to New Jersey. Transco,
the EPA and the DOJ agreed to settle this matter by signing a Consent Decree
that provides for a civil penalty of $1.4 million.

Williams Field Services (WFS), an Energy Services subsidiary, received a
Notice of Violation (NOV) from the EPA in February 2000. WFS received a
contemporaneous letter from the DOJ indicating that the DOJ will also be
involved in the matter. The NOV alleged violations of the Clean Air Act at a gas

68

processing plant. WFS, the EPA and the DOJ agreed to settle this matter for a
penalty of $850,000. In the course of investigating this matter, WFS discovered
a similar potential violation at the plant and disclosed it to the EPA and the
DOJ. In December 2001, the EPA, the DOJ and WFS agreed to settle this
self-reported matter by signing a Consent Decree that provides for a penalty of
$950,000.

OTHER

In January, 2002, Williams announced the goal to reduce the company's
annual operating expenses based on the company's current cost structure by $50
million, effective 2003. Management is evaluating its organizational structure
to determine effective and efficient ways to align services to meet Williams'
current business requirements as an energy-only company. In conjunction with
this goal, Williams is offering an enhanced-benefit early retirement option to
certain employee groups. The potential impact to 2002 expense, assuming election
by 100 percent of those eligible for the early retirement option, would be
approximately $80 million. Williams does not anticipate that all eligible
employees will elect the option. Additionally, Williams also will offer
severance and redeployment services to employees whose positions are eliminated
as a result of the organizational changes.

Williams has also announced plans to sell its midwest petroleum products
pipeline and on-system terminals. A potential buyer would be Williams Energy
Partners L.P., a consolidated entity.

69

ITEM 7A. MARKET RISK DISCLOSURES

Interest Rate Risk

Williams' current interest rate risk exposure is related primarily to its
debt portfolio and its energy risk management and trading portfolio. In 2000,
Williams' interest rate exposure also related to an investment in Ferrellgas
Partners L.P. senior common units and Williams obligated mandatorily redeemable
preferred securities of Trust.

Williams' interest rate risk exposure resulting from its debt portfolio is
influenced by short-term rates, primarily LIBOR-based borrowings from commercial
banks and the issuance of commercial paper, and long-term U.S. Treasury rates.
To mitigate the impact of fluctuations in interest rates, Williams targets to
maintain a significant portion of its debt portfolio in fixed rate debt.
Williams has also utilized interest-rate swaps to change the ratio of its fixed
and variable rate debt portfolio based on management's assessment of future
interest rates, volatility of the yield curve and Williams' ability to access
the capital markets in a timely manner. Williams periodically enters into
interest-rate forward contracts to establish an effective borrowing rate for
anticipated long-term debt issuances. The maturity of Williams' long-term debt
portfolio is partially influenced by the expected life of its operating assets.

At December 31, 2001 and 2000, the amount of Williams' fixed and variable
rate debt was at targeted levels. Williams has traditionally maintained an
investment grade credit rating as one aspect of managing its interest rate risk.
In order to fund its 2002 capital expenditure plan, Williams will need to access
various sources of liquidity, which will likely include traditional borrowing
and leasing markets.

Williams also has interest rate risk in long-dated energy-related contracts
included in its energy risk management and trading portfolio. The value of these
transactions can fluctuate daily based on movements in the underlying interest
rate curves used to assign value to the transactions. Williams strives to
mitigate the associated interest rate risk from the value of these transactions
by fixing the underlying interest rate inherent in the energy risk management
and trading portfolio. During 2001, Williams began actively managing this
exposure as a component of its targeted levels of fixed to floating obligations.
Williams uses both floating to fixed interest rate swaps and other derivative
transactions to manage this variable rate exposure.

The tables on the following page provide information as of December 31,
2001 and 2000, about Williams' interest rate risk sensitive instruments. For
investment in Ferrellgas Partners L.P. senior common units, notes payable,
long-term debt and Williams obligated mandatorily redeemable preferred
securities of Trust, the table presents principal cash flows and
weighted-average interest rates by expected maturity dates. For interest-rate
swaps, the table presents notional amounts and weighted-average interest rates
by contractual maturity dates. Notional amounts are used to calculate the
contractual cash flows to be exchanged under the interest-rate swaps.

70

- ---------------

(1) 2001 -- Weighted average interest rate is LIBOR plus one percent for all
years; 2000 -- Weighted average interest rate is LIBOR plus .70 percent for
all years.

(2) The interest rate swaps which are outstanding at December 31, 2001 are
reflected at fair value within energy risk management and trading assets and
liabilities in the Consolidated Balance Sheet as these swaps are entered
into to mitigate the interest rate risk inherent in the energy risk
management and trading portfolio. Notional amounts total approximately $1
billion at December 31, 2001.

(3) LIBOR

71

COMMODITY PRICE RISK

Energy Marketing & Trading has trading operations that incur commodity
price risk as a consequence of providing price-risk management services to
third-party customers. The most significant exposure to commodity price-risk is
associated with the natural gas and electricity markets in the United States.
This exposure is primarily within the portfolio of transportation, storage,
full-requirements, load serving and power tolling contracts. Energy Marketing &
Trading also has commodity price-risk exposure to crude oil, refined products,
electricity, natural gas and natural gas liquids markets in the United States
and the natural gas markets in Canada through other energy contracts such as
forward, futures, options, swaps, and purchase and sale contracts. These energy
and energy-related contracts are valued at fair value and unrealized gains and
losses from changes in fair value are recognized in income. These energy and
energy-related contracts are subject to risk from changes in energy commodity
market prices, volatility and correlation of those commodity prices, the
portfolio position of its contracts, the liquidity of the market in which the
contract is transacted and changes in interest rates. Energy Marketing & Trading
actively seeks to diversify its portfolio in managing the commodity price risk
in the transactions that it executes in various markets and regions by executing
offsetting contracts to manage this risk in accordance with parameters
established in its trading policy. Energy Marketing & Trading's Risk Control
Group monitors compliance with the established trading policy and measures the
risk associated with the trading portfolio.

Energy Marketing & Trading measures the market risk in its trading
portfolio utilizing a value-at-risk methodology to estimate the potential
one-day loss from adverse changes in the fair value of its trading operations.
At December 31, 2001 and 2000, the value at risk for the trading operations was
$92.7 million and $90.1 million, respectively. As supplemental quantitative
information to further understand the general risk levels of the trading
portfolio, the average of the actual monthly changes in the fair value of the
trading portfolio for 2001 was an increase of $120 million. 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 trading portfolio.
Energy Marketing & Trading's value-at-risk model includes all financial
instruments and physical positions and commitments in its trading portfolio and
assumes that as a result of changes in commodity prices, there is a 95 percent
probability that the one-day loss in the fair value of the trading portfolio
will not exceed the value at risk. The value-at-risk model uses historical
simulations to estimate hypothetical movements in future market prices assuming
normal market conditions based upon historical market prices. Value at risk does
not consider that changing the energy risk management and trading portfolio in
response to market conditions could affect market prices and could take longer
to execute than the one-day holding period assumed in the value-at-risk model.
Through risk management practices and policies, Energy Marketing & Trading was
able to minimize the increase in value at risk while growing the net energy risk
management and trading assets 179 percent. This was accomplished primarily
through the execution of offsetting contracts, which has the effect of
mitigating the commodity price risk exposure within the portfolio of energy and
energy-related contracts.

FOREIGN CURRENCY RISK

Williams has international investments that could affect the 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.

International investments accounted for under the cost method totaled $143
million and $144 million at December 31, 2001 and 2000, respectively. The fair
value of these investments is deemed to approximate their carrying amount as the
investments are primarily in non-publicly traded companies for which it is not
practicable to estimate the fair value of these investments. Williams continues
to believe that it 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 of these
investments at December 31, 2001, could change by approximately $29 million
assuming a direct correlation between the currency fluctuation and the value of
the investments.

72

The net assets of foreign operations which are consolidated are located
primarily in Canada and approximate 11 percent of Williams' net assets at
December 31, 2001. These foreign operations, whose functional currency is the
local currency, do not have significant transactions or financial instruments
denominated in other currencies. However, these investments do have the
potential to impact Williams' 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 $155 million at December 31, 2001.

Williams historically has 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 (see Note
18). However, Williams evaluates currency fluctuations and will consider the use
of derivative financial instruments or employment of other investment
alternatives if cash flows or investment returns so warrant.

EQUITY PRICE RISK

Equity price risk primarily arises from investments in publicly traded
energy-related companies. The investments in the energy-related companies are
carried at fair value and totaled approximately $8 million and $22 million at
December 31, 2001 and 2000, respectively.

73

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT AUDITORS

To the Stockholders of
The Williams Companies, Inc.

We have audited the accompanying consolidated balance sheet of The Williams
Companies, Inc. as of December 31, 2001 and 2000, and the related consolidated
statements of operations, stockholders' equity, and cash flows for each of the
three years in the period ended December 31, 2001. Our audits also included the
financial statement schedule listed in the Index at Item 14(a). These financial
statements and schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
schedule based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. 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, 2001 and 2000, and the consolidated
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States. Also, in our opinion, the related
financial statement schedule, when considered in relation to the basic financial
statements taken as a whole, present fairly in all material respects the
information set forth therein.

ERNST & YOUNG LLP

Tulsa, Oklahoma
March 6, 2002

74

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

- ---------------

* Includes consumer excise taxes of $308.9 million, $287.6 million and $229.0
million in 2001, 2000 and 1999, respectively.

See accompanying notes.

75

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED BALANCE SHEET

See accompanying notes.

76

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

See accompanying notes.
77

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

- ---------------

* Includes cash and cash equivalents of discontinued operations of $213.9
million and $483.9 million for 2000 and 1999, respectively.

See accompanying notes.

78

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

DESCRIPTION OF BUSINESS

Operations of The Williams Companies, Inc. (Williams) are located
principally in the United States and are organized into three industry groups:
Energy Marketing & Trading, Gas Pipeline and Energy Services.

Energy Marketing & Trading is a fully integrated energy marketer which
offers price-risk management services and buys, sells and arranges for
transportation/transmission of energy commodities -- including natural gas and
gas liquids, crude oil and refined products, and electricity -- to local
distribution companies, utilities, municipalities, rural electric cooperatives
and large industrial customers in North America. Additionally, Energy Marketing
& Trading commenced operations in Europe in 2001.

Gas Pipeline is comprised primarily of five interstate natural gas
pipelines located throughout the majority of the United States as well as
investments in North American natural gas pipeline-related companies. The five
Gas Pipeline operating segments have been aggregated for reporting purposes and
include Williams Gas Pipelines Central, Kern River Gas Transmission, Northwest
Pipeline, Texas Gas Transmission and Transcontinental Gas Pipe Line.

Energy Services includes five operating segments: Exploration & Production,
International, Midstream Gas & Liquids, Petroleum Services and Williams Energy
Partners. Exploration & Production includes natural gas exploration, production
and marketing activities primarily in the Rocky Mountain, Midwest and Gulf Coast
regions. During 2001, Exploration & Production acquired Barrett Resources
Corporation (Barrett) which was an independent natural gas and oil exploration
and production company with producing properties located principally in the
Rocky Mountain and Mid-Continent regions of the United States. International
includes direct investments in projects in Argentina, Brazil, Venezuela and
Lithuania, investments in energy and infrastructure development funds in Asia
and South America and soda ash mining operations in Colorado. Midstream Gas &
Liquids is comprised of natural gas gathering and processing and treating
facilities in the Rocky Mountain, Midwest and Gulf Coast regions of the United
States, natural gas liquids pipelines in the Rocky Mountain, Southwest, Midwest
and Gulf Coast regions of the United States and assets in Canada including
several natural gas liquids extraction and fractionation plants, natural gas
liquids pipeline, storage facilities, and a natural gas processing plant.
Petroleum Services includes petroleum refining and marketing in Alaska and the
Southeast, a petroleum products pipeline and ethanol production and marketing
operations in the Midwest region, and retail travel centers concentrated in the
Midsouth and along the United States interstate highway system and convenience
stores in Alaska. Williams Energy Partners includes a network of storage,
transportation and distribution assets for crude petroleum products and ammonia.

BASIS OF PRESENTATION

Effective February 2001, management of certain operations, previously
conducted by Energy Marketing & Trading, was transferred to Petroleum Services.
These operations included the procurement of crude oil and marketing of refined
products produced from the Memphis refinery, for which prior year segment
information reflects the transfer. Additionally, the refined product sales
activities surrounding certain terminals located throughout the United States
were transferred. This sales activity was previously included in the trading
portfolio of Energy Marketing & Trading and was therefore reported net of
related cost of sales. Following the transfer, these sales are reported on a
"gross" basis.

During first-quarter 2001, Williams Energy Partners L.P. completed an
initial public offering of approximately 4.6 million common units at $21.50 per
unit for net proceeds of approximately $92 million. The initial public offering
represents 40 percent of the units, and Williams retains a 60 percent interest
in the partnership, including its general partner interest. Williams Energy
Partners L.P. and Williams' general partnership interest is reported as Williams
Energy Partners, a separate segment within Energy Services, and consists
primarily of certain terminals and an ammonia pipeline previously reported
within Petroleum Services

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and Midstream Gas & Liquids, respectively. Also during first-quarter 2001,
management of international activities, previously reported in Other, was
transferred and the international activities are reported as a separate segment
within Energy Services.

On April 23, 2001, Williams distributed 398.5 million shares, or
approximately 95 percent, of Williams' communications business, Williams
Communications Group, Inc. (WCG), to Williams' shareholders. WCG has been
accounted for as discontinued operations, and, accordingly, the accompanying
consolidated financial statements and notes reflect the results of operations,
net assets and cash flows of WCG as discontinued operations. For information
relating to litigation involving the distribution of WCG shares, see Note 19.
Unless indicated otherwise, the information in the Notes to Consolidated
Financial Statements relates to the continuing operations of Williams (see Note
3).

Certain prior year amounts have been reclassified to conform to current
year classifications.

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of Williams and
its majority-owned subsidiaries and investments. Companies in which Williams and
its 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, are accounted for under the equity method.

USE OF ESTIMATES

The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results could differ from
those estimates.

Estimates and assumptions which, in the opinion of management, are
significant to the underlying amounts included in the financial statements and
for which it would be reasonably possible that future events or information
could change those estimates include: 1) contingent obligations including
guarantees related to WCG obligations; 2) litigation-related contingencies; 3)
valuations of energy contracts, including energy-related contracts; 4)
environmental remediation obligations; 5) impairment assessments of goodwill and
long-lived assets; 6) realization of deferred income tax assets; and 7) Gas
Pipeline revenues subject to refund. These estimates are discussed further
throughout the accompanying notes.

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.

INVENTORY VALUATION

Inventories are stated at cost, which is not in excess of market, except
for certain assets held for energy risk management activities by Energy
Marketing & Trading, which are primarily stated at fair value. The cost of
inventories is determined using the following methods: certain crude oil and
refined products inventories held by Petroleum Services are determined using the
first-in, first-out (FIFO) cost method as adjusted for the effects of fair value
hedges as prescribed by Statement of Financial Accounting Standards (SFAS) No.
133, "Accounting for Derivative Instruments and Hedging Activities;" certain
natural gas inventories held by Transcontinental Gas Pipe Line are determined
using the last-in, first-out (LIFO) cost method; and the cost of the remaining
inventories is primarily determined 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. Depreciation is provided
primarily on the straight-line method over estimated useful lives. 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.

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 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.

Proved properties, including developed and undeveloped, and costs
associated with probable reserves, are assessed for impairment using estimated
future cash flows. Estimating future cash flows involves the use of complex
judgments such as estimation of the proved and probable 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.

GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill represents the excess of cost over fair value of assets of
businesses acquired. In accordance with SFAS No. 142, "Goodwill and Other
Intangible Assets," approximately $1 billion of goodwill acquired subsequent to
June 30, 2001, in the acquisition of Barrett (see Note 2) is not being
amortized. All other goodwill is amortized on a straight-line basis over periods
from 20 to 40 years. Other intangible assets are amortized on a straight-line
basis over periods from three to 25 years. Accumulated amortization at December
31, 2001 and 2000 was $16.3 million and $45.2 million, respectively.
Amortization expense was $7 million, $10.7 million and $20.4 million in 2001,
2000 and 1999, respectively. See RECENT ACCOUNTING STANDARDS for further
discussion of SFAS No. 142.

TREASURY STOCK

Treasury stock purchases are accounted for under the cost method whereby
the entire cost of the acquired stock is recorded as treasury stock. Gains and
losses on the subsequent reissuance of shares are credited or charged to capital
in excess of par value using the average-cost method.

ENERGY COMMODITY RISK MANAGEMENT AND TRADING ACTIVITIES

Energy Marketing & Trading has energy commodity risk management and trading
operations that enter into energy contracts to provide price-risk management
services to its third-party customers. Energy contracts utilized in energy
commodity risk management and trading activities are valued at fair value in
accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," and Emerging Issues Task Force Issue (EITF) No. 98-10, "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities."
Williams adopted SFAS No. 133 effective January 1, 2001. Such adoption had no
impact on the accounting for energy commodity risk management and trading
activities. Prior to adopting SFAS No. 133, Energy Marketing & Trading followed
the guidance in EITF No. 98-10. Energy contracts include forward contracts,
futures contracts, option contracts, swap agreements, commodity inventories,
short-and long-term purchase and sale commitments, which involve physical
delivery of an energy commodity and energy-related contracts, such as
transportation, storage, full requirements, load serving and power tolling
contracts. In addition, Williams enters into interest rate swap agreements and
credit default swaps to manage

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the interest rate and credit risk in its energy trading portfolio. These energy
contracts and interest rate and credit default swap agreements, with the
exception of certain commodity inventories, are recorded in current and
noncurrent energy risk management and trading assets and energy risk management
and trading liabilities in the Consolidated Balance Sheet. The classification of
current versus noncurrent is based on the timing of expected future cash flows.
In accordance with SFAS No. 133 and EITF No. 98-10, the net change in fair value
of these contracts representing unrealized gains and losses is recognized in
income currently and recorded as revenues in the Consolidated Statement of
Operations. Energy Marketing & Trading reports its trading operations' physical
sales transactions net of the related purchase costs, consistent with fair value
accounting for such trading activities. The accounting for Energy Marketing &
Trading's energy-related contracts requires Williams to assess whether certain
of these contracts are executory service arrangements or leases pursuant to SFAS
No. 13, "Accounting for Leases." There currently is not extensive authoritative
guidance for determining when an arrangement is a lease or an executory service
arrangement. As a result, Williams assesses each of its energy-related contracts
and makes the determination based on the substance of each contract focusing on
factors such as physical and operational control of the related asset, risks and
rewards of owning, operating and maintaining the related asset and other
contractual terms.

Fair value of energy contracts is determined based on the nature of the
transaction and the market in which transactions are executed. Certain
transactions are executed in exchange-traded or over-the-counter markets for
which quoted prices in active periods exist. Transactions are also executed in
exchange-traded or over-the-counter markets for which quoted market prices may
exist; however, the markets may be relatively inactive and price transparency is
limited. Certain transactions are executed for which quoted market prices are
not available. Quoted market prices for varying periods in active markets are
readily available for valuing forward contracts, futures contracts, swap
agreements and purchase and sales transactions in the commodity markets in which
Energy Marketing & Trading transacts. For contracts or transactions that extend
into periods for which actively quoted prices are not available, Energy
Marketing & Trading estimates energy commodity prices in the illiquid periods by
incorporating information obtained from commodity prices in actively quoted
markets, prices reflected in current transactions and market fundamental
analysis. For contracts where quoted market prices are not available, primarily
transportation, storage, full requirements, load serving and power tolling
contracts, Energy Marketing & Trading estimates fair value using models and
other valuation techniques that reflect the best information available under the
circumstances. Fair value for energy-related contracts is estimated using
valuation techniques that incorporate option pricing theory, statistical and
simulation analysis, present value concepts incorporating risk from uncertainty
of the timing and amount of estimated cash flows and specific contractual terms.
These valuation techniques utilize factors such as 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 is transacted, and a risk-free market discount rate. Fair value also
reflects a risk premium that market participants would consider in their
determination of fair value. Regardless of the method for which fair value is
determined, the recognized fair value of all contracts also considers the risk
of non-performance and credit considerations of the counterparty.

In some cases, Energy Marketing & Trading enters into price-risk management
contracts that have forward start dates commencing upon completion of
construction and development of assets to be owned and operated by third
parties. Until construction commences, revenue recognition and the fair value of
these contracts is limited to the amount of any guaranty or similar form of
acceptable credit support that encourages the counterparty to perform under the
terms of the contract with appropriate consideration for any contractual
provisions that provide for contract termination by the counterparty.

The fair value of Energy Marketing & Trading's trading portfolio is
continually subject to change due to changing market conditions and changing
trading portfolio positions. Determining fair value for these contracts also
involves complex assumptions including estimating natural gas and power market
prices in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

illiquid periods and markets, estimating volatility 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.

GAS PIPELINE REVENUES

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 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.

ENERGY SERVICES REVENUES

Revenues generally are recorded when services have been performed or
products have been delivered. A portion of Petroleum Services is subject to FERC
regulations and, accordingly, the method of recording these revenues is
consistent with Gas Pipeline's method discussed above.

Additionally, revenues from the production of natural gas in properties for
which Exploration & Production has an interest with other producers, are
recognized based on the actual volumes sold during the period. Any differences
between volumes sold and entitlement volumes, based on Exploration &
Production's net working interest, 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.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

On January 1, 2001, Williams adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." This standard, as amended, did
not impact the accounting for derivatives within Energy Marketing & Trading's
energy commodity risk management and trading activities which are accounted for
at fair value as discussed above. All other derivatives are reflected on the
balance sheet at their fair value and are recorded in other current assets,
other assets and deferred charges, accrued liabilities and other liabilities and
deferred income in the Consolidated Balance Sheet as of December 31, 2001.

Derivative instruments held by Williams, other than those utilized in the
energy risk management and trading activities, consist primarily of futures
contracts, swap agreements, forward contracts and option contracts. Most of
these transactions are executed in exchange-traded or over-the-counter markets
for which quoted prices in active periods exist. For contracts with lives
exceeding the time period for which quoted prices are available, fair value
determination involves estimating commodity prices during the illiquid periods
by incorporating information obtained from commodity prices in actively quoted
markets, prices reflected in current transactions and market fundamental
analysis.

The accounting for changes in the fair value of a derivative depends upon
whether it has been designated in a hedging relationship and, further, on the
type of hedging relationship. To qualify for designation in a hedging
relationship, specific criteria must be met and the appropriate documentation
maintained. Hedging relationships are established pursuant to Williams' risk
management policies and are initially and regularly evaluated to determine
whether they are expected to be, and have been, highly effective hedges. If a
derivative ceases to be a highly effective hedge, hedge accounting is
discontinued prospectively, and future changes in the fair value of the
derivative are recognized in earnings each period. Changes in the fair value of
derivatives not designated in a hedging relationship are recognized in earnings
each period.

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

For derivatives designated as a hedge of a recognized asset or liability or
an unrecognized firm commitment (fair value hedges), 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 are recognized each period in earnings. If a
firm commitment designated as the hedged item in a fair value hedge is
terminated or otherwise no longer qualifies as the hedged item, any asset or
liability previously recorded as part of the hedged item is recognized currently
in earnings.

For derivatives designated as a hedge of a forecasted transaction or of the
variability of cash flows related to a recognized asset or liability (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 change in fair
value of the derivative are recognized currently in earnings. Gains or losses
deferred in accumulated other comprehensive income associated with terminated
derivatives and derivatives that cease to be highly effective hedges remain in
accumulated other comprehensive income until the hedged item affects earnings.
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.
If the forecasted transaction is no longer probable of occurring, any gain or
loss deferred in accumulated other comprehensive income is recognized in
earnings currently.

On January 1, 2001, Williams recorded a cumulative effect of an accounting
change associated with the adoption of SFAS No. 133, as amended, to record all
derivatives at fair value. The cumulative effect of the accounting change was
not material to net income (loss), but resulted in a $95 million reduction of
other comprehensive income (net of income tax benefits of $59 million) related
to derivatives which hedge the variable cash flows of certain forecasted energy
commodity transactions. Of the transition adjustment recorded in other
comprehensive income at January 1, 2001, net losses of approximately $90 million
(net of income tax benefits of $56 million) were reclassified into earnings
during 2001, offsetting net gains realized in earnings from favorable market
movements associated with the underlying transactions being hedged.

With the adoption of SFAS No. 133 on January 1, 2001, the accounting for
certain aspects of derivative instruments and hedging activities was different
in periods prior to the adoption of SFAS No. 133. Prior to 2001, Williams
entered into energy derivative financial instruments and derivative commodity
instruments (primarily futures contracts, option contracts and swap agreements)
to hedge against market price fluctuations of certain commodity inventories and
sales and purchase commitments. Certain of these instruments were not required
to be recorded on the balance sheet; there was not a distinction between cash
flow and fair value hedges and no ineffectiveness was required to be recorded
currently in earnings. Unrealized and realized gains and losses on those hedge
contracts were deferred and recognized in income in the same manner as the
hedged item. No unrealized gains or losses were required to be reported in other
comprehensive income. These contracts were initially and regularly evaluated to
determine that there was high correlation between changes in the fair value of
the hedge contract and fair value of the hedged item. In instances where the
anticipated correlation of price movements did not occur, hedge accounting was
terminated and future changes in the value of the instruments were recognized as
gains or losses. If the hedged item of the underlying transaction was sold or
settled, the instrument was recognized into income (loss).

Williams entered into interest-rate swap agreements to modify the interest
characteristics of its long-term debt. These agreements were designated with all
or a portion of the principal balance and term of specific debt obligations.
These agreements involved the exchange of amounts based on a fixed interest rate
for amounts based on variable interest rates without an exchange of the notional
amount upon which the payments are based. The difference to be paid or received
was accrued and recognized as an adjustment of interest accrued. Gains and
losses from terminations of interest-rate swap agreements were deferred and
amortized as an adjustment of the interest expense on the outstanding debt over
the remaining original term of the terminated

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

swap agreement. In the event the designated debt was extinguished, gains and
losses from terminations of interest-rate swap agreements were recognized into
income (loss).

MAJOR MAINTENANCE COSTS

Williams incurs planned major maintenance costs at its two refineries and
an ethylene production facility and accrues for these costs in advance of the
period in which costs are actually incurred. For the refineries, such repairs
are completed over a planned cycle of five to six years, with modular components
completed each year. For the ethylene facility, major maintenance repairs are
scheduled to occur approximately every four years. At December 31, 2001, the
total expected cost of the major maintenance projects was approximately $40
million for the refineries and approximately $6 million for the ethylene
production facility. The balance of costs to be accrued is approximately $28
million for the refineries and $5 million for the ethylene production facility
over the 2002-2005 period.

Accruals are initiated upon completion of the most recent major maintenance
project. These projects are completed over periods of several days to several
weeks, with annual accruals in advance of costs actually being incurred expected
to total approximately $7 million for the refineries and approximately $2
million for the ethylene production facility over the 2002-2005 period.

IMPAIRMENT OF LONG-LIVED ASSETS

Williams evaluates the long-lived assets, including other intangibles and
related goodwill, of identifiable business activities for impairment when events
or changes in circumstances indicate, in management's judgment, that the
carrying value of such assets may not be recoverable. When such a determination
has been made, management's estimate of undiscounted future cash flows
attributable to the assets is compared to the carrying value of the assets to
determine whether an impairment has occurred. If an impairment of the carrying
value has occurred, the amount of the impairment recognized in the financial
statements is determined 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, the carrying value
of these assets is compared 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 is redetermined when related events or
circumstances change.

Judgments and assumptions are inherent in management's estimate of
undiscounted future cash flows used to determine recoverability of an asset and
the estimate of an asset's fair value used to calculate the amount of impairment
to recognize. The use of alternate judgments and/or assumptions could result in
the recognition of different levels of impairment charges in the financial
statements.

CAPITALIZATION OF INTEREST

Williams capitalizes 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 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.

EMPLOYEE STOCK-BASED AWARDS

Employee stock-based awards are accounted for under Accounting Principles
Board Opinion (APB) 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.

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

INCOME TAXES

Williams includes the operations of its subsidiaries in its 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 Williams' assets and liabilities. Management's judgment and income
tax assumptions are used to determine the levels, if any, of valuation
allowances associated with deferred tax assets.

EARNINGS PER SHARE

Basic earnings per share are based on the sum of the average number of
common shares outstanding and issuable restricted and deferred shares. Diluted
earnings per share include any dilutive effect of stock options and, for
applicable periods presented, convertible preferred stock.

FOREIGN CURRENCY TRANSLATION

The functional currency of Williams is the U.S. dollar. The functional
currency of certain of Williams' continuing foreign operations is the local
currency for the applicable foreign subsidiary or equity method investee. These
foreign currencies include the Canadian dollar, British pound, Euro, and
Brazilian real. 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 Williams' share of
the results of operations of its equity affiliates are translated 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 equity, common stock or limited partnership units, 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.

SECURITIZATIONS AND TRANSFERS OF FINANCIAL INSTRUMENTS

Williams has agreements to sell, on an ongoing basis, certain of its trade
accounts receivable through revolving securitization structures and retains
servicing responsibilities as well as a subordinate interest in the transferred
receivables. Williams accounts for the securitization of trade accounts
receivable in accordance with SFAS No. 140, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities." As a result,
the related receivables are removed from the Consolidated Balance Sheet and a
retained interest is recorded for the amount of receivables sold in excess of
cash received.

Williams determines the fair value of its retained interests based on the
present value of future expected cash flows using management's best estimates of
various factors, including credit loss experience and discount rates
commensurate with the risks involved. These assumptions are updated periodically
based on actual results, thus the estimated credit loss and discount rates
utilized are materially consistent with historical performance. The fair value
of the servicing responsibility is estimated based on internal costs, which
approximate market. Costs associated with the sale of receivables are included
in nonoperating other income (expense) -- net in the Consolidated Statement of
Operations.

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

RECENT ACCOUNTING STANDARDS

The Financial Accounting Standards Board (FASB) issued SFAS No. 141,
"Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible
Assets." SFAS No. 141 establishes accounting and reporting standards for
business combinations and requires all business combinations to be accounted for
by the purchase method. The Statement is effective for all business combinations
initiated after June 30, 2001, and any business combinations accounted for using
the purchase method for which the date of acquisition is July 1, 2001, or later.
SFAS No. 142 addresses accounting and reporting standards for goodwill and other
intangible assets. Under the provisions of this Statement, goodwill and
intangible assets with indefinite useful lives are no longer amortized, but will
be tested annually for impairment. Williams applied the new rules on accounting
for goodwill and other intangible assets beginning January 1, 2002. Application
of the nonamortization provisions of the Statement will not materially impact
the comparability of the Consolidated Statement of Operations. During
first-quarter 2002, Williams began the initial impairment tests of goodwill as
of January 1, 2002. Preliminary results of these tests have indicated that there
will not be a significant unfavorable impact of adopting this standard; however,
all tests have not been completed. Approximately $1 billion of goodwill recorded
as a result of the Barrett acquisition completed on August 2, 2001, (see Note 2)
is not being amortized.

The FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This Statement addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs and amends FASB Statement No. 19, "Financial
Accounting and Reporting by Oil and Gas Producing Companies." The Statement
requires that the fair value of a liability for an asset retirement obligation
be recognized in the period in which it is incurred if a reasonable estimate of
fair value can be made, and that the associated asset retirement costs be
capitalized as part of the carrying amount of the long-lived asset. The
Statement is effective for financial statements issued for fiscal years
beginning after June 15, 2002. The effect of this standard on Williams' results
of operations and financial position is being evaluated. While it is likely
there will ultimately be material obligations related to the future retirement
of assets such as refineries and pipelines, Williams cannot currently estimate
the financial impact at the date of adoption as Williams has not yet completed
its evaluation. However, it is Williams' belief that any such impact would be a
charge to earnings.

The FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." This Statement supersedes SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of,"
and amends Accounting Principles Board Opinion No. 30, "Reporting the Results of
Operations -- Reporting the Effects of Disposal of a Segment of a Business and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions." The
Statement retains the basic framework of SFAS No. 121, resolves certain
implementation issues of SFAS No. 121, extends applicability to discontinued
operations, and broadens the presentation of discontinued operations to include
a component of an entity. The Statement is being applied prospectively,
beginning January 1, 2002. Initial adoption of the Statement did not have any
impact on Williams' results of operations or financial position.

NOTE 2. BARRETT ACQUISITION

Through two transactions, Williams acquired all of the outstanding stock of
Barrett. On June 11, 2001, Williams acquired 50 percent of Barrett's outstanding
common stock in a cash tender offer of $73 per share for a total of
approximately $1.2 billion. Williams acquired the remaining 50 percent of
Barrett's outstanding common stock on August 2, 2001, through a merger by
exchanging each remaining share of Barrett common stock for 1.767 shares of
Williams common stock for a total of approximately 30 million shares of Williams
common stock valued at $1.2 billion. The value of the 30 million shares of
Williams common stock was based on the average market price of Williams common
stock for the 2 days before and after the May 7, 2001, announcement of the terms
of the acquisition. This acquisition has been accounted for as a purchase
business

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

combination with a purchase price, including transaction fees and other related
costs, of approximately $2.5 billion, excluding $312 million of debt obligations
of Barrett assumed in the acquisition.

Williams' 50 percent share of Barrett's results of operations for the
period June 11, 2001 to August 1, 2001, as well as amortization of the excess of
Williams' investment over the underlying equity in Barrett's net assets for that
period, is included in equity earnings within investing income (loss) in the
Consolidated Statement of Operations and Exploration & Production's segment
profit. Beginning August 2, 2001, 100 percent of Barrett's results of operations
is included in Exploration & Production's revenues and operating income in the
Consolidated Statement of Operations, and the majority of these assets are
included in Exploration & Production's segment assets.

As of August 2, 2001, Barrett's estimated proved gas and oil reserves were
1.9 trillion cubic feet of gas equivalents. Barrett's assets included long-lived
reserves that Williams believes offer opportunity for long-term and steady
growth and align strategically with Williams' other assets. Williams is a major
gatherer and processor in the Rockies and has natural gas pipelines and gas
liquids pipelines that transport product out of the Rockies. In addition, these
new gas reserves help to balance the risk profile of Williams' growing power
trading portfolio by providing an additional physical and natural hedge against
a short natural gas position. As a result of the value that the Barrett
acquisition provides to Williams overall, $1.0 billion of goodwill was allocated
to Exploration & Production and $105.5 million was allocated to Energy Marketing
& Trading.

The following unaudited pro forma information combines the results of
operations of Williams and Barrett and incorporates the impact of the Williams
shares issued as if the purchase of 100 percent of Barrett occurred at the
beginning of each year presented:

Pro forma financial information is not necessarily indicative of results of
operations that would have occurred if the acquisition had occurred at the
beginning of each year presented or of future results of operations of the
combined companies.

The following table summarizes the estimated fair values of the assets
acquired and liabilities assumed at the date of acquisition. Fair value is
determined based on the nature of the asset acquired or liability assumed and
utilizes judgments and assumptions of management. Where available, exchange
quoted energy commodity market prices and current interest rate levels were
used. When the contract life or estimated reserve life exceeds the time period
for which quoted prices are available, judgment is used to estimate the energy
commodity prices during the illiquid periods by incorporating information
obtained from commodity prices in actively quoted markets, prices reflected in
current transactions and market fundamental analysis. Complex judgments also
include estimation of the oil and gas reserve quantities, risk associated with
the different

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categories of oil and gas reserves, timing of development and production of oil
and gas reserves, oil and gas capital expenditures necessary to develop the
reserves, production costs and discount rate.

NOTE 3. DISCONTINUED OPERATIONS

EVENTS AROUND THE WCG SEPARATION AND OTHER RELATED INFORMATION

On March 30, 2001, Williams' board of directors approved a tax-free spinoff
of WCG to Williams' shareholders. Williams distributed 398.5 million shares, or
approximately 95 percent of the WCG common stock held by Williams, to holders of
record on April 9, 2001, of Williams' common stock. Distribution of .822399 of a
share of WCG common stock for each share of Williams common stock occurred on
April 23, 2001.

Williams, prior to the spinoff and in an effort to strengthen WCG's capital
structure, entered into an agreement under which Williams contributed an
outstanding promissory note from WCG of approximately $975 million and certain
other assets, including a building under construction and a commitment to
complete the construction. In return, Williams received 24.3 million newly
issued common shares of WCG.

The WCG common stock distribution was recorded as a dividend and resulted
in a decrease to consolidated stockholders' equity of approximately $2.0
billion, which included an increase to accumulated other comprehensive income of
approximately $21.3 million. The WCG shares retained by Williams are included in
investments in the Consolidated Balance Sheet. In third-quarter 2001, Williams
recognized a $70.9 million loss related to the write-down of this investment due
to the decline in value which was determined to be other than temporary (see
Note 4). At year-end, Williams wrote off its remaining $25 million investment in
WCG common stock as discussed further below. Additionally, receivables include
amounts due from WCG of approximately $27 million, net of allowance of $85
million, at December 31, 2001. This amount includes a $21 million deferred
payment (net of allowance of $85 million) for services provided to WCG due March
15, 2002. In February 2002, the deferred payment from WCG was extended to
September 15, 2002.

Williams, prior to the spinoff, provided indirect credit support for $1.4
billion of WCG's Note Trust Notes through a commitment to make available
proceeds of a Williams equity issuance or other permitted redemption sources in
the event any one of the following were to occur: (1) a WCG default; (2)
downgrading of Williams' senior unsecured debt to Ba1 or below by Moody's
Investor's Service, BB or below by Standard &

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Poor's, or BB+ or below by Fitch Ratings, if Williams' common stock closing
price is below $30.22 for ten consecutive trading days while such downgrade is
in effect; or (3) to the extent proceeds from WCG's refinancing or remarketing
of certain structured notes prior to March 2004 produces proceeds of less than
$1.4 billion. On March 5, 2002, Williams received the requisite approvals on its
consent solicitation to amend the terms of the WCG Note Trust Notes. The
amendment, among other things, eliminates acceleration of the WCG Note Trust
Notes due to a WCG bankruptcy or from a Williams credit rating downgrade. The
amendment also affirms Williams' obligations for all payments due with respect
to the WCG Note Trust Notes, which are due March, 2004, and allows Williams to
fund such payments from any available sources. With the exception of the March
and September 2002 interest payments, totaling $115 million, WCG remains
indirectly obligated to reimburse Williams for any payments Williams is required
to make in connection with the Structured Notes.

Williams has provided a guarantee of WCG's obligations under a 1998
transaction in which WCG entered into an operating lease agreement covering a
portion of its fiber-optic network. The total cost of the network assets covered
by the lease agreement is $750 million. The lease term initially totaled five
years and, if renewed, could extend to seven years. WCG has an option to
purchase the covered network assets during the lease term at an amount
approximating lessor's cost. On March 6, 2002, a representative of WCG notified
Williams that WCG intends to issue a notice so as to be able to purchase the
assets in the immediate future. As a result of an agreement between Williams and
WCG's revolving credit facility lenders, if Williams gains control of the
network assets covered by the lease, Williams may be obligated to return the
assets to WCG and the liability of WCG to compensate Williams for such property
may be subordinated to the interests of WCG's revolving credit facility lenders
and may not mature any earlier than one year after the maturity of WCG's
revolving credit facility.

Williams has also provided guarantees on certain performance obligations of
WCG totaling approximately $57 million.

Williams has received a private letter ruling from the Internal Revenue
Service (IRS) stating that the distribution of WCG common stock would be
tax-free to Williams and its stockholders. Although private letter rulings are
generally binding on the IRS, Williams will not be able to rely on this ruling
if any of the factual representations or assumptions that were made to obtain
the ruling are, or become, incorrect or untrue in any material respect. However,
Williams is not aware of any facts or circumstances that would cause any of the
representations or assumptions to be incorrect or untrue in any material
respect. The distribution could also become taxable to Williams, but not
Williams shareholders, under the Internal Revenue Code (IRC) in the event that
Williams' or WCG's subsequent business combinations were deemed to be part of a
plan contemplated at the time of distribution and would constitute a total
cumulative change of more than 50 percent of the equity interest in either
company.

Under the terms of an amended tax-sharing agreement between WCG and
Williams, WCG will remain liable to Williams for federal and state income tax
audit adjustments relating to the period from October 1, 1999, through the date
of the spinoff, but will not be responsible for any interest accruing through
2005 on such tax deficiencies. With regard to the tax-free status of the
spinoff, Williams will have the overall risk that the transaction is tax free,
but WCG will have liability to Williams if WCG causes the spinoff to be taxable.
Additionally, WCG and Williams have each agreed to be separately responsible for
any tax resulting from actions taken by its respective company that violate the
IRC requirement relating to a more than 50 percent change in equity interest in
either company discussed above and to mutually monitor activities of both
companies with respect to this requirement.

As part of the separation of Williams and WCG, both companies entered into
service agreements to support ongoing operations of WCG relating primarily to
certain human resources services, buildings and facilities, administrative and
strategic sourcing services and information technology. Many of these service
agreements expired at the end of 2001, however, certain of the agreements are
longer in term and some

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

agreements have been amended to extend the terms into 2002. As these service
agreements expire, the fees and reimbursements that are paid by WCG will also
cease.

Williams, with respect to shares of WCG's common stock that Williams
retained, has committed to the IRS to dispose of all of the WCG common stock
that it retains as soon as market conditions allow, but in any event not longer
than five years after the spinoff. As part of a separation agreement, but
subject to an additional favorable ruling by the IRS that such a limitation is
not inconsistent with any ruling issued to Williams regarding the tax-free
treatment of the spinoff, Williams agreed not to dispose of the retained WCG
shares for three years from the date of distribution and to notify WCG of an
intent to dispose of such shares. However, on February 28, 2002, Williams filed
with the IRS a request to withdraw its request for a ruling that the agreement
between Williams and WCG that Williams would not transfer any retained WCG stock
for a three year period from the spinoff would not be inconsistent with the
favorable tax-free treatment ruling issued to Williams. Williams represented in
the withdrawal request that it had abandoned its intent to make the lock-up
effective, thereby making the ruling request moot.

SIGNIFICANT EVENTS OCCURRING AFTER THE SEPARATION

In third-quarter 2001, Williams purchased the Williams Technology Center
and other ancillary assets (Technology Center) and three corporate aircraft from
WCG for $276 million, which represents the approximate actual cost of
construction of the Williams Technology Center and the acquisition costs of the
ancillary assets and aircraft. Williams then entered into long-term lease
arrangements under which WCG is the sole lessee of the Technology Center and
aircraft (see Note 13). As a result of this transaction, Williams' Consolidated
Balance Sheet includes $28.8 million in current accounts and notes receivable
and $137.2 million in noncurrent other assets and deferred charges, net of
allowance of $103.2 million, relating to amounts due from WCG (see Note 13).

For information relating to litigation involving the distribution of WCG
shares see Note 19.

Recent disclosures and announcements by WCG, including WCG's recent
announcement that it might seek to reorganize under the U.S. Bankruptcy Code,
have resulted in Williams concluding that it is probable that it will not fully
realize the $375 million of receivables from WCG at December 31, 2001 nor
recover its remaining $25 million investment in WCG common stock. In addition,
Williams has determined that it is probable that it will be required to perform
under the $2.21 billion of guarantees and payments obligations discussed above.
Other events that have affected Williams' assessment include the credit
downgrades of WCG, the bankruptcy of a significant competitor announced on
January 28, 2002, and public statements by WCG regarding an ongoing
comprehensive review of its bank secured credit arrangements. As a result of
these factors, Williams, using the best information available at the time and
under the circumstances, has developed an estimated range of loss related to its
total WCG exposure. Management utilized the assistance of external legal counsel
and an external financial and restructuring advisor in making estimates related
to its guarantees and payment obligations and ultimate recovery of the
contractual amounts receivable from WCG. At this time, management believes that
no loss within the range is more probable than another. Accordingly, Williams
has recorded the $2.05 billion minimum amount of the range of loss which is
reported in the Consolidated Statement of Operations as a $1.84 billion pre-tax
charge to discontinued operations and a $213 million pre-tax charge to
continuing operations. Williams recognized a related deferred tax benefit in the
Consolidated Statement of Operations of $742.5 million ($68.9 million in
continuing operations and $673.6 million in discontinued operations). The
ultimate amount of tax benefit realized could be different from the deferred tax
benefit recorded, as influenced by potential changes in federal income tax laws
and the circumstances upon the actual realization of the tax benefits from WCG's
balance sheet restructuring program.

The charge to discontinued operations of $1.84 billion includes the $1.77
billion minimum amount of the estimated range of loss from performance on $2.21
billion of guarantees and payment obligations and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

approximately $16 million in expenses. With the exception of the interest on the
Note Trust Notes and the expenses, Williams has assumed for purposes of this
estimated loss that it will become an unsecured creditor of WCG for all or part
of the amounts paid under the guarantees and payment obligations. However, it is
probable that Williams will not be able to recover a significant portion of the
receivables. The estimated loss from the performance of the guarantees and
payment obligations is based on the overall estimate of recoveries on amounts
receivable discussed below. Due to the amendment of the WCG Note Trust Notes
discussed above, $1.1 billion of the accrued loss will be classified as a
long-term liability in the Consolidated Balance Sheet.

The charge to continuing operations of $213 million includes estimated
losses from an assessment of the recoverability of carrying amounts of the $106
million deferred payment for services provided to WCG, the $269 million minimum
lease payment receivable from WCG, and a remaining $25 million investment in WCG
common stock. The $85 million provision on the deferred payment is based on the
overall estimate of recoveries on amounts receivable using the same assumptions
on collectability as discussed below. The $103 million provision on the minimum
lease payments receivable is based on an estimate of the fair value of the
leased assets. The $25 million write-off of the WCG investment is based on
management's assessment of realization as a result of WCG's balance sheet
restructuring program.

The estimated range of loss assumes that Williams, as a creditor of WCG,
will recover only a portion of its unsecured claims against WCG. Such claims
include a $2.21 billion receivable from performance on guarantees and payment
obligations and a $106 million deferred payment for services provided to WCG.
With the assistance of external legal counsel and an external financial and
restructuring advisor, and considering the best information available at the
time and under the circumstances, management developed a range of loss on these
receivables with a minimum loss of 80 percent on claims in a bankruptcy of WCG.
Estimating the range of loss as a creditor involves making complex judgments and
assumptions about uncertain outcomes. The actual loss may ultimately differ from
the recorded loss due to changes in numerous factors, which include, but are not
limited to, the future demand for telecommunications services and the state of
the telecommunications industry, WCG's individual performance, and the nature of
the restructuring of WCG's balance sheet. There could be additional losses
recognized in the future, a portion of which may be reflected as discontinued
operations.

The minimum amount of loss in the range is estimated based on recoveries
from a successful reorganization process under Chapter 11 of the U.S. Bankruptcy
Code. Recoveries after a successful reorganization process depend, among other
things, on the impact of a bankruptcy on WCG's financial performance and WCG's
ability to continue uninterrupted business services to its customers and to
maintain relationships with vendors. To estimate recoveries of the unsecured
creditors, Williams estimated an enterprise value of WCG using a present value
analysis and reduced the enterprise value by the level of secured debt which may
exist in WCG's restructured balance sheet. In its estimate of WCG's enterprise
value, Williams considered a range of cash flow estimates based on information
from WCG and from other external sources. Future cash flow projections are
valued using discount rates ranging from 17 percent to 25 percent. The range of
cash flows is based on different scenarios related to the growth, if any, of
WCG's revenues and the impact that a bankruptcy may have on revenue growth. The
range of discount rates considers WCG's assumed restructured capital structure
and the market return that equity investors may require to invest in a
telecommunications business operating in the current distressed industry
environment. The range of loss also considers recoveries based on transaction
values from recent telecommunications restructurings and from a liquidation of
WCG's assets.

Should WCG go into bankruptcy under Chapter 7 of the U.S. Bankruptcy Code,
recoveries under a liquidation would include factors such as the nature of WCG's
assets, the value of operating assets in a distressed telecommunications market,
the cost of liquidation, operating losses during the period of liquidation, the
length of liquidation period and claims of creditors superior to those of
Williams' unsecured claims.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SUMMARIZED RESULTS OF DISCONTINUED OPERATIONS

Summarized results of discontinued operations for the years ended December
31, 2001, 2000 and 1999, are as follows:

- ---------------

* Represents results of operations from January 1, 2001 through April 23, 2001.

On January 25, 2001, WCG's board of directors approved a plan for WCG's
management to divest operations that previously comprised the Solutions segment.
On January 29, 2001, WCG signed an agreement to sell the domestic and Mexican
operations of Solutions to Platinum Equity, LLC. This sale closed in first-
quarter 2001. WCG divested its remaining Canadian Solutions operations in 2001.
The estimated pre-tax loss on disposal of WCG's Solutions segment in 2000
represents the pre-tax estimated loss on sale, including exit costs and the
pre-tax estimated operating losses of Solutions from January 1, 2001, to the
anticipated disposal date. The 2001 benefit for income taxes attributable to
discontinued operations includes an approximately $40 million benefit resulting
from Williams finalizing the tax basis of the businesses disposed.

Prior to January 1, 2000, Williams' revenue recognition policy on WCG
Solutions' new system sales and upgrades had been to recognize revenues under
the percentage-of-completion method. A portion of the revenues on the contracts
was initially recognized upon delivery of equipment with the remaining revenues
under the contract being recognized over the installation period based on the
relationship of incurred labor to total estimated labor. In light of the new
guidance in SAB No. 101, effective January 1, 2000, Williams changed its method
of accounting for new systems sales and upgrades from the
percentage-of-completion method to the completed-contract method. The cumulative
effect of the accounting change resulted in a charge to the 2000 loss on
discontinued operations of $21.6 million (net of income tax benefits of $14.9
million and minority interest of $21 million).

In October 1999, WCG completed an initial public offering of approximately
34 million shares of its common stock at $23 per share for proceeds of
approximately $738 million. In addition, approximately 34 million shares of
common stock were privately sold in concurrent investments by SBC Communications
Inc., Intel Corporation, and Telefonos de Mexico S.A. de C.V. for proceeds of
$738.5 million. These transactions resulted in a reduction of Williams'
ownership interest in WCG from 100 percent to 85.3 percent. In accordance with
Williams' policy regarding the issuance of subsidiary's common stock, Williams
recognized a $1.17 billion increase to Williams' capital in excess of par, a
$3.4 million decrease to accumulated other comprehensive income, and an initial
increase of $307 million to Williams' minority interest liability. The issuances
of stock by WCG were not subject to federal income taxes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NET ASSETS OF DISCONTINUED OPERATIONS

Net assets of discontinued operations as of December 31, 2000, are as
follows:

NOTE 4. INVESTING ACTIVITIES

Investing income (loss) for the years ended December 31, 2001, 2000 and
1999, is as follows:

- ---------------

* Items also included in segment profit.

Williams recognized a $94.2 million charge in third-quarter 2001,
representing declines in the value of certain investments, including $70.9
million related to Williams' investment in WCG and the $23.3 million related to
loss from other investments, which were determined to be other than temporary.
These determinations were primarily based on the continued depressed market
values of these investments and the overall market value decline experienced by
related industry sectors. In addition, a $25 million charge relating to
Williams' remaining investment in WCG common stock was recorded in conjunction
with Williams' assessment of realization as a result of WCG's balance sheet
restructuring program. The total charges of $119.2 million are included in
investing income (loss) and are reflected in net income (loss) with no
associated tax benefit.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Investments at December 31, 2001 and 2000, are as follows:

Dividends and distributions received from companies carried on the equity
basis were $51 million, $21 million and $14 million in 2001, 2000 and 1999,
respectively.

The Ferrellgas Partners L.P. senior common units were sold in 2001 for
$199.1 million. Williams recognized no gain or loss associated with this
transaction as the purchase price of the units sold approximated their carrying
value. As part of the sale, Williams is party to a put agreement whereby the
purchaser's lenders can require Williams to repurchase the units upon certain
events of default by the purchaser or failure or default by Williams under any
of its debt obligations greater than $60 million. The total contingent
obligation under the put agreement at December 31, 2001, was $99.6 million.
Williams' contingent obligation reduces as purchaser's payments are made to the
lender. The put agreement expires December 30, 2005. There have been no events
of default and the purchaser has performed as required under payment terms with
the lender.

At December 31, 2001, commitments for additional investments in Gulfstream
Pipeline, LLC, certain international cost investments and advances to Longhorn
Partners Pipeline, L.P. are $233 million.

NOTE 5. ASSET SALES, IMPAIRMENTS AND OTHER ACCRUALS

The $170 million impairment charge, reflected in the Consolidated Statement
of Operations, relates to the soda ash mining facility located in Colorado. The
facility, which began production in fourth-quarter 2000, experienced higher than
expected construction costs and implementation difficulties through December
2001. As a result, an impairment of the assets based on management's estimate of
the fair value was recorded in fourth-quarter 2001. Management's estimate was
based on the present value of discounted future cash flows. In addition,
management engaged an outside business consulting firm to provide further
information to be utilized in management's estimation. Future events and the use
of different judgments and/or assumptions could result in the recognition of an
additional impairment charge.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 2001, 2000 and 1999, are as follows:

The guarantee loss accruals and impairments of $47.5 million in 2000
include impairment charges resulting from the decision to discontinue mezzanine
lending services, and the accruals represent the estimated liabilities
associated with guarantees of third-party lending activities.

NOTE 6. PROVISION FOR INCOME TAXES

The provision for income taxes from continuing operations includes:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Reconciliations from the provision for income taxes from continuing
operations at the federal statutory rate to the provision for income taxes are
as follows:

Significant components of deferred tax liabilities and assets as of
December 31, 2001 and 2000, are as follows:

Cash payments for income taxes (net of refunds) were $87 million and $112
million in 2001 and 2000, respectively. In 1999, cash refunds exceeded cash
payments resulting in a net refund of $387 million. Federal tax refunds received
in 1999 are reflected as current tax benefits with offsetting deferred tax
provisions attributable to temporary differences between the book and tax basis
of certain assets.

Valuation allowances were established during 2001 for deferred tax assets
from basis differences in investments for which the ultimate realization of the
tax asset may be dependent on future capital gains. The recording of the
investment in the retained shares of WCG after the spinoff (see Note 3) resulted
in a $129 million tax asset for which a valuation allowance of $129 million was
established. The remaining $44 million of the tax asset, for which a valuation
allowance was established, resulted from the financial impairment of certain
investments during 2001 (see Note 4).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The merger with Barrett (see Note 2) resulted in $620 million of net
liability added to Williams' deferred tax balances as of the merger date.
Included in this amount was $70 million of deferred tax assets for pre-
affiliation federal net operating loss carryovers which are expected to be
utilized by Williams prior to expiration of the carryovers in 2011 through 2018.

NOTE 7. EXTRAORDINARY GAIN

On December 17, 1999, Williams sold its retail propane business, Thermogas
L.L.C. (Thermogas), previously a subsidiary of MAPCO, to Ferrellgas Partners
L.P. (Ferrellgas) for $443.7 million, including $175 million in senior common
units of Ferrellgas. The sale resulted from an unsolicited offer from Ferrellgas
and yielded an after-tax gain of $65.2 million (net of a $47.9 million provision
for income taxes), which is reported as an extraordinary gain. The results of
operations from this business are not significant to consolidated net income for
1999. Thermogas operations for 1999 are reported within the Energy Marketing &
Trading segment.

NOTE 8. EARNINGS PER SHARE

Basic and diluted earnings per common share are computed for the years
ended December 31, 2001, 2000 and 1999, as follows:

Approximately 15.3 million, 7.2 million and 6.2 million options to purchase
shares of common stock with weighted-average exercise prices of $36.12, $43.11
and $38.56, respectively, were outstanding on December 31, 2001, 2000 and 1999,
respectively, but have been excluded from the computation of diluted earnings
per share. Inclusion of these shares would have been antidilutive, as the
exercise prices of the options exceeded the average market prices of the common
shares for the respective years.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 9. EMPLOYEE BENEFIT PLANS

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
benefits to the amount recognized in the Consolidated Balance Sheet at December
31 of each year indicated. The year 2000 disclosure excludes WCG which has been
accounted for as discontinued operations (see Note 1). Subsequent measurement of
the impact of the spinoff of WCG identified additional benefit obligations and
plan assets of $2.3 million and $11.8 million, respectively, which have been
included in the table as a divestiture in the year 2001.

Amounts recognized in the Consolidated Balance Sheet consist of:

Prepaid benefit cost.......................... $ 135.1 $ 79.7 $ -- 5.9
Accrued benefit cost.......................... (34.1) (27.5) (160.0) (178.9)
Intangible asset.............................. 1.9 -- -- --
Accumulated other comprehensive income (before
tax)........................................ 3.6 -- -- --
-------- -------- ------- -------
Prepaid (accrued) benefit cost................ $ 106.5 $ 52.2 $(160.0) $(173.0)
======== ======== ======= =======

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Net pension and other postretirement benefit expense consists of the
following:

The projected benefit obligation, accumulated benefit obligation and fair
value of plan assets for the pension plans with accumulated benefit obligations
in excess of plan assets were $65.7 million, $51.9 million and $19.7 million,
respectively, as of December 31, 2001, and $65.0 million, $50.4 million and
$22.5 million, respectively, as of December 31, 2000.

The following are the weighted-average assumptions utilized as of December
31 of the year indicated:

The annual assumed rate of increase in the health care cost trend rate for
2002 is 11.8 percent, and systematically decreases to 5 percent by 2015.

The various nonpension postretirement benefit plans which Williams sponsors
provide for retiree contributions and contain other cost-sharing features such
as deductibles and coinsurance. The accounting for

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these plans anticipates future cost-sharing changes to the written plans that
are consistent with Williams' expressed intent to increase the retiree
contribution rate generally in line with health care cost increases.

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:

The amount of postretirement benefit costs deferred as a regulatory asset
at December 31, 2001 and 2000, is $56 million and $84 million, respectively, and
is expected to be recovered through rates over approximately 13 years.

Williams maintains various defined-contribution plans. Williams recognized
costs related to continuing operations of $36 million in 2001, $30 million in
2000 and $29 million in 1999 for these plans.

NOTE 10. INVENTORIES

Inventories at December 31, 2001 and 2000, are as follows:

As of December 31, 2001 and 2000, approximately 35 percent and 54 percent
of inventories, respectively, were stated at fair value. Inventories, primarily
related to energy risk management and trading activities, stated at fair value
at December 31, 2001 and 2000, included refined products of $90.8 million and
$195.1 million, respectively; natural gas in underground storage of $65.3
million and $125.8 million, respectively; and natural gas liquids of $97.9
million and $124.4 million, respectively. Inventories determined using the LIFO
cost method were approximately five percent and three percent of inventories at
December 31, 2001 and 2000, respectively. Certain crude oil and refined products
inventories determined using the FIFO cost method and adjusted for the effects
of fair value hedges, as prescribed by SFAS No. 133 were approximately 25
percent of inventories at December 31, 2001. The remaining inventories were
primarily determined using the average-cost method.

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NOTE 11. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31, 2001 and 2000, is as follows:

Depreciation, depletion and amortization expense for property, plant and
equipment was $790.7 million, $636.1 million and $585.1 million, respectively,
in 2001, 2000 and 1999.

Included in gross property, plant and equipment at December 31, 2001 and
2000, is approximately $1.1 billion and $940 million, respectively, of
construction in progress which is not yet subject to depreciation. In addition,
property of Exploration & Production includes approximately $839 million at
December 31, 2001, of capitalized costs from the Barrett acquisition (see Note
2) related to properties with probable reserves not yet subject to depletion.

Commitments for construction and acquisition of property, plant and
equipment are approximately $771 million at December 31, 2001.

Included in net property, plant and equipment is approximately $1.8 billion
and $1.9 billion at December 31, 2001 and 2000, respectively, related to amounts
in excess of the original cost of the regulated facilities within Gas Pipeline
as a result of Williams' and prior acquisitions. This amount is being amortized
over the estimated remaining useful lives of these assets at the date of
acquisition. Current FERC policy does not permit recovery through rates for
amounts in excess of original cost of construction.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 12. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Under Williams' cash-management system, certain subsidiaries' cash accounts
reflect credit balances to the extent checks written have not been presented for
payment. The amounts of these credit balances included in accounts payable are
$32 million at December 31, 2001, and $70 million at December 31, 2000.

Accrued liabilities at December 31, 2001 and 2000, are as follows:

NOTE 13. DEBT, LEASES AND BANKING ARRANGEMENTS

NOTES PAYABLE

During 2001, Williams' commercial paper program, backed by a short-term
credit facility, was increased from $1.7 billion to $2.2 billion. At December
31, 2001 and 2000, $1.4 billion and $1.7 billion, respectively, of commercial
paper was outstanding under the respective programs. Interest rates vary with
current market conditions. In January 2002, $300 million of commercial paper was
repaid with proceeds from the issuance of long-term debt obligations and, as
such, $300 million is classified as long-term as discussed below. In addition,
Williams has entered into various other short-term credit agreements, as
discussed below, with amounts outstanding totaling $300 million at December 31,
2001, as compared to $350 million at December 31, 2000. The weighted-average
interest rate on all short-term borrowings at December 31, 2001 and 2000, was
3.33 percent and 7.18 percent, respectively.

In June 2001, Williams entered into a $200 million (amended in July to $300
million) short-term debt obligation expiring January 2002. The interest rate
varies based on LIBOR plus .875 with an interest rate of 2.81 percent at
December 31, 2001. In January 2002, this debt obligation was repaid with
proceeds from the issuance of long-term debt obligations and, as such, is
classified as long-term as discussed below.

In July 2001, Williams issued $300 million in floating rate notes due July
2002. The interest rate varies based on LIBOR plus .875 percent and was 3.15
percent at December 31, 2001.

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

LONG-TERM DEBT

Long-term debt at December 31, 2001 and 2000, is as follows:

- ---------------

* At December 31, 2001.

(1) $240 million, 6.125% notes, payable 2012, redeemed at par in February 2002,
and $400 million of 6.75% notes, payable 2016, putable/callable in 2006.

For financial statement reporting purposes at December 31, 2001, $300
million of commercial paper, $300 million of short-term debt obligations and
$244 million of long-term debt obligations due within one year, which would have
otherwise been classified as current, have been classified as noncurrent based
on Williams' intent and ability to refinance on a long-term basis. In January
2002, in connection with the issuance of the FELINE PACS (see Note 23), Williams
issued $1.1 billion of 6.5 percent long-term debt obligations due in 2007, but
subject to remarketing in 2004. Proceeds from the issuance of these long-term
debt obligations were sufficient to complete these refinancings.

Under the terms of Williams' $700 million revolving credit agreement,
Northwest Pipeline, Transcontinental Gas Pipe Line and Texas Gas Transmission
have access to various amounts of the facility, while Williams (Parent) has
access to all unborrowed amounts. Interest rates vary with current market
conditions. At December 31, 2001, no amounts were outstanding under this
revolving credit agreement. Additionally, certain Williams subsidiaries have
revolving credit facilities with a total capacity of $110 million at December
31, 2001.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Significant long-term debt issuances and retirements, other than amounts
under revolving credit agreements, in 2001 are as follows:

- ---------------

(1) Putable/callable in 2006.

(2) Subject to redemption at par at the option of the debtholder in 2001.

In connection with the Barrett acquisition (see Note 2), Williams' December
31, 2001 Consolidated Balance Sheet includes $155 million of debt obligations of
Barrett. Barrett's debt obligations consist of $150 million principal amount of
7.55 percent notes due 2007, which are guaranteed by Williams, and $5 million
from purchase price allocation. Additionally, Williams repaid $155 million of
debt obligations under Barrett's bank-credit facility in fourth-quarter 2001.

The agreements governing Williams' debt contain covenants and, in some
cases, conditions for future borrowings, with which Williams believes it is
currently in compliance. The conditions for future borrowings include the
absence of default under such agreements, continued accuracy of the
representations and warranties contained in such agreements and absence of any
material adverse changes. Additionally, the agreements governing Williams' debt
include limitations upon liens on Williams' assets with certain exceptions,
including purchase money liens, liens existing on property when acquired by
Williams, liens on receivables, and liens payable solely out of the proceeds of
oil, gas or other minerals produced from the property subject to the lien, as
further defined in the agreements and indentures. Most of Williams' private debt
agreements, including the $2.2 billion short-term credit facility backing
Williams' commercial paper program and $700 million revolving credit agreement,
are subject to compliance with certain financial covenants, including a
requirement that Williams' net debt, as defined in the governing agreements, not
exceed 65 percent of consolidated net worth plus net debt, each as defined in
the governing agreements. Consolidated net worth is defined as total assets less
liabilities and minority and preferred interests in consolidated subsidiaries
plus certain minority interests as defined in the debt agreements. Net debt is
defined as all debt, other than non-recourse debt, as well as certain Williams'
guarantees as defined in the agreements less cash and cash equivalents.
Williams' ratio of net debt to consolidated net worth plus net debt at December
31, 2001 was 61.5 percent. Following the January 2002 issuance of the FELINE
PACS (see

105

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Note 23), the definition of consolidated net worth was amended to include those
securities and the definition of net debt was amended to exclude those
securities. If the FELINE PACS were included in consolidated net worth at
December 31, 2001, Williams' ratio of net debt to consolidated net worth plus
net debt would have been 57.6 percent. None of the Williams loans, notes or
debentures maintains preferential rights in the event of liquidation.

Terms of certain subsidiaries' borrowing arrangements with lenders limit
the transfer of funds to Williams (Parent). At December 31, 2001, approximately
$423 million of net assets of consolidated subsidiaries was restricted. In
addition, certain equity method investees' borrowing arrangements and foreign
government regulations limit the amount of dividends or distributions to
Williams. Restricted net assets of equity method investees was approximately
$337 million at December 31, 2001.

Aggregate minimum maturities, considering the reclassification of current
obligations as previously described, for each of the next five years are as
follows:

Cash payments for interest (net of amounts capitalized) are as follows:
2001 -- $643 million; 2000 -- $648 million; and 1999 -- $512 million.

LEASES-LESSEE

Future minimum annual rentals under noncancelable operating leases as of
December 31, 2001, are payable as follows:

Total rent expense was $112 million in 2001, $107 million in 2000 and $109
million in 1999.

During 2000, Williams entered into operating lease agreements with two
special purpose entities (SPEs) owned by third parties covering certain Williams
travel center stores, offshore oil and gas pipelines and an onshore gas
processing plant. The SPEs are not consolidated by Williams as their equity is
provided by non-related parties. The total estimated cost of the assets covered
by the lease agreements is approximately $300 million. The lease terms include a
five-year base term including the construction phase and can be renewed for
another five-year term upon mutual agreement of the lessor and lessee.

Williams has an option to purchase the leased assets during the lease terms
at amounts approximating the lessors' cost. Williams provides a residual value
guarantee equal to 85 percent of the lessor's cost on the completed travel
center stores and equal to 89.9 percent of the lessor's cost, less the present
value of actual lease payments, on the offshore oil and gas pipelines and the
onshore gas processing plant. In the event that Williams does not exercise its
purchase option, Williams expects the fair market value of the covered assets to
substantially offset Williams' obligation under the residual value guarantees.
Williams' disclosures for future

106

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

minimum annual rentals under noncancelable operating leases do not include
amounts for residual value guarantees. As of December 31, 2001, approximately
$276 million of costs has been incurred by the lessors.

LEASES-LESSOR

In third-quarter 2001, Williams purchased the Technology Center and three
corporate aircraft from WCG for $276 million, which represents the approximate
actual cost of construction of the Williams Technology Center and the
acquisition cost of the ancillary assets and aircraft. Williams then entered
into long-term lease arrangements under which WCG is the sole lessee of the
Technology Center and aircraft assets. The lease arrangements are fully backed
by the underlying assets and have payment terms ranging from three to ten years.
WCG has an option to purchase the Technology Center, at any time during the term
of the lease, at the unamortized cost of those assets. Williams has a put option
that requires WCG to purchase the Technology Center due to a default by WCG on
the lease at the unamortized cost of the assets plus accrued rent, or within the
90-day period prior to the 10-year lease termination or in the event of a
casualty loss which exceeds set amounts at the unamortized cost of the
Technology Center. WCG also has an option to purchase the corporate aircraft, at
any time during the term of the lease, at the greater of the unamortized cost or
the market value of those assets. The leases are classified as direct-financing
leases. As a result, Williams removed the leased assets discussed above from its
books and recorded a minimum lease payment receivable equal to the total of the
minimum lease payments of $396 million reduced by the unearned interest income
which is computed using a variable interest rate and initially equaled $120
million. Lease payments from WCG are applied as a reduction of the receivable
while the unearned income is accreted to interest income using the effective
interest method over the life of the leases. As of December 31, 2001, the
Consolidated Balance Sheet includes $28.8 million in current accounts and notes
receivable and $137.2 million (net of allowance for doubtful accounts of $103.2
million) in noncurrent other assets and deferred charges relating to these
leasing arrangements.

Future minimum lease payments receivable under the leasing arrangements as
of December 31, 2001, are as follows:

NOTE 14. PREFERRED INTERESTS IN CONSOLIDATED SUBSIDIARIES

Williams owns the controlling interest in various entities formed in
separate transactions that resulted in the sale of a non-controlling preferred
ownership interest in one entity in each transaction to an outside investor. The
assets and liabilities of each of these entities are included in the
Consolidated Balance Sheet. The preferred ownership interest in each entity is
reflected in the preferred interest in consolidated subsidiaries caption of the
Consolidated Balance Sheet. The outside investors in these entities are
unconsolidated special purpose entities formed solely for the purpose of
purchasing the preferred ownership interest in the respective entity and are
capitalized with no less than three-percent equity from an independent third
party. Each outside investor is entitled to a priority return paid from the
operating results of the entity in which they have an

107

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

investment. Williams has the option to acquire each outside investor's interest
in each entity for an amount approximating the fair value of their ownership
interest. Absent the occurrence of certain events, the purchase option can be
exercised at any time prior to the expiration of the initial priority return
period.

In addition to financial support in favor of these entities, typically in
the form of demand notes, Williams provides the outside investor in each entity
with certain assurances that the entities involved in each transaction will
maintain certain financial ratios and follow various restrictive covenants
similar to, but in some cases broader than those found in Williams' credit
agreements. A violation of any restrictive covenant, a default by Williams of
its debt obligations, a failure to make priority distributions, or a failure to
negotiate new priority return structures prior to the end of the initial
priority return structure period, could ultimately result in an election by the
outside investor in the impacted entity to liquidate the assets of that entity.
A liquidation could result in a demand of repayment on any Williams obligations
as well as the sale of other assets owned or secured by the entity in order to
generate proceeds to return the investor's capital account balance. Williams can
prevent liquidation of each entity through the exercise of the option to
purchase the outside investor's preferred ownership interest.

At December 31, 2001, outside investors owned preferred interests in the
following Williams subsidiaries.

SNOW GOOSE ASSOCIATES, L.L.C.

In December 2000, Williams formed two separate legal entities, Snow Goose
Associates, L.L.C. (Snow Goose) and Arctic Fox Assets, L.L.C. (Arctic Fox) for
the purpose of generating funds to invest in certain Canadian energy-related
assets. An outside investor contributed $560 million in exchange for the non-
controlling preferred interest in Snow Goose. The investor in Snow Goose is
entitled to quarterly priority distributions, representing an adjustable rate
structure of approximately 3.5 percent at December 31, 2001. The initial
priority return period is currently set to expire in December 2005.

Snow Goose loaned the proceeds received from the outside investor to Arctic
Fox. These proceeds were ultimately used to purchase the Canadian energy-related
assets. Snow Goose's sole asset consists of a note receivable, due in December
2005 from Arctic Fox. At December 31, 2001, the assets of Arctic Fox include
approximately a $400 million note receivable from Williams Energy (Canada),
Inc., due in December 2005, collateralized by the Canadian energy-related
assets, $35 million in loans from Williams payable upon demand, an investment in
operating assets with a carrying value of approximately $140 million and an
investment in 342,000 shares of Williams' cumulative convertible preferred stock
with a liquidation value of $1,000 per share. If sold in a liquidation, each
share of the Williams' cumulative preferred stock would become convertible into
a number of Williams common stock determined by dividing $1,000 by a conversion
price. The initial conversion price is $31.8125 per share. The initial
conversion price is subject to adjustment for events such as stock splits of
Williams common stock, the issuance of stock dividends, issuance of below market
value subscription rights or warrants, and issuance of unusually large cash
dividends.

In addition to the covenants discussed above, the Snow Goose transaction
requires Williams to maintain a credit rating equal to or higher than BBB- by
Standard & Poor's or a credit rating equal to or higher than Baa3 by Moody's
Investor's Service, but Williams must also maintain credit ratings of BB+ by
Standard & Poor's and Ba1 by Moody's Investor's Service regardless of the rating
by the other agency. Other significant covenants include: (i) an obligation of
Williams Energy (Canada), Inc. to have earnings before interest, taxes,
depreciation and amortization each quarter that are at least three times greater
than the interest due on its loan from Arctic Fox for the quarter; (ii) an
obligation of Williams Energy (Canada), Inc. to have total debt that is less
than 50 percent of its total capitalization; (iii) an obligation of Arctic Fox
to have assets with a book value that is at least two times larger than the
unrecovered capital of the outside investor in Snow Goose; and (iv) an
obligation of Arctic Fox to have cash flow each quarter that is at least three
times greater than amounts payable to the outside investor in Snow Goose for
that quarter.

108

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CASTLE ASSOCIATES L.P.

In December 1998, Williams formed Castle Associates L.P. (Castle) through a
series of transactions that resulted in the sale of a non-controlling preferred
interest in Castle to an outside investor for $200 million. Williams used the
proceeds of the sale for general corporate purposes. At December 31, 2001, the
assets of Castle include approximately $145 million in loans from Williams
payable upon demand (demand loans), a $125 million loan from a Williams
subsidiary secured by operating assets and a Williams guarantee due in December
2003, $60 million in third-party receivables guaranteed by Williams, and
approximately $204 million in other various assets. While no event of default
would arise from a downgrade of Williams' unsecured credit rating below Baa3 by
Moody's Investor's Service and below BBB- by Standard & Poor's, Williams would
be required to replace the demand loans with other assets. The outside investor
is entitled to quarterly priority distributions based upon an adjustable rate
structure of approximately 3.8 percent at December 31, 2001, in addition to a
portion of the participation in the operating results of Castle. The initial
priority return structure is currently set to expire in December 2002.

Castle must satisfy certain financial covenants beyond those found in
Williams' standard credit agreements, including a requirement that it must have
assets with a value of at least 1.75 times the outside investors contributed
capital, and a requirement that at the end of each fiscal quarter, Castle's
profits for the year to date be at least 1.4 times the investor's priority
return.

PICEANCE PRODUCTION HOLDINGS LLC

In December 2001, Williams formed Piceance Production Holdings LLC
(Piceance) and Rulison Production Company LLC (Rulison) in a series of
transactions that resulted in the sale of a non-controlling preferred interest
in Piceance to an outside investor for $100 million. Williams used the proceeds
of the sale for general corporate purposes. The assets of Piceance include
fixed-price overriding royalty interests in certain oil and gas properties owned
by a Williams subsidiary as well as a $135 million note from Rulison. The
outside investor is entitled to monthly priority distributions beginning in
January 2002, based upon an adjustable rate structure currently approximating
3.9 percent in addition to participation in a portion of the operating results
of Piceance. The initial priority return structure is currently scheduled to
expire in December 2006.

Piceance must satisfy certain financial covenants beyond those found in
Williams' standard credit agreements, including a requirement that it have
assets with a value of at least 1.35 times the investor's capital account, and a
requirement that at the end of each fiscal quarter, Piceance's profits for the
year to date be at least 1.2 times the investor's priority return.

Williams is allowed to access the excess cash flow of Piceance and Rulison
between distribution period through demand loans. However, if Williams' credit
ratings fall below BBB- by Standard & Poor's and Baa3 by Moody's Investor's
Service or below BB+ by Standard & Poor's or below Ba1 by Moody's Investor's
Service, Williams will be prevented from using demand loans, and therefore
excess cash will be retained between distribution periods. These ratings
triggers do not force an acceleration.

Failure to satisfy the terms of the agreements would entitle the investor
to deliver a transfer notice declaring the occurrence of a transfer event. In
such case, unless the Williams' subsidiary that is a member of Piceance
exercises its purchase option, the managing member interest will automatically
be transferred to the investor ten days following the transfer event. Upon a
transfer event, the managing member can elect to liquidate and wind-up Piceance.

In addition to the transactions discussed above, an outside investor owns a
non-controlling preferred interest in the following Williams subsidiary.

109

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

WILLIAMS RISK HOLDINGS L.L.C.

During 1998, Williams formed Williams Risk Holdings L.L.C. (Holdings) in a
series of transactions that resulted in the sale of a non-controlling preferred
interest in Holdings to an outside investor for $135 million. Williams used the
proceeds from the sale for general corporate purposes. The outside investor in
Holdings is not a special purpose entity. The outside investor is entitled to
monthly preferred distributions based upon an adjustable rate structure of
approximately 5.9 percent at December 31, 2001, in addition to participation in
a portion of the operating results of Holdings. The initial priority return
structure of Holdings is currently scheduled to expire in September 2003 at
which time Williams can attempt to negotiate a new priority return or elect to
retire the outside investor's interest. In addition, terms of the Holdings
transaction require Williams to maintain a specified minimum credit rating with
various ratings organizations. Violation of various restrictive covenants,
including a downgrade of Williams' senior unsecured rating below BB by Standard
& Poor's or Ba1 by Moody's Investor's Service, could require an early retirement
of the outside investor's ownership interest.

Holdings must satisfy certain financial covenants beyond those found in
Williams standard credit agreements, including, (i) a requirement that Holdings'
cash, promissory notes and investments minus its contingent liabilities be equal
to or greater than the purchase price of the outside investors' interests; (ii)
a requirement that Holdings' maintain a consolidated net worth at least two
times greater than the purchase price of the outside investors' interests; and
(iii) a requirement that Holdings' subsidiary's assets exceed by at least 1.05
times the fair market value of such subsidiary's liabilities.

NOTE 15. WILLIAMS OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST
HOLDING ONLY WILLIAMS INDENTURES

In December 1999, Williams formed Williams Capital Trust I which issued
$175 million in zero coupon Williams obligated mandatorily redeemable preferred
securities. During April 2001, these securities were redeemed.

NOTE 16. STOCKHOLDERS' EQUITY

In January 2001, Williams issued approximately 38 million shares of common
stock in a public offering at $36.125 per share. The impact of this issuance
resulted in increases of approximately $38 million to common stock and $1.3
billion to capital in excess of par value.

During 1999, each remaining share of the $3.50 Williams preferred stock was
converted at the option of the holder into 4.6875 shares of Williams common
stock prior to the redemption date.

Williams maintains a Stockholder Rights Plan under which each outstanding
share of Williams common stock has one-third of a preferred stock purchase right
attached. Under certain conditions, each right may be exercised to purchase, at
an exercise price of $140 (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 Williams common stock; or commences an offer for 15 percent
or more of Williams common stock; or the board of directors determines an
Adverse Person has become the owner of a substantial amount of Williams common
stock. The rights, which until exercised do not have voting rights, expire in
2006 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 Williams common
stock or the board of directors determines that a person is an Adverse Person,
each holder of a right (except an Acquiring Person or an Adverse Person) shall
have the right to receive, upon exercise, Williams common stock having a value
equal to two times the exercise price of the right. In the event Williams is
engaged in a merger, business combination or 50 percent or more of Williams'
assets, cash flow or earnings power is sold or transferred, each holder of a
right (except an Acquiring Person or an Adverse Person) shall have the right to
receive, upon

110

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

exercise, common stock of the acquiring company having a value equal to two
times the exercise price of the right.

NOTE 17. STOCK-BASED COMPENSATION

Williams has several plans providing for common-stock-based awards to
employees and to non-employee directors. The plans permit the granting of
various types of awards including, but not limited to, stock options,
stock-appreciation rights, 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. The purchase price per
share for stock options and the grant price for stock-appreciation rights may
not be less than the market price of the underlying stock on the date of grant.
Depending upon terms of the respective plans, stock options generally become
exercisable in one-third increments each year from the anniversary of the grant
or after three or five years, subject to accelerated vesting if certain future
stock prices or if specific financial performance targets are achieved. Stock
options expire 10 years after grant. At December 31, 2001, 46.4 million shares
of Williams common stock were reserved for issuance pursuant to existing and
future stock awards, of which 18.2 million shares were available for future
grants (20.9 million at December 31, 2000).

Certain of these plans had loan programs that provided loans for either a
three- or five-year term using stock certificates as collateral. Interest
payments are due annually during the term of the loan and interest rates are
based on the minimum applicable federal rates required to avoid imputed income.
The principal amount is due at the end of the loan term. Participants who leave
the company during the loan period are required to pay the loan balance and any
accrued interest within 30 days of termination. The amount of loans outstanding
at December 31, 2001 and 2000, totaled approximately $38.1 million and $53.5
million, respectively.

Effective November 14, 2001, the Company will no longer issue new loans
under the stock option loan program. Current loan holders have been offered a
one-time opportunity to refinance outstanding loans at a market rate of interest
commensurate with the borrower's credit standing. The refinancing, if elected,
would be in the form of a full recourse note, interest payable annually in cash,
and loan maturity of no later than December 31, 2005. The loan would remain in
force until maturity in the event of the employee's termination. The Company
would hold the collateral shares and would review the borrower's financial
position upon the one-time election and on an annual basis thereafter. If a
current loan holder does not make the election to refinance, the current loans
would remain outstanding with no refinancing at maturity.

111

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following summary reflects stock option activity for Williams common
stock and related information for 2001, 2000 and 1999:

- ---------------

(1) Effective with the spinoff of WCG on April 23, 2001, the number of
unexercised Williams stock options and the exercise price were adjusted to
preserve the intrinsic value of the stock options that existed prior to the
spinoff.

The following summary provides information about Williams stock options
outstanding and exercisable at December 31, 2001:

The estimated fair value at date of grant of options for Williams common
stock granted in 2001, 2000 and 1999, using the Black-Scholes option pricing
model, is as follows:

112

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Pro forma net income (loss) and earnings per share, assuming Williams 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, are as follows:

Pro forma amounts for 2001 include compensation expense from certain
Williams awards made in 1999 and compensation expense from Williams awards made
in 2001.

Pro forma amounts for 2000 include compensation expense from certain
Williams awards made in 1999 and the total compensation expense from Williams
awards made in 2000, as these awards fully vested in 2000 as a result of the
accelerated vesting provisions. Pro forma amounts for 2000 include $37.3 million
for Williams awards and $105.7 million related to discontinued operations.

Pro forma amounts for 1999 include the remaining total compensation expense
from Williams awards made in 1998 and the total compensation expense from
certain Williams awards made in 1999, as these awards fully vested in 1999 as a
result of the accelerated vesting provisions. In addition, 1999 pro forma
amounts include compensation expense related to the WCG plan awards and
conversions in 1999. Pro forma amounts for 1999 include $47.1 million related to
Williams awards and $6.2 million related to discontinued operations. Since
compensation expense from stock options is recognized over the future years'
vesting period for pro forma disclosure purposes, and additional awards
generally are made each year, pro forma amounts may not be representative of
future years' amounts.

Williams granted deferred shares of approximately 1,423,000 in 2001,
332,000 in 2000 and 260,000 in 1999. Deferred shares are valued at the date of
award, and the weighted-average grant date fair value of the shares granted was
$40.84 in 2001, $39.13 in 2000 and $34.84 in 1999. Approximately $22 million,
$11 million and $13 million was recognized as expense for deferred shares of
Williams in 2001, 2000 and 1999, respectively. Expense related to deferred
shares is recognized in the performance year or over the vesting period,
depending on the terms of the awards. Williams issued approximately 260,000 in
2001, 140,000 in 2000 and 125,000 in 1999, of the deferred shares previously
granted.

NOTE 18. FINANCIAL INSTRUMENTS, DERIVATIVES, INCLUDING ENERGY TRADING
ACTIVITIES, AND CONCENTRATION OF CREDIT RISK

FINANCIAL INSTRUMENTS FAIR VALUE

Fair-value methods

The following methods and assumptions were used by Williams in estimating
its fair-value disclosures for financial instruments:

Cash and cash equivalents and notes payable: The carrying amounts reported
in the balance sheet approximate fair value due to the short-term maturity of
these instruments.

Retained interest in accounts receivable sold to SPEs: The carrying
amounts reported in the balance sheet approximate fair value. Fair value is
based on the present value of future expected cash flows using management's best
estimates of various factors, including credit loss experience and discount
rates commensurate with the risks involved.

113

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Notes and other noncurrent receivables, margin deposits and deposits
received from customers relating to energy trading and hedging activities: For
those instruments with interest rates approximating market or maturities of less
than three years, fair value is estimated to approximate historically recorded
amounts.

Investments-cost and advances to affiliates: Fair value is reflected to
approximate historically recorded amounts as the investments are primarily in
non-publicly traded foreign companies for which it is not practicable to
estimate fair value of these investments.

Investment in WCG: Fair value is calculated based on the year-end closing
price of WCG common stock. The carrying amount reflects write-downs of the WCG
investment to zero (see Note 4).

Ferrellgas Partners L.P. senior common units: These securities are
classified as available-for-sale and are reported at fair value, with net
unrealized appreciation or depreciation reported as a component of accumulated
other comprehensive income.

Long-term debt: The fair value of Williams' long-term debt is valued using
indicative year-end traded bond market prices for publicly traded issues, while
private debt is valued based on the prices of similar securities with similar
terms and credit ratings. At December 31, 2001 and 2000, 75 percent and 59
percent, respectively, of Williams' long-term debt was publicly traded. Williams
used the expertise of outside investment banking firms to assist with the
estimate of the fair value of long-term debt.

Williams obligated mandatorily redeemable preferred securities of
Trust: Fair value is based on the prices of similar securities with similar
terms and credit ratings as the preferred securities are not publicly traded.
Williams used the expertise of an outside investment banking firm to establish
the fair value of obligated mandatorily redeemable preferred securities.

Interest-rate swaps: Fair value is determined by discounting estimated
future cash flows using forward-interest rates derived from the year-end yield
curve. Fair value was calculated by the financial institutions that are the
counterparties to the swaps.

Foreign exchange forward contract: Fair value is determined by discounting
estimated future cash flows using forward foreign exchange rates derived from
the year-end forward exchange curve. Fair value was calculated by the financial
institution that is counterparty to the agreement.

Energy risk management and trading and hedging contracts: Energy contracts
utilized in trading activities include forward contracts, futures contracts,
option contracts, swap agreements, commodity inventories, short- and long-term
purchase and sale commitments, which involve physical delivery of an energy
commodity and energy-related contracts, such as transportation, storage, full
requirements, load serving and power tolling contracts. In addition, Williams
enters into interest-rate swap agreements and credit default swaps to manage the
interest rate and credit risk in its energy trading portfolio. Fair value of
energy contracts is determined based on the nature of the transaction and the
market in which transactions are executed. Certain transactions are executed in
exchange-traded or over-the-counter markets for which quoted prices in active
periods exist. Transactions are executed in exchange-traded or over-the-counter
markets for which quoted market prices may exist; however, the markets may be
relatively inactive, and price transparency is limited. Certain transactions are
executed for which quoted market prices are not available. See Note 1 regarding
Energy commodity risk management and trading activities and Derivative
instruments and hedging activities for further discussion about determining fair
value for energy contracts.

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Carrying amounts and fair values of Williams' financial instruments and energy
risk management and trading activities

- ---------------

(a) It is not practicable to estimate the fair value of these financial
instruments because of their unusual nature and unique characteristics.

(b) At December 31, 2001, Williams had interest rate swaps to mitigate its
interest rate risk in its energy trading portfolio and are included in
energy risk management and trading and price-risk management activities.

Other financial instruments

Williams, through wholly owned bankruptcy remote subsidiaries, sells
certain trade accounts receivable to special purpose entities (SPEs) in a
securitization structure requiring annual renewal. Williams acts as the
servicing agent for sold receivables and receives a servicing fee approximating
the fair value of such services.

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At December 31, 2001, approximately $625 million of accounts receivable that
would otherwise be Williams receivables were sold to the SPEs in exchange for
$420 million in cash and a $205 million subordinated retained interest in the
accounts receivable sold to the SPEs. In 2000, Williams sold accounts receivable
to special purpose entities under a similar structure. For 2001 and 2000,
Williams received cash from the SPEs of approximately $12.8 billion and $9
billion, respectively. The sales of these receivables resulted in a charge to
results of operations of approximately $17 million and $23 million in 2001 and
2000, respectively. The retained interest in accounts receivable sold to the
SPEs is subject to credit risk to the extent that these receivables are not
collected. See Concentration of credit risk below.

In addition to the guarantees included in the table, the guarantees and
payment obligations related to WCG discussed in Note 3, certain residual value
guarantees discussed in Note 13 and potential obligation under a put agreement
discussed in Note 4, Williams has issued other guarantees and letters of credit
with off balance sheet risk that total approximately $99 million and $78 million
at December 31, 2001 and 2000, respectively. Williams believes it will not have
to perform under these other guarantees and letters of credit, because the
likelihood of default by the primary party is remote and/or because of certain
indemnifications received from other third parties.

DERIVATIVES, INCLUDING ENERGY RISK MANAGEMENT AND TRADING ACTIVITIES

Energy risk management and trading activities

Williams, through Energy Marketing & Trading, has energy commodity risk
management and trading operations that enter into energy contracts to provide
price-risk management services associated with the energy industry to its
customers. Contracts utilized in energy commodity risk management and trading
activities include forward contracts, futures contracts, option contracts, swap
agreements, short- and long-term purchase and sale commitments which involve
physical delivery of an energy commodity and energy-related contracts, including
transportation, storage, full requirements, load serving and power tolling
contracts. In addition, Williams enters into interest rate swap agreements and
credit default swaps to manage the interest rate and credit risk in its energy
portfolio. See Note 1 for a description of the accounting valuation for these
energy commodity risk management and trading activities. The net gain recognized
in revenues from all price-risk management and trading activities was $1,696
million, $1,285.1 million and $214 million in 2001, 2000 and 1999, respectively.

Energy Marketing & Trading actively manages the risk assumed from its
activities and operations. This risk results from exposure to commodity market
prices, volatility in those prices, correlation of commodity prices, the
liquidity of the market in which the contract is transacted, interest rates,
credit and counterparty performance. Energy Marketing & Trading manages market
risk on a portfolio basis through established trading policy guidelines which
are monitored on a daily basis. Energy Marketing & Trading actively seeks to
diversify its portfolio in managing the commodity price risk in the transactions
that it executes in various markets and regions by executing offsetting
contracts to manage such commodity price risk.

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. An exchange-traded or
over-the-counter market for which quoted prices in active periods are available
exists for the futures contracts entered into by Energy Marketing & Trading. The
fair value of these contracts is based on quoted prices.

Swap agreements call for Energy Marketing & Trading 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 and purchase and sale commitments with fixed
volumes which involve physical delivery of energy commodities, contain both
fixed and variable pricing terms. Swap agreements, forward contracts and
purchase and sale commitments with fixed volumes are valued based

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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.

Certain of Energy Marketing & Trading's purchase and sale commitments,
which involve physical delivery of energy commodities, contain optionality
clauses or other arrangements that result in varying volumes. In addition,
Energy Marketing & Trading buys and sells physical and financial option
contracts which 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.

Energy-related contracts include transportation, storage, full
requirements, load serving and power tolling contracts. Transportation contracts
provide Energy Marketing & Trading the right, but not the obligation, to
transport physical quantities of natural gas from one location to another on a
daily basis. The payment or settlement required typically has a fixed component
paid regardless of whether the transportation capacity is used and a variable
component. Variable payments are made for shipments actually made during the
month. The decision to use the capacity to ship natural gas is based on the
difference between the price of natural gas at the pipeline receipt and delivery
locations and the variable cost of transportation. Storage contracts provide
Energy Marketing & Trading the right, but not the obligation, to store physical
quantities of gas to take advantage of anticipated differentials between the
price of natural gas during the period between injection and withdrawal and to
enable it to supply existing delivery commitments when the estimated price
spread differential less the cost of storing the natural gas is favorable.
Energy Marketing & Trading enters full requirements arrangements which are
structured to meet a variety of customers' needs. Agreements may be designed to
manage natural gas and power supply requirements, service load growth, manage
unplanned outages or other scenarios. Load serving agreements require Energy
Marketing & Trading to procure energy supplies for its customers necessary to
meet their load or energy needs. Power tolling contracts provide Energy
Marketing & Trading the right, but not the obligation, to call on the
counterparty to convert natural gas to electricity at a predefined heat
conversion rate. Energy Marketing & Trading supplies the natural gas to the
power plants and markets the electricity output. In exchange for this right,
Energy Marketing & Trading pays a monthly fee and a variable fee based on usage.
The decision as to whether the option will be exercised is dependent on the
differential between natural gas and power commodity prices considering the heat
conversion rate and variable fee.

Fair value of these energy-related contracts is estimated using valuation
techniques that incorporate option pricing theory, statistical and simulation
analysis, present value concepts incorporating risk from uncertainty of the
timing and amount of estimated cash flows and specific contractual terms. These
valuation techniques utilize factors such as 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, the liquidity of the market in which the
contract is transacted and a risk-free market discount rate. Fair value also
reflects a risk premium that market participants would consider in their
determination of fair value.

Interest-rate swap agreements are used to manage the interest rate risk in
the energy trading portfolio. Under these agreements, Energy Marketing & Trading
pays a fixed rate and receives a variable rate on the notional amount of the
agreements. The fair value of these contracts is determined by discounting
estimated future cash flows using forward interest rates derived from interest
rate yield curves. Credit default swaps are used to manage counterparty credit
exposure in the energy trading portfolio. Under these agreements, Energy
Marketing & Trading pays a fixed rate premium for a notional amount of risk
coverage associated with certain

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credit events. The covered credit events are bankruptcy, obligation
acceleration, failure to pay and restructuring. The fair value of these
agreements is based on current pricing received from the counterparties.

The valuation of the contracts entered into by Energy Marketing & Trading
also considers factors such as the liquidity of the market in which the contract
is transacted, uncertainty regarding the ability to liquidate the position
considering market factors applicable at the date of such valuation and risk of
non-performance and credit considerations of the counterparty. For contracts or
transactions that extend into periods for which actively quoted prices are not
available, Energy Marketing & Trading estimates energy commodity prices in the
illiquid periods by incorporating information obtained from commodity prices in
actively quoted markets, prices reflected in current transactions and market
fundamental analysis.

Determining fair value for contracts also involves complex assumptions
including estimating natural gas and power market prices in illiquid periods and
markets, estimating volatility and correlation of natural gas and power prices,
evaluating risk from uncertainty inherent in estimating cash flows and estimates
regarding counterparty performance and credit considerations.

Energy Marketing & Trading has the 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. Energy Marketing & Trading attempts
to minimize credit-risk exposure to trading counterparties and brokers through
formal credit policies, consideration of credit ratings from public rating
agencies, monitoring procedures, master netting agreements and collateral
support under certain circumstances. In addition, Williams has entered into
credit default swaps to reduce this exposure. Valuation allowances are provided
for credit risk in accordance with established credit policies.

The concentration of counterparties within the energy and energy trading
industry impacts Williams' overall exposure to credit risk in that these
counterparties are similarly influenced by changes in the economy and regulatory
issues.

The counterparties associated with assets from energy commodity risk
management and trading activities as of December 31, 2001 and 2000, are
summarized as follows:

The net cash inflows related to these contracts at December 31, 2000 were
approximately $1 billion. At December 31, 2000, the cash inflows extend
primarily through 2022.

Energy commodity cash flow hedges

Williams is also exposed to market risk from changes in energy commodity
prices within the Energy Services business unit and the non-trading operations
of Energy Marketing & Trading. Williams utilizes derivatives to manage its
exposure to the variability in expected future cash flows attributable to
commodity price risk associated with forecasted purchases and sales of natural
gas, refined products, crude oil, electricity, ethanol and corn. These
derivatives have been designated as cash flow hedges.

Williams produces, buys and sells natural gas at different locations
throughout the United States. To reduce exposure to a decrease in revenues or an
increase in costs from fluctuations in natural gas market prices, Williams
enters into natural gas futures contracts and swap agreements to fix the price
of anticipated sales and purchases of natural gas.

Williams' refineries purchase crude oil for processing and sell the refined
products. To reduce the exposure to increasing costs of crude oil and/or
decreasing refined product sales prices due to changes in market prices,
Williams enters into crude oil and refined products futures contracts and swap
agreements to lock in the prices of anticipated purchases of crude oil and sales
of refined products.

Williams' electric generation facilities utilize natural gas in the
production of electricity. To reduce the exposure to increasing costs of natural
gas due to changes in market prices, Williams enters into natural gas futures
contracts and swap agreements to fix the prices of anticipated purchases of
natural gas. To reduce the exposure to decreasing revenues from electricity
sales, Williams enters into fixed-price forward physical contracts to fix the
prices of anticipated sales of electric production.

Derivative gains or losses from these cash flow hedges are deferred in
other comprehensive income and reclassified into earnings in the same period or
periods during which the hedged forecasted purchases or sales affect earnings.
To match the underlying transaction being hedged, derivative gains or losses
associated with anticipated purchases are recognized in costs and operating
expenses and amounts associated with anticipated sales are recognized in
revenues in the Consolidated Statement of Operations. Approximately $1 million
of gains from hedge ineffectiveness is included in revenues in the Consolidated
Statement of Operations during 2001. There were no derivative gains or losses
excluded from the assessment of hedge effectiveness and no hedges were
discontinued during 2001 as a result of it becoming probable that the forecasted
transaction will not occur. There is approximately $142 million of pre-tax gains
related to terminated derivatives included in accumulated other comprehensive
income at December 31, 2001. These amounts will be recognized into net income as
the hedged transaction occurs. As of December 31, 2001, Williams has hedged
future cash flows associated with anticipated energy commodity purchases and
sales for up to 15 years, and, based on recorded

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

values at December 31, 2001, approximately $139 million of net gains (net of
income tax provision of $86 million) will be reclassified into earnings within
the next year offsetting net losses that will be realized in earnings from
unfavorable market movements associated with the underlying hedged transactions.

Energy commodity fair-value hedges

Williams' refineries carry inventories of crude oil and refined products.
Williams enters into crude oil and refined products futures contracts and swap
agreements to reduce the market exposure of these inventories from changing
energy commodity prices. These derivatives have been designated as fair-value
hedges. Derivative gains and losses from these fair-value hedges are recognized
in earnings currently along with the change in fair value of the hedged item
attributable to the risk being hedged. Gains and losses related to hedges of
inventory are recognized in costs and operating expenses in the Consolidated
Statement of Operations. Approximately $5 million of net gains from hedge
ineffectiveness was recognized in costs and operating expenses in the
Consolidated Statement of Operations during 2001. There were no derivative gains
or losses excluded from the assessment of hedge effectiveness.

Other energy commodity derivatives

Williams' operations associated with crude oil refining and refined
products marketing also include derivative transactions (primarily forward
contracts, futures contracts, swap agreements and option contracts) which are
not designated as hedges. The forward contracts are for the procurement of crude
oil and refined products supply for operational purposes, while the other
derivatives manage certain risks associated with market fluctuations in crude
oil and refined product prices related to refined products marketing. The net
change in fair value of these derivatives representing unrealized gains and
losses is recognized in earnings currently as revenues or costs and operating
expenses in the Consolidated Statement of Operations.

Foreign currency hedges

Williams has a Canadian-dollar-denominated note receivable that is exposed
to foreign-currency risk. To protect against variability in the cash flows from
the repayment of the note receivable associated with changes in foreign currency
exchange rates, Williams entered into a forward contract to fix the U.S. dollar
principal cash flows from this note. This derivative has been designated as a
cash flow hedge and is expected to be highly effective over the period of the
hedge. Gains and losses from the change in fair value of the derivative are
deferred in other comprehensive income (loss) and reclassified to other income
(expense) -- net below operating income when the Canadian-dollar-denominated
note receivable impacts earnings as it is translated into U.S. dollars. 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 during 2001 as a result of it becoming probable that the forecasted
transaction will not occur. This foreign-currency risk exposure is being hedged
over the next 48 months. Of the $3.7 million net loss (net of income tax
benefits of $2.3 million) deferred in other comprehensive income (loss) at
December 31, 2001, the amount that will be reclassified into earnings over the
next year will vary based on the gain or loss recognized as the note receivable
is translated into U.S. dollars following changes in foreign-exchange rates.

Interest-rate derivatives

Williams enters into interest-rate swap agreements to manage its exposure
to interest rates and modify the interest characteristics of its long-term debt.
These agreements are designated with specific debt obligations, and involve the
exchange of amounts based on the difference between fixed and variable interest
rates calculated by reference to an agreed-upon notional amount. Interest-rate
swaps in place during 2001 effectively modified Williams' exposure to interest
rates by converting a portion of Williams' fixed rate debt to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

a variable rate. These derivatives were designated as fair value hedges and were
perfectly effective. As a result, there was no current impact to earnings due to
hedge ineffectiveness or due to the exclusion of a component of a derivative
from the assessment of effectiveness. The change in fair value of the
derivatives and the adjustments to the carrying amount of the underlying hedged
debt were recorded as equal and offsetting gains and losses in other income
(expense) -- net below operating income in the Consolidated Statement of
Operations. There are no interest-rate derivatives designated as fair value
hedges at December 31, 2001.

Kern River Gas Transmission had interest-rate swap agreements to manage
interest-rate risk that were not designated as hedges of long-term debt. Changes
in fair value were recorded each period in other income (expense) -- net below
operating income in the Consolidated Statement of Operations. These agreements
were terminated during 2001. Offsetting amounts were recorded as an adjustment
to a regulatory asset, which is expected to be recovered in future
transportation rates.

CONCENTRATION OF CREDIT RISK

Williams' cash equivalents consist of high-quality securities placed with
various major financial institutions with credit ratings at or above AA by
Standard & Poor's or Aa by Moody's Investor's Service. Williams' investment
policy limits its credit exposure to any one issuer/obligor.

The following table summarizes concentration of receivables, net of
allowances, by product or service at December 31, 2001 and 2000:

Natural gas customers include pipelines, distribution companies, producers,
gas marketers and industrial users primarily located in the eastern,
northwestern and midwestern United States. Petroleum products customers include
wholesale, commercial, governmental, industrial and individual consumers and
independent dealers located primarily in Alaska and the midsouth and
southeastern United States. 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.
Collection of the retained interest in accounts receivable sold to the SPEs is
dependent on the collection of the receivables. The underlying receivables are
primarily for the sale or transportation of natural gas and related products or
services and the sale of petroleum products in the United States. As a general
policy, collateral is not required for receivables, but customers' financial
condition and credit worthiness are evaluated regularly.

As of December 31, 2001, $388 million of certain power receivables from the
ISO and the California Power Exchange have not been paid. In addition, Williams
and other energy traders and marketers have been ordered to continue selling
power to the ISO and certain other utilities irrespective of their credit
ratings. Williams believes that it has appropriately reflected the collection
and credit risk associated with receivables and trading assets in the statement
of position and results of operations at December 31, 2001.

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NOTE 19. CONTINGENT LIABILITIES AND COMMITMENTS

RATE AND REGULATORY MATTERS AND RELATED LITIGATION

Williams' 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 $96
million for potential refund as of December 31, 2001.

On January 30, 1998, the FERC convened a public conference to consider, on
an industry-wide basis, issues with respect to rates of return for interstate
natural gas pipelines. In July 1998, the FERC issued orders announcing a
modification of its methodology for calculating a pipeline's return on equity.
Certain parties appealed the FERC's action because the modified formula results
in somewhat higher rates of return compared to the rates of return calculated by
the prior formula. These appeals have been denied and the FERC has continued to
utilize the formula as modified in 1998.

As a result of FERC Order 636 decisions in prior years, each of the natural
gas pipeline subsidiaries has undertaken the reformation or termination of its
respective gas supply contracts. None of the pipelines has any significant
pending supplier take-or-pay, ratable take or minimum take claims.

Williams Energy Marketing & Trading subsidiaries are engaged in power
marketing in various geographic areas, including California. Prices charged for
power by Williams and other traders and generators in California and other
western states have been challenged in various proceedings including those
before the FERC. In December 2000, the FERC issued an order which provided that,
for the period between October 2, 2000 and December 31, 2002, it may order
refunds from Williams and other similarly situated companies if the FERC finds
that the wholesale markets in California are unable to produce competitive, just
and reasonable prices or that market power or other individual seller conduct is
exercised to produce an unjust and unreasonable rate. Beginning on March 9,
2001, the FERC issued a series of orders directing Williams and other similarly
situated companies to provide refunds for any prices charged in excess of FERC
established proxy prices in January, February, March, April and May 2001, or to
provide justification for the prices charged during those months. According to
these orders, Williams' total potential refund liability for January through May
2001 is approximately $30 million. Williams has filed justification for its
prices with the FERC and calculated its refund liability under the methodology
used by the FERC to compute refund amounts at approximately $11 million. On July
25, 2001, the FERC issued an order establishing a hearing to establish the facts
necessary to determine refunds under the approved methodology. Refunds under
this order will cover the period of October 2, 2000 through June 20, 2001. They
will be paid as offsets against outstanding bills and are inclusive of any
amounts previously noticed for refund for that period. The judge presiding over
the refund proceedings is expected to issue his findings in August 2002. The
FERC will subsequently issue a refund order based on these findings.

In the order issued June 19, 2001, the FERC implemented a revised price
mitigation and market monitoring plan for wholesale power sales by all suppliers
of electricity, including Williams, in spot markets for a region that includes
California and ten other western states (the "Western Systems Coordinating
Council," or "WSCC"). In general, the plan, which will be in effect from June
20, 2001 through September 30, 2002, establishes a market clearing price for
spot sales in all hours of the day that is based on the bid of the highest-cost
gas-fired California generating unit that is needed to serve the ISO's load.
When generation operating reserves fall below seven percent in California (a
"reserve deficiency period"), absent cost-based justification for a higher
price, the maximum price that Williams may charge for wholesale spot sales in
the WSCC is the market clearing price. When generation operating reserves rise
to seven percent or above in California, absent cost-based justification for a
higher price, Williams' maximum price will be limited to 85 percent of the
highest hourly price that was in effect during the most recent reserve
deficiency period. This methodology initially resulted in a maximum price of $92
per megawatt hour during non-emergency periods and $108 per

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megawatt hour during emergency periods, and these maximum prices remained
unchanged throughout Summer and Fall 2001.

The California Public Utilities Commission (CPUC) filed a complaint with
the FERC on February 25, 2002, seeking to void or, alternatively, reform a
number of the long-term power purchase contracts entered into between the State
of California and several suppliers in 2001, including Energy Marketing &
Trading. The CPUC alleges that the contracts are tainted with the exercise of
market power and significantly exceed "just and reasonable" prices. The
Electricity Oversight Board made a similar filing on February 27, 2002.

On December 19, 2001, the FERC reaffirmed its June 19 and July 25 orders
with certain clarifications and modifications. It also altered the price
mitigation methodology for spot market transactions for the WSCC market for the
winter 2001 season and set the period maximum price at $108 per megawatt hour
through April 30, 2002. Under the order, this price would be subject to being
recalculated when the average gas price rises by a minimum factor of ten percent
effective for the following trading day, but in no event will the maximum price
drop below $108 per megawatt hour. The FERC also upheld a ten percent addition
to the price applicable to sales into California to reflect credit risk.

Certain entities have also asked the FERC to revoke Williams' authority to
sell power from California-based generating units at market-based rates to limit
Williams to cost-based rates for future sales from such units and to order
refunds of excessive rates, with interest, back to May 1, 2000, and possibly
earlier.

On March 14, 2001, the FERC issued a Show Cause Order directing Williams
Energy Marketing & Trading Company and AES Southland, Inc. to show cause why
they should not be found to have engaged in violations of the Federal Power Act
and various agreements, and they were directed to make refunds in the aggregate
of approximately $10.8 million, and have certain conditions placed on Williams'
market-based rate authority for sales from specific generating facilities in
California for a limited period. On April 30, 2001, the FERC issued an Order
approving a settlement of this proceeding. The settlement terminated the
proceeding without making any findings of wrongdoing by Williams. Pursuant to
the settlement, Williams agreed to refund $8 million to the ISO by crediting
such amount against outstanding invoices. Williams also agreed to prospective
conditions on its authority to make bulk power sales at market-based rates for
certain limited facilities under which it has call rights for a one-year period.
Williams also has been informed that the facts underlying this proceeding are
also under investigation by a California Grand Jury.

On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking
proposing to adopt uniform standards of conduct for transmission providers. The
proposed rules define transmission providers as interstate natural gas pipelines
and public utilities that own, operate or control electric transmission
facilities. The proposed standards would regulate the conduct of transmission
providers with their energy affiliates. The FERC proposes to define energy
affiliates broadly to include any transmission provider affiliate that engages
in or is involved in transmission (gas or electric) transactions, or manages or
controls transmission capacity, or buys, sells, trades or administers natural
gas or electric energy or engages in financial transactions relating to the sale
or transmission of natural gas or electricity. Current rules affecting Williams
regulate the conduct of Williams' natural gas pipelines and their natural gas
marketing affiliates. If adopted, these new standards would require the adoption
of new compliance measures by certain Williams subsidiaries.

On February 13, 2002, the FERC issued an Order Directing Staff
Investigation commencing a proceeding titled Fact-Finding Investigation of
Potential Manipulation of Electric and Natural Gas Prices. Through the
investigation, the FERC intends to determine whether "any entity, including
Enron Corporation (through any of its affiliates or subsidiaries), manipulated
short-term prices for electric energy or natural gas in the West or otherwise
exercised undue influence over wholesale electric prices in the West, since
January 1, 2000, resulting in potentially unjust and unreasonable rates in
long-term power sales contracts subsequently entered into by sellers in the
West." This investigation does not constitute a Federal Power Act complaint,
rather, the results of the investigation will be used by the FERC in any
existing or subsequent Federal Power

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Act or Natural Gas Act complaint. The FERC Staff is directed to complete the
investigation as soon as "is practicable." Williams, through many of its
subsidiaries, is a major supplier of natural gas and power in the West and, as
such, anticipates being the subject of certain aspects of the investigation.

ENVIRONMENTAL MATTERS

Since 1989, Texas Gas and Transcontinental Gas Pipe Line have had studies
under way to test certain of their facilities for the presence of toxic and
hazardous substances to determine to what extent, if any, remediation may be
necessary. Transcontinental Gas Pipe Line has responded to data requests
regarding such potential contamination of certain of its sites. The costs of any
such remediation will depend upon the scope of the remediation. At December 31,
2001, these subsidiaries had accrued liabilities totaling approximately $33
million for these costs.

Certain Williams subsidiaries, including Texas Gas and Transcontinental Gas
Pipe Line, have been identified as potentially responsible parties (PRP) 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.
Although no assurances can be given, Williams does not believe that these
obligations or the PRP status of these subsidiaries will have a material adverse
effect on its financial position, results of operations or net cash flows.

Transcontinental Gas Pipe Line, Texas Gas and Williams Gas Pipelines
Central (Central) have identified polychlorinated biphenyl contamination in air
compressor systems, soils and related properties at certain compressor station
sites. Transcontinental Gas Pipe Line, Texas Gas and Central have also been
involved in negotiations with the U.S. Environmental Protection Agency (EPA) and
state agencies to develop screening, sampling and cleanup programs. In addition,
negotiations with certain environmental authorities and other programs
concerning investigative and remedial actions relative to potential mercury
contamination at certain gas metering sites have been commenced by Central,
Texas Gas and Transcontinental Gas Pipe Line. As of December 31, 2001, Central
had accrued a liability for approximately $9 million, representing the current
estimate of future environmental cleanup costs to be incurred over the next six
to ten years. Texas Gas and Transcontinental Gas Pipe Line likewise had accrued
liabilities for these costs which are included in the $33 million liability
mentioned above. Actual costs incurred will depend 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 July 1999, Transcontinental Gas Pipe Line received a letter stating that
the U.S. Department of Justice (DOJ), at the request of the EPA, intends to file
a civil action against Transcontinental Gas Pipe Line arising from its waste
management practices at Transcontinental Gas Pipe Line's compressor stations and
metering stations in 11 states from Texas to New Jersey. Transcontinental Gas
Pipe Line, the EPA and the DOJ agreed to settle this matter by signing a Consent
Decree that provides for a civil penalty of $1.4 million.

Williams Energy Services (WES) and its subsidiaries also accrue
environmental remediation costs for its natural gas gathering and processing
facilities, petroleum products pipelines, retail petroleum and refining
operations and for certain facilities related to former propane marketing
operations primarily related to soil and groundwater contamination. In addition,
WES owns a discontinued petroleum refining facility that is being evaluated for
potential remediation efforts. At December 31, 2001, WES and its subsidiaries
had accrued liabilities totaling approximately $43 million. WES accrues
receivables related to environmental remediation costs based upon an estimate of
amounts that will be reimbursed from state funds for certain expenses associated
with underground storage tank problems and repairs. At December 31, 2001, WES
and its subsidiaries had accrued receivables totaling $1 million.

Williams Field Services (WFS), a WES subsidiary, received a Notice of
Violation (NOV) from the EPA in February 2000. WFS received a contemporaneous
letter from the DOJ indicating that the DOJ will

124

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

also be involved in the matter. The NOV alleged violations of the Clean Air Act
at a gas processing plant. WFS, the EPA and the DOJ agreed to settle this matter
for a penalty of $850,000. In the course of investigating this matter, WFS
discovered a similar potential violation at the plant and disclosed it to the
EPA and the DOJ. In December 2001, the EPA, the DOJ and WFS agreed to settle
this self-reported matter by signing a Consent Decree that provides for a
penalty of $950,000.

In connection with the 1987 sale of the assets of Agrico Chemical Company,
Williams 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, 2001, Williams had
approximately $10 million accrued for such excess costs. The actual costs
incurred will depend on the actual amount and extent of contamination
discovered, the final cleanup standards mandated by the EPA or other
governmental authorities, and other factors.

On July 2, 2001, the EPA issued an information request asking for
information on oil releases and discharges in any amount from Williams'
pipelines, pipeline systems, and pipeline facilities used in the movement of oil
or petroleum products, during the period July 1, 1998 through July 2, 2001. In
November 2001, Williams furnished its response.

OTHER LEGAL MATTERS

In connection with agreements to resolve take-or-pay and other contract
claims and to amend gas purchase contracts, Transcontinental Gas Pipe Line and
Texas Gas each 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. As a result of
such settlements, Transcontinental Gas Pipe Line is currently defending three
lawsuits brought by producers. In one of the cases, a jury verdict found that
Transcontinental Gas Pipe Line was required to pay a producer damages of $23.3
million including $3.8 million in attorneys' fees. In addition, through December
31, 2001, post-judgment interest was approximately $10.5 million.
Transcontinental Gas Pipe Line's appeals have been denied by the Texas Court of
Appeals for the First District of Texas, and on April 2, 2001, the company filed
an appeal to the Texas Supreme Court. On February 21, 2002, the Texas Supreme
Court denied Transcontinental Gas Pipe Line's petition for review. As a result,
Transcontinental Gas Pipe Line recorded a pre-tax charge to income (loss) for
the year ended December 31, 2001 in the amount of $37 million ($18 million is
included in Gas Pipeline's segment profit and $19 million in interest accrued)
representing management's estimate of the effect of this ruling.
Transcontinental Gas Pipe Line plans to request rehearing of the court's
decision. In the other cases, producers have asserted damages, including
interest calculated through December 31, 2001, of $16.3 million. Producers have
received and may receive other demands, which could result in additional claims.
Indemnification for royalties will depend on, among other things, the specific
lease provisions between the producer and the lessor and the terms of the
settlement between the producer and either Transcontinental Gas Pipe Line or
Texas Gas. Texas Gas may file to recover 75 percent of any such additional
amounts it may be required to pay pursuant to indemnities for royalties under
the provisions of Order 528.

On June 8, 2001, 14 Williams entities were named as defendants in a
nationwide class action lawsuit which has been pending against other defendants,
generally pipeline and gathering companies, for more than one year. The
plaintiffs allege that the defendants, including the Williams defendants, have
engaged in mismeasurement techniques that distort the heating content of natural
gas, resulting in an alleged underpayment of royalties to the class of producer
plaintiffs. In September 2001, the plaintiffs voluntarily dismissed two of the
14 Williams entities named as defendants in the lawsuit. In November 2001,
Williams, along with other Coordinating Defendants, filed a motion to dismiss
under Rules 9b and 12b of the Kansas Rules of Civil Procedure. In January 2002,
most of the Williams defendants, along with a group of Coordinating Defendants,
filed a motion to dismiss for lack of personal jurisdiction. The court has not
yet ruled on these motions. In the

125

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

next several months, the Williams entities will join with other defendants in
contesting certification of the plaintiff class.

In 1998, the United States Department of Justice informed Williams that
Jack Grynberg, an individual, had filed claims in the United States District
Court for the District of Colorado under the False Claims Act against Williams
and certain of its wholly owned subsidiaries including Central, Kern River Gas
Transmission, Northwest Pipeline, Williams Gas Pipeline Company,
Transcontinental Gas Pipe Line Corporation, Texas Gas, Williams Field Services
Company and Williams Production Company. Mr. Grynberg has also filed claims
against approximately 300 other energy companies and alleges that the defendants
violated the False Claims Act in connection with the measurement and purchase of
hydrocarbons. The relief sought is an unspecified amount of royalties allegedly
not paid to the federal government, treble damages, a civil penalty, attorneys'
fees, and costs. On April 9, 1999, the United States Department of Justice
announced that it was declining to intervene in any of the Grynberg qui tam
cases, including the action filed against the Williams entities in the United
States District Court for the District of Colorado. On October 21, 1999, the
Panel on Multi-District Litigation transferred all of the Grynberg qui tam
cases, including those filed against Williams, to the United States District
Court for the District of Wyoming for pre-trial purposes. Motions to dismiss the
complaints filed by various defendants, including Williams, were denied on May
18, 2001.

Williams and certain of its subsidiaries are named as defendants in various
putative, nationwide class actions brought on behalf of all landowners on whose
property the plaintiffs have alleged WCG installed fiber-optic cable without the
permission of the landowners. Williams believes that WCG's installation of the
cable containing the fiber network that crosses over or near the putative class
members' land does not infringe on their property rights. Williams also does not
believe that the plaintiffs have sufficient basis for certification of a class
action. It is likely that Williams will be subject to other putative class
action suits challenging WCG's railroad or pipeline rights of way. However,
Williams has a claim for indemnity from WCG, subject to their ability to
perform, for damages resulting from or arising out of the businesses or
operations conducted or formerly conducted or assets owned or formerly owned by
any subsidiary of WCG.

In November 2000, class actions were filed in San Diego, California
Superior Court by Pamela Gordon and Ruth Hendricks on behalf of San Diego rate
payers against California power generators and traders including Williams Energy
Services Company and Williams Energy Marketing & Trading Company, subsidiaries
of Williams. Three municipal water districts also filed a similar action on
their own behalf. Other class actions have been filed on behalf of the people of
California and on behalf of commercial restaurants in San Francisco Superior
Court. These lawsuits result from the increase in wholesale power prices in
California that began in the summer of 2000. Williams is also a defendant in
other litigation arising out of California energy issues. The suits claim that
the defendants acted to manipulate prices in violation of the California
antitrust and unfair business practices statutes and other state and federal
laws. Plaintiffs are seeking injunctive relief as well as restitution,
disgorgement, appointment of a receiver, and damages, including treble damages.
These cases have all been coordinated in San Diego County Superior Court.

On May 2, 2001, the Lieutenant Governor of the State of California and
Assemblywoman Barbara Matthews, acting in their individual capacities as members
of the general public, filed suit against five companies including Williams
Energy Marketing & Trading and 14 executive officers, including Keith Bailey,
Chairman of Williams, Steve Malcolm, President and CEO of Williams, and Bill
Hobbs, President and CEO of Williams Energy Marketing & Trading, in Los Angeles
Superior State Court alleging State Antitrust and Fraudulent and Unfair Business
Act Violations and seeking injunctive and declaratory relief, civil fines,
treble damages and other relief, all in an unspecified amount. This case is
being coordinated with the other class actions in San Diego Superior Court.

On May 17, 2001, the DOJ advised Williams that it had commenced an
antitrust investigation relating to an agreement between a subsidiary of
Williams and AES Southland alleging that the agreement limits the expansion of
electric generating capacity at or near the AES Southland plants that are
subject to a long-term

126

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

tolling agreement between Williams and AES Southland. In connection with that
investigation, the DOJ has issued two Civil Investigative Demands to Williams
requesting answers to certain interrogatories and the production of documents.
Williams is cooperating with the investigation.

On October 5, 2001, suit was filed on behalf of California taxpayers and
electric ratepayers in the Superior Court for the County of San Francisco
against the Governor of California and 22 other defendants consisting of other
state officials, utilities and generators, including Energy Marketing & Trading.
The suit alleges that the long-term power contracts entered into by the state
with generators are illegal and unenforceable on the basis of fraud, mistake,
breach of duty, conflict of interest, failure to comply with law, commercial
impossibility and change in circumstances. Remedies sought include rescission,
reformation, injunction, and recovery of funds.

On October 19, 2001, Williams settled a $42 million claim for coal royalty
payments relating to a discontinued activity by agreeing to pay $9.5 million.

Since January 29, 2002, Williams is aware of numerous shareholder class
action suits that have been filed in the United States District Court for the
Northern District of Oklahoma. The majority of the suits allege that Williams
and co-defendants, 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. This case was filed against
Williams, certain corporate officers, all members of the Williams board of
directors and all of the offerings' underwriters. Williams does not anticipate
any immediate action by the Court in these actions. In addition, class action
complaints have been filed against Williams and the members of its board of
directors under the Employee Retirement Income Security Act by participants in
Williams' 401(k) plan based on similar allegations.

In addition to the foregoing, various other proceedings are pending against
Williams or its subsidiaries which are incidental to their operations.

Enron Corp. (Enron) and certain of its subsidiaries, with whom Energy
Marketing & Trading and other Williams subsidiaries have had commercial
relations, filed a voluntary petition for Chapter 11 reorganization under the
U.S. Bankruptcy Code in the Federal District Court for the Southern District of
New York on December 2, 2001. Additional Enron subsidiaries have subsequently
filed for Chapter 11. The court has not set a date for the filing of claims.
During fourth-quarter 2001, Energy Marketing & Trading recorded a total decrease
to revenues of approximately $130 million as a part of its valuation of energy
commodity and derivative trading contracts with Enron entities, approximately
$91 million of which was recorded pursuant to events immediately preceding and
following the announced bankruptcy of Enron. Other Williams subsidiaries
recorded approximately $5 million of bad debt expense related to amounts
receivable from Enron entities in fourth-quarter 2001, reflected in selling,
general and administrative expenses. At December 31, 2001, Williams has reduced
its recorded exposure to accounts receivable from Enron entities, net of margin
deposits, to expected recoverable amounts.

SUMMARY

While no assurances may be given, Williams, based on advice of counsel,
does not believe 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 have a materially
adverse effect upon Williams' future financial position, results of operations
or cash flow requirements.

COMMITMENTS

Energy Marketing & Trading has entered into certain contracts giving
Williams the right to receive fuel conversion services as well as certain other
services associated with electric generation facilities that are either

127

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

currently in operation or are to be constructed at various locations throughout
the continental United States. At December 31, 2001, annual estimated committed
payments under these contracts range from approximately $20 million to $462
million, resulting in total committed payments over the next 21 years of
approximately $8 billion.

See Note 4 for commitments related to certain equity and cost method
investments and Note 11 for commitments for construction and acquisition of
property, plant and equipment.

NOTE 20. RELATED PARTY TRANSACTIONS

In fourth-quarter 2000, Williams entered into a $600 million debt
obligation with Lehman Brothers Inc. Lehman Brothers Inc. is a related party as
a result of a director that serves on both Williams' and Lehman Brothers
Holdings, Inc.'s board of directors. This debt obligation was paid in
first-quarter 2001. In addition, Williams paid $27 million to Lehman Brothers
Inc. in 2001, primarily for underwriting fees related to debt and equity
issuances.

128

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 21. ACCUMULATED OTHER COMPREHENSIVE INCOME

The table below presents changes in the components of accumulated other
comprehensive income.

129

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Unrealized appreciation (depreciation) on securities for years prior to
2000 represents activity related to securities held by WCG. At December 31,
2000, the unrealized appreciation (depreciation) on securities balance includes
$76.1 million of unrealized net appreciation related to securities held by WCG.
Foreign currency translation balances include translation losses of $38.5
million and $13.6 million at December 31, 2000 and 1999, respectively, which
relate to WCG. The adjustment due to the spinoff of WCG for 2001 includes
unrealized appreciation (depreciation) on securities and foreign currency
translation balances which relate to WCG and are included in the $2.0 billion
decrease to stockholders' equity (see Note 3). The remaining balances relate to
the continuing operations of Williams.

NOTE 22. SEGMENT DISCLOSURES

Williams evaluates performance based upon 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. 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 as if the
sales were to unaffiliated third parties, that is, at current market prices.

The majority of energy commodity hedging by the Energy Services' business
units is done through intercompany derivatives with Energy Marketing & Trading
which, in turn, enters into offsetting derivative contracts with unrelated third
parties. Energy Marketing & Trading bears the counter party performance risks
associated with unrelated third parties. Similarly, hedging of interest rate
risk in the energy trading portfolio by Energy Marketing & Trading is
facilitated by the corporate treasury operation. All hedging effectiveness,
ineffectiveness and risk of this activity is recognized by Energy Marketing &
Trading.

Williams' 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 includes corporate operations.

Segment amounts for 2000 and 1999 have been restated to reflect two new
reporting segments, International and Williams Energy Partners, and the
reclassification of Energy Marketing & Trading to a third industry group (see
Note 1).

Exploration & Production's 2001 additions to long-lived assets and increase
in total assets, as noted on pages 132 and 133, respectively, are due primarily
to the Barrett acquisition (see Note 2).

130

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table reflects the reconciliation of operating income as
reported on the Consolidated Statement of Operations to segment profit (loss),
per the table on page 132.

The following geographic area data includes revenues from external
customers based on product shipment origin and long-lived assets based upon
physical location.

Long-lived assets are comprised of property, plant and equipment and
goodwill and other intangible assets.

131

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- ---------------

* Energy Marketing & Trading intercompany cost of sales, which are netted in
revenues consistent with fair-value accounting, exceed intercompany revenues.

132

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONCLUDED)

NOTE 23. SUBSEQUENT EVENTS

In January 2002, Williams issued 44 million publicly traded units, more
commonly known as FELINE PACs, that include a senior debt security and an equity
purchase contract. The debt has a term of five years, and the equity purchase
contract will require the company to deliver Williams common stock to holders
after three years based on a previously agreed rate. Net proceeds from this
issuance were approximately $1.1 billion.

The FELINE PACS were issued as part of Williams' plan to strengthen its
balance sheet and maintain its investment-grade rating. Some of the steps which
could impact amounts recorded at December 31, 2001 include:

- A $1 billion reduction in planned capital spending for 2002.

- Sales of certain non-core assets during 2002, from which Williams expects
to receive proceeds of between $250 million and $750 million.

- Initiation of action to eliminate ratings triggers on certain obligations
and contingencies that do not appear as debt on the Consolidated Balance
Sheet.

Williams has also announced plans to sell its midwest petroleum products
pipeline and on-system terminals. A potential buyer would be Williams Energy
Partners, L.P., a consolidated entity.

133

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.

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.

First-quarter 2001 net income includes an after-tax loss from discontinued
operations of $179.1 million related to the spinoff of WCG and fourth-quarter
2001 loss from discontinued operations includes $1.17 billion after-tax impact
for accruals of WCG guarantees and payment obligations (see Note 3).
Additionally, first and fourth-quarter 2001 net income (loss) includes
additional pre-tax impairment charges of $11.2 million and $.9 million,
respectively, relating to Petroleum Services' end-to-end mobile computing
systems business.

Second and fourth-quarter 2001 net income (loss) includes a pre-tax gain
from the sale of certain convenience stores at Petroleum Services of $72.1
million and $3.2 million, respectively. Second and third-quarter 2001 net income
includes a pre-tax impairment loss related to certain south Texas non-regulated
gathering and processing assets at Midstream Gas & Liquids of $10.9 million and
$4.2 million, respectively. A $1.3 million reduction to these impairment charges
was made in fourth-quarter 2001 based on proceeds from the sales which closed in
first-quarter 2002. Additionally, second-quarter 2001 includes a $27.5 million
pre-tax gain on the sale of Williams' limited partnership interest in Northern
Border Partners, L.P. at Gas Pipeline.

Included in third-quarter 2001 net income is a $94.2 million pre-tax charge
related to the write-down of certain equity and cost basis investments (see Note
4).

Fourth-quarter 2001 net income (loss) includes a $170 million pre-tax
impairment charge relating to the soda ash mining operations located in Colorado
(see Note 5). Also, included in fourth-quarter 2001 net

134

THE WILLIAMS COMPANIES, INC.

QUARTERLY FINANCIAL DATA -- (CONCLUDED)
(UNAUDITED)

income (loss) is a $130 million pre-tax decrease to revenues and a $5 million
pre-tax charge to bad expense related to Williams' estimated net exposure for
the Enron bankruptcy at Energy Marketing & Trading and Gas Pipeline,
respectively (see Note 19), a $13.3 million pre-tax impairment charge for the
termination of a plant expansion at Energy Marketing & Trading and a $14.7
million pre-tax impairment charge and other loss accruals related to certain
travel centers at Petroleum Services. Additionally, fourth-quarter 2001 net
income (loss) includes a $37 million pre-tax charge resulting from an
unfavorable court decision in one of Transcontinental Gas Pipe Line's royalty
claims proceeding (see Note 19) and $213 million pre-tax charges included in
continuing operations related to estimated losses from an assessment of the
recoverability of WCG related receivables (see Note 3).

Second-quarter 2000 net income includes approximately $75 million in
pre-tax reductions to certain rate refund liabilities and related interest
accruals based on favorable FERC and judicial rulings received regarding
regulatory proceedings. Also included in second and fourth-quarter 2000 net
income (loss) is a $25.9 million and a $17.2 million pre-tax charge,
respectively, resulting from the decision to discontinue Energy Marketing &
Trading's mezzanine lending services (see Note 5). Fourth-quarter 2000 net
income includes a $16.3 million pre-tax charge relating to management's decision
and commitment to sell Energy Marketing & Trading's distributed power generation
business and an $11.9 million pre-tax charge relating to management's decision
and commitment to sell certain of Petroleum Services' end-to-end mobile
computing systems business. These charges represent the impairment of the assets
to fair value based on the expected net sales proceeds.

First, third and fourth-quarter 2000 include after-tax loss from
discontinued operations of $39.2 million, $55.4 million and $411.9 million,
respectively, while second-quarter 2000 includes after-tax income of $65.4
million, all of which are related to WCG which was spun off April 23, 2001 (see
Note 3).

135

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES
(UNAUDITED)

The following information pertains to the Company's 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. Williams has significant oil and gas producing activities
primarily in the Rocky Mountain, Mid-continent and Gulf Coast regions of the
United States. Additionally, Williams has oil and gas producing activities in
Argentina; however, proved reserves and revenues related to these activities are
approximately 5.6 percent and 4.3 percent, respectively, of Williams' total oil
and gas producing activities. The following information relates only to the oil
and gas activities in the United States.

CAPITALIZED COSTS

- Capitalized costs include the cost of equipment and facilities for oil
and gas producing activities. This amount does not include approximately
$1 billion of goodwill related to the purchase of Barrett Resources Corp.
(Barrett).

- 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); successful
exploratory wells and related equipment and facilities (and uncompleted
exploratory well costs) and support equipment.

- Unproved properties consist primarily of acreage related to probable
reserves acquired through the Barrett acquisition in addition to a small
portion of unproved exploratory acreage.

COSTS INCURRED DURING 2001

- Costs incurred include capitalized and expensed items.

- Property acquisition costs include costs incurred to purchase, lease, or
otherwise acquire a property, the majority of which is related to the
Barrett acquisition.

- Exploration costs include the costs of geological and geophysical
activity, dry holes, drilling and equipping exploratory wells, 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.

136

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES -- (CONTINUED)
(UNAUDITED)

RESULTS OF OPERATIONS

- Results of operations for producing activities consist of all related
activities within the Exploration & Production reporting unit.

- Oil and gas revenues consist primarily of natural gas production sold to
Energy Marketing & Trading 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 Energy Marketing & Trading or third party purchases.
In addition, other revenues include recognition of income from
transactions which transferred certain non-operating benefits to a third
party.

- 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.

137

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES -- (CONTINUED)
(UNAUDITED)

PROVED RESERVES

- Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
indicate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e.,
prices and costs as of the date the estimate is made.

- 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 $2.31 per mmcf and $9.17 per mmcf at December 31,
2001 and December 31, 2000, 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 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.

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.

138

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES -- (CONCLUDED)
(UNAUDITED)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

SOURCES OF CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

139

THE WILLIAMS COMPANIES, INC.

SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS

- ---------------

(a) Deducted from related assets.

(b) Included in liabilities.

(c) Represents balances written off, net of recoveries and reclassifications.

(d) Represents payments made.

(e) Reflects a reclassification of the reserve related to Enron from Price-risk
management credit reserves to Allowance for doubtful
accounts -- Receivables (see Note 19 of Notes to Consolidated Financial
Statements) and amounts related to acquisitions of businesses.

(f) Reflects a reclassification of the reserve related to Enron from Price-risk
management credit reserves to Allowance for doubtful
accounts -- Receivables (see Note 19 of Notes to Consolidated Financial
Statements).

(g) Primarily relates to acquisitions of businesses.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

140

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information regarding the directors and nominees for director of
Williams required by Item 401 of Regulation S-K will be presented under the
heading "Election of Directors" in Williams' Proxy Statement prepared for the
solicitation of proxies in connection with the Annual Meeting of Stockholders of
Williams for 2002 (the "Proxy Statement"), which information is incorporated by
reference herein. Information regarding the executive officers of Williams is
presented following Item 4 herein 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 is included under the heading "Compliance
with Section 16(a) of the Securities Exchange Act of 1934" in the Proxy
Statement, which information is incorporated by reference herein.

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 402 of Regulation S-K regarding executive
compensation is presented under the headings "Election of Directors" and
"Executive Compensation and Other Information" in the 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 the
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 is presented under
the headings "Security Ownership of Certain Beneficial Owners and Management" in
the Proxy Statement, which information is incorporated by reference herein.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information regarding certain relationships and related transactions
required by Item 404 of Regulation S-K is presented under the heading "Certain
Relationships and Related Transactions" in the Proxy Statement, which
information is incorporated by reference herein.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) 1 and 2.

141

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 (c). The exhibits listed below are filed as part of this annual
report.

EXHIBITS

142

143

144

145

146

- ---------------

* Each such exhibit has heretofore been filed with the Securities and Exchange
Commission as part of the filing indicated and is incorporated herein by
reference.

** Williams agrees upon request to furnish each such exhibit to the Securities
and Exchange Commission. The total amount of the securities authorized under
each such exhibit does not exceed ten percent of the total assets of Williams
and its subsidiaries taken as a whole.

(b) Reports on Form 8-K.

On November 29, 2001, Williams filed a current report on Form 8-K to
reaffirm its 2001 earnings guidance and 15 percent annual earnings growth.

On December 19, 2001, Williams filed a current report on Form 8-K to
announce steps to further strengthen its balance sheet and liquidity profile.

On December 21, 2001, Williams filed a current report on Form 8-K to
announce that international rating agencies Fitch, Inc., Standard & Poor's and
Moody's Investors Service had reaffirmed Williams' investment-grade ratings.

(d) The financial statements of partially owned companies are not presented
herein since none of them individually, or in the aggregate, constitute a
significant subsidiary.

147

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

THE WILLIAMS COMPANIES, INC.
(Registrant)

By: /s/ SUZANNE H. COSTIN
----------------------------------
Suzanne H. Costin
Attorney-in-fact

Date: March 7, 2002

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.

148

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INDEX TO EXHIBITS

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