WILLIAMS COMPANIES INC - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 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, 2002

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 (IRS Employer
Incorporation or Organization) Identification No.)

ONE WILLIAMS CENTER, TULSA, OKLAHOMA 74172
(Address of Principal Executive Offices) (Zip Code)

918-573-2000
(Registrant's Telephone Number, Including Area Code)

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. [X]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [X] No [ ]

The aggregate market value of the voting and non-voting common equity held
by non-affiliates computed by reference to the price at which the common equity
was last sold, as of the last business day of the registrant's most recently
completed second quarter was approximately $3,099,735,940.

The number of shares outstanding of the registrant's common stock held by
non-affiliates outstanding at February 28, 2003 was 517,538,177.

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
the registrant for 2003 are incorporated by reference in Part III of this Form
10-K.
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THE WILLIAMS COMPANIES, INC.
FORM 10-K

TABLE OF CONTENTS

iii

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

In this report, Williams (which includes The Williams Companies, Inc. and
unless the context otherwise requires, all of our subsidiaries) is at times
referred to in the first person as "we," "us" or "our". We also sometimes refer
to Williams as the "Company."

WEBSITE ACCESS TO REPORTS

Our Internet address is www.williams.com. As required, as of November 15,
2002, we make available free of charge on or through our Internet website our
annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K and amendments to those reports filed or furnished pursuant to Section
13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we
electronically file such material with, or furnish it to, the Securities and
Exchange Commission.

GENERAL

We are an energy company originally incorporated under the laws of the
state of Nevada in 1949 and reincorporated under the laws of the state of
Delaware in 1987. We were founded in 1908 when two Williams brothers began a
construction company in Fort Smith, Arkansas. Today, we primarily find, produce,
gather, process and transport natural gas. Our operations serve the Northwest,
California, Rocky Mountains, Gulf Coast and Eastern Seaboard markets.

In 2002, we faced many challenges including credit issues following the
deterioration of our energy industry sector in the wake of the Enron bankruptcy
and the assumption of payment obligations and performance on guarantees
associated with our former telecommunications subsidiary, Williams
Communications Group, Inc. (WCG). With the deterioration of the energy industry,
the credit rating agencies' requirements for investment grade companies became
more stringent. In response to those requirements, we announced plans on
December 19, 2001, to strengthen our balance sheet in an effort to maintain our
investment grade ratings. Those plans including revisions throughout the year
due to changing market conditions included reducing capital expenditures,
eliminating certain credit ratings triggers from our loan agreements, cost
reductions including a reduction of quarterly dividends paid on our common
stock, and asset sales to generate proceeds to be used to reduce outstanding
debt. Despite our balance sheet strengthening efforts, we lost our investment
grade ratings in July 2002. With the loss of our investment grade ratings our
business changed significantly, especially our Energy Marketing & Trading
business. Some counterparties were unwilling to extend credit and required cash,
letters of credit, or other collateral. By mid-year we faced a liquidity crisis.
Concurrently, our credit facility banks were unwilling to extend our $2.2
billion 364 day unsecured credit facility. We quickly worked with our banks and
other parties to obtain secured credit facilities. In 2002, we also sold a
significant amount of assets to meet our liquidity gap. Following this liquidity
crisis, we continued to pursue cost reducing measures including a downsizing of
our work force. We also settled substantially all issues between us and WCG
through WCG's chapter 11 reorganization.

To meet future debt obligations and liquidity needs and focus on creating
future shareholder value, on February 20, 2003, we reiterated our strategy to
become a smaller integrated natural gas company focusing on key growth markets
within our Gas Pipeline, Exploration & Production, and Midstream Gas & Liquids
segments. In conjunction with the strategy announcement and to help meet future
debt obligations and future liquidity needs, we also announced plans to sell
more assets including Texas Gas Transmission Corporation, our general and
limited partner interest in Williams Energy Partners L.P., and certain assets
within our Midstream Gas & Liquids and Exploration & Production business
segments, and explained that we are attempting to further limit our exposure to
losses in the Energy Marketing & Trading segment. We also expect further work
force reductions in 2003.

We will need to complete further cost reductions and asset sales and the
realization of our strategy in order to meet our liquidity needs and to satisfy
our loan covenants regarding minimum levels of liquidity. See

1

Managements' Discussion and Analysis of Financial Condition and Results of
Operations -- Financial Condition and Liquidity for further details on liquidity
issues we are facing. See also the Risk Factors page 34 for a discussion of
factors that could adversely affect our business, operating results, and
financial condition as well as adversely affect the value of an investment in
our securities.

Our ongoing business segments include Gas Pipeline, Exploration &
Production, Midstream Gas & Liquids, and Energy Marketing & Trading. At year-end
2002, our business segments also included Williams Energy Partners L.P. and
Petroleum Services. Subject to completion of asset sales, those business
segments will likely be eliminated in the future. See Part I -- Item 1.
Business -- Business Segments for a detailed description of assets owned and
services provided by each business segment.

GAS PIPELINE

- We own one of the nation's largest interstate natural gas pipeline
systems with 20,200 miles of interstate natural gas pipelines for
transportation of natural gas across the country to utilities and
industrial customers.

- Our pipelines include Transcontinental Gas Pipe Line Corporation, Texas
Gas Transmission Corporation and Northwest Pipeline Corporation. We have
announced our intention to sell Texas Gas Transmission Corporation. If
this pipeline is sold, our network will cover 14,400 miles of natural gas
pipelines.

- We also own a 50 percent interest in the Gulfstream Pipeline.

EXPLORATION & PRODUCTION

- We had 2.8 trillion cubic feet of proved natural gas reserves as of
December 31, 2002.

- We produce, develop, explore for and manage natural gas reserves
primarily located in the Rocky Mountain and Mid-Continent regions of the
United States.

- We produce natural gas predominately from tight-sand formations and coal
bed methane reserves.

MIDSTREAM GAS & LIQUIDS

- We own and operate gas gathering and processing facilities within the
western states of Wyoming, Colorado, and New Mexico and the onshore and
offshore shelf and deepwater areas in and around the Gulf Coast states of
Texas, Alabama, Mississippi, and Louisiana.

- We own interests in and/or operate natural gas liquids fractionation and
storage assets within central region of Kansas and southern Louisiana,
and natural gas liquid transportation pipelines in the Gulf Coast.

- We own and operate an ethylene production, storage and transportation
complex (partially owned) and olefin extraction assets within Louisiana.

- We own and/or operate natural gas processing, liquid extraction,
fractionation and olefin extraction assets within Canada.

- We provide natural gas liquid and petrochemical marketing and risk
management services to customers from products produced from our
processing and extraction facilities as well as from outside sources.

- We have ownership interests in various Venezuelan energy assets.

ENERGY MARKETING & TRADING

- Our Energy Marketing & Trading segment 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, crude oil and emissions credits, primarily on a wholesale
level.
2

- We have announced our intention to sell certain portions of the Energy
Marketing & Trading portfolio, to liquidate of certain positions and
negotiations with parties for a joint venture or sale of all or a portion
of the trading portfolio.

INVESTMENT IN WILLIAMS ENERGY PARTNERS L.P.

- We have a 53 percent limited partnership interest and own 100 percent of
the general partnership interest in Williams Energy Partners L.P.
(Williams Energy Partners). In February 2003, we announced our intention
to sell our ownership interests in Williams Energy Partners.

- Williams Energy Partners owns a 6,700 mile refined petroleum products
pipeline system (the Williams Pipe Line system acquired from Petroleum
Services in 2002) that serves the mid-continent region of the United
States with 39 system terminals and 26 million barrels of storage.

- Williams Energy Partners has five petroleum products terminal facilities
located along the Gulf Coast and near the New York harbor (marine
terminals) with an aggregate storage capacity of approximately 18 million
barrels.

- Williams Energy Partners has 23 petroleum products terminals located
principally in the southeastern United States (inland terminals) with an
aggregate storage capacity of five million barrels.

- Williams Energy Partners also has an 1,100-mile ammonia pipeline system
that serves the mid-continent region of the United States.

OTHER

Our ongoing business segments are accounted for as continuing operations in
the accompanying financial statements and notes to financial statements included
in Part II. Assets announced to be sold are also included in continuing
operations until such time that they qualify for treatment as "discontinued
operations" under generally accepted accounting principles (GAAP).

At year-end 2002, we also had a Petroleum Services business segment. Many
of the assets within the Petroleum Services business segment have been sold or
are being offered for sale and have been reclassified to "Discontinued
Operations" in the accompanying financial statements and notes to financials in
Part II. We intend to sell substantially all assets held in the Petroleum
Services segment with the exception of our interest in Longhorn Partners
Pipeline. The assets in the Petroleum Services segment are considered non-core
and no longer fit into our overall strategy to focus our competencies in the
natural gas market. Assets within the Petroleum Services segment currently
include:

- a petroleum products refinery and 29 convenience stores in Alaska;

- a 3.0845 percent interest in the Trans-Alaska Pipeline System (TAPS)
pipeline and the Valdez crude terminal in Alaska; and

- a 32.1 percent interest in the Longhorn Partners pipeline in south and
west Texas.

Other assets sold in 2002 and early 2003 or subject to an approved sale
have also been reclassified, in accordance with GAAP, from their traditional
business segment to "Discontinued Operations" in the accompanying financial
statements and notes to financial statements included in Part II.

Our principal executive offices are located at One Williams Center, Tulsa,
Oklahoma 74172. Our telephone number is 918-573-2000.

3

RECENT DEVELOPMENTS

ASSET SALES AND COST REDUCTIONS

Since December 2001, we have continued to work on strengthening our balance
sheet through a number of efforts including asset sales and cost reductions. We
have completed the sale or announced our intention to sell the following:

GAS PIPELINE

- March 27, 2002 -- We sold our Kern River interstate natural gas pipeline
business to a unit of Mid-American Energy Holdings Company for $450
million in cash and the assumption of $510 million in debt. In
conjunction with the sale, MEHC Investment, Inc., a wholly-owned
subsidiary of Mid-American Energy Holdings Company, and a member of the
Berkshire Hathaway family of companies, agreed to acquire 1,466,667
shares of our 9 7/8 percent cumulative convertible preferred stock at
$187.50 per share for a total of $275 million. Each share of convertible
preferred stock is convertible into ten shares of our common stock.

- August 16, 2002 -- We completed the sale of our general partner interest
in Northern Border Partners, L.P. for $12 million to a unit of
Calgary-based TransCanada.

- September 5, 2002 -- We sold our Cove Point liquefied natural gas
facility and 87 mile pipeline for $217 million in cash before certain
adjustments to a subsidiary of Dominion Resources.

- October 29, 2002 -- We sold our ownership interest in the Canadian and
United States segments of the Alliance pipeline to Enbridge Inc. and Fort
Chicago Energy Partners L.P. for approximately $173 million cash.

- November 15, 2002 -- We sold our Central interstate natural gas pipeline
to Southern Star Central Corp for $380 million in cash and the assumption
of $175 million in debt.

- February 20, 2003 -- We announced our intention to sell Texas Gas
Transmission Corporation.

EXPLORATION & PRODUCTION

- March 29, 2002 -- We completed a $73 million sale of selected exploration
and production properties in the Wind River basin.

- July 31, 2002 -- We sold our Jonah Field natural gas production
properties in Wyoming for $350 million to EnCana Oil & Gas (USA) Inc. In
addition, we completed the sale of the vast majority of our natural gas
production properties in the Anadarko Basin to Chesapeake Exploration
Limited Partnership for approximately $37.5 million. These sales of
exploration and production properties generated $326 million in net cash
proceeds.

- February 20, 2003 -- We announced our intention to sell selected assets
within the Exploration & Production segment.

MIDSTREAM GAS & LIQUIDS

- July 22, 2002 -- We announced our intention to sell our natural gas
processing and liquids extraction operations in western Canada.

- July 29, 2002 -- We sold our Kansas Hugoton natural gas gathering system
to FrontStreet Hugoton LLC, an affiliate of FrontStreet Partners, LLC and
GE Structured Finance Group for $77 million in cash.

- August 1, 2002 -- We announced a series of transactions including the
sale for approximately $1.2 billion of 98 percent of Mapletree LLC and 98
percent of E-Oaktree, LLC to Enterprise Products Partners, L.P. Mapletree
owns the Mid-America Pipeline, a 7,226-mile natural gas liquids pipeline

4

system. E-Oaktree owns 80 percent of the Seminole Pipeline, a 1,281-mile
natural gas liquids pipeline system. The sale generated $1.15 billion in
net cash proceeds.

- August 20, 2002 -- We announced our intention to sell our ownership
interest in an olefins plant in Geismar, Louisiana and an associated
ethylene pipeline system in Louisiana.

- February 20, 2003 -- We announced our intention to sell selected assets
within the Midstream Gas & Liquids segment.

ENERGY MARKETING & TRADING

- February 4, 2003 -- We announced the sale of our 170-megawatt power
facility in Worthington, Indiana, to Hoosier Energy and terminated our
power load serving full-requirements contract with Hoosier Energy for
cash totaling $67 million.

PETROLEUM SERVICES

- April 11, 2002 -- We transferred the Williams Pipe Line System to
Williams Energy Partners in exchange for $674 million cash and 7,830,924
Class B units of limited partnership interests in Williams Energy
Partners.

- June 18, 2002 -- We announced plans to sell our Memphis and Alaska
refineries and related petroleum assets. On March 4, 2003, we sold our
Memphis, Tennessee refinery and other related operations to Premcor Inc.
for approximately $455 million in cash.

- February 27, 2003 -- We sold our retail travel center operations for
approximately $190 million in cash before debt repayments to Pilot Travel
Centers LLC.

- February 20, 2003 -- We announced a definitive agreement to sell our
equity interest in Williams Bio-Energy L.L.C. for approximately $75
million to a new company formed by Morgan Stanley Capital Partners.
Williams Bio-Energy owns and operates an ethanol production plant in
Pekin, Illinois, holds 78.4 percent interest in another ethanol plant in
Aurora, Nebraska, and has various agreements to market ethanol from
third-party plants.

WILLIAMS ENERGY PARTNERS

- February 20, 2003 -- We announced our intention to sell our general
partner and limited partner interest in Williams Energy Partners.

OTHER

- March 22, 2002 -- We announced our intention to sell our interest in a
soda ash and sodium bicarbonate mining operation.

- September 19, 2002 -- We sold our 26.85 percent equity interest in AB
Mazeikiu Nafta, the Lithuania oil refining and transportation complex, to
YUKOS Oil Company for $85 million.

In an effort to further reduce costs, we have reduced the total number of
employees from approximately 12,400 at the end of 2001 to approximately 9,800 at
the end of 2002 and approximately 7,300 as of March 14, 2003. The reduction in
work force was carried out in part through an enhanced-benefit early retirement
program that concluded during the second quarter of 2002 and reductions
associated with asset sales.

Going forward, we intend to focus on our natural gas businesses including
natural gas transportation through our interstate natural gas pipelines, natural
gas exploration and production, and natural gas gathering and processing in key
growth markets.

5

IMPROVING OUR FINANCIAL POSITION

In addition to asset sales, we have taken other steps to improve our
financial position. On January 14, 2002, we completed the sale of $1.1 billion
of publicly traded units, known as FELINE PACS initially consisting of Income
PACS, which include a senior debt security and an equity purchase contract.
These units trade on the New York Stock Exchange under the ticker symbol WMB
PrI. The net proceeds of the offering were used to fund our capital program,
repay commercial paper and other short-term debt and for general corporate
purposes. On March 19, 2002, we closed a two-part debt transaction totaling $1.5
billion that included $850 million of 30-year notes with an interest rate of
8.75 percent and $650 million of 10-year notes with an interest rate of 8.125
percent. Proceeds were used to repay outstanding short-term debt, provide
working capital and for general corporate purposes.

On August 1, 2002, we announced a series of transactions that resolved
then-current liquidity issues and strengthened our finances. We entered into
agreements for $1.1 billion of credit through an amended $700 million secured
revolving credit facility and a new $400 million secured letter of credit
facility. We also entered into a $900 million senior secured credit agreement
with a group of investors led by Lehman Brothers Inc. and a Berkshire Hathaway
affiliate. The execution of these new credit facilities in conjunction with the
asset sales announced on August 1, 2002, addressed our mid-year liquidity
crisis. See Note 11 to our Notes to Consolidated Financial Statements for more
information on the credit facilities.

On March 4, 2003, Northwest Pipeline Corporation completed a $175 million
debt offering of senior notes due 2010. Northwest Pipeline Corporation intends
to use the proceeds for general corporate purposes, including the funding of
capital expenditures.

ADDRESSING ENERGY MARKETING AND TRADING ISSUES

We have also spent considerable effort addressing concerns of the Federal
Energy Regulatory Commission (FERC), the Commodity Futures Trading Commission
(CFTC), the Securities and Exchange Commission (SEC), the Department of Justice
(DOJ), and state regulatory bodies and attorneys general regarding energy
trading practices. On July 26, 2002, we announced an agreement in principle with
the state of California and other parties, including the states of Washington
and Oregon, on a settlement regarding certain outstanding litigation and claims
against us, including the state's claims for refunds at issue before the FERC.
On November 11, 2002, we announced that we had agreed to restructure our
long-term energy contracts with the state of California as part of the
settlement. All necessary approvals were obtained, and the settlement was closed
on December 31, 2002, although court approvals are still pending with respect to
certain private plaintiffs. The settlement resolved most of the outstanding
litigation and civil claims filed against us related to our participation in the
natural gas and power markets during 2000 and 2001.

Due to continuing market declines and the overall energy marketing and
trading environment in the post-Enron world, we announced on June 10, 2002, that
we were reducing our financial commitment to that part of our business as a
realistic response to industry upheavals. Consistent with the effort in 2002,
Energy Marketing & Trading reduced its number of employees from approximately
1,000 at December 31, 2001 to approximately 410 at December 31, 2002. As of
February 25, 2003, the number of Energy Marketing & Trading employees was
approximately 330.

RESOLUTION OF WILLIAMS COMMUNICATIONS GROUP ISSUES

In 2002, we settled substantially all claims and disputes between us and
our former telecommunications subsidiary, WCG as part of WCG's chapter 11
reorganization. Prior to the commencement of WCG's chapter 11 on April 22, 2002,
we held various claims against WCG and its subsidiaries in an aggregate amount
of approximately $2.3 billion as a consequence of certain guarantees, services
provided, and other financial accommodations, including the following:

- Prior to the 2001 spinoff of WCG, we had provided various administrative
services to WCG for which we were owed approximately $106 million.

6

- Prior to the 2001 spinoff of WCG, we also provided indirect credit
support for $1.4 billion of WCG's structured notes through a commitment
to make available proceeds of an equity issuance in the event any one of
the following were to occur: (1) a WCG default; (2) downgrading of our
senior unsecured debt by any of our credit rating agencies to below
investment grade if our common stock closing price remained below $30.22
for ten consecutive trading days while such downgrade is in effect; or
(3) proceeds from WCG's refinancing or remarketing of the structured
notes prior to March 2004 produced proceeds of less than $1.4 billion. On
March 5, 2002, we received the requisite approvals on our consent
solicitation to amend the terms of the WCG structured notes. The
amendment, among other things, eliminated acceleration of the notes due
to a WCG bankruptcy or our credit rating downgrade. The amendment also
affirmed our obligations for all payments related to the WCG structured
notes, which are due March 2004, and allows us to fund such payments from
any available sources. With the exception of the March and September 2002
interest payments, totaling $115 million, WCG remained indirectly
obligated to reimburse us for any payments we are required to make in
connection with the WCG structured notes.

- In September 2001, we provided additional financing to WCG through a
sale/leaseback transaction pursuant to which WCG sold to us the Williams
Technology Center (Technology Center), related real estate and certain
ancillary assets including corporate aircraft for $276 million in cash
and WCG leased the foregoing property back from us for periods ranging
from three to ten years. The Technology Center is a 15-story office
building located in Tulsa, Oklahoma that WCG utilizes as its
headquarters.

- On March 8, 2002, we received a lease obligation notice letter from WCG
relating to the asset defeasance program (ADP) that was entered into
while WCG was still one of our subsidiaries. Under the ADP, we were
obligated to pay $754 million related to WCG's purchase of certain
telecommunications facilities that WCG had been leasing. We paid the $754
million on March 29, 2002, and in return received an unsecured claim
against WCG for the amount paid.

On April 22, 2002, WCG filed for chapter 11 bankruptcy protection. Through
a negotiated settlement, we sold our claims against WCG including the $754
million claim associated with the ADP, the $1.4 billion claim associated with
the WCG structured notes and a $106 million administrative services claim to
Leucadia National Corporation (Leucadia) for $180 million in cash and received
releases from WCG and its affiliates and insiders. In addition, the order
confirming WCG's chapter 11 plan permanently enjoins all of WCG's creditors from
asserting direct or derivative claims against us. As part of the settlement, we
also sold the Technology Center to WCG in exchange for two promissory notes with
face amounts totaling $174.4 million secured by a mortgage on the Technology
Center. We no longer own any interest in WCG or its post-bankruptcy successor,
WilTel Communications Group, Inc. (WilTel) and all prior WCG obligations to us
have been extinguished as a result of the chapter 11 bankruptcy. We remain
committed on certain pre-spinoff parental guarantees with a carrying value at
December 31, 2002 of $48 million. Further, the September 2001 sale leaseback
transaction involving the Technology Center was terminated as part of the
bankruptcy process. The sale leaseback transaction involving WilTel's two
corporate aircraft continues in effect until WilTel refinances that transaction.
At that time, the proceeds of the refinancing are to be paid to us in partial
satisfaction of one of the notes mentioned above. The settlement was closed into
escrow on October 15, 2002, and finalized on December 2, 2002, and we received
$180 million. See Note 2 of our Notes to Consolidated Financial Statements for
more information on our settlement with WCG.

FINANCIAL INFORMATION ABOUT SEGMENTS

See Note 19 of our Notes to Consolidated Financial Statements for
information with respect to each segment's revenues, profits or losses and total
assets.

7

BUSINESS SEGMENTS

GENERAL

Substantially all of our operations are conducted through our subsidiaries.
To achieve organizational and operating efficiencies, our interstate natural gas
pipelines and pipeline joint venture investments are organized under our
wholly-owned subsidiary, Williams Gas Pipeline Company, LLC; our Exploration &
Production business is operated through several wholly-owned subsidiaries
including Williams Production Company LLC and Williams Production RMT Company;
our Midstream Gas & Liquids business is operated primarily through wholly-owned
subsidiaries including Williams Field Services Group, Inc. and Williams Natural
Gas Liquids, Inc.; our energy marketing and trading activities are primarily
operated through our wholly-owned subsidiary, Williams Energy Marketing &
Trading Company; our investment in a master limited partnership that focuses on
the storage, transportation and distribution of refined petroleum products and
ammonia is reported under Williams Energy Partners; and our Petroleum Services
business is operated through various wholly-owned subsidiaries. Item 1 of this
report is organized to reflect this structure.

For organizational and reporting purposes, we classify our businesses into
the following segments:

GAS PIPELINE

- Transportation and storage of natural gas and related activities through
the operation and ownership of three wholly-owned interstate natural gas
pipelines, one of which we have announced our intention to sell, and
several pipeline joint ventures.

EXPLORATION & PRODUCTION

- Exploration, production and management of natural gas and oil through
ownership of 2.8 trillion cubic feet equivalent of proved natural gas
reserves primarily located in the Rocky Mountain and Mid-Continent
regions of the United States, a portion of which we have announced our
intention to sell.

MIDSTREAM GAS & LIQUIDS

- Natural gas gathering, treating and processing activities through
ownership and operation of approximately 9,000 miles of gathering lines,
eleven natural gas processing plants (two of which are partially owned),
and nine natural gas treating plants within the United States.

- Natural gas liquids fractionation, storage, and transportation activities
through ownership interests in fractionation facilities, storage caverns
and facilities within central Kansas and southern Louisiana, and liquids
pipelines in the Gulf Coast.

- Ethylene production and olefin extraction activities in Louisiana through
an ownership interest in an ethylene production, storage and
transportation complex (partially owned) and refinery off gas processing,
and olefin extraction and fractionation facilities.

- Natural gas processing, liquid extraction, fractionation, storage and
olefin extraction activities within Alberta and British Columbia, Canada,
through a natural gas field processing plant, five natural gas liquid
extraction plants (two of which are partially-owned), a natural gas
liquids gathering system and liquid storage facilities, a liquids
fractionation facility and an olefins fractionation facility.

- Natural gas liquid and petrochemical product marketing and risk
management services within the United States and Canada.

- Venezuelan gas compression, liquids extraction, fractionation and
terminaling activities through various investments and contractual
arrangements.

- We have announced our intention to sell certain domestic and Canadian
assets within the Midstream Gas & Liquids segment.

8

ENERGY MARKETING & TRADING

- 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, crude oil and emissions credits primarily
on a wholesale level, which we have announced our intention to sell in
whole or in part.

INVESTMENT IN WILLIAMS ENERGY PARTNERS

- Transportation of petroleum products and related terminal services and
ammonia transportation and terminal services. On February 20, 2003, we
announced our intention to sell our interests in Williams Energy
Partners.

PETROLEUM SERVICES

- Petroleum products refinery and 29 convenience stores in Alaska.

- A 3.0845 percent interest in the TAPS pipeline and the Valdez crude
terminal in Alaska.

- A 32.1 percent interest in the Longhorn Partners pipeline in south and
west Texas.

We have announced our intention to sell substantially all assets within the
Petroleum Services segment with the exception of our interest in Longhorn
Partners Pipeline.

We perform certain management, legal, financial, tax, consultative,
administrative and other services for our subsidiaries and at March 14, 2003,
employed approximately 1,925 employees at the corporate level to provide these
services. Our principal sources of cash are from external financings, dividends
and advances from our subsidiaries, investments, payments by subsidiaries for
services rendered, interest payments from subsidiaries on cash advances and net
proceeds from asset sales. The amount of dividends available to us from
subsidiaries largely depends upon each subsidiary's earnings and operating
capital requirements. The terms of many of our subsidiaries' borrowing
arrangements limit the transfer of funds to us. The Federal Energy Regulatory
Commission (FERC) has also proposed restrictions on various cash management
programs employed by companies in the energy industry, including us. See Note 16
to our Notes to Consolidated Financial Statements for further information on the
proposed cash management restrictions.

We believe that we have adequate sources and availability of raw materials
and commodities for existing and anticipated business needs. With the
deterioration of our credit ratings, we now must pre-pay for crude supply for
our Alaska refining operations and for gas supplies for our domestic and
Canadian Midstream Gas & Liquids operations. Our pipeline systems are all
regulated in various ways resulting in the financial return on the investments
made in the systems being limited to standards permitted by the regulatory
agencies. Each of the pipeline systems has ongoing capital requirements for
efficiency and mandatory improvements, with expansion opportunities also
necessitating periodic capital outlays.

GAS PIPELINE

GENERAL

We own and operate, through Williams Gas Pipeline Company, LLC and its
subsidiaries (Gas Pipeline), a combined total of approximately 20,200 miles of
pipelines with a total annual throughput of approximately 3,200 trillion British
Thermal Units of natural gas and peak-day delivery capacity of approximately 13
billion cubic feet of gas. Gas Pipeline consists of Transcontinental Gas Pipe
Line Corporation (Transco), Northwest Pipeline Corporation (Northwest Pipeline),
and Texas Gas Transmission Corporation (Texas Gas). Gas Pipeline also holds
interests in joint venture interstate and intrastate natural gas pipeline
systems including a 50 percent interest in the Gulfstream Natural Gas System,
L.L.C. At December 31, 2002, Gas Pipeline employed approximately 2,300
employees. On February 20, 2003, we announced our intention to sell Texas Gas.

In February 2001, subsidiaries of Duke Energy and the Company completed
their joint acquisition of The Coastal Corporation's 100 percent ownership
interest in Gulfstream Natural Gas System, L.L.C., and

9

announced that they were proceeding with the development of the Gulfstream gas
pipeline project. In June, 2001 construction commenced on the project, which
consists of a new natural gas pipeline system extending from the Mobile Bay area
in Alabama to markets in Florida. On December 28, 2001, Gulfstream filed an
application with the FERC to allow Gulfstream to phase the construction of its
approved facilities. On May 28, 2002, the first phase of the project was placed
into service at a cost of approximately $1.5 billion. The construction of the
second phase of the project will be timed to match the anticipated in-service
dates of the markets Gulfstream will serve. The total estimated capital cost of
the project is approximately $1.7 billion, of which our portion is estimated to
be approximately $850 million. At December 31, 2002, our investment in
Gulfstream was $734 million.

On April 24, 2001 the respective U.S. and Canadian general partners of the
Georgia Strait Crossing Pipeline Project (GSX), a joint venture of the Company
and BC Hydro, filed separate applications with the FERC and Canada's National
Energy Board (NEB) to construct and operate a new pipeline that will provide
95,700 dekatherms ("Dth") per day of firm transportation capacity from Sumas,
Washington to Vancouver Island, British Columbia. The installation of GSX will
include approximately 85 miles of pipeline, a 10,302 horsepower compressor
station and two meter stations. On September 20, 2002, the FERC issued an order
approving the construction and operation of the U.S. portion of the project. GSX
anticipates the NEB will issue a certificate approving the project by October
2003. Construction is expected to begin in the summer of 2004. The estimated
cost of GSX is approximately $210 million, with Gas Pipeline's share being 50
percent of such amount. The targeted in-service date is October 2005.

REGULATORY MATTERS

Gas Pipeline's interstate 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, its rates and charges for the
transportation of natural gas in interstate commerce, the extension, enlargement
or abandonment of jurisdictional facilities and accounting, among other things,
are subject to regulation. Each gas pipeline company holds certificates of
public convenience and necessity issued by the FERC authorizing ownership and
operation of all pipelines, facilities and properties 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 transmission facilities. Cardinal Pipeline Company, LLC,
a North Carolina natural gas pipeline company that is operated and 45 percent
owned by Gas Pipeline, is subject to the jurisdiction of the North Carolina
Utilities Commission.

Each of our interstate natural gas pipeline companies establishes its rates
primarily through the 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, certain revenues
previously collected may be subject to refund. See Note 16 of our Notes to
Consolidated Financial Statements for the amounts accrued for potential refund
at December 31, 2002.

On March 13, 2003, we entered into a settlement with FERC regarding its
investigation of the relationship between Transco and Energy Marketing & Trading
whereby Transco will pay a civil penalty in the amount of $20 million payable
over a five year period. In addition, we agreed to certain operational
restrictions and agreed to implement a compliance program to ensure future
compliance with the settlement agreement and FERC's marketing affiliate rules.
See Note 16 of our Notes to Consolidated Financial Statements for further
information on the settlement.

COMPETITION

The FERC has taken various actions to strengthen market forces in the
natural gas pipeline industry which has led to increased competition throughout
the industry. In a number of key markets, interstate

10

pipelines are now facing competitive pressures from other major pipeline
systems, enabling local distribution companies and end users to choose a
supplier or switch suppliers based on the short-term price of gas and the cost
of transportation. We expect competition for natural gas transportation to
continue to intensify in future years due to increased customer access to other
pipelines, 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. Gas Pipeline does not anticipate any significant financial impact from
"capacity turnback." We anticipate that we will be able to remarket most future
capacity subject to capacity turnback, although competition may cause some of
the remarketed capacity to be sold at lower rates or for shorter terms.

Several state jurisdictions have been involved in implementing changes
similar to the changes that have occurred at the federal level. The District of
Columbia and states, including New York, New Jersey, Pennsylvania, Maryland,
Georgia, Delaware, Virginia, California, Wyoming, Kentucky, Ohio, and Indiana,
are currently at various points in the process 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 our interstate natural gas pipeline companies generally owns its
facilities, with certain portions, including some 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
held 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. We believe that, with respect to any
capital expenditures and operation and maintenance expenses required to meet
applicable environmental standards and regulations, the FERC would grant the
requisite rate relief so that the pipeline companies could recover most of the
cost of these expenditures in their rates. For this reason, we believe that
compliance with applicable environmental requirements by the interstate pipeline
companies is not likely to have a material adverse upon our earnings or
competitive position.

For a discussion of specific environmental issues involving the interstate
pipelines, including estimated cleanup costs associated with certain pipeline
activities, see "Environmental" under Management's Discussion and Analysis of
Financial Condition and Results of Operations and "Environmental Matters" in
Note 16 of Notes to Consolidated Financial Statements.

11

PRINCIPAL COMPANIES IN THE GAS PIPELINE SEGMENT

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

Transcontinental Gas Pipe Line Corporation (Transco)

Transco is an interstate natural gas transportation company that owns and
operates a 10,400-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. (Williams Field
Services), an affiliated company and part of the Midstream Gas & Liquids
business.

PIPELINE SYSTEM AND CUSTOMERS

At December 31, 2002, Transco's system had a mainline delivery capacity of
approximately 4.2 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 3.3 billion cubic feet of natural
gas per day for a system-wide delivery capacity total of approximately 7.5
billion cubic feet of natural gas per day. Excluding the production area
facilities operated by Williams Field Services, Transco's system is composed of
approximately 7,600 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. No customer accounted for
more than ten percent of Transco's total revenues in 2002. Transco's firm
transportation agreements are generally long-term agreements with various
expiration dates and account for the major portion of Transco's business.
Additionally, Transco offers storage services and interruptible transportation
services under short-term agreements.

Transco has natural gas storage capacity in five underground storage fields
located on or near its pipeline system or market areas and operates three of
these storage fields. Transco also has storage capacity in a 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, an 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

In 2002, Transco completed construction of, and placed into service, three
major projects, the Sundance Expansion Project, Phase 2 of the MarketLink
Expansion Project, and the Leidy East Project.

The Sundance Expansion Project was placed in service on May 1, 2002, adding
approximately 228 million cubic feet per day (MMcf/d) of firm transportation
capacity from Transco's Station 65 in Louisiana to delivery points in Georgia,
South Carolina and North Carolina. Approximately 38 miles of new pipeline loop
along the existing mainline system were installed along with approximately
41,225 horsepower of new compression and modifications to existing compressor
stations in Georgia, South Carolina and North Carolina. The capital cost of the
project was approximately $117 million.

Phase 1 of the Market Link Expansion Project, which was placed in service
on December 19, 2001, added approximately 160 MMcf/d of firm transportation
capacity. Phase 2 of the MarketLink Expansion Project was

12

placed in service on November 1, 2002, adding approximately 126 MMcf/d of firm
transportation capacity. Both phases of the MarketLink Project provide firm
natural gas transportation service from Leidy, Pennsylvania to markets in the
northeastern United States. The total capital cost of Phases 1 and 2 is
estimated to be $243 million.

The Leidy East Project was placed in service on November 1, 2002, adding
approximately 126 MMcf/d of firm natural gas transportation service from Leidy,
Pennsylvania to the northeastern United States. The project facilities included
approximately 31 miles of pipeline looping and 3,400 horsepower of uprated
compression. The capital cost of the project is estimated to be $98 million.

On February 14, 2002, the FERC issued an order granting a certificate of
public convenience and necessity to Transco to construct and operate the
Momentum Expansion Project, an expansion of Transco's pipeline system from
Station 65 in Louisiana to Station 165 in Virginia. On February 4, 2003, Transco
filed an application with the FERC to amend the certificate to reduce the
overall size of the expansion from approximately 347 MMcf/d to approximately 312
MMcf/d and to place the Momentum facilities into service in two phases, with the
first phase, consisting of approximately 260 MMcf/d, to be placed into service
on May 1, 2003 and the second phase, consisting of approximately 52 MMcf/d, to
be placed into service on May 1, 2004. The reduction in the size of the
expansion reflects the withdrawal of two shippers under the project and the
partial replacement of those shippers with the two shippers who had subscribed
to service under Transco's previously proposed Cornerstone Expansion Project.
The revised project facilities include approximately 50 miles of pipeline
looping and 45,000 horsepower of compression. The revised capital cost of the
project is estimated to be approximately $189 million.

On May 6, 2002, Transco filed an application for FERC approval of an
expansion of Transco's 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.
Binding precedent agreements have been executed with two shippers for a total of
49 MMcf/d of incremental firm transportation capacity to the shippers'
respective delivery points on the Trenton-Woodbury Line. On December 24, 2002,
the FERC issued a final order authorizing Transco to construct and operate the
project. The target in-service date for the project is November 1, 2003. The
project will require approximately seven miles of pipeline looping at a capital
cost of approximately $20 million.

Pursuant to Transco's open season for the Cornerstone Expansion Project,
Transco executed precedent agreements with two shippers for a total firm
transportation quantity of approximately 52 MMcf/d. However, Transco and the
shippers have agreed that Transco will provide such firm transportation service
under the Momentum Expansion Project instead of under Cornerstone as noted in
the above project description for the Momentum Expansion Project.

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
proposed in-service date of May 1, 2005, has been postponed pending further
development of the project.

In March 1997, as amended in December 1997, Independence Pipeline Company,
a general partnership owned equally by wholly-owned subsidiaries of Transco, ANR
Pipeline Company and National Fuel Gas Company, filed an application with FERC
for approval to construct and operate a new pipeline consisting of approximately
400 miles of 36-inch pipe from ANR Pipeline Company's existing compressor
station at Defiance, Ohio to Transco's facilities at Leidy, Pennsylvania. 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 filed for rehearing of the interim order. On April 26,
2000, the FERC issued an order denying rehearing and requiring that Independence
submit by June 26, 2000, agreements with nonaffiliated shippers for at least 35
percent of the capacity of the project. Independence met this requirement, and
on July 12, 2000, the FERC issued an order granting the necessary certificate
authorizations for the Independence Pipeline project. Independence accepted the
certificate authorization on August 11, 2000. On September 28, 2000, the FERC
issued an order denying all requests for rehearing and requests for
reconsideration of the Independence

13

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 from November 2002 to November 2004. On June 24, 2002, Independence
filed a request with the FERC to vacate its certificate because it has been
unable to obtain sufficient contracts to proceed with the project to meet the
November 2004 in service date. On July 19, 2002, FERC issued an order vacating
Independence's certificate. As a result, Transco recorded a $12.3 million
pre-tax charge to income in 2002 associated with the impairment of Transco's
investment in Independence.

OPERATING STATISTICS

The following table summarizes transportation data for the Transco system
for the periods indicated:

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 to a market-area zone. Market-area transportation involves
gas that Transco both receives and delivers within the market-area zones.
Production-area transportation involves gas that Transco both receives and
delivers within the production-area zones.

Northwest Pipeline Corporation (Northwest Pipeline)

Northwest Pipeline is an interstate natural gas transportation company that
owns and operates a natural gas pipeline system extending from the San Juan
Basin in northwestern New Mexico and southwestern Colorado through Colorado,
Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border
near Sumas, Washington. Northwest Pipeline provides services for markets in
California, New Mexico, Colorado, Utah, Nevada, Wyoming, Idaho, Oregon and
Washington directly or indirectly through interconnections with other pipelines.

PIPELINE SYSTEM AND CUSTOMERS

At December 31, 2002, 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 4,000 miles of mainline and lateral
transmission pipelines and 43 compressor stations having sea level-rated
capacity of approximately 348,000 horsepower.

In 2002, Northwest Pipeline transported natural gas for a total of 166
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 2002
accounted for approximately 14.2 percent and 12.7 percent, respectively, of its
total operating revenues. No other customer accounted for more than 10 percent
of Northwest Pipeline's total operating revenues in 2002. 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.

14

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 firm delivery capacity of approximately 600 million cubic feet of gas
per day.

EXPANSION PROJECTS

On August 29, 2001, Northwest Pipeline filed an application with the FERC
to construct and operate an expansion of its pipeline system designed to provide
an additional 175,000 Dth per day of capacity to its transmission system in
Wyoming and Idaho in order to reduce reliance on displacement capacity. The
Rockies Expansion Project includes the installation of 91 miles of pipeline loop
and the upgrading or modification to six compressor stations for a total
increase of 26,057 horsepower. Northwest Pipeline reached a settlement agreement
with the majority of its firm shippers to support roll-in of the expansion costs
into its existing rates. The FERC issued a certificate in September 2002
approving the project. Northwest Pipeline filed an application with the FERC in
February 2003 to amend the certificate to reflect minor facility scope changes.
Construction is scheduled to start by May 2003, with a targeted in-service date
of November 1, 2003. The current estimated cost of the expansion project is
approximately $140 million, of which approximately $16 million may be offset by
settlement funds anticipated to be received from a former customer in connection
with a contract restructuring.

On October 31, 2001, Northwest Pipeline filed an application with the FERC
to construct and operate an expansion of its pipeline system designed to provide
276,625 Dth per day of firm transportation service from Sumas, Washington to
Chehalis, Washington to serve new power generation demand in western Washington.
The Evergreen Expansion Project includes installing 28 miles of pipeline loop,
upgrading, replacing or modifying five compressor stations and adding a net
total of 64,160 horsepower of compression. The FERC issued a certificate on June
27, 2002, approving the expansion and the incremental rates to be charged to
Northwest Pipeline's expansion customers. Northwest Pipeline started
construction in October 2002 with completion targeted for October 1, 2003.
Northwest Pipeline filed an application with the FERC in January 2003 to amend
the certificate to reflect minor facility scope and schedule changes. The
estimated cost of the expansion project is approximately $198 million. The
Evergreen Expansion customers have agreed to pay for the cost of service of this
expansion on an incremental basis. This expansion is based on 15 and 25-year
contracts and is expected to provide approximately $42 million of operating
revenues in its first 12 months of operation.

Northwest Pipeline's October 3, 2001, application with respect to the
Evergreen Expansion Project, which was approved by the FERC on June 27, 2002,
also requested approvals to construct and operate an expansion of its pipeline
system designed to replace 56,000 Dth per day of northflow design displacement
capacity from Stanfield, Oregon to Washougal, Washington. The Columbia Gorge
Project includes upgrading, replacing or modifying five existing compressor
stations and adding a net total of 24,030 horsepower of compression. Northwest
Pipeline reached a settlement with the majority of its firm shippers to support
roll-in of 84 percent of the expansion costs into the existing rates with the
remainder to be allocated to the incremental Evergreen Expansion customers.
Northwest Pipeline's January 2003 application to amend the certificate also
reflected minor facility scope changes for the Columbia Gorge Project. Northwest
Pipeline plans to start construction of this expansion project by May 2003, with
a targeted in-service date of November 1, 2003. The estimated cost of the
expansion project is approximately $43 million.

On November 1, 2002, Northwest Pipeline placed in service the Grays Harbor
Lateral project. This lateral pipeline provides 161,500 Dth per day of firm
transportation capacity to serve a new power generation plant in the state of
Washington. The Grays Harbor Lateral project was requested by one of Northwest
Pipeline's customers and included installation of 49 miles of 20-inch pipeline,
the addition of 4,700 horsepower at an existing compressor station, and a new
meter station. The cost of the lateral project is estimated to be approximately
$92 million. The customer has suspended construction of the contemplated new
power generation plant, but remains obligated to pay for the cost of service of
the lateral pipeline on an incremental rate basis over the 30-year term of the
contract.

15

OPERATING STATISTICS

The following table summarizes transportation data for the Northwest
Pipeline System for the periods indicated:

Texas Gas Transmission Corporation

On February 20, 2003, we announced our intention to sell Texas Gas.

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 east Texas and extending 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, 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, 2002, Texas Gas' system, with a peak-day delivery capacity
of approximately 2.8 billion cubic feet of natural gas per day, was composed of
approximately 5,800 miles of mainline, storage and branch transmission pipelines
and 31 compressor stations having a sea level-rated capacity totaling
approximately 556,000 horsepower.

In 2002, Texas Gas transported natural gas to customers in Louisiana,
Arkansas, Mississippi, Tennessee, Kentucky, Indiana, Illinois and Ohio, and
indirectly to customers in the northeast. At December 31, 2002, Texas Gas had
transportation contracts with approximately 550 shippers. Transportation
shippers include distribution companies, municipalities, intrastate pipelines,
direct industrial users, electrical generators, gas marketers and producers. Two
customers accounted for approximately 18 percent and 12 percent, respectively,
of Texas Gas' 2002 operating revenues. Texas Gas transported gas for 100
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. No other
customer accounted for more than ten percent of total operating revenues in
2002. 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' 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 in Indiana and Kentucky. The storage capacity of Texas
Gas' certificated storage fields is approximately 178 billion cubic feet of
natural gas, of which approximately 55 billion cubic feet is working gas. Texas
Gas' storage gas is used in part to meet operational balancing needs on its
system, in part to meet the requirements of Texas Gas' firm and interruptible
storage customers, and in part 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 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.

16

OPERATING STATISTICS

The following table summarizes transportation data for the Texas Gas system
for the periods indicated

EXPLORATION & PRODUCTION

GENERAL

Our Exploration & Production segment, which is comprised of several
wholly-owned subsidiaries including Williams Production Company LLC and Williams
Production RMT Company, produces, develops, explores for and manages natural gas
reserves primarily located in the Rocky Mountain and Mid-Continent regions of
the United States. Exploration & Production specializes in natural gas
production from tight-sands formations and coal bed methane reserves in the
Piceance, San Juan, Powder River, Arkoma and Raton basins. Approximately 98.6
percent of Exploration & Production's domestic reserves are natural gas.

Exploration & Production's primary strategy is to utilize existing
expertise in the development of tight-sands and coalbed methane reserves.
Exploration & Production's current multi-year drilling plan and probable
reserves, provides us with a strong opportunity. Exploration & Production's goal
is to drill existing proved undeveloped reserves, which comprise nearly 52
percent of proved reserves and to drill in areas of probable reserves. In
addition, Exploration & Production provides a significant amount of equity
production that is gathered and/or processed by our Midstream Gas & Liquids
facilities.

Substantially all of the assets of Williams Production RMT Company
(formerly Barrett Resources Corporation) are pledged under the 360-day $900
million secured credit facility with Lehman Commercial Paper, Inc. and an
affiliate of Berkshire Hathaway. See Note 11 of our Consolidated Financial
Statements for further details on the secured credit facilities.

In February 2003, we announced our intention to sell additional selected
assets within the Exploration & Production segment.

OIL AND GAS PROPERTIES

Exploration & Production's properties are located primarily in the Rocky
Mountain and Mid-Continent regions of the United States. Rocky Mountain
properties are located in New Mexico, Wyoming, Colorado and Utah. Mid-Continent
properties are located in Oklahoma and Kansas.

Rocky Mountain Properties

PICEANCE BASIN

The Piceance Basin is located in northwestern Colorado, where Exploration &
Production primarily targets the tight sands contained within the Williams Fork
coalbed formation. The Piceance Basin is our largest area of concentrated
development comprising approximately 48 percent of our proved reserves. With
over 1.3 trillion cubic feet equivalent of proved reserves at year-end 2002,
this area has approximately 900 undrilled proved locations in inventory.
Probable reserves in this basin provide additional potential beyond our existing
proved reserves. Within this basin, Exploration & Production has the ability to
gather, process and deliver to four interstate and one intrastate pipelines.
Exploration & Production is currently drilling wells in this basin on 20 acre
well density. Exploration & Production successfully completed a 16 well pilot
project on ten acre spacing in the Piceance Basin during 2002. This ten acre
downspacing, currently pending Colorado Oil and Gas Conservation Commission
approval, may enable us to increase our reserves by drilling at greater
densities. In 2002, Exploration & Production drilled 129 gross wells and
produced a net of approximately

17

60 billion cubic feet equivalent (Bcfe) of natural gas from the Piceance Basin.
Exploration & Production's estimated proved reserves in the Piceance Basin at
year-end 2002 were 1,372 Bcfe.

SAN JUAN BASIN

The San Juan Basin is a large gas producing area, located in northwest New
Mexico and southwest Colorado. Exploration & Production produces natural gas
primarily from the Fruitland Coal, Mesaverde and Dakota formations. Recently
approved 80-acre spacing for Mesaverde development and 160-acre spacing for
parts of the Fruitland Coal have resulted in the addition of new reserves. In
2002, Exploration & Production successfully introduced horizontal drilling to
its Fruitland Coal development. In 2002, Exploration & Production participated
in 119 gross wells (33 operated) and produced a net of approximately 52 Bcfe
from the San Juan Basin. Exploration & Production's estimated proved reserves in
the San Juan Basin at year-end 2002 were 710 Bcfe.

POWDER RIVER BASIN

Located in northeast Wyoming, the Powder River Basin includes large areas
with multiple coal seam potential providing drilling opportunities, targeting
thick coals at shallow depths. Exploration & Production is one of the largest
natural gas producers in the Powder River Basin and operates the largest
leasehold position in the basin. In 2002, Exploration & Production drilled 939
gross wells (576 operated) from this basin and produced a net of approximately
48 Bcfe of natural gas. Exploration & Production's estimated proved reserves in
the Powder River Basin at year-end 2002 were 306 Bcfe.

RATON BASIN

Located in south central Colorado, the Raton Basin is known for quality
coal bed methane production. Coal bed methane production is predominantly from
two groups of coals in the Vermejo and Raton formations. In 2002, Exploration &
Production drilled 38 gross wells in the Raton Basin and produced a net of
approximately six Bcfe. Exploration & Production's estimated proved reserves in
the Raton Basin at year-end 2002 were 134 Bcfe.

UINTA BASIN

The Brundage Canyon field, located in northeastern Utah, is Exploration &
Production's principal property in the Uinta Basin. Production from this field
is predominately oil, produced from the Lower Green River Formation. In 2002,
Exploration & Production drilled 26 gross wells in the Uinta Basin and produced
a net of approximately 462 thousand barrels of oil equivalent. Exploration &
Production's estimated proved reserves at year-end 2002 were 9 million barrels
of oil equivalent.

Mid-Continent Properties

ARKOMA BASIN

Exploration & Production's Arkoma Basin properties are located in
southeastern Oklahoma. Exploration & Production's production from the Arkoma
Basin is primarily from the Hartshorne coal bed methane formation. Exploration &
Production is utilizing horizontal drilling technology to develop the coal
seams. In 2002, Exploration & Production drilled 51 gross wells (44 operated) in
the Arkoma Basin and produced a net of approximately three Bcfe. Exploration &
Production's estimated proved reserves in the Arkoma Basin at year-end 2002 were
83 Bcfe.

HUGOTON AREA

The Hugoton Embayment properties are located in southwest Kansas.
Exploration & Production produced a net of approximately 10 Bcfe of natural gas
from the Hugoton Area in 2002. Exploration & Production's estimated proved
reserves in the Hugoton area at year-end 2002 were 102 Bcfe.

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Other Properties

Exploration & Production has operations in other areas, including the Green
River Basin, located in southwest Wyoming, the Gulf Coast region and northeast
Colorado. These properties contain approximately 2.5 percent of Exploration &
Production's estimated proved reserves.

GAS RESERVES AND WELLS

At December 31, 2002, 2001 and 2000, Exploration & Production had proved
developed natural gas reserves of 1,368 Bcfe, 1,599 Bcfe and 603 Bcfe,
respectively, and proved undeveloped reserves of 1,466 Bcfe, 1,579 Bcfe and 599
Bcfe, respectively. At December 31, 2002, 48 percent of Exploration &
Production's total proved reserves are located in the Piceance Basin in
Colorado, 25 percent are located in the San Juan Basin of Colorado and New
Mexico and 11 percent are located in the Powder River Basin in Wyoming. The
remaining 16 percent of proved reserves are primarily in the Raton, Arkoma,
Hugoton, and Green River basins, the Gulf Coast regions and northeast Colorado.
No major discovery or other favorable or adverse event has caused a significant
change in estimated gas reserves since year-end 2002. Exploration & Production
has not filed on a recurring basis estimates of its total proved net oil and gas
reserves with any U.S. regulatory authority or agency other than the Department
of Energy (DOE) and the Securities and Exchange Commission (SEC). The estimates
furnished to the DOE have been consistent with those furnished to the SEC,
although Exploration & Production has not yet filed any information with respect
to its estimated total reserves at December 31, 2002, with the DOE. Certain
estimates filed with the DOE may not necessarily be directly comparable due to
special DOE reporting requirements, such as requirements to report in some
instances on a gross, net or total operator basis, and requirements to report in
terms of smaller units. The underlying estimated reserves for the DOE did not
differ by more than five percent from the underlying estimated reserves utilized
in preparing the estimated reserves reported to the SEC.

Approximately 95 percent of Exploration & Production's proved reserves
estimates are either audited or prepared by Netherland, Sewell & Associates,
Inc., Ryder Scott Company or Miller and Lents, LTD., depending on the basin.
Approximately three percent of the 95 percent of Exploration & Production's
proved reserves estimates that are audited or prepared externally are prepared
by Miller and Lents, LTD. under an agreement with the Williams Coal Seam Gas
Royalty Trust.

At December 31, 2002, the gross and net developed acres leased by
Exploration & Production totaled 1,129,044 and 605,450 respectively, and the
gross and net undeveloped acres leased were 1,463,629 and 663,459, respectively.
At December 31, 2002, Exploration & Production owned interests in 10,528 gross
producing wells (4,697 net) on its leasehold lands.

OPERATING STATISTICS

Exploration & Production focuses on low-risk development drilling. The
following tables summarize drilling activity by number and type of well for the
periods indicated:

The majority of Exploration & Production's natural gas production is
currently being sold to Energy Marketing & Trading at prevailing market prices.
Because Exploration & Production currently has a low-risk drilling program in
proven basins, the main component of risk that it manages is price risk.
Exploration & Production manages price risk as needed by hedging when market
conditions warrant. Exploration & Production has entered into derivative
contracts with Energy Marketing & Trading that hedge approximately 83 percent of
projected 2003 domestic natural gas production before consideration of any
potential property sales in 2003. Energy Marketing & Trading then enters into
offsetting derivative contracts with unrelated third parties. Approximately 81
percent of Exploration and Production's natural gas production in 2002 was
hedged.

Exploration & Production's 2002 net production increased by nearly 62
percent over the previous year. The total net production sold during 2002, 2001
and 2000 was 211.5 Bcfe, 130.7 Bcfe and 65.6 Bcfe, respectively. The average
production costs including production taxes per thousand cubic feet of gas
equivalent (Mcfe) produced were $.58, $.61 and $.57, in 2002, 2001 and 2000,
respectively. The average sales price per Mcfe was $2.11, $2.67 and $2.96,
respectively, for the same periods. Additionally, Exploration & Production
realized the impact of hedging contracts, which was a gain of $1.19 and $.46 per
Mcfe for 2002 and 2001, respectively, and a loss of $.74 for 2000.

Divestitures

Effective July 1, 2002, Williams Production Company divested of its
interest in the Jonah field located in the Green River Basin in southwest
Wyoming. This divestiture comprised 365 Bcfe in year-end 2001 reserves and
approximately 112 million cubic feet equivalent (MMcfe) per day in production.
Effective March 1, 2002, Williams Production RMT Company divested of its
non-core Wind River properties located in southwest Wyoming, which represented
60.2 Bcfe in year-end 2001 reserves and approximately 29 MMcfe per day in
production. Effective July 1, 2002, Williams Production RMT Company divested of
its non-core Anadarko properties located in western Oklahoma, which comprised 23
Bcfe in year-end 2001 reserves and approximately 10 MMcfe per day in production.
Other smaller divestitures of non-core properties during the year consisted of
22 Bcfe in year-end 2001 reserves and approximately 15 MMcfe per day in
production.

ENVIRONMENTAL AND OTHER REGULATORY MATTERS

Our Exploration and Production business is subject to various federal,
state and local laws and regulations on taxation, the exploration for and
development, production and marketing of oil and gas, and environmental and
safety matters. Many laws and regulations require drilling permits and governs
the spacing of wells, rates or production, prevention of waste and other
matters. Such laws and regulations have increased the costs of planning,
designing, drilling, installing, operating and abandoning our oil and gas wells
and other facilities. In addition, these laws and regulations, and any others
that are passed by the jurisdictions where we have production, could limit the
total number of wells drilled or the allowable production from successful wells
which could limit our reserves.

Our operations are subject to complex environmental laws and regulations
adopted by the various jurisdictions in which we operate. We could incur
liability to governments or third parties for any unlawful discharge of oil, gas
or other pollutants into the air, soil, or water, including responsibility for
remedial costs. We could potentially discharge such materials into the
environment in many ways including:

- from a well or drilling equipment at a drill site;

- leakage from gathering systems, pipelines, transportation facilities and
storage tanks;

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- damage to oil and gas wells resulting from accidents during normal
operations; and

- blowouts, cratering and explosions.

Because the requirements imposed by such laws and regulations are
frequently changed, we cannot assure you that laws and regulations enacted in
the future, including changes to existing laws and regulations, will not
adversely affect our business. In addition, because we acquire properties that
have been operated in the past by others, we may be liable for environmental
damage caused by such former operators.

COMPETITION

The natural gas industry is highly competitive. We compete in the areas of
property acquisitions and the development, production and marketing of, and
exploration for, natural gas with major oil companies, other independent oil and
natural gas concerns and individual producers and operators. We also compete
with major and independent oil and gas concerns in recruiting and retaining
qualified employees. Many of these competitors have substantially greater
financial and other resources than us.

OWNERSHIP OF PROPERTY

The majority of Exploration & Production's ownership interest in
exploration and production properties are held as working interests in oil and
gas leaseholds.

OTHER INFORMATION

In 1993, Exploration & Production conveyed a net profits interest in
certain of its properties to the Williams Coal Seam Gas Royalty Trust.
Substantially all of the production attributable to the properties conveyed to
the trust was from the Fruitland coal formation and constituted coal seam gas.
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 all of 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
Securities and Exchange Commission (SEC)and has been repurchasing the units and
reselling the units on the open market from time to time. As of March 1, 2003,
our option to repurchase trust units covered 2,608,791 trust units.

INTERNATIONAL EXPLORATION AND PRODUCTION INTERESTS

Exploration & Production also has investments in international oil and gas
interests. Exploration & Production owns approximately a 69 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 51.7 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. In Venezuela, we own a 10 percent interest in the La Concepcion
Area, a third round field development located in Western Venezuela, near Lake
Maracaibo. Combined these interests make up 5.2 percent of Exploration &
Production's total proved reserves.

MIDSTREAM GAS & LIQUIDS

GENERAL

Our Midstream Gas & Liquids segment subsidiaries provide a suite of natural
gas gathering, processing, treating and natural gas liquid and olefin
fractionation, transportation, storage, risk management and marketing services
throughout the United States, western Canada, and Venezuela.

On February 20, 2003, we announced our intention to sell additional
selected assets within the Midstream Gas & Liquids segment. Midstream Gas and
Liquids' current suite of assets include the following operations:

21

Substantially all of our assets within the Midstream Gas & Liquids segment
are pledged as collateral under our existing secured revolving credit facility
and secured letter of credit facility. See Note 11 to our Notes to Consolidated
Financial Statements for more information on the credit facilities.

Domestic Gathering and Processing; Natural Gas Liquid Fractionation, Storage
and Transportation

Midstream Gas & Liquids owns and/or operates domestic gas gathering and
processing assets primarily within the western states of Wyoming, Colorado, and
New Mexico; and the onshore and offshore shelf and deepwater areas in and around
the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama. These
assets consist of approximately 9,000 miles of gathering pipelines with capacity
in excess of eight billion cubic feet per day (including certain gathering lines
owned by Transco but operated by Midstream Gas & Liquids), eleven processing
plants (two partially owned) and nine natural gas treating plants with a
combined daily inlet capacity in excess of 5.5 billion cubic feet per day.

Midstream Gas & Liquids also owns interests in and/or operates natural gas
liquid fractionation, storage and transportation assets that supplement the
gathering and processing operations listed above. These assets include three
partially owned natural gas liquid fractionation facilities (two of which are
operated by Midstream Gas & Liquids) within central Kansas and southern
Louisiana that have a combined production capacity in excess of 200,000 barrels
per day. These assets also include ownership interests in approximately 25
million barrels of natural gas liquid storage capacity (wholly-owned) within
central Kansas and approximately 3,500 miles of domestic natural gas liquids
pipelines (partially owned) primarily located in the onshore and offshore Gulf
Coast areas.

Included in the assets listed above are the assets of Discovery Producer
Services LLC and its subsidiary Discovery Transmission Services LLC (Discovery).
Midstream Gas & Liquids owns a 50 percent interest in Discovery. During 2002,
Midstream Gas & Liquids became the operator of Discovery. Discovery's assets
include a cryogenic natural gas processing plant near Larose, Louisiana, a
natural gas liquids fractionator plant near Paradis, Louisiana and an offshore
natural gas gathering and transportation system.

Gulf Coast Petrochemical and Olefins

In southern Louisiana, Midstream Gas & Liquids provides customers in the
petrochemical industry a full suite of products and services. These operations
include a 42 percent interest in a 1.3 billion pound per year ethylene
production, storage and transportation complex in Geismer, Louisiana and the
ownership interest in Gulf Liquids New River LLC (Gulf Liquids). Gulf Liquids, a
start up entity that began operations in late 2001, consists of two refinery off
gas processing facilities, an olefinic fractionator and propylene splitter and
connecting pipeline system. In September 2002, Midstream Gas & Liquids acquired
the remaining interest in and became the operator of Gulf Liquids. Prior to
2002, the ownership interests in the Geismer ethylene production complex and
Gulf Liquids were included as a component of the Petroleum Services and Energy
Marketing & Trading business segments respectively. We have announced our
intention to sell the petrochemical and olefins assets located in Geismar,
Louisiana.

Natural Gas Liquids Marketing and Risk Management

Midstream Gas & Liquids marketing and risk management operations provide
natural gas liquid and petrochemical product supply to third party end users.
Supply for the third party end user is obtained from the equity production from
Midstream Gas & Liquid's processing, fractionation and Gulf Coast olefins
facilities as well as from outside sources. During 2002, natural gas liquid
marketing and risk management operations were transferred from Energy Marketing
& Trading to Midstream Gas & Liquids.

Canada

Midstream Gas & Liquids owns and operates natural gas treating and
extraction facilities in Alberta and British Columbia, Canada. These operations
include a natural gas processing plant, four natural gas liquid extraction
plants (two of which are partially-owned), a natural gas liquids gathering
system and natural gas liquid storage and fractionation facilities.

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Canadian operations also include a newly constructed liquids extraction
plant located near Ft. McMurray, Alberta and an olefin fractionation facility
near Edmonton, Alberta. Operations of these facilities began in the first
quarter of 2002. These new facilities extract olefin liquids from off-gas and
then fractionate, store, treat and terminal propane and propylene. This project
involves the recovery of hydrocarbon liquids, impurities and olefins from the
off-gas produced from third party tar sands refining facilities near Ft.
McMurray, Alberta.

We have announced our intention to sell certain of our Canadian operations.

Venezuela

Midstream Gas & Liquids owns interests in one medium- and two high-pressure
gas compression facilities, two natural gas liquids extraction units, one
fractionation facility, and an operations contract on an oil and gas loading and
storage facility located in Venezuela. During 2002, these operations were
transferred to Midstream Gas & Liquids from the previously reported
International business segment.

Expansion Projects

GATHERING AND PROCESSING -- WYOMING EXPANSION

In January 2002, Midstream Gas & Liquids completed an expansion of our Echo
Springs natural gas plant near Wamsutter, Wyoming. This expansion included the
addition of a third cryogenic gas processing unit that boosted the inlet
capacity of the plant from 250 to 390 million cubic feet per day and liquids
extraction from 18,000 barrels to 28,000 barrels per day. This project also
included the expansion of the gathering system that brings natural gas to the
Echo Springs facility.

GATHERING AND PROCESSING -- DEEPWATER PROJECTS

In 2002, Midstream Gas & Liquids expanded its Gulf Coast gathering and
processing operations with the completion of the 137-mile pipeline system 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. First production from Nansen and Boomvang occurred in
late January 2002 and early July 2002, respectively.

During 2002, Midstream Gas & Liquids also completed construction of Canyon
Station, a state of the art production handling platform that treats and
processes up to 500 million cubic feet gas per day from the Aconcagua Canden
Hills and Kings Peak deepwater fields. First volumes began flowing through
Canyon Station in September and are currently flowing in excess of 400 million
cubic feet per day.

Midstream Gas & Liquids also continues construction on the deepwater
projects for the Devils Tower field (operated by Dominion Exploration and
Production) in the eastern Gulf of Mexico. This project called for Midstream Gas
& Liquids 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. First production is expected in late 2003. Midstream Gas & Liquids
intends to use the facilities to provide production-handling services to
surrounding fields. Midstream Gas & Liquids' Mobile Bay plant will process the
gas and recover natural gas liquids, which will then be transported to the Baton
Rouge Fractionator via the Tri-States and Wilprise pipelines, all owned in whole
or in part by Midstream Gas & Liquids.

Midstream Gas & Liquids also signed an agreement with Kerr-McGee to build a
100-mile oil pipeline to their Gunnison prospect. This pipeline will be
connected to our Galveston Area Block A-244 platform for deliveries into a third
party crude oil system. First oil production is expected by the second quarter
2004.

Customers and Operations

Midstream Gas & Liquids' domestic gas gathering and processing customers
are generally natural gas producers who have proved and/or producing natural gas
fields in the areas surrounding Midstream Gas & Liquids' infrastructure. During
2002, these operations gathered gas for 244 customers and processed gas for 96
customers. The largest gathering customer accounted for approximately 15 percent
of total gathered volumes,

23

and the two largest processing customers accounted for 24 percent and 15
percent, respectively, of processed volumes. Midstream Gas & Liquids' gathering
and processing agreements are generally long-term agreements with various
expiration dates.

Midstream Gas & Liquids markets natural gas liquids and petrochemical
products to a wide range of users in the energy and petrochemical industries.
Midstream Gas & Liquids' marketing and risk management operations provide liquid
and petrochemical product supply to third parties from the equity production
from Midstream Gas & Liquids' domestic facilities as well as from outside
sources. The majority of domestic sales are based on supply contracts of less
than one-year in duration. Midstream Gas & Liquids' Canadian operations sold
natural gas liquids produced from the Canadian facilities to third party end
users. Canadian natural gas liquid sales contracts are typically long-term in
nature. In order to meet the delivery requirements under various contracts
Midstream Gas & Liquids maintains inventories of natural gas liquids at various
locations throughout the United States and Canada.

Midstream Gas & Liquids' Venezuelan assets were originally constructed and
are currently operated for the exclusive benefit of Petroleos de Venezuela S.A.
(PDVSA), the state owned Petroleum Corporation of Venezuela. The significant
contracts are 20 years in duration with revenues based on a combination of fixed
capital payments, throughput volumes, and in the case of one of the gas
compression facilities, a minimum throughput guarantee. During December 2002 and
early 2003, a countrywide strike took place within Venezuela that resulted in
significant political instability and a volatile economic environment. Employees
of PDVSA joined this strike, which had an impact on the operations of most of
the Venezuelan facilities. All owned facilities are presently operating.
However, an operating agreement for the PDVSA owned oil terminaling facility is
the subject of a contract dispute with PDVSA. The ultimate impact the economic
and political instability will have on Midstream Gas & Liquids' Venezuelan
operations will depend upon the duration of the economic and political
instability as well as the ability to enforce certain contract provisions with
PDVSA.

Operating Statistics

The following table summarizes Midstream Gas & Liquids' significant
operating statistics.

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

* Excludes volumes associated with partially owned assets that are not
consolidated for financial reporting purposes.

** Average thousand barrels per day.

REGULATORY AND ENVIRONMENTAL MATTERS

Under the Natural Gas Act (NGA), gathering and processing facilities and
services are not subject to the regulatory authority of the FERC. Onshore
gathering is reserved to the states and offshore gathering is subject to the
Outer Continental Shelf Lands Act (OCSLA).

Of the states where Midstream Gas & Liquids operates, currently only
Kansas, Oklahoma and Texas actively regulate gathering activities. Those states
regulate gathering through complaint mechanisms under which the state commission
may resolve disputes involving an individual gathering arrangement. Although
gathering facilities located offshore are not subject to the NGA, some
controversy exists as to how the FERC should determine whether offshore
facilities function as gathering. These issues are currently before the FERC and
appellate courts. Most gathering facilities offshore are subject to the OCSLA,
which provides in part that

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outer continental shelf pipelines "must provide open and nondiscriminatory
access to both owner and nonowner shippers."

Midstream Gas & Liquids' business operations are subject to various
federal, state, and local environmental and safety laws and regulations. The
Discovery and other pipeline systems are subject to FERC regulation common to
interstate gas transmission. Midstream Gas & Liquids' liquid 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
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 Gas & Liquids to certain other regulations concerning its terms and
conditions of service. Certain of our pipelines also file tariff rates covering
intrastate movements with various state commissions. The United States
Department of Transportation has prescribed safety regulations for common
carrier pipelines. The pipeline systems are subject to various state laws and
regulations concerning safety standards, exercise of eminent domain, and similar
matters. The Kansas Department of Health and Environment (KDHE) has proposed new
regulations to govern underground storage in Kansas, which may require
additional equipment and testing for Midstream Gas & Liquids' storage operations
in Kansas.

The majority of our Midstream Gas & Liquids' Canadian assets, 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 the British Columbia 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, providing that licensed operators are held responsible for
ensuring that their operations are conducted in accordance with all provincial
regulatory requirements. For situations in which non-compliance with the
applicable regulations is at issue, the AEUB and Alberta Environment have
implemented an enforcement process with escalating consequences. The 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 Canada's
National Energy Board (NEB). One pipeline system, which is Leg Number 2 of the
natural gas liquids gathering system, is regulated by the NEB as a Group 2
inter-provincial pipeline between British Columbia 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 stringent
Group 1 NEB-mandated accounting and reporting requirements.

COMPETITION

The gathering and processing business is a local business with varying
competitive factors in each basin. Midstream Gas & Liquids' gathering and
processing business competes with interstate and intrastate pipelines, producers
and independent gatherers and processors. Numerous factors impact any given
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. Midstream Gas & Liquids' gathering and processing services are
generally covered under long-term contracts with applicable acreage or reserve
dedications. Midstream Gas & Liquids' relatively large positions in the Western
and Gulf Regions are indicators that demand for future gathering and processing
infrastructure and services should continue.

OWNERSHIP OF PROPERTY

Midstream Gas & Liquids typically owns its gathering and processing
facilities. 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 Midstream Gas & Liquids or on
sites held under leases or permits issued or approved by public authorities.

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ENERGY MARKETING & TRADING

GENERAL

Our Energy Marketing & Trading segment, is a national energy services
provider that buys, sells and transports energy and energy-related commodities,
including power, natural gas, refined products, crude oil, and emission credits,
primarily on a wholesale level. In addition, Energy Marketing & Trading provides
energy-related services through a variety of financial instruments and
structured transactions including exchange-traded futures, as well as
over-the-counter forwards, options, swaps, tolling, load serving, full
requirements, storage, transportation, and transmission agreements and other
derivatives related to various energy and energy-related commodities. As a
result of current liquidity and credit constraints, in June 2002 we decided to
limit our financial commitment and exposure to the Energy Marketing & Trading
business. Energy Marketing & Trading initiated efforts in 2002 to sell all or
portions of its portfolio and/or pursue potential joint venture or business
combination opportunities. Energy Marketing & Trading's future results will
likely be affected by the reduction in liquidity available from its parent, the
unwillingness of counterparties to enter into transactions with Energy Marketing
& Trading, the liquidity of markets in which Energy Marketing & Trading
operates, and the creditworthiness of other counterparties in the industry and
their ability to perform their contractual obligations. During 2002, Energy
Marketing & Trading's ability to manage or hedge its portfolio against adverse
market movements was limited by a lack of market liquidity as well as market
concerns regarding our credit and liquidity situation. See Note 15 of our Notes
to Consolidated Financial Statements for information on financial instruments
and energy trading activities.

At December 31, 2002, Energy Marketing & Trading employed approximately 410
employees, compared with approximately 1,000 employees at the end of 2001. As of
February 25, 2003, the number of Energy Marketing & Trading employees was
approximately 330 and additional staffing reductions are expected during 2003.

As discussed below and in Note 1 and 16 to our -- Notes to Consolidated
Financial Statements, in 2002, the energy marketing and trading business sector,
including Energy Marketing & Trading, experienced significant financial
challenges, for example associated with credit downgrades and reduced liquidity,
as well as significant legal and regulatory challenges, for example associated
with federal and state investigations and numerous lawsuits, that adversely
affected the energy marketing and trading business. These challenges are
expected to continue in 2003.

During 2002, Energy Marketing & Trading marketed over 404,711 physical
gigawatt hours of power. As part of its approximately 11,000 megawatt power
supply portfolio at year-end, 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 had
a number of long-term tolling agreements at December 31, 2002, to market
capacity of electric generation facilities totaling approximately 7,500
megawatts (California -- 3,956 megawatts; Alabama -- 845 megawatts;
Louisiana -- 765 megawatts; New Jersey -- 752 megawatts; Pennsylvania -- 655
megawatts; and Michigan -- 538 megawatts). Under these tolling arrangements,
Energy Marketing & Trading has the right, but not the obligation, to supply fuel
for conversion to electricity and then market capacity, energy and ancillary
services related to the generating facilities owned and operated by various
unrelated third parties. As of December 31, 2002, Energy Marketing & Trading
also had entered into several agreements to provide full requirements services
for a number of customers whose supply resources are being managed with
approximately 2,520 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 two
natural gas-fired electric generating plants owned by affiliated companies and
located near Bloomfield, New Mexico (60 megawatts); in Hazleton, Pennsylvania
(147 megawatts); and near Worthington, Indiana (170 megawatts). Energy Marketing
& Trading's subsidiary, Worthington Generation, L.L.C., which owns the
Worthington facility, was sold in January of 2003 for $67 million, including a
termination of an approximately 1,056 megawatt load serving transaction in
Indiana. In connection with a global settlement of claims asserted by the state
of California, and as more fully discussed in Note 16 of our Notes to
Consolidated Financial Statements, Energy Marketing & Trading renegotiated
long-term power agreements with the California Department of Water Resources.

26

Energy Marketing & Trading's primary power customers include utilities,
municipalities, cooperatives, governmental agencies and other power marketers.

In 2002, Energy Marketing & Trading marketed natural gas throughout North
America with total physical volumes averaging 3.8 billion cubic feet per day.
Beginning in 2000, Energy Marketing & Trading's natural gas marketing operations
focused on activities that facilitate and/or complement the group's power
portfolio. In addition to procuring supply for our Midstream Gas & Liquids
operations, marketing equity gas for our Exploration & Production operations and
managing firm service contracts for our Gas Pipeline operation, Energy Marketing
& Trading's natural gas customers include local distribution companies,
utilities, producers, industrials and other gas marketers.

In 2002, 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 2002, Energy
Marketing & Trading marketed on average approximately 832,000 barrels per day of
physical crude oil and petroleum products.

In 2002, Energy Marketing & Trading curtailed its European trading
activities conducted through its London office as part of our efforts to scale
back our entire trading business in 2002. Included in the 2002 Energy Marketing
& Trading staffing reductions noted above is a decrease in staffing of its
London office from 32 at the end of 2001 to nine at the end of 2002.

OPERATING STATISTICS

The following table summarizes marketing and trading gross sales volumes
for the periods indicated. Petroleum products volumes for 2001 and 2000 do not
include volumes associated with the natural gas liquids business transferred to
the Midstream Gas & Liquids segment during 2002.

Energy Marketing & Trading

As of December 31, 2002, Energy Marketing & Trading had approximately 287
customers compared with over 652 customers at the end of 2001.

REGULATORY AND LEGAL MATTERS

Energy Marketing & Trading's business is subject to a variety of laws and
regulations at the local, state and federal levels in the United States and
Europe (including the United Kingdom). In the U.S. Energy Marketing & Trading is
regulated by the FERC and the Commodity Futures Trading Commission. Electricity
and natural gas markets, in California and elsewhere, continue to be subject to
numerous and wide-ranging federal and state regulatory proceedings and
investigations, as well as civil actions, regarding among other things, market
structure, behavior of market participants, market prices, and reporting to
trade publications. Discussions in California and other states have ranged from
threats of re-regulation to suspension of plans to

27

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 Energy Marketing &
Trading. These allegations have resulted in multiple state and federal
investigations as well as the filing of class-action lawsuits in which Energy
Marketing & Trading is named a defendant. Energy Marketing & Trading's long-term
power contract with the California Department of Water Resources has also been
challenged both at the FERC and in civil suits. On November 11, 2002, Energy
Marketing & Trading and Williams executed a settlement agreement that is
intended to resolve many of these disputes with the State of California with
respect to non-criminal matters and includes renegotiated long-term energy
contracts. The settlement is also intended to resolve complaints brought by the
California Attorney General against us and the State of California's refund
claims. In addition, the settlement is intended to resolve ongoing
investigations by the States of California, Oregon, and Washington. The
settlement closed December 31, 2002, although certain court approvals are
pending. Notwithstanding this settlement, numerous investigations and actions
related to energy marketing and trading remain. Energy Marketing & Trading may
be liable for refunds and other damages and penalties as a result of the above
actions and investigations. Each of these matters as well as other regulatory
and legal matters related to Energy Marketing & Trading are discussed in more
detail in Note 16 to our Consolidated Financial Statements. The outcome of these
matters could affect the creditworthiness and ability to perform contractual
obligations of Energy Marketing & Trading as well as the creditworthiness and
ability to perform contractual obligations of other market participants.

On March 13, 2003, we entered into a settlement with FERC regarding its
investigation of the relationship between Transco and Energy Marketing & Trading
whereby Transco will pay a civil penalty in the amount of $20 million payable
over a five year period. In addition, we agreed to certain operational
restrictions and agreed to implement a compliance program to ensure future
compliance with the settlement agreement and FERC's marketing affiliate rules.
See Note 16 of our Notes to Consolidated Financial Statements for further
information on the settlement.

COMPETITION AND MARKET ENVIRONMENT

Energy Marketing & Trading's operations compete directly with large
independent energy marketers, marketing affiliates of regulated pipelines and
utilities and natural gas producers. The financial trading business is highly
competitive and Energy Marketing & Trading 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. In 2002, the energy marketing and trading industry,
including Energy Marketing & Trading, experienced significant credit and
liquidity constraints affecting the conduct of new business and performance on
preexisting commitments. Energy Marketing & Trading's business also had relied
upon our senior unsecured long-term debt investment-grade rating to satisfy
credit support requirements of many counterparties. As a result of the credit
rating downgrades to below investment grade levels, Energy Marketing & Trading's
participation in energy risk management and trading activities requires adequate
assurance or alternate credit support under certain existing agreements. In
addition, we are required to fund margin requirements pursuant to industry
standard derivative agreements with cash, letters of credit or other negotiable
instruments. Certain of Energy Marketing & Trading's counterparties have
experienced significant declines in their financial stability and
creditworthiness which may adversely impact their ability to perform under
contracts with Energy Marketing & Trading. Energy Marketing & Trading initiated
efforts in 2002 to sell all or portions of its portfolio and/or pursue potential
joint venture or business combination opportunities. During 2002, Energy
Marketing & Trading closed out trading positions with a number of counterparties
and has disputes associated with this liquidation. One counterparty has disputed
a settlement amount related to the liquidation of a trading position with Energy
Marketing & Trading and the amount of settlement is in excess of $100 million
payable to Energy Marketing & Trading. The matter is being arbitrated. Credit
constraints, declines in market liquidity, and financial instability of market
participants, are expected to continue and potentially grow in 2003. Continued
liquidity and credit constraints of Williams may also significantly impact
Energy Marketing & Trading's ability to manage market risk and meet contractual
obligations. These matters are further discussed in Management's Discussion &
Analysis of Financial Conditions and Results of Operations.

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OWNERSHIP OF PROPERTY

The primary assets of Energy Marketing & Trading are its term contracts,
related systems and technological support. In addition, Energy Marketing &
Trading owned a gas-fired generating facility located near Worthington, Indiana
with a capacity of approximately 170 megawatts. In January 2003, Energy
Marketing & Trading sold Worthington Generation L.L.C., its subsidiary that owns
the Worthington generation facility.

As a result of our current liquidity constraints, Energy Marketing &
Trading initiated efforts in 2002 to sell all or portions of its portfolio
and/or pursue potential joint venture or business combination opportunities. No
assurances can be made regarding the ultimate consummation of any sales or
business combination activities currently being pursued. Energy Marketing &
Trading is continuing to evaluate its potential alternatives. As discussed
further in Note 1 to our Notes to Consolidated Financial Statements, portions of
Energy Marketing & Trading's portfolio have been recognized at their estimated
"fair value," which according to generally accepted accounting principles is the
amount at which they could be exchanged in a current transaction between willing
parties other than in a forced liquidation or sale. Given the financial
condition and liquidity constraints and needs of the Company, however, amounts
ultimately realized in any portfolio sales or business combination may be
significantly different than fair value estimates presented in the financial
statements, depending on the timing and terms of any such transactions.

ENVIRONMENTAL MATTERS

Power generation facilities are subject to various environmental laws and
regulations, including laws and regulations regarding emissions. We do not
believe compliance with various environmental laws and regulations would have a
material adverse effect on capital expenditures, earnings and the competitive
position of Energy Marketing & Trading. Facility availability may be affected by
these laws and regulations.

WILLIAMS ENERGY PARTNERS L.P.

GENERAL

We have announced our intention to sell our interests in Williams Energy
Partners.

In October 2000, we formed Williams Energy Partners, a wholly-owned master
limited partnership through various wholly-owned subsidiaries, to acquire, own
and operate a diversified portfolio of energy assets, concentrated around the
storage, transportation and distribution of refined petroleum products and
ammonia. In February 2001, 4,600,000 common units, representing approximately 40
percent of the total outstanding units of Williams Energy Partners, were sold to
the public in an initial public offering. Williams Energy Partners' common units
trade on the New York Stock Exchange under the symbol WEG. Following this
transaction, we owned approximately 65 percent of Williams Energy Partners,
including 100 percent of Williams Energy Partners' general partner interest.

On April 11, 2002, Williams Energy Partners acquired all of the membership
interests of Williams Pipe Line Company LLC from a wholly owned subsidiary of
ours for approximately $1 billion. As consideration, Williams Energy Partners
paid us $674.4 million in cash, after netting our $6 million required
contribution to maintain our 2 percent general partner interest. We also
received $304 million in the form of class B units representing limited partner
interests in Williams Energy Partners. We currently own approximately a 53
percent limited partnership interest subject to certain limitations on voting
rights and 100 percent of WEG GP LLC, Williams Energy Partners' sole general
partner.

Williams Energy Partners" current asset portfolio includes:

- the Williams Pipe Line system, a 6,700 mile refined petroleum products
pipeline system that serves the mid-continent region of the United States
with 39 system terminals and 26 million barrels of storage;

- five petroleum products terminal facilities located along the Gulf Coast
and near the New York harbor (marine terminals) with an aggregate storage
capacity of approximately 18 million barrels;

29

- 23 petroleum products terminals located principally in the southeastern
United States (inland terminals) with an aggregate storage capacity of
five million barrels; and

- an 1,100-mile ammonia pipeline system that serves the mid-continent
region of the United States.

REGULATORY AND ENVIRONMENTAL MATTERS

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.

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. If the Surface
Transportation Board finds that a carrier's rates violate these statutory
commands, it may prescribe a reasonable rate. 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.

COMPETITION

In certain markets, barges provide an alternative source for transporting
refined products; however, pipelines are generally the lowest-cost alternative
for refined product movements between different markets. As a result, the
Williams Pipe Line system's most significant competitors are other pipelines
that serve the same markets.

Williams Energy Partners experiences the greatest demand at its marine
terminals when customers tend to store more product to take advantage of
favorable pricing expected in the future. When the opposite market condition
exists some companies choose not to store product or are less willing to enter
into long-term storage contracts. The additional heating and blending services
that Williams Energy Partners provides at its marine terminals attract
additional demand for our storage services and result in increased revenue
opportunities.

Several major and integrated oil companies have their own proprietary
storage terminals along the Gulf Coast that are currently being used in their
refining operations. If these companies choose to shut down their refining
operations and elect to store and distribute refined petroleum products through
their proprietary terminals, Williams Energy Partners would experience increased
competition for the services that it provides. In addition, several companies
have facilities in the Gulf Coast region and offer competing storage and
distribution services.

OWNERSHIP OF PROPERTY

Williams Energy Partners owns its pipeline and terminalling assets. Its
facilities are located on property owned, leased, licensed, or subject to
right-of-way agreements.

PETROLEUM SERVICES

GENERAL

We completed a number of asset sales in the Petroleum Services segment
during 2002 and early 2003. We regard the remaining assets within the Petroleum
Services segment as non-strategic and substantially all of the remaining assets
with the exception of our interest in Longhorn Partners pipeline will be sold in
the near

30

future. Certain assets within the Petroleum Services segment, including the
Alaska refinery and convenience stores, are pledged under our secured credit
facilities.

The Petroleum Services segment currently owns and operates a petroleum
products refinery and 29 convenience stores in Alaska and markets products
related thereto. We have announced our intention to sell the Alaska refinery and
related operations. In 2002, no one customer accounted for ten percent of
Petroleum Services' total revenues.

We and our 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 pipeline from Houston, Texas,
to El Paso, Texas. Pipeline construction is substantially complete and all
regulatory and environmental approvals have been received. Operations are
expected to commence by year-end 2003, once start-up financing is obtained. we
have contributed a total of approximately $96 million and loaned approximately
$139 million (including accrued interest of $21.5 million) to the joint venture.
Williams Pipe Line Company, a subsidiary of Williams Energy Partners LP, has
designed and constructed and will operate the pipeline.

On June 30, 2000, we purchased a 3.08 percent interest in TAPS and the
Valdez Crude terminal in Alaska from Mobil Alaska Pipeline Company for $32.5
million. Petroleum Services' share of the crude oil deliveries for 2002 and 2001
was approximately 14.4 million barrels and 14.0 million barrels, respectively.

We also own Williams Bio-Energy L.L.C. that owns and operates an ethanol
production plant in Pekin, Illinois, a 78.4 percent interest in another ethanol
plant in Aurora, Nebraska, and have various agreements to market ethanol from
third-party plants. On February 20, 2003, we announced a definitive agreement to
sell our equity interest in Williams Bio-Energy L.L.C.

REFINING

Petroleum Services, through a subsidiary, owns and operates the North Pole,
Alaska petroleum products refinery. The financial results of the North Pole
refinery may be significantly impacted by changes in market prices for crude oil
and refined products. Petroleum Services cannot predict the future of crude oil
and product prices or their impact on its financial results. Due to our current
credit situation, we must pre-pay for crude oil supply for our refinery
operations. On June 18, 2002, we announced our intention to sell the Alaska
refinery and related petroleum assets.

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 the TAPS, its supply point for
crude oil. 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. The refinery producers 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.

The North Pole Refinery processed and sold the following volumes per day:

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 permit the North Pole Refinery to purchase 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

31

finished product and the remainder of the throughput is returned to the TAPS and
either delivered to repay exchange obligations or sold.

RETAIL PETROLEUM

Petroleum Services, under the brand name "Williams Express," is engaged in
the retail marketing of gasoline, diesel fuel, other petroleum products,
convenience merchandise and fast food items. At December 31, 2002, the retail
petroleum group operated 29 Williams Express convenience stores in Alaska. The
convenience store sites are primarily concentrated in the vicinities of
Anchorage and Fairbanks, Alaska. All of the motor fuel sold by Williams Express
convenience stores is supplied either by exchanges or directly from the North
Pole Refinery.

Convenience merchandise and fast food accounted for approximately 57
percent of the retail petroleum group's gross margins in 2002. Gasoline and
diesel sales volumes for the periods indicated are noted below:

REGULATORY MATTERS

Environmental regulations and changing crude oil supply patterns continue
to affect the refining industry. Environmental Protection Agency regulations,
adopted pursuant to the Clean Air Act, require refiners to change the
composition of fuel manufactured. A refiner's ability to respond to the effects
of regulation and changing supply patterns will determine its ability to
maintain and capture new market shares. We will continue to attempt to position
ourself to respond to changing regulations and supply patterns but cannot
predict how future changes in the marketplace will affect our market areas.
Williams Alaska Petroleum (WAPI) is actively engaged in administrative
litigation being conducted jointly by the FERC and the Regulatory Commission of
Alaska concerning the TAPS Quality Bank. Primary issues being litigated include
the appropriate valuation of the naphtha and residual product cuts within the
TAPS crude stream as well as the appropriate retroactive effect of the
determinations. WAPI's interest in these proceedings is material, but the
outcome cannot be predicted with certainty nor can the likely result be
quantified. See Note 16 to our Notes to Consolidated Financial Statements for
further detail on the Quality Bank matter.

COMPETITION

Competition exists from other refineries, cargo shipments, railroads and
tank trucks. Competition is affected by trades of products or crude oil
production from other refineries that have access to the Alaska market and by
trades among brokers, traders and others who control products. These trades can
result in the diversion of volumes from the North Pole refinery that might
otherwise be refined. The possible 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 refinery throughput.

The principal competitive forces affecting Petroleum Services' refining
business are feedstock costs, refinery efficiency, refinery product mix and
product distribution. Petroleum Services has no crude oil reserves and does not
engage in crude oil exploration, and it must therefore obtain its crude oil
requirements from unaffiliated sources. Petroleum Services 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 Petroleum Services' 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.

32

OWNERSHIP OF PROPERTY

The North Pole refinery is located on land leased from the state of Alaska
under a long-term lease scheduled to expire in 2005 and renewable at that time
by us. The Anchorage, Alaska terminal is located on land leased from the Alaska
Railroad Corporation under two long-term leases. Petroleum Services' management
believes the condition and maintenance of its assets are adequate and sufficient
for the conduct of its business.

ENVIRONMENTAL MATTERS

Groundwater monitoring and remediation are ongoing at the North Pole
refinery and air and water pollution control equipment is operating to comply
with applicable regulations. The Clean Air Act Amendments of 1990 continue to
impact Petroleum Services' refining business 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 Petroleum Services'
competitive position.

Petroleum Services and its subsidiaries also accrue environmental
remediation costs for its refining and former retail petroleum operation
primarily related to soil and groundwater contamination. In addition, Petroleum
Services owns a discontinued petroleum refining facility that is being evaluated
for potential remediation efforts. At December 31, 2002, Petroleum Services and
its subsidiaries had accrued liabilities totaling approximately $9.6 million.

We have indemnified the purchaser of the Memphis refinery for certain
environmental matters.

Petroleum Services is subject to various federal, state and local laws and
regulations relating to environmental quality control. Management believes that
Petroleum Services' 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
Petroleum Services. See Note 16 of our Notes to Consolidated Financial
Statements for further details on legal and environmental matters.

ENVIRONMENTAL MATTERS

In addition to the environmental matters included in the business segment
discussions above, a description of environmental claims is included in Note 16
of our Notes to Consolidated Financial Statements and is incorporated herein by
reference.

EMPLOYEES

At March 14, 2003, we and our subsidiaries had approximately 7,300
full-time employees, of whom approximately 490 were represented by unions and
covered by collective bargaining agreements. We expect further workforce
reductions in 2003. Our employees are jointly employed by us and one of our
subsidiaries. With the exception of the countrywide strike in Venezuela, we
consider our relations with our employees to be generally good.

FORWARD LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT
FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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

33

Forward-looking statements can be identified by words such as
"anticipates," "believes," "could," "continues," "estimates," "expects,"
"forecasts," "might," "planned," "potential," "projects," "scheduled" or similar
expressions. Although we believe these forward-looking statements are based on
reasonable assumptions, statements made regarding future results are subject to
a number of assumptions, uncertainties and risks that could cause future results
to be materially different from the results stated or implied in this document.
Events in 2002 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 and the energy industry
generally 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 us.

RISK FACTORS

You should carefully consider the following risk factors in addition to the
other information in this annual report. Each of these factors could adversely
affect our business, operating results, and financial condition as well as
adversely affect the value of an investment in our securities.

RISKS AFFECTING OUR STRATEGY AND FINANCING NEEDS

OUR STRATEGY TO STRENGTHEN OUR BALANCE SHEET AND IMPROVE LIQUIDITY DEPENDS ON
OUR ABILITY TO DIVEST SUCCESSFULLY CERTAIN ASSETS.

On February 20, 2003, we announced our intention to sell an additional
$2.25 billion in assets, properties and investments. At December 31, 2002, we
had debt obligations of $3.8 billion (including certain contractual fees and
deferred interest related to underlying debt) that will mature between now and
March 2004. Because our cash flow from operations will be insufficient alone to
repay all such debt and our access to capital markets is limited, in part as a
result of the loss of our investment grade ratings, we will depend on our sales
of assets to generate sufficient net cash proceeds to enable the payment of our
maturing obligations.

Our secured credit facilities limit our ability to sell certain assets and
require generally that one-half of all net proceeds from asset sales be applied
(a) to repayment of certain long-term debt, (b) to cash collateralization of
designated letters of credit, and (c) to reduction of the lender commitments
under the secured facilities. The timing of and the net cash proceeds realized
from such sales are dependent on locating and successfully negotiating sales
with prospective buyers, regulatory approvals, industry conditions, and lender
consents. If the realized cash proceeds are insufficient or are materially
delayed, we might not have sufficient funds on hand to pay maturing indebtedness
or to implement our strategy.

RECENT DEVELOPMENTS AFFECTING THE WHOLESALE POWER AND ENERGY TRADING INDUSTRY
SECTOR HAVE REDUCED MARKET ACTIVITY AND LIQUIDITY AND MIGHT CONTINUE TO
ADVERSELY AFFECT OUR RESULTS OF OPERATIONS.

As a result of the 2000-2001 energy crisis in California, the resulting
collapse in energy merchant credit, the recent volatility in natural gas prices,
the Enron Corporation bankruptcy filing, and investigations by governmental
authorities into energy trading activities and increased litigation related to
such inquiries, companies generally in the regulated and so-called unregulated
utility businesses have been adversely affected.

These market factors have led to industry-wide downturns that have resulted
in some companies being forced to exit from the energy trading markets, leading
to a reduction in the number of trading partners and in market liquidity and
announcements by us, other energy suppliers and gas pipeline companies of plans
to sell large numbers of assets in order to boost liquidity and strengthen their
balance sheets. Proposed and completed sales by other energy suppliers and gas
pipeline companies could increase the supply of the type of assets we are
attempting to sell and potentially lead either to our failing to execute such
asset sales or our obtaining lower prices on completed asset sales. If either of
these developments were to occur, our ability to realize our strategy of
improving our liquidity and reducing our indebtedness through asset sales could
be significantly hampered.

34

BECAUSE WE NO LONGER MAINTAIN INVESTMENT GRADE CREDIT RATINGS, OUR
COUNTERPARTIES MIGHT REQUIRE US TO PROVIDE INCREASING AMOUNTS OF CREDIT
SUPPORT WHICH WOULD RAISE OUR COST OF DOING BUSINESS.

Our transactions in each of our businesses, especially in our Energy
Marketing & Trading business, will require greater credit assurances, both to be
given from, and received by, us to satisfy credit support requirements.
Additionally, certain market disruptions or a further downgrade of our credit
rating might further increase our cost of borrowing or further impair our
ability to access one or any of the capital markets. Such disruptions could
include:

- further economic downturns;

- capital market conditions generally;

- market prices for electricity and natural gas;

- terrorist attacks or threatened attacks on our facilities or those of
other energy companies; or

- the overall health of the energy industry, including the bankruptcy of
energy companies.

RISKS RELATED TO OUR BUSINESS

ELECTRICITY, NATURAL GAS LIQUIDS AND GAS PRICES ARE VOLATILE AND THIS
VOLATILITY COULD ADVERSELY AFFECT OUR FINANCIAL RESULTS, CASH FLOWS, ACCESS TO
CAPITAL AND ABILITY TO MAINTAIN EXISTING BUSINESSES.

Our revenues, operating results, profitability, future rate of growth and
the carrying value of our electricity and gas businesses depend primarily upon
the prices we receive for natural gas and other commodities. Prices also affect
the amount of cash flow available for capital expenditures and our ability to
borrow money or raise additional capital.

Historically, the markets for these commodities have been volatile and they
are likely to continue to be volatile. Wide fluctuations in prices might result
from relatively minor changes in the supply of and demand for these commodities,
market uncertainty and other factors that are beyond our control, including:

- worldwide and domestic supplies of electricity natural gas petroleum, and
relate commodities;

- weather conditions;

- the level of consumer demand;

- the price and availability of alternative fuels;

- the availability of pipeline capacity;

- the price and level of foreign imports;

- domestic and foreign governmental regulations and taxes;

- the overall economic environment; and

- the credit in the markets where products are bought and sold.

These factors and the volatility of the energy markets make it extremely
difficult to predict future electricity and gas price movements with any
certainty. Further, electricity and gas prices do not necessarily move in
tandem.

WE MIGHT NOT BE ABLE TO SUCCESSFULLY MANAGE THE RISKS ASSOCIATED WITH SELLING
AND MARKETING PRODUCTS IN THE WHOLESALE ENERGY MARKETS.

Our trading portfolios consist of wholesale contracts to buy and sell
commodities, including contracts for electricity, natural gas, natural gas
liquids and other commodities that are settled by the delivery of the commodity
or cash throughout the United States. If the values of these contracts change in
a direction or manner that we do not anticipate or cannot manage, we could
realize material losses from our trading activities. In the past, certain
marketing and trading companies have experienced severe financial problems

35

due to price volatility in the energy commodity markets. In certain instances
this volatility has caused companies to be unable to deliver energy commodities
that they had guaranteed under contract. In such event, we might incur
additional losses to the extent of amounts, if any, already paid to, or received
from, counterparties. In addition, in our businesses, we often extend credit to
our counterparties. Despite performing credit analysis prior to extending
credit, we are exposed to the risk that we might not be able to collect amounts
owed to us. If the counterparty to such a financing transaction fails to perform
and any collateral we have secured is inadequate, we will lose money.

If we are unable to perform under our energy agreements, we could be
required to pay damages. These damages generally would be based on the
difference between the market price to acquire replacement energy or energy
services and the relevant contract price. Depending on price volatility in the
wholesale energy markets, such damages could be significant.

OUR RISK MEASUREMENT AND HEDGING ACTIVITIES MIGHT NOT PREVENT LOSSES.

Although we have risk management systems in place that use various
methodologies to quantify risk, these systems might not always be followed or
might not always work as planned. Further, such risk measurement systems do not
in themselves manage risk, and adverse changes in energy commodity market
prices, volatility, adverse correlation of commodity prices, the liquidity of
markets, and changes in interest rates might still adversely affect our earnings
and cash flows and our balance sheet under applicable accounting rules, even if
risks have been identified.

To lower our financial exposure related to commodity price and market
fluctuations, we have entered into contracts to hedge certain risks associated
with our assets and operations, including our long-term tolling agreements. In
these hedging activities, we have used fixed-price, forward, physical purchase
and sales contracts, futures, financial swaps and option contracts traded in the
over-the-counter markets or on exchanges, as well as long-term structured
transactions when feasible. Substantial declines in market liquidity, however,
as well as deterioration, of our credit, and termination of existing positions
(due for example to credit concerns) have greatly limited our ability to hedge
risks identified and have caused previously hedged positions to become unhedged.
To the extent we have unhedged positions, fluctuating commodity prices could
cause our net revenues and net income to be volatile.

OUR OPERATING RESULTS MIGHT FLUCTUATE ON A SEASONAL AND QUARTERLY BASIS.

Revenues from our businesses, including gas transmission and the sale of
electric power, can have seasonal characteristics. In many parts of the country,
demand for power peaks during the hot summer months, with market prices also
peaking at that time. In other areas, demand for power peaks during the winter.
In addition, demand for gas and other fuels peaks during the winter. As a
result, our overall operating results in the future might fluctuate
substantially on a seasonal basis. The pattern of this fluctuation might change
depending on the nature and location of our facilities and pipeline systems and
the terms of our power sale agreements and gas transmission arrangements.

OUR INVESTMENTS AND PROJECTS LOCATED OUTSIDE OF THE UNITED STATES EXPOSE US TO
RISKS RELATED TO LAWS OF OTHER COUNTRIES, TAXES, ECONOMIC CONDITIONS,
FLUCTUATIONS IN CURRENCY RATES, POLITICAL CONDITIONS AND POLICIES OF FOREIGN
GOVERNMENTS. THESE RISKS MIGHT DELAY OR REDUCE OUR REALIZATION OF VALUE FROM
OUR INTERNATIONAL PROJECTS.

We currently own and might acquire and/or dispose of material
energy-related investments and projects outside the United States. The economic
and political conditions in certain countries where we have interests or in
which we might explore development, acquisition or investment opportunities
present risks of delays in construction and interruption of business, as well as
risks of war, expropriation, nationalization, renegotiation, trade sanctions or
nullification of existing contracts and changes in law or tax policy, that are
greater than in the United States. The uncertainty of the legal environment in
certain foreign countries in which we develop or acquire projects or make
investments could make it more difficult to obtain non-recourse project or other
financing on suitable terms, could adversely affect the ability of certain
customers to honor their obligations

36

with respect to such projects or investments and could impair our ability to
enforce our rights under agreements relating to such projects or investments.

Operations in foreign countries also can present currency exchange rate and
convertibility, inflation and repatriation risk. In certain conditions under
which we develop or acquire projects, or make investments, economic and monetary
conditions and other factors could affect our ability to convert our earnings
denominated in foreign currencies. In addition, risk from fluctuations in
currency exchange rates can arise when our foreign subsidiaries expend or borrow
funds in one type of currency but receive revenue in another. In such cases, an
adverse change in exchange rates can reduce our ability to meet expenses,
including debt service obligations. Foreign currency risk can also arise when
the revenues received by our foreign subsidiaries are not in U.S. dollars. In
such cases, a strengthening of the U.S. dollar could reduce the amount of cash
and income we receive from these foreign subsidiaries. While we believe we have
hedges and contracts in place to mitigate our most significant foreign currency
exchange risks, our hedges might not be sufficient or we might have some
exposures that are not hedged which could result in losses or volatility in our
revenues.

RISKS RELATED TO LEGAL PROCEEDINGS AND GOVERNMENTAL INVESTIGATIONS

WE MIGHT BE ADVERSELY AFFECTED BY GOVERNMENTAL INVESTIGATIONS AND ANY RELATED
LEGAL PROCEEDINGS RELATED TO THE ALLEGED CONDUCTING OF "ROUNDTRIP" TRADES BY
OUR ENERGY TRADING BUSINESS.

Public and regulatory scrutiny of the energy industry and of the capital
markets has resulted in increased regulation being either proposed or
implemented. In particular, the activities of Enron Corporation and other energy
traders in allegedly using "roundtrip" trades which involve the prearrangement
of simultaneously executed and offsetting buy and sell trades for the purpose of
increasing reported revenues or trading volumes, or influencing prices and which
lack a legitimate business purpose, have resulted in increased public and
regulatory scrutiny. To date, we have responded to requests for information from
the FERC and the SEC, related to an investigation of "roundtrip" energy
transactions from January 2000 to the present. We also have received and are
responding to subpoenas and supplemental requests for information regarding gas
and power trading activities from the Houston office of the U.S. Attorney
relating to a Houston grand jury inquiry, which involve the same issues and time
period covered by the SEC requests, and from the Commodity Futures Trading
Commission (CFTC).

Such inquiries are ongoing and continue to adversely affect the energy
trading business as a whole. We might see these adverse effects continue as a
result of the uncertainty of these ongoing inquiries or additional inquiries by
other federal or state regulatory agencies. In addition, we cannot predict the
outcome of any of these inquiries, including the grand jury inquiry, or whether
these inquiries will lead to additional legal proceedings against us, civil or
criminal fines or penalties, or other regulatory action, including legislation,
which might be materially adverse to the operation of our trading business and
our trading revenues and net income or increase our operating costs in other
ways.

WE MIGHT BE ADVERSELY AFFECTED BY GOVERNMENTAL INVESTIGATIONS RELATED TO
PRICING INFORMATION THAT WE PROVIDED TO MARKET PUBLICATIONS.

On October 25, 2002, we disclosed that inaccurate pricing information had
been provided to energy industry trade publications. This disclosure came as a
result of an internal review conducted in conjunction with requests for
information made by the FERC and the CFTC on energy trading practices. We had
separately commenced a review of our historical survey publication data after
another market participant announced in September 2002 that certain of its
employees had provided inaccurate pricing data to publications. Later we
received a subpoena from a federal grand jury regarding the same matters. We
cannot predict the outcome of this investigation or whether this investigation
will lead to additional legal proceedings against us, civil or criminal fines or
penalties, or other regulatory action, including legislation, which MIGHT be
materially adverse to the operation of our trading business and our trading
revenues and net income or increase our operating costs in other ways.

37

WE MIGHT BE ADVERSELY AFFECTED BY OTHER LEGAL PROCEEDINGS AND GOVERNMENTAL
INVESTIGATIONS RELATED TO THE ENERGY MARKETING AND TRADING BUSINESS.

Electricity and natural gas markets in California and elsewhere will
continue to be subject to numerous and far-reaching federal and state
proceedings and investigations because of allegations that wholesale price
increases resulted from the exercise of market power and collusion of the power
generators and sellers such as Energy Marketing & Trading. Discussions by
governmental authorities and representatives in California and other states have
ranged from threats of re-regulation to suspension of plans to move forward
towards deregulation. The outcomes of these proceedings and investigations might
directly or indirectly affect our creditworthiness and ability to perform our
contractual obligations as well as other market participants' creditworthiness
and their ability to perform of their contractual obligations.

RISKS RELATED TO THE REGULATION OF OUR BUSINESSES

OUR BUSINESSES ARE SUBJECT TO COMPLEX GOVERNMENT REGULATIONS. THE OPERATION OF
OUR BUSINESSES MIGHT BE ADVERSELY AFFECTED BY CHANGES IN THESE REGULATIONS OR
IN THEIR INTERPRETATION OR IMPLEMENTATION.

Existing regulations might be revised or reinterpreted, new laws and
regulations might be adopted or become applicable to us or our facilities, and
future changes in laws and regulations might have a detrimental effect on our
business. Certain restructured markets have recently experienced supply problems
and price volatility. These supply problems and volatility have been the subject
of a significant amount of press coverage, much of which has been critical of
the restructuring initiatives. In some of these markets, including California,
proposals have been made by governmental agencies and other interested parties
to re-regulate areas of these markets which have previously been deregulated. We
cannot assure you that other proposals to re-regulate will not be made or that
legislative or other attention to the electric power restructuring process will
not cause the deregulation process to be delayed or reversed. If the current
trend towards competitive restructuring of the wholesale and retail power
markets is reversed, discontinued or delayed, our business models might be
inaccurate and we might face difficulty in accessing capital to refinance our
debt and funding for operating and generating revenues in accordance with our
current business plans.

For example, in 2000, the FERC issued Order 637, which sets forth revisions
to its policies governing the regulation of interstate natural gas pipelines
that it finds necessary to adjust its current regulatory model to the needs of
evolving markets. The FERC, however, determined that any fundamental changes to
its regulatory policy will be considered after further study and evaluation of
the evolving marketplace. Order 637 revised the FERC's pricing policy to waive
through September 30, 2002 the maximum price ceilings for short-term releases of
capacity of less than one year and to permit pipelines to file proposals to
implement seasonal rates for short-term services and term-differentiated rates.
Certain parties requested rehearing of Order 637 and eventually appealed certain
issues to the District of Columbia Circuit Court of Appeals. The D.C. Circuit
remanded as to certain issues, and on October 31, 2002, the FERC issued its
order on remand. Rehearing requests for that order are now pending with the
FERC. Given the extent of the FERC's regulatory power, we cannot give any
assurance regarding the likely regulations under which we will operate our
natural gas transmission and storage business in the future or the effect of
regulation on our financial position and results of operations.

The FERC has proposed to broaden its regulations that restrict relations
between our jurisdictional natural gas companies, or "jurisdictional companies,"
and our marketing affiliates. In addition, the proposed rules would limit
communications between each of our jurisdictional companies and all of our other
companies engaged in energy activities. The rulemaking is pending at the FERC
and the precise scope and effect of the rule is unclear. If adopted as proposed,
the rule could adversely affect our ability to coordinate and manage our energy
activities.

38

OUR REVENUES MIGHT DECREASE IF WE ARE UNABLE TO GAIN ADEQUATE, RELIABLE AND
AFFORDABLE ACCESS TO TRANSMISSION AND DISTRIBUTION ASSETS DUE TO THE FERC AND
REGIONAL REGULATION OF WHOLESALE MARKET TRANSACTIONS FOR ELECTRICITY AND GAS.

We depend on transmission and distribution facilities owned and operated by
utilities and other energy companies to deliver the electricity and natural gas
we buy and sell in the wholesale market. If transmission is disrupted, if
capacity is inadequate, or if credit requirements or rates of such utilities or
energy companies are increased, our ability to sell and deliver products might
be hindered. The FERC has issued power transmission regulations that require
wholesale electric transmission services to be offered on an open-access, non-
discriminatory basis. Although these regulations are designed to encourage
competition in wholesale market transactions for electricity, some companies
have failed to provide fair and equal access to their transmission systems or
have not provided sufficient transmission capacity to enable other companies to
transmit electric power. We cannot predict whether and to what extent the
industry will comply with these initiatives, or whether the regulations will
fully accomplish the FERC'S objectives.

In addition, the independent system operators who oversee the transmission
systems in regional power markets, such as California, have in the past been
authorized to impose, and might continue to impose, price limitations and other
mechanisms to address volatility in the power markets. These types of price
limitations and other mechanisms might adversely impact the profitability of our
wholesale power marketing and trading. Given the extreme volatility and lack of
meaningful long-term price history in many of these markets and the imposition
of price limitations by regulators, independent system operators or other marker
operators, we can offer no assurance that we will be able to operate profitably
in all wholesale power markets.

THE DIFFERENT REGIONAL POWER MARKETS IN WHICH WE COMPETE OR WILL COMPETE IN
THE FUTURE HAVE CHANGING REGULATORY STRUCTURES, WHICH COULD AFFECT OUR GROWTH
AND PERFORMANCE IN THESE REGIONS.

Our results are likely to be affected by differences in the market and
transmission regulatory structures in various regional power markets. Problems
or delays that might arise in the formation and operation of new regional
transmission organizations (RTOs) might restrict our ability to sell power
produced by our generating capacity to certain markets if there is insufficient
transmission capacity otherwise available. The rules governing the various
regional power markets might also change from time to time which could affect
our costs or revenues. Because it remains unclear which Companies will be
participating in the various regional power markets, or how RTOs will develop or
what regions they will cover, we are unable to assess fully the impact that
these power markets might have on our business.

Problems that might arise in the formation and operation of new RTOs might
result in delayed or disputed collection of revenues. The rules governing the
various regional power markets might also change from time to time which could
affect our costs or revenues. Because it remains unclear which companies will be
participating in the various regional power markets, or how RTOs will develop or
what regions they will cover, we are unable to assess fully the impact that
these power markets might have on our business.

OUR GAS SALES, TRANSMISSION, AND STORAGE OPERATIONS ARE SUBJECT TO GOVERNMENT
REGULATIONS AND RATE PROCEEDINGS THAT COULD HAVE AN ADVERSE IMPACT ON OUR
ABILITY TO RECOVER THE COSTS OF OPERATING OUR PIPELINE FACILITIES.

Our interstate gas sales, transmission, and storage operations conducted
through our Gas Pipelines business are subject to the FERC's rules and
regulations in accordance with the Natural Gas Act of 1938 and the Natural Gas
Policy Act of 1978. The FERC's regulatory authority extends to:

- transportation and sale for resale of natural gas in interstate commerce;

- rates and charges;

- construction;

- acquisition, extension or abandonment of services or facilities;

- accounts and records;

39

- depreciation and amortization policies; and

- operating terms and conditions of service.

The FERC has taken certain actions to strengthen market forces in the
natural gas pipeline industry that has led to increased competition throughout
the industry. In a number of key markets, interstate pipelines are now facing
competitive pressure from other major pipeline systems, enabling local
distribution companies and end users to choose a transmission provider based on
economic and other considerations.

RISKS RELATED TO ENVIRONMENTAL MATTERS

WE COULD INCUR MATERIAL LOSSES IF WE ARE HELD LIABLE FOR THE ENVIRONMENTAL
CONDITION OF ANY OF OUR ASSETS.

We are generally responsible for all on-site liabilities associated with
the environmental condition of our facilities and assets, which we have acquired
or developed, regardless of when the liabilities arose and whether they are
known or unknown. In addition, in connection with certain acquisitions and sales
of assets, we might obtain, or be required to provide, indemnification against
certain environmental liabilities. If we incur a material liability, or the
other party to a transaction fails to meet its indemnification obligations to
us, we could suffer material losses.

ENVIRONMENTAL REGULATION AND LIABILITY RELATING TO OUR BUSINESS WILL BE
SUBJECT TO ENVIRONMENTAL LEGISLATION IN ALL JURISDICTIONS IN, WHICH IT
OPERATES, AND ANY CHANGES IN SUCH LEGISLATION COULD NEGATIVELY AFFECT OUR
RESULTS OF OPERATIONS.

Our operations are subject to extensive environmental regulation pursuant
to a variety of federal, provincial, state and municipal laws and regulations.
Such environmental legislation imposes, among other things, restrictions,
liabilities and obligations in connection with the generation, handling, use,
storage, transportation, treatment and disposal of hazardous substances and
waste and in connection with spills, releases and emissions of various
substances into the environment. Environmental legislation also requires that
our facilities, sites and other properties associated with our operations be
operated, maintained, abandoned and reclaimed to the satisfaction of applicable
regulatory authorities. Existing environmental regulations could also be revised
or reinterpreted, new laws and regulations could be adopted or become applicable
to us or our facilities, and future changes in environmental laws and
regulations could occur. The federal government and several states recently have
proposed increased environmental regulation of many industrial activities,
including increased regulation of air quality, water quality and solid waste
management.

Compliance with environmental legislation will require significant
expenditures, including expenditures for compliance with the Clean Air Act and
similar legislation, for clean up costs and damages arising out of contaminated
properties, and for failure to comply with environmental legislation and
regulations which might result in the imposition of fines and penalties. The
steps we take to bring certain of our facilities into compliance could be
prohibitively expensive, and we might be required to shut down or alter the
operation of those facilities, which might cause us to incur losses.

Further, our regulatory rate structure and our contracts with clients might
not necessarily allow us to recover capital costs we incur to comply with new
environmental regulations. Also, we might not be able to obtain or maintain from
time to time all required environmental regulatory approvals for certain
development projects. If there is a delay in obtaining any required
environmental regulatory approvals or if we fail to obtain and comply with them,
the operation of our facilities could be prevented or become subject to
additional costs. Should we fail to comply with all applicable environmental
laws, we might be subject to penalties and fines imposed against us by
regulatory authorities. Although we do not expect that the costs of complying
with current environmental legislation will have a material adverse effect on
our financial condition or results of operations, no assurance can be made that
the costs of complying with environmental legislation in the future will not
have such an effect.

40

RISKS RELATING TO ACCOUNTING POLICY

POTENTIAL CHANGES IN ACCOUNTING STANDARDS MIGHT CAUSE US TO REVISE OUR
FINANCIAL DISCLOSURE IN THE FUTURE, WHICH MIGHT CHANGE THE WAY ANALYSTS
MEASURE OUR BUSINESS OR FINANCIAL PERFORMANCE.

Recently discovered accounting irregularities in various industries have
forced regulators and legislators to take a renewed look at accounting
practices, financial disclosures, companies' relationships with their
independent auditors and retirement plan practices. Because it is still unclear
what laws or regulations will develop, we cannot predict the ultimate impact of
any future changes in accounting regulations or practices in general with
respect to public companies or the energy industry or in our operations
specifically.

In addition, the Financial Accounting Standards Board (FASB) or the SEC
could enact new accounting standards that might impact how we are required to
record revenues, expenses, assets and liabilities. For instance, Statement of
Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement
Obligations," which we will implement effective on January 1, 2003, 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 can be
made. See Note 1 to our Consolidated Financial Statements for further details.

In October 2002, the FASBs Emerging Issues Task Force (EITF) reached
consensus on Issue No. 02-03 deliberations and rescinded Issue No. 98-10. As a
result, all energy trading contracts that do not meet the definition of a
derivative under SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities," will be reported on an accrual basis.

We will initially apply the consensus effective January 1, 2003, and expect
to record a reduction to net income of approximately $750 million to $800
million on an after-tax basis which will be reported as a cumulative effect of a
change in accounting principle.

The accounting for Energy Marketing & Trading's energy-related contracts,
which include contracts such as transportation, storage, load serving and
tolling agreements, requires us to assess whether certain of these contracts are
executory service arrangements or leases pursuant to SFAS No. 13, "Accounting
for Leases." On January 23, 2003, the EITF reached a tentative consensus on
Issue No. 01-8, "Determining Whether an Arrangement Contains a Lease," and
directed the Working Group consider this Issue to further address certain
matters, including transition. The March 14, 2003 report of the Working Group
indicates the Working Group will support a prospective transition of this Issue,
where the consensus could be applied to our arrangements consummated or
substantively modified after the date of the final consensus.

Our preliminary review indicates that certain of our tolling agreements
could be considered to be leases under the tentative consensus. Accordingly, if
the EITF did not adopt a prospective transition and applied the consensus to
existing arrangements there would be a significant negative impact to Williams'
financial position and results of operations. Other future changes in accounting
standards could lead to negative impacts on reported earnings or increases in
liabilities, which in turn could affect our reported results of operations.

RISKS RELATING TO OUR INDUSTRY

THE LONG-TERM FINANCIAL CONDITION OF OUR U.S. AND CANADIAN NATURAL GAS
TRANSMISSION AND MIDSTREAM BUSINESSES ARE DEPENDENT ON THE CONTINUED
AVAILABILITY OF NATURAL GAS RESERVES.

The development of additional natural gas reserves requires significant
capital expenditures by others for exploration and development drilling and the
installation of production, gathering, storage, transportation and other
facilities that permit natural gas to be produced and delivered to our pipeline
systems. Low prices for natural gas, regulatory limitations, or the lack of
available capital for these projects could adversely affect the development of
additional reserves and production, gathering, storage and pipeline transmission
and import and export of natural gas supplies. Additional natural gas reserves
might not be developed in commercial quantities and in sufficient amounts to
fill the capacities of our gathering and processing pipeline facilities.

41

OUR GATHERING, PROCESSING AND TRANSPORTING ACTIVITIES INVOLVE NUMEROUS RISKS
THAT MIGHT RESULT IN ACCIDENTS AND OTHER OPERATING RISKS AND COSTS.

There are inherent in our gas gathering, processing and transporting
properties a variety of hazards and operating risks, such as leaks, explosions
and mechanical problems that could cause substantial financial losses. In
addition, these risks could result in loss of human life, significant damage to
property, environmental pollution, impairment of our operations and substantial
losses to us. In accordance with customary industry practice, we maintain
insurance against some, but not all, of these risks and losses. The occurrence
of any of these events not fully covered by insurance could have a material
adverse effect on our financial position and results of operations. The location
of pipelines near populated areas, including residential areas, commercial
business centers and industrial sites, could increase the level of damages
resulting from these risks.

OTHER RISKS

RECENT TERRORIST ACTIVITIES AND THE POTENTIAL FOR MILITARY AND OTHER ACTIONS
COULD ADVERSELY AFFECT OUR BUSINESS.

The continued threat of terrorism and the impact of retaliatory military
and other action by the United States and its allies might lead to increased
political, economic and financial market instability and volatility in prices
for natural gas, which could affect the market for our gas operations. In
addition, future acts of terrorism could be directed against companies operating
in the United States, and it has been reported that terrorists might be
targeting domestic energy facilities. While we are taking steps that we believe
are appropriate to increase the security of our energy assets, there is no
assurance that we can completely secure our assets or to completely protect them
against a terrorist attack. These developments have subjected our operations to
increased risks and, depending on their ultimate magnitude, could have a
material adverse effect on our business. In particular, we might experience
increased capital or operating costs to implement increased security for our
energy assets.

The insurance industry has also been disrupted by these events. As a
result, the availability of insurance covering risks that we and our competitors
typically insure against might decrease. In addition, the insurance that we are
able to obtain might have higher deductibles, higher premiums and more
restrictive policy terms.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

See Note 19 of our Notes to Consolidated Financial Statements for amounts
of revenues during the last two fiscal years from external customers
attributable to the United States and all foreign countries. See Note 19 of our
Notes to Consolidated Financial Statements for information relating to
long-lived assets during the last three fiscal years, other than financial
instruments, long-term customer relationships of a financial institution,
mortgage and other servicing rights and deferred policy acquisition costs,
located in the United States and all foreign countries. See Item 1 -- Forward
Looking Statements/Risk Factors and Cautionary Statement for a description of
the risks attendant to our foreign operations and any dependence on one or more
of our segments upon such foreign operations.

ITEM 3. LEGAL PROCEEDINGS

For information regarding certain proceedings pending before federal
regulatory agencies, see Note 16 of our Notes to Consolidated Financial
Statements. We are also subject to other ordinary routine litigation incidental
to our 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

42

of any such remediation will depend upon the scope of the remediation. At
December 31, 2002, these subsidiaries had accrued liabilities totaling
approximately $31 million for these costs related to these sites.

Certain of our 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, we do 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 and Texas Gas have identified polychlorinated biphenyl
contamination in compressor systems, soils and related properties at certain
compressor station sites. Transco and Texas Gas have entered into consent orders
with the EPA and state agencies to develop screening, sampling and cleanup
programs. As of December 31, 2002, much of the work required by such consent
orders had been completed. 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 Texas Gas and Transco. 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 addition to our gas pipelines, we have also accrued environmental
remediation costs for our 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 2002, an arbitrator determined
that our subsidiary must pay $2.8 million in damages to the purchaser of certain
marketing facilities. Settlement discussions with that purchaser have commenced.
In addition, we own a discontinued petroleum refining facility that is being
evaluated for potential remediation efforts. At December 31, 2002, Midstream Gas
& Liquids and Petroleum Services had accrued liabilities totaling approximately
$51 million for these cost. We accrue 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, 2002, we have accrued receivables totaling
$1 million.

In connection with the 1987 sale of the assets of Agrico Chemical Company,
we agreed to indemnify the purchaser for environmental cleanup costs resulting
from certain conditions at specified locations, to the extent such costs exceed
a specified amount. At December 31, 2002, we had approximately $9 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 our 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, we furnished our response.

In 2002, Williams Refining & Marketing, LLC (Williams Refining) submitted
to the EPA a self-disclosure letter indicating noncompliance with the EPA's
benzene waste "NESHAP" regulations. This unintentional noncompliance had
occurred due to a regulatory interpretation that resulted in under-counting the
total annual benzene level at the Memphis refinery. Also in 2002, the EPA
conducted an all-media audit of the Memphis refinery. The EPA anticipates
releasing a report of its audit findings in mid-2003. The EPA will likely assess
a penalty on Williams Refining due to the benzene waste NESHAP issue, but the
amount of any such penalty is not known. On March 4, 2003, we completed the sale
of the Memphis refinery. We are obligated to indemnify the purchaser for any
such penalty.

In 2002, the Memphis/Selby County Health Department (MSCHD) assessed a
$100,000 penalty on Williams Refining due to a four-day period in 2001 within
which Williams Refining allegedly released excess emissions of sulfur dioxide.
Negotiations with the MSCHD are ongoing.

43

In 2002, Williams Field Services Company (WFSC) submitted to the Oklahoma
Department of Environmental Quality (ODEQ) with a WFSC gas processing facility's
air permit. This unintentional noncompliance had occurred due to operational
difficulties with the facility's flare. WFSC is in negotiations with ODEQ, and
the amount of any penalty that ODEQ may assess to WFSC is not known.

OTHER LEGAL MATTERS

In connection with agreements to resolve take-or-pay and other contract
claims and to amend gas purchase contracts, our subsidiaries 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 has been sued by certain producers seeking indemnification
from Transco. Transco is currently defending two lawsuits in which producers
have asserted damages, including interest calculated through December 31, 2002,
of approximately $18 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 FERC Order 528.

On June 8, 2001, 14 of our 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 January 2002, most of the Williams
defendants, along with a group of Coordinating Defendants, filed a motion to
dismiss for lack of personal jurisdiction. On August 19, 2002, the defendants'
motion to dismiss on non-jurisdictional grounds was denied. In the fourth
quarter 2002, the plaintiffs moved for certification of a plaintiffs' class. The
Williams entities joined with other defendants in contesting certification of
the class.

In 1998, the DOJ informed us 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 us and certain of our 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 our 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 us,
to the United States District Court for the District of Wyoming for pre-trial
purposes. In October 2002, the court granted the United States' motion to
dismiss Grynberg's royalty valuation claims. Grynberg's measurement claims are
not affected by the dismissal.

Between November 2000 and May 2001, class actions were filed on behalf of
California electric ratepayers against California power generators and traders
including Energy Marketing & Trading. 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. As part of a comprehensive settlement with the state of
California and other parties, we and the plaintiffs in these suits have resolved
these claims. While the settlement is final as to the state of California, it
must still be approved by the San Diego Superior Court

44

as to the ratepayer plaintiffs. Numerous other federal investigations regarding
California power prices are also underway that involve Energy Marketing &
Trading.

Since January 29, 2002, numerous shareholder class action suits have been
filed in the United States District Court for the Northern District of Oklahoma.
The majority of the suits allege that we and our co-defendants, Williams
Communications and certain corporate officers and directors, 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 us, certain of
our corporate officers, all members of our board of directors and all of the
offerings' underwriters. In addition, in 2002 class action complaints were filed
in the United States District Court for the Northern District of Oklahoma
against us and the members of our board of directors under the Employee
Retirement Income Security Act by participants in our 401(k) plan based on
similar allegations. We and other defendants have filed motions to dismiss each
of these suits. Oral argument on the motions will be held in April 2003.

Our subsidiary Williams Alaska Petroleum (WAPI) is actively engaged in
administrative litigation being conducted jointly by the FERC and the Regulatory
Commission of Alaska concerning the Trans-Alaska Pipeline System (TAPS) Quality
Bank. Primary issues being litigated include the appropriate valuation of the
naphtha, heavy distillate, vacuum gas oil and residual product cuts within the
TAPS Quality Bank as well as the appropriate retroactive effects of the
determinations. WAPI's interest in these proceedings is material as the matter
involves claims by crude producers and the State of Alaska for retroactive
payments plus interest from WAPI in the range of $150 million to $200 million in
aggregate. Because of the complexity of the issues involved, however, the
outcome cannot be predicted within certainty nor can the likely result be
quantified.

SUMMARY

While no assurances may be given, we, based on advice of counsel, do 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 our future financial position, results of operations or cash flow
requirements.

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

None.

ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

The name, age, period of service, and title of each of the executive
officers of Williams as of February 28, 2003, are listed below.

ALAN S. ARMSTRONG.............. Senior Vice President, Midstream Gas & Liquids
Age: 40
Position held since February 2002
From 1999 to February 2002, Mr. Armstrong was Vice
President, Gathering and Processing for Midstream. From 1998
to 1999 he was Vice President, Commercial Development for
Midstream Gas & Liquids.
JAMES J. BENDER................ Senior Vice President and General Counsel
Age 46
Position held since December 16, 2002
Prior to joining Williams, Mr. Bender was Senior Vice
President and General Counsel with NRG Energy, Inc., a
position held since June 2000, prior to which he had been
Vice President, General Counsel and Secretary of NRG Energy
Inc. since June 1997.

45

GARY R. BELITZ................. Acting Chief Financial Officer, Controller and Chief
Accounting Officer
Age: 53
Position Held since December 2002
Mr. Belitz was named Acting Chief Financial Officer on
December 31, 2002. Prior to that, he has been Controller of
the Company since January 1, 1992 and Chief Accounting
Officer since May 1994.
RALPH A. HILL.................. Senior Vice President, Exploration and Production
Age: 43
Position held since December 1998
Mr. Hill was vice president of the exploration and
productions unit from 1993 to 1998.
WILLIAM E. HOBBS............... Senior Vice President, Energy Marketing & Trading
Age: 43
Position held since October 2002
From February 2000 to October 2002, Mr. Hobbs was President
and Chief Executive Officer of Williams Energy Marketing &
Trading. From 1997 to February 2000, he served as a Vice
President of various Williams subsidiaries.
MICHAEL P. JOHNSON, SR......... Senior Vice President, Strategic Services and Administration
Age: 55
Position held since April 1999
Mr. Johnson was named Senior Vice President of Human
Resources and Administration for Williams in April 1999.
Prior to joining Williams in December 1998, he held officer
level positions, such as Vice President of Human Resources,
Vice President for Corporate People Strategies, and Vice
President Human Resource Services, for Amoco Corporation
from 1991-1998.
STEVEN J. MALCOLM.............. Chief Executive Officer and President of Williams
Age: 54
Position held since September 21, 2001
Mr. Malcolm was elected Chief Executive Officer of Williams
in January 2002 and Chairman of the Board in May 2002. He
was elected President and Chief Operating Officer of
Williams in September 2001. Prior to that, he was an
Executive Vice President of Williams since May 2001,
President and Chief Executive Officer of Williams Energy
Services, LLC, a subsidiary of Williams, since December 1998
and the Senior Vice President and General Manager of
Williams Field Services Company, a subsidiary of Williams,
since November 1994.
J. DOUGLAS WHISENANT........... Senior Vice President, Gas Pipeline
Age: 56
Position held since October 2002
From December 2001 to October 2002, Mr. Whisenant was
President of Williams Gas Pipeline, a subsidiary of the
Company. Prior to that, he served as Senior Vice President
and General Manager of Williams Gas Pipeline -- West from
1997 to December 2001.
MARK D. WILSON................. Senior Vice President, Corporate Development & Planning
Age: 36
Position held since October 2002
Mr. Wilson was Vice President of Corporate Development for
Williams from December 2000 to October 2002. Prior to
joining Williams, Mr. Wilson served as Senior Vice
President -- Corporate Development for Koch Petroleum Group
at Koch Industries from 1997 to 2000. From 1992 to 1997, he
served as a management consultant to the energy industry at
Arthur D. Little, Inc. and Booz-Allen & Hamilton, Inc. where
he led teams in mergers and acquisitions, strategy
development, change management and process improvement.

46

PHILLIP D. WRIGHT.............. Senior Vice President and Chief Restructuring Officer
Age: 47
Position held since October 2002
From September 2001 to October 2002, Mr. Wright served as
President and Chief Executive Officer of Williams Energy
Services. From 1996 until September 2001, he was Senior Vice
President, Enterprise Development and Planning for Williams'
energy services group. Mr. Wright has held various positions
within Williams since 1989.

PART II

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

Our common stock is listed on the New York Stock Exchange and Pacific Stock
Exchanges under the symbol "WMB." At the close of business on March 14, 2003, we
had approximately 14,590 holders of record of our common stock and approximately
175,000 beneficial owners that hold in street name. 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:

Some of our subsidiaries' borrowing arrangements limit transfer of funds to
us. These terms have not impeded, nor are they expected to impede, our ability
to pay dividends. However, our secured credit facility currently prohibits us
from paying cash dividends on common stock in excess of $6,250,000 per fiscal
quarter.

Preferred Stock Issuance:

Securities: On March 7, 2002, we sold 1,466,667 shares of
9 7/8% Cumulative Convertible Preferred Stock
(9 7/8% Preferred Stock), par value $1.00 per
share.

Purchaser: MEHC Investment, Inc.

Consideration: $187.50 per share less fees of $2,750,000.

Terms of conversion: Each share of 9 7/8% Preferred Stock may be
converted at any time, at the option of the
holder into the number of fully-paid and non-
assessable shares of common stock obtained by
dividing the Stated Value (originally $187.50
per share) by the Conversion Price then in
effect (originally $18.75 per share).

On or after March 27, 2017, we may, by giving
notice to the holders of the 9 7/8% Preferred
Stock, convert each share of 9 7/8% Preferred
Stock held by such holder into the number of
shares of common stock equal to the Stated
Value plus all accrued and unpaid dividends to
the date of conversion divided by the
Conversion Price then in effect; provided that
in order to be allowed to exercise this right
to compel mandatory conversion, the average of
the last reported closing prices for the common
stock for the 20 day period ending not more
than 10 days prior to the date of

47

the giving of the mandatory notice must be
greater than 128% of the Conversion Price then
in effect.

Exemption from
Registration Claimed: We claim exemption from registration under
Section 4(2) of the Securities Act of 1933 as a
private placement.

48

ITEM 6. SELECTED FINANCIAL DATA

The following financial data as of December 31, 2002 and 2001 and for the
three years ended December 31, 2002 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 of Notes to
Consolidated Financial Statements in Item 8). 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 of this report.

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

(1) See Note 3 of Notes to Consolidated Financial Statements for discussion of
write-downs of certain assets related to Williams Communications Group, Inc.
(WCG) in 2002 and 2001 and see Note 4 of Notes to Consolidated Financial
Statements for discussion of asset sales, impairments and other accruals in
2002, 2001 and 2000.

(2) See Note 2 of Notes to Consolidated Financial Statements for the discussion
of the 2002, 2001 and 2000 losses from discontinued operations. The income
(loss) from discontinued operations for 1999 and 1998 relates to the
operations of WCG, Kern River Gas Transmission, Williams Gas Pipelines
Central, the Colorado soda ash mining operations, Mid-America and Seminole
pipelines, retail travel centers, bio-energy operations and Midsouth
refinery.

(3) The extraordinary gain for 1999 relates to the sale of Williams' retail
propane business, Thermogas L.L.C. The extraordinary loss for 1998 relates
to redemption of higher interest rate debt.

(4) Stockholders' equity for 2001 includes the January 2001 common stock
issuance (see Note 13), the issuance of common stock for the Barrett
acquisition and the impact to Williams of the WCG spinoff (see Note 2).
Stockholders' equity for 1999 includes the issuance of WCG's common stock.

49

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

OVERVIEW OF THE YEAR 2002

In 2002, Williams faced many challenges including credit and liquidity
constraints following the deterioration of our energy industry sector in the
wake of the Enron collapse and the assumption of payment obligations and
performance on guarantees associated with its former telecommunications
subsidiary, Williams Communications Group, Inc. (WCG). With the deterioration of
the energy industry, the credit rating agencies' requirements for investment
grade companies became more stringent. Williams' credit rating was lowered below
an investment grade rating in the middle of 2002. During 2002 and more recently,
Williams has sold a significant amount of assets and/or businesses and outlined
plans to sell more assets to satisfy maturing debt obligations and strengthen
its short-term liquidity position. In regards to the short-term, Williams, at
December 31, 2002, has maturing notes payable and long-term debt totaling
approximately $3.8 billion (which includes certain contractual fees and deferred
interest associated with an underlying debt) through the first quarter of 2004.
The following discussion outlines in more detail the events of 2002 through the
filing of this Form 10-K and the challenges facing the company.

During December 2001 and first-quarter 2002, Williams announced plans to
strengthen its balance sheet and support retention of its investment grade
ratings. The plans included reducing capital expenditures during the balance of
2002, future sales of assets to generate proceeds to be used to reduce
outstanding debt and the lowering of expenses, in part through an
enhanced-benefit early retirement program which concluded during the second
quarter. Towards these plans and in satisfaction of continued liquidity demands,
Williams completed debt issuances and sold one of its regulated interstate
pipelines. In addition, the company completed a consent agreement on behalf of
the WCG obligations that precluded immediate performance by Williams in the
event of a bankruptcy filing by WCG. In addition, the plan included the
elimination of certain "ratings triggers" that would give rise to options to put
or accelerate debt or cause redemption of preferred interests. Exposure to these
ratings triggers was removed by the third quarter of 2002. Williams also had
exposure to ratings triggers through certain contracts of Energy Marketing &
Trading which are discussed under Credit Ratings within Financial Condition and
Liquidity.

During the second quarter of 2002, Williams experienced liquidity
constraints, the effect of which limited Energy Marketing & Trading's ability to
manage market risk and exercise hedging strategies as market liquidity
deteriorated. During May 2002, major rating agencies lowered their credit
ratings on Williams' unsecured long-term debt; however, the ratings remained
investment grade for the balance of the second quarter. Williams announced it
was expanding the scope of its plan to preserve its investment grade ratings,
which included its intentions to offer for sale its two refineries and related
assets, further reduce capital expenditures, scale back the operations of its
Energy Marketing & Trading business and reduce its work force accordingly.

Williams experienced a substantial net loss for the second quarter of 2002.
The loss primarily resulted from a decline in Energy Marketing & Trading's
results and reflected a significant decline in the forward mark-to-market value
of its portfolio, the costs associated with terminated power projects, and the
partial impairment of goodwill reflecting a decline in fair value from the
deteriorating energy merchant market conditions. Williams also recognized asset
impairments and cost write-offs of certain of its assets, in large part a result
of asset sale considerations and terminated projects reflecting a reduced
capital expenditure program. In addition, the board of directors reduced the
common stock dividend for the third quarter from the prior level of $.20 per
share to $.01 per share. In July 2002, the major rating agencies downgraded
Williams' unsecured long-term debt credit ratings to below investment grade,
reflecting the uncertainty associated with the trading business, short-term cash
requirements facing Williams and the increased level of debt the company had
incurred to meet the WCG payment obligations and guarantees. Concurrent with
these events, Williams was unable to complete a renewal of its unsecured
short-term bank facility which expired on July 24, 2002. Subsequently, Williams
and a subsidiary obtained two secured facilities totaling $1.3 billion,
including a letter of credit facility for $400 million and a $900 million
short-term loan (RMT note payable), and amended its existing revolving credit
facility, which expires July 2005, to make it secured. These facilities include
pledges of certain assets and contain financial ratios and other covenants that
must be maintained (see

50

Note 11 of Notes to Consolidated Financial Statements). Included in these
covenants are provisions that limit the ability to incur future indebtedness,
pledge assets and pay dividends on common stock. In addition, debt and related
commitments from banks must be reduced based on proceeds of asset sales and
minimum levels of required current and future liquidity were established. If
such provisions of these facilities are not adhered to, then Williams' lenders
can declare all amounts outstanding to be immediately due and payable.

Also following the credit rating downgrade and in response to a potential
liquidity shortfall, Williams sold certain exploration and production properties
and substantially all of its natural gas liquids pipeline systems, receiving net
cash proceeds of approximately $1.5 billion and resulting in gains on sales of
$443 million ($302 million of which is reflected in discontinued operations).
These actions, combined with the RMT note payable noted previously, provided
proceeds to meet notes payable maturities. Williams also sold certain liquified
natural gas assets for approximately $229 million, its 27 percent ownership
interest in a Lithuanian refinery, pipeline and terminal investment for $85
million and its $75 million note receivable from the Lithuanian investment for
face value. These transactions closed in September. Additionally in 2002,
Williams' board of directors had approved for sale the Central natural gas
pipeline unit, the soda ash mining operations, the Memphis refinery, bio-energy
operations and the travel centers. The sale of Central closed in November 2002.
The sales of the travel centers for $190 million before debt repayments and the
Memphis refinery for $455 million were completed in February and March 2003,
respectively. The remaining assets are expected to be sold in the first half of
2003. Concurrent with Williams' strategy of selling assets to reduce debt,
reviews for impairment were performed on assets that were being considered for
possible sale, including an assessment of the more likely than not probabilities
of sale for each asset. The impairment reviews are updated to incorporate new
information obtained through the maturation of the assets sales process or
closing of a sale. Impairments and losses totaling $814 million on completed
transactions and certain assets held for sale, are reported in discontinued
operations for 2002 and an additional $378 million of impairments or guarantee
loss accruals are reported in continuing operations for 2002. These impairments
reflected management's estimate of the fair value of these assets based on
information available at the time of the respective reviews.

OUTLOOK FOR 2003

On February 20, 2003, Williams outlined its planned business strategy for
the next several years and believes it to be a comprehensive response to the
events which have impacted the energy sector and Williams during 2002. The plan
focuses on retaining a strong, but smaller, portfolio of natural-gas businesses
and bolstering Williams' liquidity through more asset sales, limited levels of
financing at the subsidiary level and additional reductions in its operating
costs. The plan is designed to provide Williams with a clear strategy to address
near-term and medium-term liquidity issues and further de-leverage the company
with the objective of returning to investment grade status by 2005, while
retaining businesses with favorable returns and opportunities for growth in the
future. As part of this plan, Williams expects to generate proceeds, net of
related debt, of nearly $4 billion from asset sales during 2003, including
approximately $2.25 billion in newly announced offerings combined with those
assets already under contract or in negotiations for sale. Newly announced
offerings include the Texas Gas pipeline system, Williams' investment in
Williams Energy Partners, and certain properties and assets within Exploration &
Production and Midstream Gas & Liquids. The specific assets and the timing of
such sales are dependent on various factors, including negotiations with
prospective buyers, regulatory approvals, industry conditions, lender consents
to sales of collateral and the short- and long-term liquidity requirements of
Williams. While management believes it has considered all relevant information
in assessing for potential impairments, the ultimate sales price for assets that
may be sold and the final decisions in the future may result in additional
impairments or losses and/or gains.

FACTORS AFFECTING WILLIAMS' BUSINESS

During 2002, the operating results of Energy Marketing & Trading were
adversely affected by several factors, including Williams' overall liquidity and
credit ratings which impacted Energy Marketing & Trading's ability to enter into
price risk management and hedging activities. The credit rating downgrades in
2002 also triggered certain Energy Marketing & Trading contractual provisions
that require Williams to provide counterparties with adequate assurance, margin,
credit enhancement, or credit replacement. See the Liquidity

51

section for further discussion of what amounts Williams and Energy Marketing &
Trading have provided. During the later half of 2002, several companies in the
energy trading sector announced that they are either reducing commitments to, or
exiting altogether, the energy trading business. These market conditions plus
the unwillingness of existing counterparties and new entrants to the sector to
enter into new business with Energy Marketing & Trading will continue to affect
results in the future and could result in additional operating losses.
Additionally, on October 25, 2002, the Emerging Issues Task Force (EITF)
concluded in Issue No. 02-3, "Issues Related to Accounting for Contracts
Involved in Energy Trading and Risk Management Activities," to rescind Issue No.
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," under which non-derivative energy trading contracts were previously
marked-to-market. As a result, a substantial portion of the Energy Marketing &
Trading activities previously required to be reported on a fair value basis must
now be reflected under the accrual method of accounting beginning January 1,
2003 (see Note 1).

Williams continues its efforts to reduce the risk and liquidity impact of
Energy Marketing & Trading on Williams. Part of these efforts includes the
announced sale of certain portions of its trading portfolio, liquidation of
certain trading positions and negotiations with parties for a joint venture or
sale of all or a large portion of the trading portfolio. It is possible that
Williams, in order to generate levels of liquidity that are needed in the
future, would be willing to accept amounts for all or a portion or its entire
portfolio that are less than its carrying value at December 31, 2002. Although
the results of these negotiations could reduce the presence of the trading
business, Energy Marketing & Trading will continue to be operated to meet the
commitments of its remaining short- and long-term contracts.

At December 31, 2002, Williams has maturing notes payable and long-term
debt totaling approximately $3.8 billion (which includes certain contractual
fees and deferred interest associated with an underlying debt) through the first
quarter of 2004. The Company's available liquidity to meet these requirements
and fund a reduced level of capital expenditures will be dependent on several
factors, including the cash flows of retained businesses, the amount of proceeds
raised from the sale of assets previously mentioned and the price of natural
gas. Future cash flows from operations may also be affected by the timing and
nature of the sale of assets. Because of recent asset sales, anticipated asset
sales and available secured credit facilities, Williams currently believes that
it has the financial resources and liquidity to meet future cash requirements
through the first quarter of 2004. In the event that Williams' financial
condition does not improve or becomes worse, or if it fails to complete asset
sales and reduce its commitment to its Energy Marketing & Trading business,
Williams may have to consider other options including the possibility of seeking
protection in a bankruptcy proceeding.

GENERAL

As a result of assets sales approved or closed during 2002 and in
accordance with the provisions related to discontinued operations within
Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," the following components have been
reported as discontinued operations (see Note 2):

- Kern River Gas Transmission (Kern River), previously one of Gas
Pipeline's segments

- Central natural gas pipeline, previously one of Gas Pipeline's segments

- Colorado soda ash mining operations, part of the previously reported
International segment

- Two natural gas liquids pipeline systems, Mid-American Pipeline and
Seminole Pipeline, previously part of the Midstream Gas & Liquids segment

- Refining and marketing operations in the Midsouth, including the Midsouth
refinery, previously part of the Petroleum Services segment

- Retail travel centers concentrated in the Midsouth, previously part of
the Petroleum Services segment

- Bio-energy operations, previously part of the Petroleum Services segment

52

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.

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 within Item 8. All
prior period information has been restated to reflect these changes.

CRITICAL ACCOUNTING POLICIES & ESTIMATES

Our financial statements reflect the selection and application of
accounting policies which require management to make significant estimates and
assumptions. The selection of these has been discussed with the company's Audit
Committee and the Audit Committee has reviewed the disclosures that follow. 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.

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
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, 2002, approximately $9 million was recorded as subject to refund, reflecting
management's estimate of amounts invoiced to customers that may ultimately
require refunding. This balance is associated entirely with one of Williams' gas
pipelines as there are no significant rate proceedings currently pending for the
other pipelines. During 2002, rate refund liability accruals were reduced by $87
million as a result of settlements of regulatory proceedings including amounts
refunded to customers. From time to time, 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 risk management and trading operations

Energy Marketing & Trading and the natural gas liquids trading operations
(reported within the Midstream Gas & Liquids segment) have energy risk
management and trading operations that enter into energy and energy-related
contracts to trade with and provide price-risk management services to its
customers. Energy and energy-related contracts utilized in energy risk
management and 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 (marked-to-market). 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 exchange traded or over-the-counter markets where quoted prices in
active markets may exist. Transactions are also executed in exchange-traded or
over-the-counter markets for which market prices may exist, however, the market
may be relatively inactive and price transparency is limited. Hence, the ability
to determine the fair value of the contract would be more subjective than if an
independent third party quote were available. 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.

53

On October 25, 2002, the (EITF) concluded in Issue No. 02-3 to rescind
Issue No. 98-10, under which non-derivative energy trading contracts were
previously marked-to-market. A substantial portion of the energy marketing and
trading activities previously reported on a fair-value basis will now be
reflected under the accrual method of accounting beginning January 1, 2003. In
addition, trading inventories will also no longer be marked to market but will
be reported on a lower of cost or market basis. Upon adoption of this new
standard on January 1, 2003, Energy Marketing & Trading and the natural gas
liquids trading operations (reported within the Midstream Gas & Liquids segment)
will record a charge as a cumulative effect of change in accounting principle.
The impact of this change in accounting principle is expected to result in a
decrease to net income of approximately $750 million to $800 million in total on
an after-tax basis for both business units. For further discussion on this
issue, please refer to Note 1 of Notes to Consolidated Financial Statements.

Accounting for Energy Marketing & Trading's energy-related contracts, which
include contracts such as transportation, storage, load serving, and tolling
agreements, requires Williams to assess whether certain of these contracts are
executory service agreements or leases pursuant to SFAS No. 13, "Accounting for
Leases." On January 23, 2003, the EITF reached a tentative consensus on Issue
No. 01-8, "Determining Whether an Arrangement Contains a Lease," and directed
the Working Group it had formed to consider this issue to further address
certain matters, including transition. The March 14, 2003 report of the Working
Group indicates the Working Group supports a prospective transition of this
Issue, where the consensus would be applied to arrangements consummated or
substantively modified after the date of the final consensus. Williams'
preliminary review indicates that certain of its tolling agreements could be
considered to be leases under the tentative consensus. Accordingly, if the EITF
did not adopt a prospective transition and applied the consensus to existing
arrangements there could be a significant impact to Williams' financial position
and results of operations.

As a result of Williams' current liquidity constraints, Energy Marketing &
Trading initiated efforts in 2002 to sell all or portions of its portfolio
and/or pursue potential joint venture or business combination opportunities. No
assurances can be made regarding the ultimate consummation of any sales or
business combination activities currently being pursued. Energy Marketing &
Trading is continuing to evaluate its potential alternatives. As discussed
further in Note 1 of Notes to Consolidated Financial Statements, portions of
Energy Marketing & Trading's portfolio have been recognized at their estimated
fair value, which per generally accepted accounting principles is the amount at
which they could be exchanged in a current transaction between willing parties
other than in a forced liquidation or sale. Given the financial condition and
liquidity constraints of Williams, however, amounts ultimately realized in any
portfolio sales or business combination may be significantly different than fair
value estimates presented in the financial statements.

Additional discussion of the accounting for energy and energy-related
contracts at fair value is included in Note 1 of Notes to Consolidated Financial
Statements and Fair Value of Energy risk management and trading activities.

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, 2002, Williams maintains $43.2 million of valuation
allowances for deferred tax assets from basis differences in investments and
capital loss carry forward generated during the year for which the ultimate
realization of the tax asset may be dependent on the availability of future
capital gains. In arriving at this conclusion, management considered forecasts
of future company performance, particularly the estimated impact of potential
asset dispositions. The ultimate amount of deferred tax assets realized could be
materially different from those recorded, as influenced by potential changes in
federal income laws and the circumstances upon the actual realization of related
tax assets.

54

Impairment of Long-Lived Assets and Goodwill

Williams evaluates the long-lived assets 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 Notes 2 and 4), numerous others were reviewed for which no
impairment was required under a "held for use" computation, pursuant to
Williams' announced strategy of selling assets as a source of funds to meet debt
obligations and provide liquidity. These computations utilized judgments and
assumptions inherent in management's estimate of undiscounted future cash flows
and "hold for use" versus sale probabilities to determine recoverability of an
asset.

Pursuant to Williams' announced strategy during 2002 of selling significant
levels of assets, numerous assets were considered more likely than not to be
sold substantially in advance of their established recovery periods. To
facilitate the actual sales, a reserve price auction process was employed for
many of the assets. This type of process is one in which initial bids are
received by interested parties, followed by submission of revised bids, with the
company eventually selecting a single party in which to finalize a sale
transaction. Under terms of the process, Williams is not obligated to accept an
offer that it does not deem satisfactory. As a result, both the estimated fair
value of an asset and management's assessment of the probability of sale often
change through the course of the process.

At December 31, 2002, certain assets are in various stages of sale
negotiations. With respect to the most significant of these, a ten percent
decrease in estimated fair value would result in additional impairment charges
of approximately $80 million, while a ten percent increase in fair value would
result in a decrease of impairment charges of approximately $70 million.

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.

Goodwill is evaluated annually for impairment. Approximately $1 billion of
Williams' goodwill is carried by Exploration & Production for which the
estimated fair value of the reporting unit exceeds its carrying value, including
goodwill, by over 75 percent.

Contingent Liabilities

Williams records liabilities 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 new or different facts or information become known
or circumstances change that affect the previous assumptions with respect to the
likelihood or amount of loss. Liabilities for contingent losses are based upon
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 liabilities for
contingent losses would be required. See Note 16 of Notes to Consolidated
Financial Statements.

55

RESULTS OF OPERATIONS

CONSOLIDATED OVERVIEW

The following table and discussion is a summary of Williams' consolidated
results of operations for the three years ended December 31, 2002. The results
of operations by segment are discussed in further detail following this
Consolidated Overview discussion.

2002 vs. 2001

CONSOLIDATED OVERVIEW. Williams' revenue decreased $1,457.1 million, or 21
percent, due primarily to lower revenues associated with energy risk management
and trading activities at Energy Marketing & Trading and the absence of $184
million of revenue related to the 198 convenience stores sold in May 2001 within
Petroleum Services. Partially offsetting these decreases was the impact of an
increase in net production volumes within Exploration & Production partly due to
the August 2001 acquisition of Barrett Resources Corporation (Barrett).

Costs and operating expenses decreased $193.1 million, or 5 percent, due
primarily to the absence of the 198 convenience stores sold in May 2001 and
lower fuel and product shrink gas purchases related to processing activities at
Midstream Gas & Liquids. Slightly offsetting these decreases are increased
depletion, depreciation and amortization and lease operating expenses at
Exploration & Production due primarily to the addition of the former Barrett
operations.

Selling, general and administrative expenses decreased $69.1 million due
primarily to lower variable compensation levels at Energy Marketing & Trading.
Selling, general and administrative expenses for 2002 also include approximately
$22 million of early retirement costs, $10 million of employee-related severance
costs and approximately $6 million related to early payoff of employee stock
ownership plan expenses.

Other (income) expense -- net in 2002, that is part of operating income,
includes $244.6 million of impairment charges and loss accruals within Energy
Marketing & Trading comprised of $138.8 million of impairments and loss accruals
for commitments for certain power assets associated with terminated power
projects, $61.1 million goodwill impairments and a $44.7 million impairment
charge related to the Worthington generation facility sold in January 2003. Also
included in other (income) expense -- net in 2002 are

56

$115 million of impairment charges related to Midstream Gas & Liquids' Canadian
assets and $18.4 million of impairment charges within Petroleum Services related
to the Alaska refinery and convenience store assets. Partially offsetting these
impairment charges and accruals are $141.7 million of net gains on sales of
natural gas production properties at Exploration & Production in 2002. Other
(income) expense -- net in 2001 includes a $75.3 million gain on the May 2001
sale of the convenience stores and impairment charges of $13.8 million and $12.1
million within Midstream Gas & Liquids and Petroleum Services, respectively (see
Note 4).

General corporate expenses increased $18.5 million, or 15 percent, due
primarily to approximately $15 million of costs related to consulting services
and legal fees associated with the liquidity and business issues addressed
beginning third-quarter 2002, $6 million of expense related to the
enhanced-benefit early retirement program offered to certain employee groups and
$6 million of expense related to employee severance costs. Partially offsetting
these increases were lower charitable contributions and advertising costs.

Operating income decreased $1,526.9 million, or 66 percent, due primarily
to lower net revenues associated with energy risk management and trading
activities at Energy Marketing & Trading and the impairment charges and loss
accruals noted above. Partially offsetting these decreases are the gains from
the sales of natural gas production properties and the impact of increased net
production volumes at Exploration & Production, higher demand revenues and the
effect of the reductions in rate refund liabilities associated with rate case
settlements at Gas Pipeline, higher natural gas liquids margins at Midstream Gas
& Liquids and higher equity earnings.

Interest accrued -- net increased $518.3 million, or 76 percent, due
primarily to $154 million related to interest expense, including amortization of
fees, on the RMT note payable (see Note 11), the $58 million effect of higher
average interest rates, the $247 million effect of higher average borrowing
levels and $56 million of higher debt issuance cost amortization expense.

In 2002, Williams entered into interest rate swaps with external counter
parties primarily in support of the energy trading portfolio. The swaps resulted
in losses of $124.2 million (see Note 19).

The 2002 investing loss decreased $66.9 million as compared to the 2001
investing loss. Investing loss for 2002 and 2001 consisted of the following
components:

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

* These items are also included in the measure of segment profit (loss).

The equity earnings increase includes a $27.4 million benefit reflecting a
contractual construction completion fee received by an equity method investment
of Williams (see Note 3) and $4 million of earnings in 2002 versus $20 million
of losses in 2001 from the Discovery pipeline project, partially offset by an
equity loss in 2002 of $13.8 million from Williams' investment in Longhorn
Partners Pipeline LP. Income (loss) from investments in 2002 includes a $58.5
million gain on the sale of Williams' equity interest in a Lithuanian oil
refinery, pipeline and terminal complex, which was included in the Other
segment, a gain of $8.7 million related to the sale of Williams' general partner
interest in Northern Borders Partners, L.P., a $12.3 million write-down of an
investment in a pipeline project which was canceled and a $10.4 million net loss
on the sale of Williams' equity interest in a Canadian and U.S. gas pipeline.
Income (loss) from investments in 2001

57

includes a $27.5 million gain on the sale of Williams' limited partner equity
interest in Northern Border Partners, L.P. offset by a $23.3 million loss from
other investments, both which were determined to be other than temporary. See
Note 2 for a discussion of the losses related to WCG. Interest income and other
decreased due to a $22 million decrease in interest income related to margin
deposits, a $4.9 million decrease in dividend income primarily as a result of
the second-quarter 2001 sale of Ferrell gas Partners L.P. senior common units
and write-downs of certain foreign investments.

Other income (expense) -- net below operating income increased $.3 million
due primarily to an $11 million gain in second-quarter 2002 at Gas Pipeline
associated with the disposition of securities received through a mutual
insurance company reorganization, a $14 million decrease in losses from the
sales of receivables to special purpose entities (see Note 15) and the absence
in 2002 of a 2001 $10 million payment to settle a claim for coal royalty
payments relating to a discontinued activity. Partially offsetting these
increases was an $8 million loss related to early retirement of remarketable
notes in first-quarter 2002.

The provision (benefit) for income taxes was favorable by $804.6 million
due primarily to a pre-tax loss in 2002 as compared to pre-tax income in 2001.
The effective income tax rate for 2002 is greater than the federal statutory
rate due primarily to the effect of taxes on foreign operations, non-deductible
impairment of goodwill and income tax credits recapture that reduced the tax
benefit of the pre-tax loss, somewhat offset by the reduction in valuation
allowances. The effective income tax rate for 2001 is greater than the federal
statutory rate due primarily to valuation allowances associated with the tax
benefits for investing losses, for which no tax benefits were provided and the
effect of state income taxes.

In addition to the operating results from activities included in
discontinued operations (see Note 2), the 2002 loss from discontinued operations
includes pre-tax impairments and losses totaling $814.3. million. The $814.3
million consists of $240.8 million of impairments related to the Memphis
refinery, $195.7 million of impairments related to bio-energy, $146.6 million of
impairments related to travel centers, $133.5 million of impairments related to
the soda ash operations, $91.3 million loss on sale related to the Central
natural gas pipeline system and a $6.4 million loss on sale related to the Kern
River natural gas pipeline system. Partially offsetting these impairments and
losses was a pre-tax gain of $301.7 million related to the sale of the Mid-
America and Seminole pipelines. Loss from discontinued operations in 2001
includes a $1.84 billion pre-tax charge for loss accruals related to guarantees
and payment obligations for WCG and $184.7 million of other pre-tax charges for
impairments and loss accruals including a $170 million pre-tax impairment charge
related to the soda ash mining facility.

Income (loss) applicable to common stock in 2002 reflects the impact of the
$69.4 million associated with accounting for a preferred security that contains
a conversion option that was beneficial to the purchaser at the time the
security was issued. The weighted-average number of shares in 2002 for the
diluted calculation (which is the same as the basic calculation due to Williams
reporting a loss from continuing operations -- see Note 6) increased
approximately 16 million from December 31, 2001. The increase is due primarily
to the 29.6 million shares issued in the Barrett acquisition in August 2001. The
increased shares had a dilutive effect on earnings (loss) per share in 2002 of
approximately $.05 per share.

2001 vs. 2000

Consolidated Overview. Williams' revenues increased $506.2 million, or 8
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 natural gas sales prices and revenues
from Barrett acquired in third-quarter 2001. 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 $69 million reduction of Gas
Pipeline's rate refund liabilities.

Total segment costs and expenses increased $98.2 million, or 2 percent, due
primarily to costs for a full year of Canadian operations acquired in
fourth-quarter 2000 and operating costs associated with Barrett acquired in
third-quarter 2001. 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.

58

Operating income increased $380.9 million, or 20 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, 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 $69 million effect in 2000 of reductions
to rate refund liabilities and approximately $26 million of impairment charges
and loss accruals within Midstream Gas & Liquids and Petroleum 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 $75.3 million, or 12 percent, due
primarily to the $71 million effect of higher borrowing levels offset by the $42
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 and a $12 million increase in amortization of debt expense.
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 $257.7 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 2). 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 3). 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 related to margin deposits of $17 million.
Minority interest in income and preferred returns of consolidated subsidiaries
increased $23.9 million, or 42 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
preferred returns related to the second-quarter 2001 redemption of Williams
obligated mandatorily redeemable preferred securities of Trust.

Other income (expense) -- net increased $26.4 million to $26.1 million of
income in 2001 due primarily to an $11 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 15).

The provision for income taxes increased $68.1 million primarily due to
higher pre-tax income and increase in valuation allowance. 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.

In addition to the operating results from the activities included in
discontinued operations (see Note 2), the loss from discontinued operations for
2001 includes a $1.84 billion pre-tax charge for loss accruals for contingent
obligations related to guarantees and payment obligations for WCG, $184.7
million of other pre-tax charges for impairments and loss accruals including a
$170 million pre-tax impairment charge related to the soda ash mining facility.
Loss from discontinued operations in 2000 primarily represents the operating
results of the operations.

59

RESULTS OF OPERATIONS -- SEGMENTS

Williams is currently organized into the following segments: Energy
Marketing & Trading, Gas Pipeline, Exploration & Production, Midstream Gas &
Liquids, Williams Energy Partners and Petroleum Services. Certain activities
previously reported within the International segment have been included in
Other. Williams currently evaluates performance based upon segment profit (loss)
from operations (see Note 19).

In addition to the impact to the segments as a result of discontinued
operations previously discussed, the following changes occurred in 2002:

- Effective July 1, 2002, management of certain operations previously
conducted by Energy Marketing & Trading, International and Petroleum
Services was transferred to Midstream Gas & Liquids. These operations
included natural gas liquids trading, activities in Venezuela and a
petrochemical plant, respectively.

- On April 11, 2002, Williams Energy Partners L.P., a partially owned and
consolidated entity of Williams, acquired Williams Pipe Line, an
operation previously included within the Petroleum Services segment.
Accordingly, Williams Pipe Line's results of operations have been
transferred from the Petroleum Services segment to the Williams Energy
Partners segment.

- Management of an investment in an Argentine oil and gas exploration
company was transferred from the previously reported International
segment to the Exploration & Production segment to align exploration and
production activities.

Prior period amounts have been restated to reflect these changes. The
following discussions relate to the results of operations of Williams' segments.

ENERGY MARKETING & TRADING

2002 vs. 2001

ENERGY MARKETING & TRADING'S revenues decreased $1,790.8 million, or 105
percent, due primarily to a $1,783.3 million decrease in risk management and
trading revenues. During 2002, Energy Marketing & Trading's results were
adversely affected by the impact of market movements against its portfolio as
discussed below and a significant reduction in origination activities. Energy
Marketing & Trading's ability to manage or hedge its portfolio against adverse
market movements was limited by a lack of market liquidity as well as Williams'
limited ability to provide credit and liquidity support.

The $1,783.3 million decrease in risk management and trading revenues is
due primarily to a decrease of $1,901.4 million in the natural gas and power
revenues partially offset by a $6.3 million increase in the petroleum products
revenues, a $12 million increase in European trading revenues, and a $99.8
million increase in revenues from the net impact of interest rate movements
including the impact of interest derivatives. The $1,783.3 million decrease in
the risk management and trading revenues includes a $205 million decrease in
revenues from new transactions originated and contract amendments as compared to
2001. Of the $1,901.4 million decline in natural gas and power revenues, $454.9
million is attributable to a decline in natural gas revenues, caused primarily
by increasing prices on short natural gas positions during the third quarter of
2002. The remaining $1,446.5 million decline relates to lower revenues from the
power portfolio caused primarily by smaller spark spreads on certain power
tolling portfolios and lower volatility (the fair value of Energy Marketing &
Trading's tolling agreements are adversely affected by declines in power and gas
volatility) compared with 2001 as well as the net impact of portfolio valuation
adjustments associated with the decline in market liquidity and portfolio
liquidation activities. The $6.3 million increase in petroleum

60

products revenues is primarily due to origination activities during the first
quarter of 2002. The $12 million increase in European trading revenues is
principally due to the commencement of trading activities in the European office
as compared to start-up activities in 2001. The European operations have now
been reduced and are in the process of being wound down.

As a result of Williams' current liquidity constraints, Energy Marketing &
Trading initiated efforts in 2002 to sell all or portions of its portfolio
and/or pursue potential joint venture or business combination opportunities. No
assurances can be made regarding the ultimate consummation of any sales or
business combination activities currently being pursued. Energy Marketing &
Trading is continuing to pursue its potential alternatives. As discussed further
in Note 1 of the Notes to Consolidated Financial Statements, portions of Energy
Marketing & Trading's portfolio have been recognized at their estimated fair
value, which under generally accepted accounting principles is the amount at
which they could be exchanged in a current transaction between willing parties
other than in a forced liquidation or sale. As a result of information obtained
through the portfolio sales efforts in 2002, the estimated fair value of certain
portions of the portfolio were adjusted to reflect viable market information
received. For those portions of the portfolio for which no viable market
information was received through sales efforts, fair value has been estimated
using other market-based information and consistent application of valuation
techniques. Portfolio valuation adjustments recognized in 2002 as a result of
new market information obtained through sales efforts resulted in a $74.8
million decrease in operating profit. Given the financial condition and
liquidity constraints of Williams which may accelerate sales, amounts ultimately
realized in any portfolio sales or business combination may be significantly
different than fair value estimates presented in the financial statements,
depending on the timing and terms of any such transactions.

Revenues for 2002 also includes a favorable fourth-quarter net effect of
approximately $85 million resulting from a settlement with the state of
California, the restructuring of associated energy contracts, and the related
improved credit situation of the counterparties during the quarter.

Energy Marketing & Trading's future results will be affected by the
reduction in liquidity and credit support available from its parent, the
willingness of counterparties to enter into transactions with Energy Marketing &
Trading, the liquidity of markets in which Energy Marketing & Trading transacts,
and the creditworthiness of other counterparties in the industry and their
ability to perform under contractual obligations. Since Williams is not
currently rated investment grade by credit rating agencies, Williams is
required, in certain instances, to provide additional adequate assurances in the
form of cash or credit support to enter into and maintain existing transactions.
With the decision to continue to limit Williams' financial commitment and
exposure to the trading business, it is likely that Energy Marketing & Trading
will have greater exposure to market movements, which could result in additional
operating losses. In addition, other companies in the energy trading and
marketing sector are experiencing financial difficulties which will affect
Energy Marketing & Trading's credit and default assessment related to the future
value of its forward positions and the ability of such counterparties to perform
under contractual obligations. The ultimate outcome of these items could result
in significant future operating losses for Energy Marketing & Trading or limit
Energy Marketing & Trading's ability to achieve profitable operations.

Selling, general, and administrative expenses decreased by $124.7 million,
or 37 percent. This cost reduction is primarily due to lower variable
compensation levels associated with reduced segment profit and the impact of
staff reductions in this segment.

Other (income) expense -- net in 2002 includes $138.8 million of
impairments and loss accruals associated with commitments for certain power
projects that have been terminated, partial impairment of goodwill totaling
$61.1 million, reflecting a decline in fair value resulting from deteriorating
market conditions during 2002 and a $44.7 million impairment charge related to
the January 2003 sale of the Worthington generation facility. Other (income)
expense -- net in 2001 included $13.3 million due to a terminated expansion
project.

Segment profit (loss) decreased $1,894.8 million, or 149 percent, due
primarily to the $1,783.3 million reduction of risk management and trading
revenues and the other (income) expense -- net items discussed previously,
partially offset by the $124.7 million reduction in selling, general and
administrative expenses,

61

discussed above, and the $23.3 million charge from the write-downs in 2001 of
marketable equity securities and a cost based investment (see Note 3).

On October 25, 2002, the EITF concluded in Issue No. 02-3 to rescind Issue
No. 98-10, under which non-derivative energy trading contracts were
marked-to-market. A substantial portion of the energy marketing and trading
activities previously reported on a fair-value basis will now be reflected under
the accrual method of accounting beginning January 1, 2003. Certain of the
trading activities utilizing derivative instruments will continue to be reported
on a fair value basis to the extent that these instruments are not designated as
hedges under SFAS No. 133. The related changes in fair value will be reported as
unrealized gains or losses in the consolidated income statement. In addition,
trading inventories will no longer be marked-to-market but will be reported on a
lower of cost or market basis. Upon adoption of this new standard on January 1,
2003, Energy Marketing & Trading will record a charge as a cumulative effect of
change in accounting principle. Energy Marketing & Trading's portion of the
impact of this change in accounting principle is expected to be a decrease to
net income of approximately $750 million to $800 million on an after-tax basis.
For further discussion on this issue, please refer to Note 1 of Notes to
Consolidated Financial Statements.

Contingent liabilities and commitments that could affect the results of
Energy Marketing & Trading, including a recent settlement between the FERC and
Transcontinental Gas Pipe Line, Energy Marketing & Trading and Williams are
discussed in Note 16 of the Notes to Consolidated Financial Statements.

2001 vs. 2000

Energy Marketing & Trading's revenues increased by $410.5 million, or 32
percent in 2001, due primarily to a $402.3 million increase in risk management
and trading revenues.

The $402.3 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 15
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. Execution of these contracts had the effect of reducing the
risk of future changes in natural gas and power prices within the portfolio and
also provided further insight into the prices for which third parties would be
willing to exchange in illiquid periods. This additional insight provided better
information for the valuation of other existing contracts which generally had
the effect of increasing the value recognized on these existing contracts.
Subsequent to the 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 was an increase in successful forward natural
gas financial trading.

Through a variety of energy commodity and derivative contracts, Energy
Marketing & Trading had 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 preceding and following
Enron's announced bankruptcy. At December 31, 2001, Williams had reduced its
exposure to accounts receivable from Enron, net of margin deposits, to expected
recoverable amounts. In 2002, Energy Marketing & Trading sold rights to certain
Enron receivables to a third party in exchange for $24.5 million cash. That
amount was recorded as trading revenues in the first quarter of 2002.

Selling, general, and administrative expenses increased by $134.7 million,
or 68 percent. This cost increase was primarily due to $42.5 million higher
variable compensation levels associated with improved
62

operating performance, $19 million of costs related to the European trading and
marketing office in London which began operation in 2001, $13 million of
increased charitable contributions to state universities, as well as increased
outside services costs and increased costs as a result of higher staffing
levels.

Other (income) expense -- net in 2001 includes a $13.3 million impairment
charge due to a terminated expansion project. In 2000, other (income)
expense -- net included $47.5 million in guarantee loss accruals and impairment
charges and $16.3 million impairment of assets related to a distributed
generation business.

Segment profit increased $299.4 million, or 31 percent, due primarily to
the $402.3 million higher trading revenues discussed above and the effect of the
$63.8 million of guarantee loss accruals and impairment charges in 2000 noted
above. Partially offsetting the increase to segment profit was the $134.7
million increase in selling, general and administrative costs, as discussed
above, $23.3 million of write-downs in 2001 of marketable equity securities and
a cost based investment and the $13.3 million impairment in 2001 noted above.

Potential Impact of California Power Regulation and Litigation

At December 31, 2002, Energy Marketing & Trading had net accounts
receivable recorded of approximately $230 million compared to $388 million at
December 31, 2001, for power sales to the California Independent System Operator
and the California Power Exchange Corporation (CPEC). 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. While the amount
recorded reflects management's best estimate of collectibility, future events or
circumstances could change those estimates.

As discussed in Rate and regulatory matters and related litigation in Note
16 of Notes to Consolidated Financial Statements, the FERC and the DOJ have
issued orders or initiated actions that relate to the activities of Energy
Marketing & Trading in California and the western states. 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 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 experienced in 2000 and 2001
resulted from the exercise of market power and collusion of the power generators
and sellers, including Energy Marketing & Trading. These allegations have
resulted in multiple state and federal investigations as well as the filing of
class-action lawsuits in which Energy Marketing & Trading is a named defendant.
Energy Marketing & Trading's long-term power contract with the State of
California has also been challenged both at the FERC and in civil suits. Most of
these initiatives, investigations and proceedings are in their preliminary
stages and their likely outcome cannot be estimated. However, Energy Marketing &
Trading and Williams executed a settlement agreement on November 11, 2002, that
is intended to resolve many of these disputes with the State of California and
that includes renegotiated long-term energy contracts. The settlement is also
intended to resolve complaints brought by the California Attorney General
against Energy Marketing & Trading and the State of California's refund claims.
In addition, the settlement is intended to resolve ongoing investigations by the
States of California, Oregon, and Washington. The settlement is subject to
various court and agency approvals (see Other legal matters in Note 16). There
can be no assurance that these initiatives, investigations and proceedings will
not have a material adverse effect on Williams' results of operations or
financial condition.

GAS PIPELINE

During 2002, Williams sold both its Central and Kern River interstate
natural gas pipeline businesses. The following discussions exclude any gains or
losses on such sales and the results of operations related to

63

these businesses which are reported within discontinued operations. The
following discussions relate to the current continuing businesses of the Gas
Pipeline segment which include Transco, Texas Gas Transmission (Texas Gas),
Northwest Pipeline and various joint venture projects. On February 20, 2003,
Williams announced its intention to sell Texas Gas. Segment revenues of Texas
Gas were $266.4 million, $249.9 million and $260.9 million in 2002, 2001 and
2000, respectively. Segment profit of Texas Gas was $116.2 million, $99.6
million and $103.2 million for 2002, 2001 and 2000, respectively.

2002 vs. 2001

GAS PIPELINE'S revenues increased $77.8 million, or 5 percent, due
primarily to $67 million higher demand revenues on the Transco system resulting
from new expansion projects and new settlement rates effective September 1,
2001, the effect of $19 million in reductions in the rate refund liabilities
associated with rate case settlements on the Transco and Texas Gas systems, $16
million higher transportation revenues on the Texas Gas and Northwest Pipeline
systems, $9 million from environmental mitigation credit sales and services and
$4 million higher revenues associated with tracked costs which are passed
through to customers and offset in general and administrative expenses.
Partially offsetting these increases were $23 million lower gas exchange
imbalance settlements (offset in costs and operating expenses), $14 million
lower storage revenues and $7 million lower revenues associated with the
recovery of tracked costs which are passed through to customers (offset in costs
and operating expenses). The decrease in storage revenues is due primarily to $9
million lower rates on Cove Point's short-term storage contracts (the Cove Point
facility was sold in September 2002) and a $6 million decrease at Transco due
primarily to lower storage demand revenues.

Costs and operating expenses decreased $33 million, or 5 percent, due
primarily to $23 million lower gas exchange imbalance settlements (offset in
revenues), $22 million lower operations and maintenance expense due primarily to
lower professional and other contractual services and telecommunications
expenses, $7 million lower other tracked costs which are passed through to
customers (offset in revenues) and a $5 million franchise tax refund for
Transco. These decreases were partially offset by the $15 million effect in 2001
of a regulatory reserve reversal resulting from the FERC's approval for recovery
of fuel costs incurred in prior periods by Transco, as well as $5 million higher
depreciation expense. The $5 million higher depreciation expense reflects a $13
million increase due to increased property, plant and equipment placed into
service (including depletion of property held for the environmental mitigation
credit sales), partially offset by an $8 million adjustment related to the 2002
rate case settlements resulting in lower depreciation rates applied
retrospectively.

General and administrative costs increased $22 million, or 11 percent, due
primarily to $14 million higher employee-related benefits expense, including $8
million related to higher pension and retiree medical expense due to decreases
in assumed return on plan assets and approximately $4 million related to expense
recognized as a result of accelerated company contributions to an employee stock
ownership plan, $11 million in costs associated with an early retirement
program, a $5 million write-off in 2002 of capitalized software development cost
resulting from cancellation of a project and $4 million higher tracked costs
(offset in revenues). These increases were partially offset by $13 million lower
charitable contributions in 2002.

Other (income) expense -- net in 2002 includes a $17 million charge
associated with a FERC penalty (see Note 16) and a $3.7 million loss on the sale
of the Cove Point facility. Other (income) expense -- net in 2001 includes an
$18 million charge resulting from the unfavorable court decision and resulting
settlement in one of Transco's royalty claims proceedings (an additional $19
million is included in interest expense).

Segment profit, which includes equity earnings and income (loss) from
investments (both included in investing income), increased $89.6 million, or 16
percent, due primarily to the higher demand revenues discussed above, the $27
million effect of rate refund liability reductions and other adjustments related
to the finalization of rate cases during third-quarter 2002, $42.1 million
higher equity earnings, the lower costs and operating expenses discussed above,
the effect of the $18 million charge in 2001 discussed previously in other
(income) expense -- net and an $8.7 million gain in 2002 on the sale of the
general partnership interest in Northern Border Partners, L.P. These increases
were partially offset by a $10.4 million loss on the sale of Gas Pipeline's 14.6
percent ownership interest in Alliance Pipeline, a $12.3 million write-down in
2002 of Gas

64

Pipeline's investment in a pipeline project that has been cancelled, the effect
of a $27.5 million gain in 2001 from the sale of the limited partnership
interest in Northern Border Partners, L.P., the $22 million increase in general
and administrative costs discussed above, the $17 million FERC penalty and the
$3.7 million loss on the sale of the Cove Point facility. The increase in equity
earnings includes a $27.4 million benefit in 2002 related to the contractual
construction completion fee received by an equity affiliate. This equity
affiliate served as the general contractor on the Gulfstream pipeline project
for Gulfstream Natural Gas System (Gulfstream), an interstate natural gas
pipeline subject to FERC regulation and also an equity affiliate. The fee, paid
by Gulfstream and associated with the completion during the second quarter of
2002 of the construction of Gulfstream's pipeline, was capitalized by Gulfstream
as property, plant and equipment and is included in Gulfstream's rate base to be
recovered in future revenues. Additionally, the equity earnings reflects an $18
million increase from Gulfstream, $12 million of which is related to interest
capitalized on the Gulfstream pipeline project in accordance with FERC
regulations.

2001 vs. 2000

Gas Pipeline's revenues decreased $141 million, or 9 percent, due primarily
to the effect of a $69 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), $10
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 $13 million higher gas transportation demand
revenues as a result of new expansion projects and new rates on the Transco
system and $9 million higher revenues from a liquefied natural gas storage
facility acquired in June 2000.

Costs and operating expenses decreased $79 million, or 10 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 $16
million in higher depreciation expense due to increased property, plant &
equipment placed into service during 2001.

General and administrative costs decreased $16 million resulting primarily
from lower tracked costs which are passed through to customers (offset in
revenues), partially offset by higher charitable contributions.

Other (income) expense -- net in 2001 within segment costs and expenses
includes 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 $25.6 million due primarily to the lower revenues
discussed previously and the item discussed previously in other (income)
expense -- net. These decreases were partially offset by the lower costs and
operating expenses discussed above, a $19 million increase in equity investment
earnings from pipeline joint venture projects, a $27.5 million gain from the
sale of Williams' limited partnership interest in Northern Border Partners, L.P.
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.

65

EXPLORATION & PRODUCTION

On February 20, 2003, Williams announced additional assets to be sold
including Exploration & Production properties. Depending on the nature and size
of the sales, future operating results could be impacted significantly.

2002 vs. 2001

EXPLORATION & PRODUCTION'S revenues increased $284.7 million, or 46
percent, due primarily to $284 million higher domestic production revenues, $27
million in unrealized gains from the mark-to-market financial instruments
related to basis differentials on natural gas production, partially offset by
$28 million lower domestic gas management revenues. The $284 million increase in
domestic production revenues includes $254 million associated with an increase
in net domestic production volumes as well as $30 million from increased net
realized average prices for production (including the effect of hedge
positions). The increase in net production volumes mainly results from the
acquisition in third-quarter 2001 of the former Barrett operations.
Approximately 83 percent of domestic production in 2002 was hedged. Exploration
& Production has entered into contracts that hedge approximately 85 percent of
projected 2003 domestic natural gas production before consideration of any
potential property sales in 2003. 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 was with Enron, which filed for
bankruptcy in December 2001. As a result, the contracts were effectively
liquidated due to contractual terms concerning bankruptcy and Energy Marketing &
Trading recorded estimated charges for the credit exposure. During the third
quarter of 2002, Energy Marketing & Trading had additional contracts not related
to Enron that were terminated. The other comprehensive income related to these
terminated contracts remains in accumulated other comprehensive income and is
recognized as the underlying volumes are produced. During 2002, approximately
$35 million related to the terminated contracts was recognized as revenues while
$45 million remains in accumulated other comprehensive income at December 31,
2002.

Domestic 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. 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 parties.

Costs and operating expenses, including selling, general and administrative
expenses, increased $131 million, due primarily to increased depreciation,
depletion and amortization, lease operating expenses and selling, general and
administrative expenses due primarily to the addition of the former Barrett
operations. The increases were partially offset by decreased gas management
purchase costs.

Other (income) expense-net in 2002 includes $120.3 million and $21.4
million in gains from the sales of substantially all of the interests in natural
gas production properties in the Jonah field (Wyoming) and in the Anadarko
Basin, respectively. The Jonah field properties represented approximately 11
percent of total reserves at December 31, 2001, the absence of which could
impact future revenue levels.

Segment profit increased $286.4 million due primarily to the gains from
asset sales mentioned above, increased production volumes, and higher net
realized average prices. Segment profit also includes $11.8 million and $15.4
million related to international activities for 2002 and 2001, respectively.

66

2001 vs. 2000

Exploration & Production's revenues increased $284.2 million, or 86
percent, due primarily to $263 million higher domestic 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 domestic 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
domestic production in 2001 was hedged. Revenues from domestic gas management
activities increased $14 million.

Segment costs and operating expenses increased $141 million, including a
$24 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 domestic lease operating expenses, $8
million higher domestic depreciation, depletion and amortization expenses and $6
million higher domestic 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 $146.5 million, or 167 percent, due primarily to
the higher domestic 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, partially offset by $6 million lower equity earnings from an Argentina oil
and gas investment.

MIDSTREAM GAS & LIQUIDS

In August 2002, Williams completed the sale of 98 percent of Mapletree LLC
and 98 percent of E-Oaktree, LLC to Enterprise Products Partners L.P. Mapletree
owned all of Mid-America Pipeline, a 7,226-mile natural gas liquids pipeline
system. E-Oaktree owned 80 percent of the Seminole Pipeline, a 1,281-mile
natural gas liquids pipeline system. The gains on the sale of these businesses
and the related results of operations have been reported as discontinued
operations. Williams has also announced the intended sale of additional assets,
including certain operations in Canada. Future asset sales would have the effect
of lowering liquid product sales in periods following their sale but are
expected to be offset by increasing deepwater or gathering and transportation
revenue. The following discussion reflects the results of Midstream Gas &
Liquids' continuing operations.

2002 vs 2001

MIDSTREAM GAS & LIQUIDS revenues increased $2.3 million as a result of a
$60.3 million increase in domestic gathering, processing, transportation and
liquid product sales revenues, a $48.7 million increase in Venezuelan revenues
and a $10.3 million increase in Canadian revenues, offset by a $117 million
decline in domestic petrochemical and trading revenues.

The $60.3 million increase in domestic gathering, processing,
transportation and liquid product sales revenues was driven by a $34 million
increase in liquid sales, a $39 million increase in liquid product sales from
Gulf Liquids, (a new off gas processing and olefin extraction facility that
became a consolidated subsidiary in September 2002) and a $10 million increase
in transportation revenues. Partially offsetting these increases is a $17
million decrease in gathering revenues primarily due to the third quarter 2002
sale of the

67

Kansas-Hugoton gathering system. The increase in liquid sales reflects a $67
million increase in gulf coast liquid sales resulting from higher production at
existing processing facilities and the September 2001 completion of a new
processing facility that processes natural gas gathered from deepwater projects
off the coast of Texas. Offsetting the increase in gulf coast liquid sales was a
$33 million decline in liquid sales in the west, primarily caused by a decline
in average liquid sales prices. The $10 million increase in transportation
revenues reflects the results of a new deepwater oil and gas transportation
system which was completely operational by mid-year.

The $117 million decline in petrochemicals and trading revenues is due
largely to a change in the reporting during September 2001 of certain
petrochemical and liquid product trading transactions from a gross revenue basis
to a net revenue basis combined with lower natural gas liquid trading margins.

The $48.7 million increase in Venezuelan revenues reflects a full year of
results from a new gas compression facility that began operations in August
2001.

The increase in Canadian revenues results from a $56 million increase in
natural gas liquids product sales from fractionation activities reflecting a 48
percent increase in volumes. The increase in volumes sold was partially offset
by a 19 percent decline in average liquid product sales prices. The increase in
volumes resulted from improvements made at a parafins facility and higher
volumes of natural gas liquid supply from processing facilities within Northern
Alberta and British Columbia. The increase in Canadian revenues is partially
offset by a $24 million decrease in processing revenues reflecting lower
processing rates under cost of service agreements as a result of lower natural
gas shrink prices combined with a $24 million decrease in liquid sales from
processing activities which reflects lower average liquid sales prices.

Costs and operating expenses decreased $112 million, or 7 percent,
primarily reflecting a decline in fuel and product shrink costs at the Wyoming
and Canadian processing facilities of $21 million and $85 million ($41 million
from costs under cost of service processing agreements), respectively. These
decreases reflect lower average natural gas prices in Canada and Wyoming, offset
by higher volumes and prices in the gulf coast. The lower average gas prices in
Wyoming during 2002 reflect a favorable differential between gas prices in
Wyoming and the gulf as a result of limited transportation capacity from Wyoming
to other markets. This favorable basis differential had the effect of lower
shrink costs and increasing liquid sales margins from Wyoming processing plants
and is not expected to continue once take away transportation capacity within
this region has been expanded. Costs and operating expenses also reflect a $92
million decline in petrochemical and trading costs resulting from the change in
reporting certain product trading classifications in September 2001, as
discussed above. Partially offsetting these decreases are $32 million of higher
product shrink costs at Gulf Liquids operations, $30 million higher depreciation
costs from the addition of Gulf Liquids and other new facilities combined with
$14 million higher transportation, fractionation, and marketing costs.
Operations and maintenance expenses were relatively unchanged on a segment
basis, with a $32 million decline in costs in the west primarily resulting from
lower maintenance spending, offset by a corresponding increase in the gulf,
Canada and Venezuela largely driven by the higher maintenance costs resulting
from the new Venezuelan gas compression facility, Canadian olefins facility, the
Gulf Liquids facilities and new deepwater offshore operations.

Selling, general and administrative costs increased $10 million primarily
due to the consolidation of Gulf Liquids during 2002.

Other (income) expense -- net within segment costs and expense for 2002
includes a $115 million impairment associated with the Canadian processing,
extraction and olefin extraction assets (see Note 4) and a $6 million impairment
associated with the sale of the Kansas Hugoton gathering system in the third
quarter. Reflected in 2001 are $13.8 million of impairment charges related to
certain south Texas non-regulated gathering and processing assets.

Segment profit of $189.3 million for 2002 was largely impacted by a $115
million impairment on Canadian natural gas processing, extraction and olefin
extraction assets during the fourth quarter. Before this impairment charge,
Midstream Gas & Liquids' 2002 segment profit reflects a $132 million increase
over 2001.

68

This increase reflects a $70 million increase in domestic operations, a $20
million increase in Venezuelan operations and a $42 million increase in Canadian
operations.

Domestic segment profit reflects a $45 million increase in liquid sales
margins resulting from the low fuel and shrink costs in the west reflecting the
wide basis differential for natural gas prices in Wyoming. Domestic segment
profit also increased $32 million due to income from equity investments
primarily related to significant improvements in the operations of Discovery
pipeline following new supply connections that resulted in higher transportation
and liquid volumes. Domestic segment profit was also impacted by a $16 million
increase in profits from an increase in deepwater operations, offset by $25
million in losses resulting from operational issues associated with Gulf
Liquids.

The increase in segment profit from Canadian operations (excluding the $115
million impairment discussed above) resulted from a $23 million increase in
liquid product margins from fractionation activities due to higher liquid sales
volumes and prices combined with a $37 million increase in liquid sales margins
from processing activities primarily resulting from lower shrink costs.
Offsetting these increases are higher depreciation, and operations and
maintenance expense primarily resulting from the new olefins fractionation
facility.

Segment profit from Venezuelan operations reflects an increase resulting
from a full year of results following the completion of a new gas compression
facility in August 2001. Midstream Gas & Liquids Venezuelan assets were
constructed and are currently operated for the exclusive benefit of Petroleos de
Venezuela S.A. (PDVSA), the state owned Petroleum Corporation of Venezuela.
During December 2002 and January 2003, a countrywide strike took place within
Venezuela that resulted in significant political instability and a volatile
economic environment. Employees of PDVSA joined this strike, which had an impact
on the operations of most of the Venezuelan facilities. All owned facilities are
presently operating. However, an operating agreement for the PDVSA owned oil
terminaling facility is the subject of a contract dispute with PDVSA. The
ultimate impact the political and economic situation within Venezuela will have
on Midstream Gas and Liquids' revenues, segment profits and operating cash flows
will depend upon the extent and duration of the political and economic
instability and the enforceability of certain contractual arrangements
provisions with PDVSA.

2001 vs. 2000

Midstream Gas & Liquids' revenues increased $332.5 million, or 21 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.
Revenues were $32 million higher due to a new Venezuelan gas compression
facility which began operations in August 2001. Revenues from domestic natural
gas liquids trading operations decreased $112 million due primarily to declining
prices on ethane and lower ethelyne volumes and prices related to marketing of
products of a petrochemical plant acquired by Williams in early 1999, as well as
a change in the reporting during 2001 of certain petrochemical and liquid
product trading transactions from a gross revenue basis to a net revenue basis.
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. Additionally, there were $15
million lower revenues related to the petrochemical plant due to a plant
turnaround in first-quarter 2001 and curtailed production. 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 $393 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 $18 million higher
domestic general operating and maintenance costs and $13 million related to the
new gas compression facility in Venezuela. Partially offsetting these increases
were $95 million lower expenses related to decreased

69

ethane prices for the natural gas liquids trading operations, $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 and the effect in 2000 of $12 million of losses
associated with certain propane storage transactions.

General and administrative expenses increased $7 million, or 6 percent, due
primarily to $11 million of general and administrative expenses related to the
Canadian operations for the first three quarters of 2001 and higher general and
administrative expenses for natural gas liquids trading operations, partially
offset by $12 million of reorganization and early retirement costs incurred in
2000.

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 charges represent the impairment of the assets to
fair value based on expected proceeds from the sales. These sales closed during
first-quarter 2002. Also included in other (income) expense-net within segment
costs and expenses for 2000 is a $12.4 million gain on the sale of certain
natural gas liquids contracts.

Segment profit decreased $106.1 million, or 38 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, $16
million lower margins from natural gas liquids trading activity, $18 million
higher domestic operating and maintenance costs, $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, $13.8 million and $12.4 million due to the 2001 impairment charge and the
2000 gain on sale of certain natural gas liquids contracts discussed above and
$10 million higher losses from equity investments. Partially offsetting these
decreases to segment profit were an $18 million increase from the new Venezuelan
gas compression facility which began operations in third-quarter 2001, $6
million lower domestic general and administrative expenses, $11 million higher
domestic gathering revenues and $12 million of losses associated with certain
propane storage transactions during 2000.

WILLIAMS ENERGY PARTNERS

On February 20, 2003, Williams announced that it is pursuing a potential
sale of its investment in Williams Energy Partners L.P., including its general
partner interest.

2002 vs. 2001

WILLIAMS ENERGY PARTNERS' revenue increased $21.2 million, or 5 percent,
reflecting increased revenues from petroleum products transportation, terminal
and other activities. Transportation revenues increased as a result of higher
average transportation rates slightly offset by lower volumes. The increase in
average transportation rates were due to supply shifts within the Williams Pipe
Line system, caused by the temporary capacity reductions of certain refineries,
which created longer hauls during the current year. These refinery capacity
reductions are not anticipated to recur in 2003. The increase in terminals and
other revenues principally reflect increased utilization and higher rates. In
addition, 2002 results benefited from the full-year impact of acquisitions made
during 2001, which include two inland terminals and one marine terminal
facility.

Costs and operating expenses increased $17 million due primarily to $10
million of higher environmental expense accruals, a full year of operating
expenses related to the marine facility and two inland terminals discussed
above, and higher third-party pipeline lease expenses. Most of the increase in
environmental expenses resulted from the completion of state-mandated
environmental assessments at six terminal facilities

70

on the pipeline system during the current year. These increases were partially
offset by lower transportation field expenses principally reflecting maintenance
cost-reduction measures implemented in the current year.

Segment profit decreased $1.9 million, or 2 percent, due to the items
discussed above, $5.9 million higher selling, general and administrative
expenses and decreased other income of $0.2 million. General and administrative
costs increased due to costs incurred during 2002 by Williams Energy Partners
relating to the acquisition of Williams Pipe Line, increased allocations from
Williams and increased equity-based incentive compensation expense.

2001 vs. 2000

Williams Energy Partners' revenue increased $29.5 million, or 8 percent,
due primarily to higher revenues from the petroleum products transportation
activities, 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 $3 million, or 3 percent, due
primarily to higher operating costs corresponding with the revenue increase
discussed above and higher general and administrative expenses.

PETROLEUM SERVICES

Petroleum Services' continuing operations include the North Pole, Alaska
refining operations, retail operations from the 29 Williams Express convenience
stores in Alaska, a 3.0845 percent undivided interest in the Trans-Alaska
Pipeline System (TAPS) acquired in June 2000 and transportation operations.
Transportation operations primarily include Williams' 32.1 percent interest in
Longhorn Partners Pipeline LP (which is not yet operational), and gas liquids
blending activities for Williams Pipe Line Company which is owned and part of
the Williams Energy Partners segment. Williams has announced that it is pursuing
the sale of its operations in Alaska. If a sale is approved and other conditions
are met, these operations would be reported as discontinued operations in the
future. In addition, 2001 and 2000 include the results of operations through May
2001 of 198 convenience stores in the Midsouth which were sold in May 2001.
These operations did not qualify as discontinued operations under previous
accounting guidance.

2002 vs. 2001

PETROLEUM SERVICES' revenues decreased $243.7 million, or 22 percent, due
primarily to $194 million lower convenience store sales and $47 million lower
Alaska refining revenues. The $194 million decrease in convenience store sales
reflects the absence of $184 million in revenues related to the sale of the 198
convenience stores in May 2001 and an $11 million decrease in revenues related
to the retained Alaska convenience stores. The $11 million decrease in revenues
of the retained Alaska convenience stores reflects $7 million from a 9 percent
decrease in gasoline sales volumes and $4 million from a 6 percent decrease in
average gasoline sales prices. The $47 million decrease in refining revenues
primarily includes $69 million from 9 percent lower average refined product
sales prices, partially offset by $21 million from a 3 percent increase in
refined product volumes sold.

Costs and operating expenses decreased $228 million, or 23 percent, due
primarily to $196 million lower convenience store costs and $32 million lower
Alaska refining costs. The $196 million decrease in convenience store costs is
due primarily to the absence of $185 million in costs related to the sale of the
198 convenience stores in May 2001 and an $11 million decrease in costs for the
retained Alaska convenience stores. The $11 million decrease in costs for the
retained Alaska convenience stores reflects $5 million from a 10 percent
decrease in average gasoline purchase prices and $6 million from 9 percent lower
gasoline sales volumes. The $32 million lower Alaska refining costs is due
primarily to $50 million from 8 percent lower average refined

71

product purchase prices, partially offset by $17 million from a 3 percent
increase in refined product volumes sold.

Other (income) expense -- net in 2002 includes a total of $18.4 million of
impairment charges related to the Alaska refining operations and the Alaska
convenience stores. As previously mentioned, Williams has announced its
intention to pursue a sale of its operations in Alaska. These impairment charges
reflect the excess of the carrying cost of these assets over management's
estimate of fair value. Other (income) expense -- net in 2001 includes the $75.3
million pre-tax gain from the sale of the 198 convenience stores and a $12.1
million impairment charge related to an end-to-end mobile computing systems
business.

Segment profit decreased $112.9 million, or 77 percent, due primarily to
the $81.6 million net unfavorable effect related to the items noted above in
other (income) expense -- net and $14 million lower operating profit from
refining operations. In addition, the decrease reflects a 2002 equity loss of
$13.8 million from its investment in Longhorn Partners Pipeline LP resulting
almost entirely from fourth-quarter 2002 adjustments recorded by Longhorn
Partners Pipeline LP to expense certain amounts previously capitalized as
property costs.

2001 vs. 2000

Petroleum Services' revenue decreased $346.6 million, or 24 percent, due
primarily to $279 million lower convenience store sales and $49 million lower
refining revenues, partially offset by $28 million higher revenues from
Williams' 3.0845 percent undivided interest in TAPS acquired in late June 2000.
The $279 million decrease in convenience store sales is due primarily to a $283
million decrease in revenues related to the sale of the 198 convenience stores
in May 2001, slightly offset by higher merchandise sales by the Alaska
convenience stores. The $49 million decrease in refining revenues is due to $145
million resulting from 16 percent lower average refined product sales prices,
partially offset by $96 million from 12 percent higher refined product volumes
sold.

Costs and operating expenses decreased $362 million, or 27 percent, due
primarily to $278 million lower convenience store costs and $57 million lower
refining costs. The $278 million decrease in convenience store costs is due
primarily to the $282 million decrease in costs related to the 198 convenience
stores which were sold in May 2001, slightly offset by higher merchandise costs
by the Alaska convenience stores. The $57 million decrease in refining costs is
due primarily to $138 million resulting from 18 percent lower average refined
product costs, partially offset by $80 million from a 12 percent increase in
refined volumes sold.

Included in other (income) expense -- net within segment costs and expenses
for 2001, is a $75.3 million pre-tax gain from the sale of the 198 convenience
stores. 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 represent 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 $106.8 million due primarily to $82.1 million net
favorable effect related to the items noted above in other (income)
expense -- net, $20 million from Williams interest in TAPS acquired in late June
2000 and $8 million higher operating profit from refining operations.

72

OTHER

2002 vs. 2001

OTHER segment profit in 2002 includes a $58.5 million gain from the
September 2002 sale of Williams' 27 percent ownership interest in the Lithuanian
refinery, pipeline and terminal complex and a $9.5 million decrease in equity
losses from the Lithuanian operations for the period. Williams received proceeds
of approximately $85 million from the sale of this investment. In addition,
Williams sold its $75 million note receivable from the Lithuanian operations at
face value.

73

FAIR VALUE OF ENERGY RISK MANAGEMENT AND TRADING ACTIVITIES

As more thoroughly described in Note 1 of Notes to Consolidated Financial
Statements, energy and energy-related contracts are carried 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,
while other transactions are executed where quoted market prices are not
available or the contracts extend into periods 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 and the natural gas liquids trading operations
transact. Market data in active periods is also available for interest rate
transactions affecting the trading portfolio. 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 proprietary
models and other valuation techniques that reflect the best information
available under the circumstances. In situations where Energy Marketing &
Trading has received current information from negotiation activities with
potential buyers of these contracts, the information is considered in the
determination of the fair value of the contract. The valuation techniques used
when estimating fair value for energy-related contracts 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. The estimates of fair value also assume
liquidating the positions in an orderly manner over a reasonable period of time
in a transaction between a willing buyer and seller. 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. The estimates of fair value are adjusted as
assumptions change or as transactions become closer to settlement and enhanced
estimates become available. 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.

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
judgment 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 it believes 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

74

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.

On October 25, 2002, the EITF, concluded in Issue No. 02-3 to rescind Issue
No. 98-10, under which non-derivative energy trading contracts were previously
marked-to-market. A substantial portion of the energy marketing and trading
activities previously reported on a fair-value basis will be reflected under the
accrual method of accounting beginning January 1, 2003. In addition, trading
inventories will no longer be marked-to-market but will be reported on a lower
of cost or market basis. Upon adoption of this new standard on January 1, 2003
Energy Marketing & Trading and the natural gas liquids trading operations
(reported in the Midstream Gas & Liquids segment) will record a charge as a
cumulative effect of change in accounting principle. The impact of this change
in accounting principle is expected to be a decrease to net income of $750
million to $800 million on an after-tax basis. For further discussion on this
issue, please refer to Note 1 of Notes to Consolidated Financial Statements.

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 and the natural gas liquids trading operations (reported in
the Midstream Gas & Liquids segment) transact. 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 and the natural gas
liquids trading operations estimate 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 through 2012, power through
2006, crude and refined products through 2004 and natural gas liquids through
2003. The ability to obtain quoted market prices varies greatly from region to
region, and the time periods mentioned above are an estimation of aggregate
liquidity. Prices reflected in current transactions executed by Energy Marketing
& Trading are used to further validate the estimates of these prices. The
ability to validate prices has been limited due to the recent decline in overall
market liquidity.

Models and other valuation techniques

Contracts for which quoted market prices are not available primarily
include transportation, storage, full requirements, load serving, transmission,
and power tolling contracts (energy-related contracts). A description of these
contracts is included in Note 15 of 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

75

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.

The chart below reflects the fair value of energy risk management and
trading contracts for Energy Marketing & Trading and the natural gas liquids
trading operations (reported in the Midstream Gas & Liquids segment) by
valuation methodology and the period in which the recorded fair value is
expected to be realized. Refer to Note 1 of Notes to Consolidated Financial
Statements regarding the estimated impact of the Company's January 1, 2003
adoption of EITF Issue No. 02-3 on fair values as reported below.

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

(1) A significant portion of the value expected to be realized relates to
contracts within the California power market. The terms of these agreements
provide for the sale of power at fixed prices ranging from $62.50 to $87.00
per megawatt hour at varying volumes through 2010 for up to 700 megawatts
per hour, and a unit-specific dispatchable fuel conversion service with
fixed capacity prices ranging from $117 to $140 per kilowatt year at varying
capacities of up to 1,175 megawatts through 2010.

(2) Quoted market prices of the underlying commodities are significant factors
in estimating the fair value.

SIGNIFICANT ESTIMATES AND ASSUMPTIONS USED IN THE VALUATION ESTIMATION PROCESS

The most significant estimates and assumptions used to estimate the value
of energy and energy-related contracts that extend beyond liquidly traded time
periods include:

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

- Estimates of volatility and correlation of natural gas, power and refined
products prices;

- Estimates of risk inherent in estimating cash flows; and

- Estimates and assumptions regarding counterparty performance and credit
considerations.

Estimates of natural gas, power, and refined products market prices in
illiquid periods

Natural gas, power, and refined products prices are the most significant
commodity prices impacting the fair value of Energy Marketing & Trading
contracts at December 31, 2002. In estimating natural gas, power, and refined
products 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

76

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, power, and
refined products, current economic and regulatory conditions, as well as,
information supporting future conditions that would affect the supply and demand
relationships. Alternative methods for determining prices in illiquid periods
could materially impact management's estimate of fair value.

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, power, and refined
products prices

Volatility of natural gas, power, and refined products 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, power, and refined products 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 are
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, power, and refined products
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. Alternative methods for
determining volatilities and correlations in illiquid periods could materially
impact management's estimate of fair value.

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 and the natural gas liquids trading operations
(reported in the Midstream Gas & Liquids segment) estimate 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 and the natural gas liquids trading operation estimate 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 and the natural gas liquids trading operations
(reported in the Midstream Gas & Liquids segment) 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.

77

The gross forward credit exposure from energy trading and price-risk
management activities for Energy Marketing & Trading and the natural gas liquids
trading operations (reported in the Midstream Gas & Liquids segment) as of
December 31, 2002 is summarized below.

Energy Marketing & Trading and the natural gas liquids trading operations
(reported in the Midstream Gas & Liquids segment) assess its credit exposure on
a net basis when appropriate and contractually allowed. The net forward credit
exposure from energy trading and price-risk management activities as of December
31, 2002 is summarized as below.

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

(1) This category includes certain balance sheet reclassifications made in 2002
that did not impact 2002 earnings.

(2) This category includes changes in the fair market value of contracts
outstanding as a result of various market movements (including changes in
market prices, market volatility, and market liquidity) and changes in the
net balance of option premiums paid and received. Option premiums paid and
received are included in the fair value of contracts outstanding during any
given period as they are a portion of the overall energy trading portfolio.
Option premiums paid result in an initial increase in the fair value of
contracts outstanding and a decrease in cash; premiums received result in an
initial decrease in the fair value of contracts outstanding and an increase
in cash. The underlying value of the options associated with the premium
payments are also included in the fair value of contracts outstanding.

Changes in fair value during 2002 include the realization of cash flows on
contracts outstanding at December 31, 2001 that were expected to be realized
during 2002. These amounts may have differed from the values that were actually
realized during 2002 due to changes in market prices, the creditworthiness of
counterparties, and other factors that occurred during 2002 prior to the
realization of those cash flows.

During 2002, 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 2002 Results
of Operations for a discussion of the type of contracts executed during the
year. The

79

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 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
recognized in the financial statements due to changes in market prices and other
factors that may have occurred during the intervening period.

Energy Marketing & Trading and the natural gas liquids trading operations
(reported in the Midstream Gas & Liquids segment) continuously evaluate the
valuation techniques and models used in estimating fair value and modify and
implement new valuation techniques based upon emerging financial theory in order
to provide a better estimate of fair value.

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 that Energy Marketing &
Trading and the natural gas liquids trading operations (reported in the
Midstream Gas & Liquids segment) use in estimating fair value based upon new
information and data available in the marketplace.

80

FINANCIAL CONDITION AND LIQUIDITY

LIQUIDITY

Williams' liquidity comes from both internal and external sources. Certain
of those sources are available to Williams (the parent) and others are available
to certain of its subsidiaries. Williams' sources of liquidity consist of the
following:

- Cash-equivalent investments at the corporate level of $1.3 billion at
December 31, 2002, as compared to $1.1 billion at December 31, 2001.

- Cash and cash-equivalent investments of various international and
domestic entities other than Williams Energy Partners of $354 million at
December 31, 2002 as compared to $163 million at December 31, 2001.

- Cash generated from operations and the future sales of certain assets.

- $463 million available under Williams' revolving credit facility at
December 31, 2002, as compared to $700 million at December 31, 2001. This
credit facility is available to the extent that it is not used to satisfy
the financial ratios and other covenants under certain credit agreements.
As discussed in Note 11 of Notes to Consolidated Financial Statements,
the borrowing capacity under this facility will reduce as assets are
sold.

- $3 million remaining at December 31, 2002, under a new $400 million
secured short-term letter of credit facility obtained in third-quarter
2002.

In April 2002, Williams filed a shelf registration statement with the
Securities and Exchange Commission to enable it to issue up to $3 billion of a
variety of debt and equity securities. This registration statement was declared
effective June 26, 2002. Because of Williams' debt rating and loan covenant
restrictions, it is unlikely that Williams would be able to issue securities
under the shelf registration statement in the near term.

In addition, there are outstanding registration statements filed with the
Securities and Exchange Commission for Williams' wholly owned subsidiaries:
Northwest Pipeline, Texas Gas Transmission and Transcontinental Gas Pipe Line.
As of March 17, 2003, 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, market conditions, and industry
conditions will affect amounts raised, if any, in the capital markets. On March
4, 2003, Northwest Pipeline Corporation, a subsidiary of Williams, completed an
offering of $175 million of 8.125 percent senior notes due 2010 to certain
institutional investors. The offering is exempt from the registration
requirements of the Securities Act of 1933. The $450 million of shelf
availability mentioned above is not affected by this offering.

Williams expects to fund capital and investment expenditures, debt payments
and working-capital requirements through (1) cash on hand, (2) cash generated
from operations, (3) the sale of assets, (4) issuance of debt by certain
subsidiaries and/or (5) amounts available under Williams' revolving credit
facility.

As discussed in Note 11 of Notes to Consolidated Financial Statements,
Williams Production RMT Company (RMT), a wholly owned subsidiary, entered into a
$900 million Credit Agreement (RMT note payable) dated as of July 31, 2002, with
certain lenders including a subsidiary of Lehman Brothers, Inc., a related party
to Williams. The RMT Note Payable is secured by substantially all of the assets
of RMT and the capital stock of Williams Production Holdings LLC (parent of
RMT), RMT and certain RMT subsidiaries. It is also guaranteed by Williams,
Williams Production Holdings LLC (Holdings) and certain RMT subsidiaries. The
assets of RMT are comprised primarily of the assets of the former Barrett
Resources Corporation acquired in 2001, which were primarily natural gas
properties in the Rocky Mountain region. Within 75 days of a parent liquidity
event, Williams must sell RMT. Under the terms of the RMT Credit Agreements,
Williams must provide liquidity projections on a weekly basis until the maturity
date. Each projection covers a period extending 12 months from the report date.
One of the parent liquidity provisions requires that Williams maintain actual
and projected liquidity (a) at any time from the closing date (July 31, 2002)
through the

81

180th day thereafter (January 27, 2003), of $600 million; (b) at any time
thereafter through and including the maturity date, of $750 million; and (c) for
liquidity projections provided during the term of the loan, projected liquidity
after the maturity date, of $200 million. The loan matures on July 25, 2003.

Outlook

On February 20, 2003, Williams announced that it intended to sell an
additional $2.25 billion over those previously announced in assets, properties
and investments. To realize this level of proceeds, Williams announced that it
was pursuing the sales of its general partnership interest and limited-partner
investments in Williams Energy Partners, its 6,000 mile Texas Gas pipeline
system and targeted assets in the Exploration & Production and Midstream Gas &
Liquids segments.

Based on the Company's forecast of cash flows and liquidity, Williams
believes that it has the financial resources and liquidity to meet future cash
requirements and satisfy current lending covenants through the first quarter of
2004. Included in this forecast are expected proceeds, net of related debt,
totaling nearly $4 billion from the sale of assets. Including periods through
first-quarter 2004, the Company has scheduled debt retirements (which includes
certain contractual fees and deferred interest associated with an underlying
debt) of approximately $3.8 billion. Realization of the proceeds from forecasted
assets sales is a significant factor for the Company to satisfy its loan
covenant which requires minimum levels of parent liquidity and to satisfy
current scheduled debt maturities.

Credit Ratings

At December 31, 2001, Williams maintained certain preferred interest and
debt obligations that contained provisions requiring accelerated payment of the
related obligation or liquidation of the related assets in the event of
specified declines in Williams' senior unsecured long-term credit ratings
assigned by Moody's Investors Service and Standard & Poor's (rating agencies).
Obligations subject to these "ratings triggers" totaled $816 million at December
31, 2001. During the first quarter of 2002, Williams negotiated changes to
certain of the agreements, which eliminated the exposure to the "ratings
trigger" clauses incorporated in the agreements. Negotiations for one of the
agreements resulted in Williams agreeing to redeem a $560 million preferred
interest over the next year in equal quarterly installments (see Note 12). The
obligations subject to "ratings triggers" were reduced to $182 million at March
31, 2002. As a result of the credit rating downgrades to below investment grade
in July 2002, Williams redeemed $135 million of preferred interests on August 1,
2002 and repaid a $47 million loan in August 2002, thereby eliminating the
remaining $182 million exposure.

Williams' energy risk management and trading business also relied upon the
investment-grade rating of Williams' senior unsecured long-term debt to satisfy
credit support requirements of many counterparties. As a result of the credit
rating downgrades to below investment grade, Energy Marketing & Trading's
participation in energy risk management and trading activities requires
alternate credit support under certain existing agreements. In addition,
Williams is required to fund margin requirements pursuant to industry standard
derivative agreements with cash, letters of credit or other negotiable
instruments. As a result of Williams credit downgrade to non-investment grade
during 2002, Williams is effectively required to post margins of 100 percent or
more on forward positions which result in a loss. Any future liquidity
requirements related to these instruments will be driven by changes in the value
of such instruments as a result of changes in price, volatility, etc.

At December 31, 2002, Williams has been assigned the following credit
ratings on its senior unsecured long-term debt, which are considered to be below
investment grade:

Moody's Investors Service.................................. Caa1 (negative outlook)
Standard & Poor's.......................................... B (negative watch)

82

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

At December 31, 2001, Williams had operating lease agreements with special
purpose entities (SPE's). The lease agreements relate to certain Williams travel
center stores (included in discontinued operations), offshore oil and gas
pipelines and an onshore gas processing plant. As a result of changes to the
agreements in conjunction with the secured financing facilities completed in
July 2002, the agreements no longer qualified for operating lease treatment. The
operating leases were recorded as capital leases within long-term debt beginning
in July 2002, however the travel center lease is reported in liabilities of
discontinued operations and was repaid in March 2003 pursuant to the travel
centers sale.

Williams had agreements to sell, on an ongoing basis, certain of its
accounts receivable to qualified special-purpose entities. On July 25, 2002,
these agreements expired and were not renewed.

Williams provides a guarantee of approximately $126.9 million towards
project financing of energy assets owned and operated by Discovery Producer
Services LLC in which Williams owns an interest of 50 percent. This obligation
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 under the guarantee generally would occur upon a
failure of payment by the financed entity or certain events of default related
to the guarantor. These events of default primarily relate to bankruptcy and/or
insolvency of the guarantor. At December 31, 2002, there were no events of
default by the guarantors or delinquent payments by the financed entity with
respect to the project financings. The guarantee expires at the end of 2003.

Williams has provided guarantees in the event of nonpayment by WCG on
certain lease performance obligations of WCG that extend through 2042 and have a
maximum potential exposure of approximately $53 million. Williams' exposure
declines systematically throughout the remaining term of WCG's obligations. The
carrying value of these guarantees was $48 million at December 31, 2002.

In addition to these guarantees, Williams has issued guarantees and other
similar arrangements with off-balance sheet risk as discussed under Guarantees
in Note 15 of Notes to Consolidated Financial Statements.

WCG

At December 31, 2001, Williams had financial exposure from WCG of $375
million of receivables and $2.21 billion of guarantees and payment obligations.
Receivables included a $106 million deferred payment for services provided to
WCG prior to the spinoff and $269 million from the long term lease to WCG of the
Technology Center building and three aircraft. The $2.21 billion of guarantees
and payment obligations included the indirect credit support for $1.4 billion of
WCG's Note Trust Notes and the guarantee of WCG's obligations under the asset
defeasance program (ADP) transaction (see Note 2). During 2002, Williams
acquired all of the WCG Note Trust Notes by exchanging $1.4 billion of Williams
Senior Unsecured 9.25 percent Notes due March 2004. WCG was indirectly obligated
to reimburse Williams for any payments Williams is required to make in
connection with the WCG Note Trust Notes. On March 29, 2002, Williams funded the
purchase price of $754 million related to WCG's March 8, 2002 exercise of its
option to purchase the covered network assets under the ADP transaction.
Williams then became entitled to an unsecured claim from WCG for the same
amount.

On April 22, 2002, WCG filed for bankruptcy protection under Chapter 11 of
the US Bankruptcy Code. The Chapter 11 Plan of Reorganization (Plan) was
confirmed by the United States Bankruptcy Court for the Southern District of New
York on September 30, 2002. On October 15, 2002, WCG consummated its Plan. The
Plan included the sale, by Williams to Leucadia National Corporation (Leucadia)
for $180 million in cash of Williams' claims against WCG for the WCG Note Trust
Notes, the funding of the WCG Purchase option for the covered network assets
under the ADP transaction and the deferred payment for services. It also
included the sale by Williams to WCG of the Technology Center building for (a) a
seven and one-half year promissory note in the principal amount of $100 million
with interest at 7 percent (Long Term Note) and (b) a four year promissory note
(which may be prepaid without penalty) with face amount of $74.4 million

83

and an original principal amount of $44.8 million (Short Term Note) both of
which are secured by a mortgage on the Technology Center and certain other
collateral.

At December 31, 2002, Williams had a $121.5 million receivable (original
principal amount of $144.8 million) from WCG for the promissory notes relating
to the sale of the Technology Center. The notes were initially recorded at fair
value based on contractual cash flows and an estimated discount rate considering
the creditworthiness of WCG, the amount and timing of the cash flows and
Williams' security in the Technology Center and certain other collateral. The
fourth-quarter 2002 sale of certain of Williams' claims against WCG to Leucadia
resulted in the elimination of $2.26 billion of receivables, and the associated
$2.08 billion allowance, from Williams' Consolidated Balance Sheet. Williams
continues to guarantee approximately $53 million, previously discussed of WCG
obligation under certain contractual commitments.

For more information regarding Williams and WCG, see WCG in Note 2 of Notes
to Consolidated Financial Statements.

OPERATING ACTIVITIES

Cash provided (used) by continuing operating activities was: 2002 -- $(800)
million; 2001 -- $1.7 billion; and 2000 -- $324 million. The 2002 $633.4 million
increase in margin deposits is due to higher deposits required by counterparties
relating to trading activities at Energy Marketing & Trading. The decrease in
accounts payable for 2002 is primarily due to decreased levels of trading
activity at Energy Marketing & Trading. The decrease in receivables which
provides cash in 2002 relates to the decrease in trading activities at Energy
Marketing & Trading offset by the expiration in 2002 of the various sale of
receivables programs which served to delay the realization of cash related to
receivables. The decrease in 2002 of accrued liabilities is due to lower
employee costs and decreased deposits received from customers relating to energy
risk management and trading and hedging activities (see Note 10).

In March 2002, WCG exercised its option to purchase certain network assets
under the ADP transaction for which Williams provided a guarantee of WCG's
obligations. On March 29, 2002, Williams, as guarantor under the agreement, paid
$754 million related to WCG's purchase of these network assets (see WCG section
for further discussion). In 2002, Williams recorded in continuing operations
additional pre-tax charges of $268.7 million related to the settlement of these
receivables and claims (see Note 2). In 2001, Williams had recorded a $188
million charge related to estimated recovery of amounts from WCG.

During 2002, Williams recorded approximately $455 million in provisions for
losses on property and other assets. Those provisions consisted primarily of
impairments of Canadian assets within Midstream Gas & Liquids and impairments of
goodwill and loss accruals related to power generating turbines at Energy
Marketing & Trading. The net gain on disposition of assets in 2002 primarily
relates to the sales of Exploration & Production properties (see Note 4) and
Williams' investment in AB Mazeikiu Nafta (see Note 3).

The amortization of deferred set-up fee and fixed rate interest on the RMT
note payable relates to amounts recognized in the income statement as interest
expense, but generally will not be paid until maturity.

During 2002, Williams was required to provide $108 million of cash
collateral in support of surety bonds underwritten by various insurance
companies and provide cash collateral in support of letters of credit due to
downgrades by credit rating agencies.

During 2002, Williams also made $78 million in contributions to its
qualified pension plans.

FINANCING ACTIVITIES

Net cash provided by financing activities of continuing operations was:
2002 -- $16.6 million; 2001 -- $2.0 billion; and 2000 -- $2.0 billion. Long-term
debt proceeds, net of principal payments, were $1.4 billion, $1.9 billion, and
$283 million, during 2002, 2001, and 2000, respectively. Notes payable payments,
net of notes payable proceeds, were $1.1 billion and $801 million, during 2002
and 2001, respectively. Notes payable proceeds, net of notes payable payments
were $1.5 billion in 2000. The increase in net borrowings from

84

2001 per the Consolidated Balance Sheet also reflects the assumption of the $1.4
billion of WCG notes. The increase in net borrowings during 2001 and 2000
reflects borrowings to fund capital expenditures, investments and acquisitions
of businesses.

On January 14, 2002, Williams completed the sale of 44 million publicly
traded units, more commonly known as FELINE PACS, that include a senior debt
security and an equity purchase contract. The $1.1 billion of 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.

On March 19, 2002, Williams issued $850 million of 30-year notes with an
interest rate of 8.75 percent and $650 million of 10-year notes with an interest
rate of 8.125 percent. The proceeds were used to repay outstanding commercial
paper, provide working capital and for general corporate purposes.

In May 2002, Energy Marketing & Trading entered into an agreement which
transferred the rights to certain receivables, along with risks associated with
that collection, in exchange for cash. Due to the structure of the agreement,
Energy Marketing & Trading accounted for this transaction as debt collateralized
by the claims. The $79 million of debt is classified as current.

As discussed in Note 11 of Notes to Consolidated Financial Statements and
under the Liquidity heading of Management's Discussion and Analysis, RMT entered
into a $900 million credit agreement dated as of July 31, 2002.

For a discussion of other borrowings and repayments in 2002, see Note 11 of
Notes to Consolidated Financial Statements.

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 2002, 2001
and 2000 reflect exercise of stock options under the plans providing for
common-stock-based awards to employees and to non-employee directors.

The proceeds from issuance of preferred stock in 2002 reflect $271 million
in net proceeds for the issuance of approximately 1.5 million shares of 9.875
percent cumulative convertible preferred stock for $275 million, which were
issued concurrent with its sale of Kern River to MEHC. Dividends on the
preferred stock are payable quarterly (see Note 13).

Dividends paid on common stock decreased $110 million from 2001 levels as
Williams' board of directors' reduced the quarterly dividend on common stock,
beginning in July 2002, from $.20 per share to $.01 per share. Additionally, one
of the new covenants within the credit agreements limits the common stock
dividends paid by Williams in any quarter to not more than $6.25 million.
Dividends on common stock in 2001 increased $75.2 million from 2000 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.

In May 2002, Williams Energy Partners L.P., a partially owned and
consolidated entity, issued approximately 8 million common units at $37.15 per
unit resulting in approximately $279 million of net proceeds. Proceeds from sale
of limited partners units of consolidated partnership in 2001 reflect an initial
public offering of Williams Energy Partners L.P., then a wholly owned
partnership, of approximately 4.6 million common units at $21.50 per unit for
net proceeds of approximately $92 million.

In December 2001, Williams received net proceeds of $95.3 million from sale
of a non-controlling preferred interest in Piceance Production Holdings LLC
(Piceance) to an outside investor (see Note 12). During 2000, Williams received
net proceeds totaling $546.8 million from the sale of a preferred return
interest in Snow Goose Associates, L.L.C. (Snow Goose) to an outside investor
(see Note 12). During 2002,

85

changes to these limited liability company member interests and interests in
Castle Associates L.P. (Castle) required classification of these outside
investor interests as debt. The changes to the Snow Goose structure also
included the repayment of the investor's preferred interest in installments.
During 2002, approximately $558 million was repaid related to these interests
and are included in the payments of long-term debt.

In third-quarter 2002, the downgrade of Williams' senior unsecured rating
below BB by Standard & Poor's, or Ba1 by Moody's Investors Service, resulted in
the early retirement of an outside investor's preferred ownership interest for
$135 million (see Note 12).

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.

Long-term debt, including long-term debt due within one year: at December
31, 2002 was $13.0 billion compared with $9.7 billion at December 31, 2001, and
$7.7 billion at December 31, 2000. At December 31, 2001, $844 million of current
debt obligations were classified as noncurrent obligations based on Williams'
intent and ability to refinance on a long-term basis. The 2002 increase in
long-term debt is due primarily to the $1.1 billion related to the FELINE PACS
issuance discussed above, the combined $1.5 billion issued on March 19, 2002 and
the assumption of the $1.4 billion of WCG Note Trust notes. Williams' long-term
debt to debt-plus-equity ratio (excluding debt of discontinued operations) was
70.2 percent at December 31, 2002, compared to 59.0 percent and 52.5 percent at
December 31, 2001 and 2000, respectively. If short-term notes payable and
long-term debt due within one year are included in the calculations, these
ratios would be 73.4 percent at December 31, 2002 compared to 64.8 percent and
62.2 percent at December 31, 2001 and 2000, respectively. Additionally, the
long-term debt to debt-plus-equity ratio as calculated for covenants under
certain debt agreements was 65.2 percent at December 31, 2002 as compared to
61.5 percent at December 31, 2001. See Note 11 of Notes to Consolidated
Financial Statements for discussion of this and other covenants.

Significant items reflected as discontinued operations within financing
activities in the Consolidated Statement of Cash Flows include the cash provided
by financing activities in 2001, primarily reflecting the issuance of $1.4
billion of WCG Note Trust Notes for which Williams provided indirect credit
support (see Note 2). WCG retained all of the proceeds from this issuance. 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. 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.

INVESTING ACTIVITIES

Net cash provided (used) by investing activities of continuing operations
was: 2002 -- $1.3 billion; 2001 -- $(3.3) billion; and 2000 $(2.0) billion.
Capital expenditures of Energy Marketing & Trading, primarily to purchase power
generating turbines, were $136 million in 2002, $104 million in 2001 and $63
million in 2000. Capital expenditures of Gas Pipeline, primarily to expand
deliverability into the east and west coast markets and upgrade current
facilities, were $697 million in 2002, $632 million in $2001, and $448 million
in 2000. Capital expenditures for Midstream Gas & Liquids, primarily to acquire,
expand and modernize gathering and processing facilities and terminals, were
$497 million in 2002, $560 million in 2001, and $326 million in 2000. Capital
expenditures for Exploration & Production, primarily for continued development
of the company's natural gas reserves base through the drilling of wells, were
$380 million in 2002, $218 million in 2001, and $70 million in 2000. Capital
expenditures for Williams Energy Partners, primarily to expand and upgrade
existing facilities, increase storage and develop pipeline connections to new
supply sources, were $40 million in 2002, $35 million in 2001, and $73 million
in 2000. Capital expenditures for Petroleum Services, were $18 million in 2002,
$13 million in 2001, and $42 million in 2000. Budgeted capital expenditures and
investments for continuing operations for 2003 are estimated to be approximately
$900 million to $1.05 billion.

The acquisition of businesses in 2001 reflects the June 11, 2001,
acquisition by Williams of 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

86

of Williams common stock in exchange for the remaining Barrett shares. In 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.

The purchase of investments/advances to affiliates in 2002 includes
approximately $234 million towards the development of the Gulfstream joint
venture project, a Williams equity investment. In 2001, Williams contributed
$437 million toward the development of Williams' joint interest in the
Gulfstream project.

For 2002, net cash proceeds from asset dispositions, the sales of
businesses and disposition of investments include the following:

- $1.15 billion related to the sale of Mid-American and Seminole Pipeline.

- $464 million related to the sale of Kern River.

- $380 million related to the sale of Central.

- $326 million from the sale of properties in Jonah Field and the Anadarko
Basin.

- $229 million related to the sale of the Cove Point LNG facility.

- $173 million related to the sale of Williams' interest in Alliance
Pipeline.

- $85 million related to the sale of Williams' interest in the Lithuanian
refinery.

- $77 million related to the sale of Kansas Hugoton.

- $12 million from the sale of the general partner interest in Northern
Border Partners.

The proceeds received from disposition of investments and other assets in
2001 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.

In 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.

As discussed previously, Williams received $180 million in proceeds from
the sale of claims against WCG to Leucadia in fourth-quarter 2002.

Significant items reflected as discontinued operations within investing
activities of the Consolidated Statement of Cash Flows include the following:

- Capital expenditures of WCG and network and purchase of investments by
WCG, totaled 1.5 billion in 2001 and 4.9 billion in 2000. WCG also had
proceeds from sales of investments of $2.9 billion in 2000.

- Capital expenditures of Kern River, primarily for expansion of its
interstate natural gas pipeline system, were $134 million in 2001 and $5
million in 2000.

87

COMMITMENTS

The table below summarizes some of the more significant contractual
obligations and commitments by period.

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

(1) An additional $228 million will be paid at maturity of the RMT note payable
related to a deferred set-up fee and deferred interest.

(2) Includes $1.1 billion of 6.5 percent notes, payable 2007 subject to
remarketing in 2004 (FELINE PACS). If the remarketing is unsuccessful in
2004 and a second remarketing in February 2005 is unsuccessful as defined in
the offering document of the FELINE PACS, then Williams could exercise its
right to foreclose on the notes in order to satisfy the obligation of the
holders of the equity forward contracts requiring the holder to purchase
Williams common stock.

(3) $67 million was paid in 2003 related to the sale of the travel centers.

(4) 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, 2002, commitments for construction and
acquisition of property, plant and equipment are approximately $448 million. At
December 31, 2002, commitments for additional investment in Gulfstream Natural
Gas System, LLC, and certain international cost investments are $49 million.

RECENTLY ISSUED ACCOUNTING STANDARDS

See Note 1 of Notes to Consolidated Financial Statements for a discussion
of recently issued accounting standards.

EFFECTS OF INFLATION

Williams' cost increases in recent years have benefited from relatively low
inflation rates during that time. Approximately 43 percent of Williams' gross
property, plant and equipment is at Gas Pipeline and approximately 57 percent is
at other operating units. Gas Pipeline is subject to regulation, which limits
recovery to historical cost. While amounts in excess of historical cost are not
recoverable under current FERC practices, 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. For the other
operating units, 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, natural gas liquids and power
prices are particularly sensitive to OPEC production levels and/or the market
perceptions concerning the supply and demand balance in the near future.

88

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 16 of our Notes to Consolidated Financial Statements), 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 is jointly and severally liable along
with unrelated third parties in some of these activities and solely responsible
in others. Current estimates of the most likely costs of such cleanup activities
are approximately $87 million, all of which is accrued at December 31, 2002.
Williams expects to seek recovery of approximately $31 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 our experience with other similar
cleanup operations. At December 31, 2002, 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 regulation at the state and local level. In
September 1998, the EPA promulgated rules designed to mitigate the migration of
ground-level ozone in certain states. Williams estimates that capital
expenditures necessary to install emission control devices over the next five
years to comply with rules will be between $306 million and $344 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 refinery into compliance over the next five years will be
approximately $51 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, 2002, for various compliance issues across the
company are approximately $19 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.

89

ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

INTEREST RATE RISK

Williams' current interest rate risk exposure is related primarily to its
debt portfolio and its energy risk management and trading portfolio.

Williams' interest rate risk exposure resulting from its debt portfolio is
influenced by short-term rates, primarily LIBOR-based borrowings from commercial
banks 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, 2002 and 2001, the amount of Williams' fixed and variable
rate debt was at targeted levels. Williams has historically maintained an
investment grade credit rating as one aspect of managing its interest rate risk.
However, in July 2002, Moody's Investors Service and Standard & Poor's
downgraded their credit ratings of Williams' long-term unsecured debt to below
investment grade.

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. Due to Williams' credit
situation at December 31, 2002, only $300 million notional of interest rate
swaps were outstanding.

The tables on the following page provide information as of December 31,
2002 and 2001, about Williams' interest rate risk sensitive instruments. For
notes payable and long-term debt 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.

90

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

(1) This is the variable rate portion related to these notes which is based on
the Eurodollar rate plus 4 percent per annum. An additional 14 percent fixed
rate, compounded quarterly, accrues to the RMT note payable (see Note 11).

(2) 2002-Weighted-average interest rate through 2006 is LIBOR plus an applicable
margin ranging from 1.125 percent to 5.0 percent, except $178 million at
Eurodollar plus 4.25 percent; weighted-average interest rate in 2007 is
Eurodollar plus 4.25 percent. 2001-Weighted-average interest rates is LIBOR
plus one percent for all years.

(3) The interest rate swaps 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.

COMMODITY PRICE RISK

TRADING

Energy Marketing & Trading and the natural gas liquids trading operations
(reported in the Midstream Gas & Liquids segment) have 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, transmission, and
power tolling contracts. Energy Marketing & Trading and the natural gas liquids
trading operations (reported in the Midstream Gas & Liquids segment) also has
commodity price-risk exposure to crude oil, refined products, electricity and
natural gas in the United States and Europe, natural gas liquids markets in the
United States and the natural gas markets in Canada through other energy
contracts such as forward, futures,

91

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 (see Note 1 of Notes to Consolidated
Financial Statements regarding change in accounting principle due to adoption of
EITF No. 02-3 effective January 1, 2003). 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 and the natural gas
liquids trading operations actively seek 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. A Risk Control Group monitors
compliance with the established trading policy and measures the risk associated
with the trading portfolio.

Energy Marketing & Trading and the natural gas liquids trading operations
(reported in the Midstream Gas & Liquids segment) 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, 2002 and 2001, the value at risk for the trading
operations was $50.2 million and $92.7 million, respectively. This decline in
value at risk is primarily a result of the 28 percent decline in overall
portfolio value outlined in previous sections. 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. The 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 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. While a one-day holding period is the industry standard, a
longer holding period could more accurately represent the true market risk in an
environment where market illiquidity and credit and liquidity constraints of the
company may result in further inability to mitigate risk in a timely manner in
response to changes in market conditions.

NON-TRADING

Williams is also exposed to market risks from changes in energy commodity
prices within Exploration & Production, Petroleum Services, the non-trading
operations of Midstream Gas & Liquids and the non-trading operations of Energy
Marketing & Trading. Exploration & Production has commodity price risk
associated with the sales prices of the natural gas and crude oil it produces.
Petroleum Services' refinery is exposed to commodity price risk for crude oil
purchases and refined product sales. Midstream Gas & Liquids is exposed to
commodity price risk related to natural gas purchases, natural gas liquids
purchases and sales, and electricity cost. Energy Marketing & Trading is exposed
to changing prices of natural gas purchased for the production of electricity.
Williams manages its exposure to certain of these commodity price risks through
the use of derivative commodity instruments.

Williams' non-trading derivative commodity instruments primarily consist of
natural gas price and basis swaps in its Exploration & Production business. A
value-at-risk methodology was used to measure the market risk of these
derivative commodity instruments in the non-trading portfolio. It estimates the
potential one-day loss from adverse changes in the fair value of these
instruments. The value-at-risk model did not consider the underlying commodity
positions to which these derivative commodity instruments relate; therefore, it
is not representative of actual losses that could occur on a total non-trading
portfolio basis that includes the underlying commodity positions. At December
31, 2002, the value-at-risk for the non-trading derivative commodity instruments
was approximately $45 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 non-trading derivative commodity instruments.
The value-at-risk model assumes that as a result of changes in commodity prices
there is a 95 percent probability that the one-day loss in fair value of the
non-trading derivative commodity instruments will not exceed the value-at-risk.
The value-at-risk model uses historical simulations

92

to estimate hypothetical movements in future market prices assuming normal
market conditions based upon historical market prices. Gains and losses on these
derivative commodity instruments would be substantially offset by corresponding
gains and losses on the hedged commodity positions.

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 $130
million and $143 million at December 31, 2002, and 2001, 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, 2002, could change by approximately $26 million
assuming a direct correlation between the currency fluctuation and the value of
the investments.

The net assets of foreign operations whose functional currency is the local
currency, which are consolidated are located primarily in Canada and approximate
15 percent of Williams' net assets at December 31, 2002. These foreign
operations 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 $148 million at December 31, 2002.

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
15). 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 $14 million and $8 million at
December 31, 2002 and 2001, respectively.

93

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, 2002 and 2001, and the related consolidated
statements of operations, stockholders' equity, and cash flows for each of the
three years in the period ended December 31, 2002. Our audits also included the
financial statement schedule listed in the index at Item 15(a). These financial
statements and schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
schedule based on our audits.

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, 2002 and 2001, and the consolidated
results of its operations and its cash flows for each of the three years in the
period ended December 31, 2002, 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, presents fairly in all material respects, the
information set forth therein.

ERNST & YOUNG LLP
Tulsa, Oklahoma
March 5, 2003

94

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

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

* Includes consumer excise taxes of $10.8 million, $33.4 million and $95.6
million in 2002, 2001 and 2000, respectively.
See accompanying notes.

95

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED BALANCE SHEET

See accompanying notes.

96

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

See accompanying notes.

97

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

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

* Includes cash and cash equivalents of discontinued operations of $7.7 million,
$42.6 million and $246.9 million for 2002, 2001 and 2000, respectively.

See accompanying notes.

98

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

2002 OVERVIEW AND RECENT DEVELOPMENTS

Events over the past year and a half have significantly impacted the
Company's operations and these events will have a continuing impact on the
Company's operations in the future. In the first quarter of 2002, as a result of
credit issues facing the Company and the assumption of payment obligations and
performance on guarantees associated with Williams Communications Group, Inc.
(WCG), Williams announced plans to strengthen its balance sheet and support
retention of its then-current investment grade ratings. During first-quarter
2002, Williams sold Kern River Gas Transmission (Kern River). During the second
quarter of 2002, the results of the Energy Marketing & Trading business were not
profitable, reflecting significantly unfavorable market movements against its
portfolio and a decline in origination activities. These unfavorable conditions
were in large part a result of market concerns about Williams' credit and
liquidity situation and limited Energy Marketing & Trading's ability to manage
market risk and exercise hedging strategies as market liquidity deteriorated.
During third-quarter 2002, Williams' credit ratings were lowered below
investment grade. Williams was also unable to complete a renewal of its
unsecured short-term bank credit facility which expired July 24, 2002. Following
these events and in response to a potential liquidity shortfall, Williams sold
assets in July 2002 receiving net proceeds of approximately $1.5 billion,
obtained secured credit facilities totaling $1.3 billion, including the $900
million short-term payable (RMT note payable), and amended its revolving credit
facility to make it secured. Also during the third and fourth quarters of 2002,
Williams completed additional asset sales resulting in net cash proceeds of
approximately $1 billion. Segment losses continued in the third and fourth
quarters of 2002 from the Energy Marketing & Trading business reflecting the
continued negative market movements against the portfolio, the absence of
origination activities and the adverse affects of Williams' overall liquidity
and credit ratings issues, which impact Energy Marketing & Trading's ability to
enter into price risk management and hedging activities.

As of December 31, 2002, the Company has scheduled debt retirements due
through first-quarter 2004 of approximately $3.8 billion, which includes certain
contractual fees and deferred interest associated with an underlying debt, and
anticipates significant additional asset sales to meet its liquidity needs over
that period. The Company has also reduced projected levels of capital
expenditures and the board of directors reduced the quarterly dividend on common
stock beginning in third-quarter 2002 from the prior level of $.20 per share to
$.01 per share. The Company has also announced its intentions to reduce its
commitment to the Energy Marketing & Trading business, which could be realized
by entering into a joint venture with a third party or through the sale of a
portion or all of the marketing and trading portfolio.

On February 20, 2003, Williams outlined its planned business strategy for
the next several years and believes it to be a comprehensive response to the
events which have impacted the energy sector and Williams during 2002. The plan
focuses on retaining a strong, but smaller, portfolio of natural-gas businesses
and bolstering Williams' liquidity through more asset sales, limited levels of
financing at the subsidiary level and additional reductions in its operating
costs. The plan is designed to provide Williams with a clear strategy to address
near-term and medium-term liquidity issues and further de-leverage the company
with the objective of returning to investment grade status by 2005, while
retaining businesses with favorable returns and opportunities for growth in the
future. As part of this plan, Williams expects to generate proceeds, net of
related debt, of nearly $4 billion from asset sales during 2003, including
approximately $2.25 billion in newly announced offerings combined with those
assets already under contract or in negotiations for sale. Newly announced
offerings include the Texas Gas pipeline system, Williams' general partnership
interest and limited partner investment in Williams Energy Partners, and certain
properties and assets within Exploration & Production and Midstream Gas &
Liquids. During first-quarter 2003, Williams closed the sales of the retail
travel centers and the Midsouth refinery.

While the Company believes that these actions will significantly address
liquidity and credit concerns through the first quarter of 2004, the resulting
downsizing of the Company will have a significant impact on

99

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the Company's future financial position and results of operations. The Company's
ability to maintain liquidity and future operations could be significantly
impacted by other events, including the possibility that the asset sales and
reduction of the Company's commitment to its Energy Marketing & Trading business
will not be accomplished as currently anticipated. The timing and amount of
proceeds to be realized from the sale of assets is subject to several variables,
including negotiations with prospective buyers, industry conditions, lender
consents to the sale of collateral, regulatory approvals and Williams'
assessment of its short and long-term liquidity requirements. The reduction of
the Company's commitment to Energy Marketing & Trading activities could be
affected by the willingness of buyers and/or potential partners to enter into
transactions with Williams, giving consideration to the current condition of the
energy trading sector and liquidity and credit constraints of Williams. As a
result of these factors, the proceeds that may be realized from the sales of
assets, including the trading portfolio, may be less than the carrying values at
December 31, 2002, and could result in additional impairments and losses. In the
event that Williams' financial condition does not improve or becomes worse, or
if it fails to complete asset sales and reduce its commitment to its Energy
Marketing & Trading business, Williams may have to consider other options
including the possibility of seeking protection in a bankruptcy proceeding.

DESCRIPTION OF BUSINESS

Operations of The Williams Companies, Inc. (Williams) are located
principally in the United States and are organized into the following reporting
segments: Energy Marketing & Trading, Gas Pipeline, Exploration & Production,
Midstream Gas & Liquids, Williams Energy Partners and Petroleum Services.

Energy Marketing & Trading is a national energy services provider that
buys, sells and transports a full suite of energy-related commodities, including
power, natural gas, crude oil, refined products and emission credits, primarily
on a wholesale level.

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

Exploration & Production includes natural gas exploration, production and
marketing activities primarily in the Rocky Mountain, Midwest and Gulf Coast
regions of the United States and Argentina.

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, majority-owned natural gas compression and
transportation facilities in Venezuela, and assets in Canada including several
natural gas liquids extraction and fractionation plants, a natural gas liquids
pipeline, storage facilities, and a natural gas processing plant.

Williams Energy Partners segment includes Williams Energy Partners L.P. (a
partially-owned and consolidated entity of Williams) and Williams' general
partnership interests. Williams GP LLC, WEG GP LLC, Williams Energy Partners
L.P. and its subsidiaries are legally separate and distinct entities from The
Williams Companies, Inc. and its other subsidiaries. The assets owned by
Williams Energy Partners L.P., Williams GP LLC and WEG GP LLC, are generally not
available for the payment of debts owed to the creditors of Williams and its
other subsidiaries. Williams Energy Partners L.P. includes a network of storage,
transportation and distribution assets for crude petroleum products and ammonia
and a petroleum products pipeline.

Petroleum Services includes petroleum refining and marketing in Alaska and
convenience stores in Alaska. Prior year amounts for Petroleum Services also
include the results of operations of convenience stores in the Midsouth which
were sold in May 2001. Williams is currently pursuing the sale of the Alaska
operations.

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On February 20, 2003, Williams announced that it was pursuing the sales of
its Texas Gas pipeline system and its general partnership interest and limited
partner investment in Williams Energy Partners, and certain properties and
assets within Exploration & Production and Midstream Gas & Liquids.

BASIS OF PRESENTATION

In accordance with the provisions related to discontinued operations within
Statement of Financial Accounting Standard (SFAS) No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," the accompanying consolidated
financial statements and notes reflect the results of operations, financial
position and cash flows of the following components as discontinued operations
(see Note 2):

- Kern River Gas Transmission (Kern River), previously one of Gas
Pipeline's segments

- Central natural gas pipeline, previously one of Gas Pipeline's segments

- Colorado soda ash mining operations, part of the previously reported
International segment

- Two natural gas liquids pipeline systems, Mid-America Pipeline and
Seminole Pipeline, previously part of the Midstream Gas & Liquids segment

- Refining and marketing operations in the Midsouth, including the Midsouth
refinery, previously part of the Petroleum Services segment

- Retail travel centers concentrated in the Midsouth, previously part of
the Petroleum Services segment

- Bio-energy operations, previously part of the Petroleum Services segment

Additionally, the results of operations and cash flows of WCG are reflected
as discontinued operations in the accompanying financial statements.

Unless indicated otherwise, the information in the Notes to the
Consolidated Financial Statements relates to the continuing operations of
Williams. Williams expects that other components of its business will be
classified as discontinued operations in the future as the sales of those assets
occur.

Additionally, activities of certain of Williams' segments were realigned or
changed due to certain transactions during 2002. These realignments include the
following:

- During first-quarter 2002, management of APCO Argentina was transferred
from the previously reported International segment to the Exploration &
Production segment.

- On April 11, 2002, Williams Energy Partners L.P., a partially owned and
consolidated entity of Williams, acquired Williams Pipe Line, an
operation previously included within Petroleum Services. Accordingly,
Williams Pipe Line's operations have been transferred from the Petroleum
Services segment to the Williams Energy Partners segment.

- Effective July 1, 2002, management of certain operations previously
conducted by Energy Marketing & Trading, International and Petroleum
Services was transferred to Midstream Gas & Liquids. These operations
included natural gas liquids trading, activities in Venezuela and a
petrochemical plant, respectively.

- The remaining operations of the previously reported International segment
have been included within Other as a result of the decrease in
significance of that segment.

Any segment information in the Notes to the Consolidated Financial
Statements has been restated for all prior periods presented to reflect the
changes noted above.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In 2001, through two transactions, Williams acquired all of the outstanding
stock of Barrett Resources Corporation (Barrett). On June 11, 2001, Williams
acquired 50 percent of Barrett's outstanding common stock in a cash tender offer
totaling 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 unaudited pro forma net income (loss) for 2001 and 2000, if the
purchase of 100 percent of Barrett occurred at the beginning of each of those
years, was $(396.0) million and $480.9 million, respectively, or $(.76) per
diluted share and $1.00 per diluted share. 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 estimated fair values of the significant assets acquired and
liabilities assumed at August 2, 2001, the date of acquisition, were: Current
assets-$127.6 million; Property, plant & equipment-$2,520.4 million; Goodwill
and other assets-$1,114.5 million; Current liabilities-$171.6 million; Long-term
debt-$312.1 million; Deferred income taxes-$634.7 million; and Other noncurrent
liabilities-$127.1 million.

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) impairment assessments of long-lived
assets and goodwill; 2) litigation-related contingencies; 3) valuations of
energy contracts, including energy-related contracts; 4) environmental
remediation obligations; 5) realization of amounts due from WCG; 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.

RESTRICTED CASH

Restricted cash within current assets consists primarily of cash collateral
as required under the $900 million short-term Credit Agreement (see Note 11) and
letters of credit. Restricted cash within noncurrent assets consists primarily
of collateral in support of surety bonds underwritten by an insurance company,
debt service reserves and letters of credit. Williams does not expect this cash
to be released within the next twelve months.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The current and noncurrent restricted cash is primarily invested in
short-term money market accounts with financial institutions and an insurance
company as well as treasury securities. The classification of restricted cash is
determined based on the expected term of the collateral requirement and not
necessarily the maturity date of the underlying securities.

ACCOUNTS RECEIVABLE

Accounts receivable are carried on a gross basis, with no discounting, less
the allowance for doubtful accounts. No allowance for doubtful accounts is
recognized at the time the revenue, which generates the accounts receivable, is
recognized. Management estimates the allowance for doubtful accounts based on
existing economic conditions, the financial conditions of the customers and the
amount and age of past due accounts. Receivables are considered past due if full
payment is not received by the contractual due date. Interest income related to
past due accounts receivable is recognized at the time full payment is received.
Past due accounts are generally written off against the allowance for doubtful
accounts only after all collection attempts have been exhausted.

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 and Midstream Gas & Liquids, which are primarily stated at
fair value prior to the application of Emerging Issues Task Force (EITF) Issue
No. 02-3 (see Recent accounting standards). The cost of 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.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment is recorded at cost. The carrying value of
these assets is also based on estimates, assumptions and judgments relative to
capitalized costs, useful lives and salvage values. 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 (loss).

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

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 Resources Corporation, was not
amortized in 2001.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Beginning January 1, 2002, all goodwill is no longer amortized, but is tested
annually for impairment. Application of the nonamortization provisions of SFAS
No. 142 did not materially impact the comparability of the Consolidated
Statement of Operations. Energy Marketing & Trading's goodwill was approximately
$45 million and $106 million at December 31, 2002, and December 31, 2001,
respectively (see Note 4). Exploration & Production's goodwill was approximately
$1 billion at December 31, 2002 and 2001.

Beginning January 1, 2002, the impairment of goodwill and other intangible
assets is measured pursuant to the guidelines of SFAS No. 142. Goodwill is
evaluated for impairment by first comparing management's estimate of the fair
value of a reporting unit with its carrying value, including goodwill. If the
carrying value exceeds its fair value, a computation of the implied fair value
of the goodwill is compared with its related carrying value. If the carrying
value of the reporting unit goodwill exceeds the implied fair value of that
goodwill, an impairment loss is recognized in the amount of the excess.

When a reporting unit is sold or classified as held for sale, any goodwill
of that reporting unit is included in its carrying value for purposes of
determining any impairment or gain/loss on sale. If a portion of a reporting
unit with goodwill is sold or classified as held for sale and that asset group
represents a business, a portion of the reporting unit's goodwill is allocated
to and included in the carrying value of that asset group. Except for
bio-energy, none of the operations sold during 2002 or classified as held for
sale at December 31, 2002 represented reporting units with goodwill or
businesses within reporting units to which goodwill was required to be
allocated.

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

TREASURY STOCK

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 AND REVENUES

Williams, through Energy Marketing & Trading and the natural gas liquids
trading operations (reported within the Midstream Gas & Liquids segment), has
energy commodity risk management and trading operations that enter into energy
and energy-related contracts to provide price-risk management services to its
third-party customers involving power, natural gas, refined products, natural
gas liquids and crude oil. 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 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. See Recent
accounting standards section within this Note for changing accounting standards
regarding recording certain energy contracts and commodity trading inventories
at fair value. Energy contracts include forward contracts, futures contracts,
option contracts, swap agreements, certain physical 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. These energy contracts and credit default swap agreements,
with the exception of physical trading commodity inventories, are recorded in
current and noncurrent energy risk management and

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 and the natural gas liquids trading operations, report their
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." 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.
See Recent accounting standards section within this Note for recent developments
regarding guidance determining whether an arrangement contains a lease.

The fair values of energy and energy-related contracts are 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, while
other transactions are executed where quoted market prices are not available or
the contracts extend into periods 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 and the natural gas liquids trading operations
transact. Market data in active periods is also available for interest rate
transactions affecting the trading portfolio. For contracts or transactions that
extend into periods for which actively quoted prices are not available, Energy
Marketing & Trading and the natural gas trading operations estimate energy
commodity prices in the illiquid periods by incorporating information obtained
from commodity prices in actively quoted markets, prices in less active 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, transmission and power
tolling contracts (energy-related contracts), Energy Marketing & Trading
estimates fair value using proprietary models and other valuation techniques
that reflect the best information available under the circumstances. In
situations where Energy Marketing & Trading has received current information
from negotiation activities with potential buyers of these contracts, the
information is considered in the determination of the fair value of the
contract. The valuation techniques used when estimating fair value for
energy-related contracts 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.
The estimates of fair value also assume liquidating the positions in an orderly
manner over a reasonable period of time in a transaction between a willing buyer
and seller. 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. The estimates
of fair value are adjusted as assumptions change or as transactions become
closer to settlement and enhanced estimates become available.

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

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 Williams' 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 illiquid
periods and markets, estimating market volatility and liquidity and correlation
of natural gas and power prices, evaluating risk arising from uncertainty
inherent in estimating cash flows and estimates regarding counterparty
performance and credit considerations. Changes in valuation methodologies or the
underlying assumptions could result in significantly different fair values.

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.

REVENUES, OTHER THAN GAS PIPELINE AND ENERGY COMMODITY RISK MANAGEMENT AND
TRADING ACTIVITIES

Revenues generally are recorded when services have been performed or
products have been delivered. A portion of Williams Energy Partners' operations
is subject to FERC regulations and, accordingly, the method of recording these
revenues is consistent with Gas Pipeline's method discussed above. Certain
Midstream Gas & Liquids revenues are from trading activities. See the previous
discussion of Energy commodity risk management and trading activities and
revenues for additional information.

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

All derivatives, other than derivatives within Midstream Gas & Liquids and
Energy Marketing & Trading's energy commodity risk management and trading
activities which are accounted for at fair value as discussed above, 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, 2002 and 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.

In first-quarter 2002, Williams began managing its interest rate risk on an
enterprise basis by the corporate parent. The more significant of these risks
relate to its debt instruments and its energy risk

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

management and trading portfolio. To facilitate the management of the risk,
entities within Williams may enter into derivative instruments (usually swaps)
with the corporate parent. The level, term and nature of derivative instruments
entered into with external parties are determined by the corporate parent.
Energy Marketing & Trading has entered into intercompany interest rate swaps
with the corporate parent, the effect of which is included in Energy Marketing &
Trading's segment revenues and segment profit (loss) as shown in the
reconciliation within the segment disclosures (Note 19). The results of interest
rate swaps with external counterparties are shown as interest rate swap loss in
the Consolidated Statement of Operations below operating income (loss).

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.

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, derivatives that cease to be highly effective hedges and cash flow
hedges that have been otherwise discontinued remain in accumulated other
comprehensive income until the hedged item affects earnings or it is probable
that the hedged item will not occur by the end of the originally specified time
period or within two months thereafter. Forecasted transactions designated as
the hedged item in a cash flow hedge are regularly evaluated to assess whether
they continue to be probable of occurring. When it is probable the forecasted
transaction will not occur, any gain or loss deferred in accumulated other
comprehensive income is recognized in earnings at that time.

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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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).

IMPAIRMENT OF LONG-LIVED ASSETS

Williams evaluates the long-lived assets 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. Beginning January 1, 2002, the impairment evaluation of tangible
long-lived assets is measured pursuant to the guidelines of SFAS No. 144. When
an indicator of impairment has occurred, 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. A
probability-weighted approach is applied to consider the likelihood of different
cash flow assumptions and possible outcomes including a sale in the near term or
hold for the remaining estimated useful life. 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 and considered held
for sale in accordance with SFAS No. 144, 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, which includes estimated cash flows from operations until
the assumed date of sale, 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. Additionally, management's judgment is used to determine the
probability of sale with respect to assets considered for disposal pursuant to
Williams' announced strategy of selling assets as a significant source of
liquidity. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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. The plans are
described more fully in Note 14. The following table illustrates the effect on
net income and earnings per share if the Company had applied the fair value
recognition provisions of SFAS No. 123, "Accounting for Stock-Based
Compensation."

Pro forma amounts for 2002 include compensation expense from certain
Williams awards made in 1999 and compensation expense from Williams awards made
in 2002 and 2001.

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 $36.7 million
for Williams awards and $106.3 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 are
generally made each year, pro forma amounts may not be representative of future
years' amounts.

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.

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EARNINGS (LOSS) PER SHARE

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

FOREIGN CURRENCY TRANSLATION

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 and Euro. Assets and liabilities of certain foreign subsidiaries and
equity investees are translated at the spot rate in effect at the applicable
reporting date, and the combined statements of operations and Williams' share of
the results of operations of its equity affiliates are translated into the U.S.
dollar at the average exchange rates in effect during the applicable period. The
resulting cumulative translation adjustment is recorded as a separate component
of other comprehensive income (loss).

Transactions denominated in currencies other than the functional currency
are recorded based on exchange rates at the time such transactions arise.
Subsequent changes in exchange rates result in transactions gains and losses
which are reflected in the Consolidated Statement of Operations.

ISSUANCE OF EQUITY OF CONSOLIDATED SUBSIDIARY

Sales of 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

Through July 2002, Williams had agreements to sell, on an ongoing basis,
certain of its trade accounts receivable through revolving securitization
structures and retained servicing responsibilities as well as a subordinate
interest in the transferred receivables. These agreements expired in July 2002
and were not renewed. Williams accounted 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 were removed from the Consolidated Balance Sheet
and a retained interest was recorded for the amount of receivables sold in
excess of cash received.

Williams determined 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 were updated
periodically based on actual results, thus the estimated credit loss and
discount rates utilized were materially consistent with historical performance.
The fair value of the servicing responsibility was 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.

RECENT ACCOUNTING STANDARDS

The Financial Accounting Standards Board (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 SFAS 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

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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 with the impact of adoption to be reported
as a cumulative effect of change in accounting principle.

Williams adopted the new rules on asset retirement obligations on January
1, 2003. As required by the new rules, Williams recorded liabilities equal to
the present value of expected future asset retirement obligations at January 1,
2003. The obligations related to producing wells, offshore platforms and
underground storage caverns. The liabilities are partially offset by increases
in net assets, net of accumulated depreciation, recorded as if the provisions of
the Statement had been in effect at the date the obligation was incurred. As a
result of the adoption of SFAS No. 143, Williams recorded a long-term liability
of $33 million; property, plant and equipment, net of accumulated depreciation,
of $15 million and a cumulative effect of a change in accounting principle of $5
million (net of $3 million of taxes). Williams also recorded a $10 million
regulatory asset for retirement costs expected to be recovered through regulated
rates. In connection with adoption of SFAS No. 143, Williams changed its method
of accounting to include salvage value of equipment related to producing wells
in the calculation of depreciation, resulting in a $9 million reduction in
accumulated depreciation and a cumulative effect of change in accounting
principle of $6 million (net of $3 million of taxes) in 2003.

Williams has not recorded liabilities for pipeline transmission assets,
processing and refining assets, and gas gathering systems. A reasonable estimate
of the fair value of the retirement obligations for these assets cannot be made
as the remaining life of these assets is not currently determinable.

The FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and
64, Amendment of FASB Statement No. 13, and Technical Corrections." The
rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment of
Debt," and SFAS No. 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund
Requirements," requires that gains and losses from extinguishment of debt only
be classified as extraordinary items in the event that they meet the criteria of
APB Opinion No. 30. SFAS No. 44, "Accounting for Intangible Assets of Motor
Carriers," established accounting requirements for the effects of transition to
the Motor Carriers Act of 1980 and is no longer required now that the
transitions have been completed. Finally, the amendments to SFAS No. 13 require
certain lease modifications that have economic effects which are similar to
sale-leaseback transactions be accounted for as sale-leaseback transactions. The
provisions of this Statement related to the rescission of SFAS No. 4 are to be
applied in fiscal years beginning after May 15, 2002, while the provisions
related to SFAS No. 13 are effective for transactions occurring after May 15,
2002. All other provisions of the Statement are effective for financial
statements issued on or after May 15, 2002. There was no initial impact of SFAS
No. 145 on Williams' results of operations and financial position. However, in
subsequent reporting periods, any gains and losses from debt extinguishments
will not be accounted for as extraordinary items.

The FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or
Disposal Activities." This Statement addresses financial accounting and
reporting for costs associated with exit or disposal activities and nullifies
EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred
in a Restructuring)." Under this Statement, a liability for a cost associated
with an exit or disposal activity is recognized at fair value when the liability
is incurred rather than at the date of an entity's commitment to an exit plan.
The provisions of this Statement are effective for exit or disposal activities
that are initiated after December 31, 2002; hence, initial adoption of this
Statement on January 1, 2003, did not have any impact on Williams' results of
operations or financial position.

The FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation -- Transition and Disclosure," which is effective for fiscal years
ending after December 15, 2002. SFAS No. 148 amends SFAS No. 123 to permit two
additional transition methods for a voluntary change to the fair value based
method of accounting for stock-based employee compensation from the intrinsic
method under APB No. 25. The

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prospective method of transition under SFAS No. 123 is an option to the entities
that adopt the recognition provisions under this statement in a fiscal year
beginning before December 15, 2003. In addition, SFAS No. 148 amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements concerning the method of accounting used
for stock-based employee compensation and the effects of that method on reported
results of operations. Under SFAS No. 148, pro forma disclosures will be
required in a specific tabular format in the "Summary of Significant Accounting
Policies." Williams has applied the disclosure requirements of this statement
effective December 31, 2002. The adoption had no effect on Williams'
consolidated financial position or results of operations. Williams continues to
account for its stock-based compensation plans under APB Opinion No. 25. See
Employee stock-based awards.

The FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others." This Interpretation requires the fair value of
guarantees issued or modified after December 31, 2002, be initially recognized
by the guarantor at the inception of the guarantee, and expands the disclosure
requirements for guarantees. Initial adoption of this Interpretation did not
have any impact on Williams' results of operations or financial position. The
expanded disclosure requirements have been presented in the Notes to
Consolidated Financial Statements.

The FASB issued FASB Interpretation No. 46, "Consolidation of Variable
Interest Entities." The Interpretation defines a variable interest entity (VIE)
as an entity in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. The investments or other interests that will absorb
portions of the VIE's expected losses or receive portions of the VIE's expected
residual returns are called variable interests. Variable interests may include,
but are not limited to, equity interests, debt instruments, beneficial
interests, derivative instruments and guarantees. The Interpretation requires an
entity to consolidate a VIE if that entity will absorb, through either a single
variable interest or combination of variable interests, a majority of the VIE's
expected losses, receive a majority of the VIE's expected residual returns, or
both. If no party will absorb a majority of the expected losses or expected
residual returns, no party will consolidate the VIE. The Interpretation must be
applied to all VIE's created after January 31, 2003 and to existing VIE's for
periods beginning after June 15, 2003. The assets, liabilities and
non-controlling interests of a VIE consolidated as a result of this
Interpretation should be measured and recorded at their carrying amount at the
effective date of the Interpretation. Any difference between the net
consolidated amount and the amount of any previously recognized interest in the
newly consolidated entity shall be recognized as the cumulative effect of a
change in accounting principle. Williams has completed a preliminary review of
its investments and contractual arrangements to identify variable interest
entities to meet the 2002 disclosure requirements of the Interpretation and has
presented such disclosures in the Notes to Consolidated Financial Statements.
Williams has not completed its full evaluation but currently believes that the
effect of adoption of the Interpretation will not be material to the
consolidated financial statements.

On October 25, 2002, the EITF reached a consensus on Issue No. 02-3,
"Issues Related to Accounting for Contracts Involved in Energy Trading and Risk
Management Activities." This Issue rescinds EITF Issue No. 98-10, the impact of
which is to preclude fair value accounting for energy trading contracts that are
not derivatives pursuant to SFAS No. 133 and commodity trading inventories. The
EITF also reached a consensus that gains and losses on derivative instruments
within the scope of SFAS No. 133 should be shown net in the income statement if
the derivative instruments are held for trading purposes. The consensus is
applicable for fiscal periods beginning after December 15, 2002, except for
physical trading commodity inventories purchased after October 25, 2002 which
may not be reported at fair value. Williams will initially apply the consensus
effective January 1, 2003 and will report the initial application as a
cumulative effect of a change in accounting principle. The effect of initially
applying the consensus will reduce net income by approximately $750 million to
$800 million on an after tax basis. Physical trading commodity inventories at
December 31, 2002 that were purchased prior to October 25, 2002 were reported at
fair value at December 31, 2002 and

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included in the effect of initially applying the consensus. The change results
primarily from power tolling load serving, transportation and storage contracts
not meeting the definition of a derivative and no longer being reported at fair
value. These contracts will be accounted for under an accrual model. Physical
trading commodity inventories will be stated at cost, not to be in excess of
market.

The accounting for Energy Marketing & Trading's energy-related contracts,
which include contracts such as transportation, storage, load serving and
tolling agreements, requires Williams to assess whether certain of these
contracts are executory service arrangements or leases pursuant to SFAS No. 13.
On January 23, 2003, the EITF reached a tentative consensus on Issue No. 01-8,
"Determining Whether an Arrangement Contains a Lease," and directed the Working
Group considering this Issue to further address certain matters, including
transition. The March 14, 2003 report of the Working Group indicates the Working
Group supports a prospective transition of this Issue where the consensus would
be applied to arrangements consummated or substantively modified after the date
of the final consensus. Williams is currently reviewing the impact of the
tentative consensus on its energy-related contracts. Williams' preliminary
review indicates that certain tolling agreements could be leases under the
tentative consensus. If the EITF did not adopt a prospective transition and
applied the consensus to existing arrangements there could be a significant
impact to Williams' financial position and results of operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 2. DISCONTINUED OPERATIONS

SUMMARIZED RESULTS OF DISCONTINUED OPERATIONS

Summarized results of discontinued operations for the years ended December
31, 2002, 2001, and 2000 are as follows:

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

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

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SUMMARIZED ASSETS AND LIABILITIES OF DISCONTINUED OPERATIONS

Summarized assets and liabilities of discontinued operations as of December
31, 2002 and 2001, are as follows:

The December 31, 2002 amounts include the assets and liabilities of the
soda ash operations, the Midsouth refinery and related assets, the travel
centers, and the bio-energy facilities as these had been approved for sale by
Williams' board of directors although the sales were not yet complete. Because
the sales are expected to close within twelve months, the noncurrent assets and
liabilities of discontinued operations have been included in the current section
of the Consolidated Balance Sheet as assets and liabilities held for sale at
December 31, 2002. Therefore, the total assets of $981.3 million and the total
liabilities of $304.1 million are recorded as current assets and current
liabilities of discontinued operations in the Consolidated Balance Sheet at
December 31, 2002. For 2001, the noncurrent assets and liabilities for these
assets were not reclassified to current assets and liabilities in the
Consolidated Balance Sheet, but are included in the assets and liabilities of
discontinued operations.

2002 TRANSACTIONS

As previously discussed, Williams began the process in 2002 of selling
assets and/or businesses to address liquidity issues. In accordance with the
provisions related to discontinued operations within SFAS No. 144, the results
of operations (including any impairments, gains or losses), financial position
and cash flows for the following assets and/or businesses, which have been sold
or approved for sale, have been reflected in the consolidated financial
statements and notes as discontinued operations:

Kern River

On March 27, 2002, Williams completed the sale of its Kern River pipeline
for $450 million in cash and the assumption by the purchaser of $510 million in
debt. As part of the agreement, $32.5 million of the purchase price was
contingent upon Kern River receiving a certificate from the FERC to construct
and operate a future expansion. This certificate was received in July 2002 and
the contingent payment plus interest was recognized as income from discontinued
operations in third-quarter 2002. Included as a component of

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impairments and net losses on sales from discontinued operations (included in
the preceding table) is a pre-tax loss of $6.4 million for the year ended
December 31, 2002. Kern River was a segment within Gas Pipeline.

Central

During third-quarter 2002, Williams' board of directors approved an
agreement to sell Central natural gas pipeline, for $380 million in cash and the
assumption by the purchaser of $175 million in debt. The sale closed November
15, 2002. The sale agreement resulted from efforts to market this asset through
a reserve price auction process that was initiated during second-quarter 2002.
Included as a component of impairments and net losses on sales (included in the
preceding table) is a pre-tax loss of $91.3 million for the year ended December
31, 2002. Central was a segment within Gas Pipeline.

Soda ash operations

In March 2002, Williams announced its intentions to sell its soda ash
mining facility located in Colorado. During third-quarter 2002, Williams' board
of directors approved a plan authorizing management to negotiate and facilitate
a sale of its interest in the soda ash operations pursuant to terms of a
proposed sales agreement. As a result of the board of directors' approval and
management's expectation of consummation of a sale, these operations met the
criteria within SFAS No. 144 to be reported as held for sale at December 31,
2002. The soda ash facility was previously written-down by $170 million in
fourth-quarter 2001 to an estimated fair value at December 31, 2001. In April
2002, Williams initiated a reserve-auction process. As this process and
negotiations with interested parties progressed through 2002, new information
regarding estimated fair value became available. As a result, additional
impairment charges totaling $133.5 million were recognized in 2002. The
impairment charges are recorded as a component of impairments and net losses on
sales (included in the preceding table), and are reflective of management's
estimate of fair value associated with revised terms of its negotiations to sell
the operations. The soda ash operations were part of the previously reported
International segment.

Mid-America and Seminole Pipelines

On August 1, 2002, Williams completed the sale of its 98 percent interest
in Mid-America Pipeline and 98 percent of its 80 percent ownership interest in
Seminole Pipeline for $1.2 billion. The sale generated net cash proceeds of
$1.15 billion. Included as a component of impairments and net losses on sales
(included in the preceding table) is a pre-tax gain of $301.7 million for the
year ended December 31, 2002. These assets were part of the Midstream Gas &
Liquids segment. A performance guarantee of $50 million for Seminole Pipeline
remained in effect at December 31, 2002. This guarantee was terminated in
February 2003.

Midsouth refinery and related assets

During the second quarter of 2002, management announced its intention to
sell its refining operations. On November 26, 2002 and pursuant to board of
director approval, Williams announced it had reached an agreement to sell its
refinery and other related operations located in Memphis, Tennessee. Impairment
charges totaling $240.8 million were recorded during 2002 to reduce the carrying
cost to management's estimate of fair market value based on information
available through the reserve auction process and sales agreement negotiations.
These impairments are recorded as components of impairments and net losses on
sales (included in the preceding table). The sale closed on March 4, 2003. These
operations were part of the Petroleum Services segment.

Williams travel centers

The travel centers had been identified as a business that does not fit into
the new core focus and were marketed for sale through a reserve auction process.
During the fourth quarter 2002 and pursuant to board of

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director approval, Williams announced that it had signed a definitive agreement
for the sale of the travel centers. Impairment charges and liability accruals
totaling $146.6 million were recorded during 2002 to reduce the carrying cost to
management's estimate of fair market value based on information available
through the reserve auction process and sales agreement negotiations. In 2001,
Williams also recorded $14.7 million of impairment and loss accruals relating to
the travel centers. These impairments are recorded as components of impairments
and net losses on sales from discontinued operations (included in the preceding
table). The sale closed on February 27, 2003. These operations were part of the
Petroleum Services segment.

Bio-energy facilities

Williams' bio-energy operations have been identified as assets not related
to the new more narrowly focused business. During fourth-quarter 2002, Williams'
board of directors approved a plan authorizing management to negotiate and
facilitate a sale pursuant to terms of a proposed sales agreement. As a result
of the board of directors' approval and management's expectation of consummation
of a sale with the year, these operations met the criteria within SFAS No. 144
to be held for sale at December 31, 2002. On February 20, 2003, Williams
announced it had signed a definitive agreement to sell these operations to a new
company formed by Morgan Stanley Capital Partners. Impairment charges totaling
$195.7 million, including $23 million related to goodwill, were recorded in 2002
to reduce the carrying cost to management's estimate of fair market value based
on information available through a reserve auction process and sales agreement
negotiations. These impairments are recorded as components of impairments and
net losses on sales (included in the preceding table). These operations were
part of the Petroleum Services segment.

WCG

Spinoff and 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. In accordance with APB 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
results of operations, financial position and cash flows for WCG have been
reflected in the accompanying consolidated financial statements and notes as
discontinued operations.

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 the Williams Technology Center (Technology Center) and
other ancillary assets under construction and a commitment to complete the
construction. In return, Williams received 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 billion, which
included an increase to accumulated other comprehensive income of approximately
$21.3 million. The WCG shares retained by Williams had a carrying value of $95.9
million at the spinoff date.

In addition, prior to the spinoff, Williams provided indirect credit
support for $1.4 billion of WCG's Note Trust Notes. 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, eliminated
acceleration of the WCG Note Trust Notes due to a WCG bankruptcy or from a
Williams credit rating downgrade. The amendment also affirmed Williams'
obligation for all payments due with respect to the WCG Note Trust Notes, which
mature in March, 2004, and allows Williams to fund such payments from any
available sources. See 2002 developments and accounting below for an update.

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Williams also provided a guarantee of WCG's obligations under a 1998 asset
defeasance program (ADP) transaction in which WCG entered into a lease agreement
covering a portion of its fiber-optic network. WCG had an option to purchase the
covered network assets during the lease term at an amount approximating lessor's
cost of $750 million. See 2002 developments and accounting below for an update.

2001 post spinoff and accounting

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 Technology Center and the acquisition costs
of the ancillary assets and aircraft. Williams then entered into long-term lease
arrangements under which WCG was the sole lessee of the Technology Center and
aircraft.

Disclosures and announcements by WCG, prior to the filing of Williams 2001
Annual Report on Form 10-K on March 7, 2002, including WCG's announcement that
it might seek to reorganize under the U.S. Bankruptcy Code, resulted in Williams
concluding that it was probable that it would not fully realize the $375 million
of receivables from WCG at December 31, 2001 nor recover its investment in WCG
common stock. The receivables included a $106 million deferred payment for
services provided to WCG prior to the spinoff and $269 million from the long
term lease to WCG of the Technology Center and aircraft. In addition, Williams
determined that it was probable that it would be required to perform under the
$2.21 billion of guarantees and payment obligations, including the indirect
credit support for $1.4 billion of WCG's Note Trust Notes and the guarantee of
WCG's obligations under the ADP transaction. Other events that affected
Williams' assessment included 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 prior to March 7, 2002 and under the circumstances, 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 that time, management believed that no loss within the range was more
probable than another. Accordingly, Williams 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.

The charge to discontinued operations in 2001 of $1.84 billion includes
$1.77 billion minimum amount of the estimated range of loss from performance on
$2.21 billion of guarantees and payment obligations, interest of $58 million on
the WCG Note Trust Notes assumed by Williams and other expenses. With the
exception of the interest on the WCG Note Trust Notes and other expenses,
Williams assumed for purposes of this estimated loss that it would become an
unsecured creditor of WCG for all or part of the amounts paid under the
guarantees and payment obligations. However, it was probable that Williams would
not be able to recover a significant portion of these unsecured claims. The
estimated loss from the performance of the guarantees and payment obligations
was based on the overall estimate of recoveries on amounts owed Williams as
discussed below. Due to the amendment of the WCG Note Trust Notes discussed
above, $1.1 billion of the accrued loss was classified as a long-term liability
in the Consolidated Balance Sheet at December 31, 2001.

The charge to continuing operations in 2001 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 the remaining $25 million
investment in WCG common stock. In third-quarter 2001, Williams recognized a
$70.9 million loss related to the write-down of its investment in WCG common
stock due to the decline in value which was determined to be other than
temporary. A provision of $85 million on the deferred payment was based on the
overall estimate of recoveries on amounts receivable using the same assumptions
on collectability as discussed below. A provision of $103 million on the minimum
lease payments receivable was based on an estimate of the fair value of the

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leased assets. The $25 million write-off of the WCG stock investment was based
on management's assessment of realization as a result of WCG's balance sheet
restructuring program.

The estimated range of loss assumed that Williams, as a creditor of WCG,
would recover only a portion of its unsecured claims against WCG. Such claims
included 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 that
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 differed from the 2001
recorded loss as Williams recognized additional losses in 2002.

The minimum amount of loss in the range was estimated based on recoveries
from a successful reorganization process under Chapter 11 of the U.S. Bankruptcy
Code. 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 were valued using discount
rates ranging from 17 percent to 25 percent. The range of cash flows was 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
considered 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
considered recoveries based on transaction values from recent telecommunications
restructurings and from a liquidation of WCG's assets.

At December 31, 2001, Williams had financial exposure from WCG of $375
million of receivables for which allowances totaling $188 million were
established in 2001 and $2.21 billion of guarantees and payment obligations for
which a total accrued loss of $1.77 billion was recorded in 2001.

2002 developments and accounting

In 2002, Williams acquired all of the WCG Note Trust Notes by exchanging
$1.4 billion of Williams Senior Unsecured 9.25 percent Notes due March 2004. WCG
was indirectly obligated to reimburse Williams for any payments Williams is
required to make in connection with the WCG Note Trust Notes.

On March 29, 2002, Williams funded the purchase price of $754 million
related to WCG's March 8, 2002 exercise of its option to purchase the covered
network assets under the ADP transaction. Williams then became entitled to an
unsecured note from WCG for the same amount.

On April 22, 2002, WCG filed for bankruptcy protection under Chapter 11 of
the U.S. Bankruptcy Code. WCG's Chapter 11 Plan of Reorganization (Plan) was
confirmed by the United States Bankruptcy Court for the Southern District of New
York (Court) on September 30, 2002. On October 15, 2002, WCG consummated the
Plan. The Plan includes (1) mutual releases, effective October 15, 2002, between
WCG (and all of its affiliates and each of their present and former directors,
officers, employees and agents), the Official Creditors Committee and Williams
(and all of its affiliates and each of their present and former directors,
officers, employees and agents), which forever bar causes of action against
Williams that are based in whole or in part on any act, omission, event,
condition or thing in existence or that occurred in whole or in part prior to
October 15, 2002, and arising out of or relating in any way to WCG or its
present or former assets; (2) a channeling injunction, effective October 15,
2002, which enjoins the holders of unsecured claims against WCG from taking any
action to assert, seek or obtain a recovery from Williams; (3) the sale by
Williams to Leucadia National Corporation (Leucadia) for $180 million in cash of
Williams' claims against WCG related to the WCG Note Trust Notes, the funding of
the WCG purchase option for the covered network assets and

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the deferred payment for services and (4) the sale by Williams to WCG of the
Technology Center for (a) a seven and one-half year promissory note in the
principal amount of $100 million with interest at 7 percent (Long Term Note),
and (b) a four year promissory note (which may be pre-paid without penalty) with
a face amount of $74.4 million and an original principal amount of $44.8 million
(Short Term Note), both of which are secured by a mortgage on the Technology
Center and certain other collateral. Interest on the principal amount of the
Short Term Note is capitalized on December 31 of each year beginning in 2003 and
accrues at the following rates: 10 percent interest from October 15, 2002 to
December 31, 2003; 12 percent interest from January 1, 2004 to December 31,
2004; 14 percent interest from January 1, 2005 to December 31, 2005 and 16
percent interest from January 1, 2006 to December 29, 2006. The sale of certain
of Williams' claims against WCG to Leucadia for $180 million in cash and the
sale by Williams to WCG of the Technology Center were completed in 2002. The
Plan does not extinguish or eliminate claims that WCG shareholders have made
against Williams and its directors and officers. For information relating to
litigation involving the distribution of WCG shares and claims that WCG
shareholders have made against Williams and its directors and officers see Note
16.

At December 31, 2002, Williams has a $121.5 million receivable (original
principal amount of $144.8 million) from WCG for the promissory notes relating
to the sale of the Technology Center pursuant to the Plan. The notes were
initially recorded at fair value based on contractual cash flows and an
estimated discount rate considering the creditworthiness of WCG, the amount and
timing of the cash flows and Williams' security in the Technology Center and
certain other collateral. The fourth quarter 2002 sale of certain of Williams'
claims against WCG to Leucadia resulted in the elimination of $2.26 billion of
receivables, and the associated $2.08 billion allowance, from Williams'
Consolidated Balance Sheet. In 2002, Williams recorded in continuing operations
additional pre-tax charges of $268.7 million related to the recovery and
settlement of these receivables and claims.

Williams has provided guarantees in the event of nonpayment by WCG on
certain lease performance obligations of WCG that extend through 2042 and have a
maximum potential exposure of approximately $53 million. Williams' exposure
declines systematically throughout the remaining term of WCG's obligations. The
carrying value of these guarantees was approximately $48 million at December 31,
2002 and are recorded as liabilities.

OTHER WCG-RELATED INFORMATION

Williams has received a private letter ruling from the Internal Revenue
Service (IRS) stating that the distribution of WCG common stock associated with
the 2001 spin-off 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.

Williams, with respect to shares of WCG's common stock that Williams
retained, committed to the IRS to dispose of all of the WCG common stock that it
retained 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

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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. WCG
common stock held by Williams was included in the WCG equity interests cancelled
and discharged in accordance with the Plan.

NOTE 3. INVESTING ACTIVITIES

Investing income (loss) for the years ended December 31, 2002, 2001 and
2000, is as follows:

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

* Items also included in segment profit.

Equity earnings for the year ended December 31, 2002, include a benefit of
$27.4 million, reflecting a contractual construction completion fee received by
an equity affiliate of Williams whose operations are accounted for under the
equity method of accounting. This equity affiliate served as the general
contractor on the Gulfstream pipeline project for Gulfstream Natural Gas System
(Gulfstream), an interstate natural gas pipeline subject to FERC regulations and
an equity affiliate of Williams. The fee paid by Gulfstream, associated with the
early completion during second-quarter of the construction of Gulfstream's
pipeline, was capitalized by Gulfstream as property, plant and equipment and is
included in Gulfstream's rate base to be recovered in future revenues.

Income (loss) from investments for the year ended December 31, 2002,
includes the following:

- $58.5 million gain on sale of Williams' investment in AB Mazeikiu Nafta,
a Lithuanian oil refinery, pipeline and terminal complex, which was
included in the previously reported International segment

- $12.3 million write-down of Gas Pipeline's investment in a pipeline
project which was cancelled in 2002

- $10.4 million net write-down pursuant to the sale of Williams' equity
interest in Alliance Pipeline, a Canadian and U.S. gas pipeline, which
was included in the Gas Pipeline segment

- $8.7 million gain on sale of Williams' general partner equity interest in
Northern Border Partners, L.P., which was included in the Gas Pipeline
segment

Income (loss) from investments for the year ended December 31, 2001,
includes the following:

- $27.5 million gain on the sale of Williams' limited partnership interest
in Northern Border Partners, L.P., which was included in the Gas Pipeline
segment

- $23.3 million of write-downs of certain investments which were included
in the Energy Marketing & Trading segment

The $95.9 million write-down of the WCG investment in 2001 resulted from a
decline in the value of the WCG common stock which was determined to be other
than temporary.

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Investments at December 31, 2002 and 2001, are as follows:

As previously noted, investments in Alliance Pipeline and AB Mazeikiu Nafta
were sold during 2002. During 2002, Williams consolidated Gulf Liquids Holdings,
LLC due to changes in 2002. Advances to affiliates at December 31, 2001 include
a $75 million loan to AB Mazeikiu Nafta, which was sold in third-quarter 2002.
At December 31, 2002, advances to affiliates are primarily related to notes and
interest receivable from Longhorn Partners Pipeline, L.P. (Longhorn) which was
held by Petroleum Services.

Dividends and distributions received from companies carried on the equity
basis were $81 million, $51 million and $21 million in 2002, 2001 and 2000,
respectively. The $27.4 million construction completion fee described previously
is included in the 2002 distributions.

At December 31, 2002, commitments for additional investments in Gulfstream
and certain international cost investments are $48.6 million. Williams, Williams
Gas Pipeline Company, L.L.C. and/or Williams Production Holdings LLC have
guaranteed commercial letters of credit totaling $16.9 million on behalf of
ACCROVEN. These expire in January 2004, have no carrying value and are fully
collateralized with cash.

Certain of the entities in which Williams invests continue to be reviewed
to determine if they are variable interest entities under FASB Interpretation
No. 46, which will be adopted for existing entities in the third quarter of
2003. These entities are Gulfstream, Longhorn Partners Pipeline, L.P. and
Discovery Pipeline. Gulfstream is a joint venture that constructed and operates
a natural gas pipeline extending from Alabama through the Gulf of Mexico and
into Florida. Gulfstream recognized net income of approximately $61.7 million on
$28.5 million of revenues in 2002 and holds $1.5 billion of total assets at
December 31, 2002. The net income total includes $51.2 million of AFUDC income.
Williams has a commitment to provide an additional $19.3 million investment in
Gulfstream. Longhorn is a joint venture that is currently developing a pipeline
to transport gasoline, diesel and jet fuel from Gulf Coast refineries to
terminals in the Permian Basin and the

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El Paso gateway market. Due to continued start-up activities related to its
development of the pipeline, Longhorn did not recognize revenue in 2002 but had
$495 million of total assets at December 31, 2002. Williams holds a receivable
from Longhorn of approximately $138.8 million at December 31, 2002. Discovery
Pipeline (Discovery) is a joint venture gas gathering and processing system in
southeast Louisiana and offshore Gulf of Mexico. Discovery recognized net income
of approximately $4.7 million on $83.2 million of revenue in 2002 and holds $432
million of total assets at December 31, 2002. In addition to its investment,
Williams has provided a guarantee in the event of nonperformance on 50 percent
of Discovery's debt obligation, or approximately $126.9 million at December 31,
2002. Performance under the guarantee generally would occur upon a failure of
payment by the financed entity or certain events of default related to the
guarantor. These events of default primarily relate to bankruptcy and/or
insolvency of the guarantor. The guarantee expires at the end of 2003, and no
amounts have been accrued as of December 31, 2002.

Summarized financial position and results of operations of Williams' equity
method investments are as follows:

Financial position at December 31, 2002 and 2001, is as follows:

Results of operations for the years ended December 31, 2002, 2001 and 2000,
are as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 4. ASSET SALES, IMPAIRMENTS AND OTHER ACCRUALS

Significant gains or losses from asset sales, impairments and other
accruals included in other (income) expense -- net within segment costs and
expenses for the years ended December 31, 2002, 2001 and 2000, are as follows:

The guarantee loss accruals and write-offs within Energy Marketing &
Trading of $56.2 million in 2002 includes accruals for commitments for certain
assets that were previously planned to be used in power projects, write-offs
associated with a terminated power plant project and a $13.2 million reversal of
loss accruals related to the wind-down of its mezzanine lending business. The
impairment of the Worthington generation facility was recorded pursuant to the
sale of the facility, which closed in first-quarter 2003. The loss accruals and
impairments of other power related assets were recorded pursuant to reducing
activities associated with the distributive power generation business. The
impairment of goodwill includes a $57.5 million goodwill impairment loss in
second-quarter 2002 reflecting a decline in the fair value from deteriorating
market conditions in the merchant energy sector in which it operates and Energy
Marketing & Trading's resulting announcement in June 2002 to scale back its own
energy marketing and risk management business. The fair value of Energy
Marketing & Trading used to calculate the goodwill impairment loss was based on
the estimated fair value of the trading portfolio inclusive of the fair value of
contracts with affiliates, which are not reflected at fair value in the
financial statements. The fair value of these contracts was estimated using a
discounted cash flow model with natural gas pricing assumptions based on current
market information. The remaining goodwill was evaluated for impairment at the
end of 2002 and an additional impairment of $3.0 million was required based on
management's estimate of the fair value of Energy Marketing & Trading at
December 31, 2002.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Approximately $38 million of the Canadian asset impairment reflects a
reduction of carrying cost to management's estimate of fair market value,
determined primarily from information available from efforts to sell these
assets. The balance is associated with assets whose carrying costs were
determined not fully recoverable and reduced to estimated fair value.

NOTE 5. PROVISION (BENEFIT) FOR INCOME TAXES

The provision (benefit) for income taxes from continuing operations
includes:

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

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Significant components of deferred tax liabilities and assets as of
December 31, 2002 and 2001, are as follows:

Cash payments for income taxes, net of refunds were $36 million, $87
million and $112 million in 2002, 2001 and 2000, respectively.

Valuation allowances were established during 2001 for deferred tax assets
from basis differences in investments for which the ultimate realization of the
tax asset was dependent on future capital gains. The recording of the investment
in the retained shares of WCG after the spinoff (see Note 2) 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 3). These valuation allowances were reduced
during 2002 as a result of capital gains generated during the year.

The impact of foreign operations on the effective tax rate increased during
2002 due to the recognition of U.S. tax on foreign dividend distributions and
recording of a financial impairment on certain foreign assets for which a
valuation allowance was established.

Federal net operating loss carryovers of $480 million at the end of 2002
are expected to be utilized by Williams prior to expiration in 2012 through
2022. Capital loss carryovers of $67 million at the end of 2002 are not expected
to be utilized by Williams prior to expiration in 2007; therefore, a valuation
allowance of $26 million was established.

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NOTE 6. EARNINGS (LOSS) PER SHARE

Basic and diluted earnings (loss) per common share are computed for the
years ended December 31, 2002, 2001 and 2000, as follows:

For the year ended December 31, 2002, diluted earnings (loss) per share is
the same as the basic calculation. The inclusion of any stock options,
convertible preferred stock and unvested deferred stock would be antidilutive as
Williams reported a loss from continuing operations for this period. As a
result, for the year ended December 31, 2002, approximately 666 thousand
weighted-average stock options, approximately 11.3 million weighted-average
shares related to the assumed conversion of the 9 7/8 percent cumulative
convertible preferred stock and approximately 3.6 million weighted-average
unvested deferred shares, that otherwise would have been included, have been
excluded from the computation of diluted earnings per common share.

Additionally, approximately 38.7 million, 15.3 million and 7.2 million
options to purchase shares of common stock with weighted-average exercise prices
of $19.90, $36.12 and $43.11, respectively, were outstanding on December 31,
2002, 2001 and 2000, 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.

NOTE 7. 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 recorded in the Consolidated Balance Sheet at December 31
of each year indicated. Prior year amounts have been restated to exclude those
benefit plans where it is anticipated that Williams will no longer serve as
sponsor related to those operations reported as discontinued operations (see
Note 1). Changes in the obligations or assets of continuing plans associated
with the transfer of such

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obligations or assets in a sale or planned sale reflected as discontinued
operations have been reflected as divestitures in the following tables.

Amounts recognized in the Consolidated Balance Sheet consist of:

Prepaid benefit cost............................. $200.6 $135.1 $ -- $ --
Accrued benefit cost............................. (91.6) (28.2) (175.6) (160.0)
Intangible asset................................. -- 1.4 -- --
Accumulated other comprehensive income (before
tax)........................................... 28.8 2.5 -- --
------ ------ ------- -------
Prepaid (accrued) benefit cost................... $137.8 $110.8 $(175.6) $(160.0)
====== ====== ======= =======

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

The projected benefit obligation and fair value of plan assets for the
pension plans with projected benefit obligations in excess of plan assets were
$392.7 million and $186.3 million, respectively, as of December 31, 2002, and
$891.8 million and $743.7 million, respectively, as of December 31, 2001. The
accumulated benefit obligation and fair value of plan assets for the pension
plans with accumulated benefit obligations in excess of plan assets were $260.3
million and $169.9 million, respectively, as of December 31, 2002. The
accumulated benefit obligation for pension plans with accumulated benefit
obligations in excess of plan assets was $28.2 million as of December 31, 2001.
There were no assets for these plans as of December 31, 2001.

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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
2003 is 12 percent, and systematically decreases to 5 percent by 2016.

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 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, 2002 and 2001, is $57.5 million and $56 million, respectively,
and is expected to be recovered through rates over approximately 11 years.

Williams maintains various defined-contribution plans. Williams recognized
costs related to continuing operations of $53 million in 2002, $35 million in
2001 and $29 million in 2000 for these plans. In 2002, these costs included the
cost related to additional contributions to an employee stock ownership plan
resulting from the retirement of related external debt.

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NOTE 8. INVENTORIES

Inventories at December 31, 2002 and 2001, are as follows:

As of December 31, 2002 and 2001, approximately 43 percent and 52 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, 2002 and 2001, included refined products of $23.1 million and
$90.8 million, respectively; natural gas in underground storage of $76.2 million
and $65.3 million, respectively; and natural gas liquids of $90.7 million and
$97.9 million, respectively. Inventories determined using the LIFO cost method
were approximately six percent of inventories at both December 31, 2002 and
2001. The remaining inventories were primarily determined using the average-cost
method.

During 2002, lower-of-cost or market reductions of approximately $18.2
million were recognized with respect to certain power-related inventories
included in materials and supplies.

EITF No. 02-3, issued October 25, 2002, does not permit mark-to-market
accounting for inventory purchased subsequent to that date. Inventories
purchased up to that date are permitted to apply mark-to-market accounting until
EITF No. 02-3 is adopted. As of December 31, 2002, Williams had between $30
million and $50 million of marked-to-market inventory that will be included in a
January 1, 2003 cumulative effect of change in accounting principle upon
adoption of EITF No. 02-3 (see Recent accounting standards in Note 1).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 9. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31, 2002 and 2001, is as follows:

Depreciation, depletion and amortization expense for property, plant and
equipment was $770.9 million, $622.2 million and $511 million, respectively, in
2002, 2001 and 2000.

Included in gross property, plant and equipment at December 31, 2002 and
2001, is approximately $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 $774 million and
$839 million at December 31, 2002 and 2001, respectively, of capitalized costs
from the Barrett acquisition related to properties with probable reserves not
yet subject to depletion.

Commitments for construction and acquisition of property, plant and
equipment are approximately $448 million at December 31, 2002.

Included in net property, plant and equipment is approximately $1.6 billion
and $1.7 billion at December 31, 2002 and 2001, 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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NOTE 10. 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
approximately $59 million and $30 million at December 31, 2002 and 2001,
respectively.

Accrued liabilities at December 31, 2002 and 2001, are as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 11. DEBT, LEASES AND BANKING ARRANGEMENTS

NOTES PAYABLE AND LONG-TERM DEBT

Notes payable and long-term debt at December 31, 2002 and 2001, is as
follows:

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

(1) At December 31, 2002.

(2) Interest rate for $921.8 million is based on the Eurodollar rate plus 4
percent per annum. The principal balance includes interest accruing to the
note at a fixed rate of 14 percent compounded quarterly.

(3) 2001 included $300 million of commercial paper which was classified as
noncurrent based on Williams' intent and ability to refinance on a long-term
basis.

(4) Includes $1.1 billion of 6.5 percent notes, payable 2007 subject to
remarketing in 2004 (FELINE PACS). If a remarketing is unsuccessful in 2004
and a second remarketing in February 2005 is unsuccessful as defined in the
offering document of the FELINE PACS, then Williams could exercise its right
to foreclose on the notes in order to satisfy the obligation of the holders
of the equity forward contracts requiring the holder to purchase Williams
common stock (see Note 13).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Notes payable at December 31, 2002, includes a $921.8 million secured note
(RMT note payable), which is discussed in detail below. In addition, Williams
has entered into a short-term credit agreement secured by the assets of a gas
processing plant in Colorado within Exploration & Production with $13 million
outstanding at December 31, 2002. Notes payable at December 31, 2001, included
$1.1 billion of commercial paper and $300 million of other various short-term
credit agreements with a weighted-average interest rate of 3.33 percent.

During third-quarter 2002, Williams' credit ratings were lowered below
investment grade and Williams was unable to complete a renewal of its unsecured
short-term-credit facility. As a result, Williams amended its revolving credit
facility to make it secured, obtained additional secured credit facilities and
amended other outstanding debt agreements. The following is a discussion of the
terms of these arrangements.

REVOLVING CREDIT FACILITIES

Under the terms of Williams' amended revolving credit agreement, Northwest
Pipeline and Transcontinental Gas Pipe Line have access to $400 million and
Texas Gas Transmission has access to $200 million, while Williams (Parent) has
access to all unborrowed amounts. Interest rates vary based on LIBOR plus an
applicable margin (which varies with Williams' senior unsecured credit ratings).
As Williams completes asset sales, the commitments from participating banks in
the revolving credit facility will be initially reduced to $400 million. After
1) the commitments are reduced to $400 million, 2) certain pre-existing debt
with a balance of $448.2 million at December 31, 2002, is paid off and
pre-existing letters of credit totaling $55.8 million at December 31, 2002, are
cash collateralized and 3) and in some cases, the letter of credit facility
(discussed below) is collateralized, the commitments may be further reduced to
zero as a result of additional asset sales. As of December 31, 2002, the
revolving credit facility commitment has been reduced from $700 million to $463
million and no amounts were outstanding under this agreement. Subsequent to
December 31, 2002, as a result of asset sales in first-quarter 2003, the
revolving credit facility commitment has been further reduced to $400 million as
of March 2003.

Under the amended terms of the revolving credit facility, the company is no
longer required to make a "no material adverse change" representation prior to
obtaining borrowings on the facility. Significant new covenants under the
agreement include: (i) restrictions on the creation of new subsidiaries, (ii)
additional restrictions on pledging assets to other creditors, (iii)
restrictions on the disposition of assets, (iv) a covenant that the ratio of
interest expense plus cash flow to interest expense be greater than 1.5 to 1,
(v) a limit on dividends on common stock paid by Williams in any quarter of
$6.25 million, (vi) certain restrictions on declaration or payment of dividends
on preferred stock issued after July 30, 2002, (vii) a limit on investments in
others of $50 million annually, (viii) a $50 million limit on additional debt
incurred by subsidiaries other than Transcontinental Gas Pipe Line, Texas Gas,
Northwest Pipeline or Williams Energy Partners L.P. and (ix) a modified
consolidated debt to consolidated net worth plus consolidated debt financial
covenant to increase the threshold to 70 percent through December 30, 2002, 68
percent from December 30, 2002 through March 30, 2003 and 65 percent after March
30, 2003. Consolidated net worth is defined as total assets plus all non-cash
losses resulting from the write-down or disposition of the Trading Book less
total liabilities and minority interests in consolidated subsidiaries plus
certain minority interests and exceptions as defined in the debt agreements, and
the $1.1 billion FELINE PACS. Debt is defined as 1) all debt, other than
non-recourse debt and the $1.1 billion FELINE PACS, 2) Williams' guarantees as
defined in the agreements, 3) capital leases, 4) payments necessary to exercise
a purchase option with respect to property encumbered by a Synthetic Lease as
defined in the agreements, 5) obligations under any Financing Transaction as
defined in the agreements, and 6) liabilities from deferred purchase price of
property or services (other than trade payables incurred in the ordinary course
of business not overdue by more than 60 days). Williams' ratio of consolidated
debt to consolidated net worth plus consolidated debt, as defined in Williams'
amended revolving credit facility, at December 31, 2002, was 65.2 percent. The
ratio of interest expense plus cash flow to interest expense as defined in the
agreements was 2.2. Failure to meet any of these covenants could become an event

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of default and could result in acceleration of amounts due under this facility
and other company debt obligations with similar covenants, or for which there
are certain provisions for cross-default in place.

The amended revolving credit facility expires July 2005 and is secured by
substantially all of Williams' Midstream Gas & Liquids assets and the equity of
substantially all of the Midstream Gas & Liquids subsidiaries and the
subsidiaries which own the refinery assets. It is also guaranteed by many of
Williams' subsidiaries, except for Transcontinental Gas Pipe Line, Texas Gas,
Northwest Pipeline and Williams Energy Partners L.P.

In addition to the revolving credit facility discussed above, $81 million
included in the previous table is outstanding under the terms of a separate $83
million revolving credit facility secured by certain olefin processing assets in
Louisiana within Midstream Gas & Liquids. Williams Energy Partners L.P. also has
an $85 million unsecured revolving credit facility with no amounts outstanding
at December 31, 2002 and $49.5 million at December 31, 2001.

SHORT-TERM CREDIT AGREEMENT -- $900 MILLION

Williams Production RMT Company (RMT), a wholly owned subsidiary, entered
into a $900 million short-term Credit Agreement dated July 31, 2002, with
certain lenders including a subsidiary of Lehman Brothers, Inc., a related party
to Williams. The loan, reported in notes payable in the Consolidated Balance
Sheet, is secured by substantially all of the assets of RMT and the capital
stock of Williams Production Holdings LLC (Holdings) (parent of RMT), RMT and
certain RMT subsidiaries. It is also guaranteed by Williams, Holdings and
certain RMT subsidiaries. The assets of RMT are comprised primarily of the
assets of the former Barrett Resources Corporation acquired in 2001, which were
primarily natural gas properties in the Rocky Mountain region. The loan matures
on July 25, 2003, and bears interest payable quarterly at the Eurodollar rate
plus 4 percent per annum (5.76 percent at December 31, 2002), plus additional
interest of 14 percent per annum compounded quarterly, which is accrued and
added to the principal balance. The principal balance at December 31, 2002, was
$921.8 million.

RMT must also pay a deferred set-up fee. The amount of the fee is dependant
upon whether a majority of the fair market value of RMT's assets or a majority
of its capital stock is sold (company sale) on or before the maturity date,
regardless of whether the loan obligations have been repaid. If a company sale
has occurred, the amount of such fee would be the greater of (x) 15 percent of
the loan principal amount, and (y) 15 percent to 21 percent, depending on the
timing of the company sale, of the difference between (A) the purchase price of
such company sale, including the amount of any liabilities assumed by the
purchaser, up to $2.5 billion, and (B) the sum of (1) the principal amount of
the outstanding loans, plus (2) outstanding debt of RMT and its subsidiaries,
plus (3) accrued and unpaid interest on the loans to the date of repayment. If a
company sale has not occurred, the fee would be 15 percent of the loan amount.
However, if a company sale occurs within three months after the maturity date,
then RMT must also pay the positive difference, if any, between the fee that
would have been paid had such company sale occurred prior to the maturity date
and the actual fee paid on the maturity date.

Significant covenants on Holdings, RMT and certain RMT subsidiaries under
the loan agreement include: (i) an interest coverage ratio computed on a
consolidated RMT basis of greater than 1.5 to 1, (ii) a fixed charge coverage
ratio computed on a consolidated RMT basis of greater than 1.15 to 1, (iii) a
limitation on restricted payments, (iv) a limitation on capital expenditures in
excess of $300 million and (v) a limitation on intercompany indebtedness.

Under the RMT Credit Agreements, Williams must provide liquidity
projections on a weekly basis until the maturity date. Each projection covers a
period extending 12 months from the report date. Williams must maintain actual
and projected parent liquidity (a) at any time from the closing date (July 31,
2002) through the 180th day thereafter (January 27, 2003), of $600 million; (b)
at any time thereafter through and including

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the maturity date, of $750 million; and (c) for liquidity projections provided
during the term of the loan, projected liquidity after the maturity date, of
$200 million. If the parent liquidity requirement is not met, RMT must be sold
within 75 days. The loan is also required to be prepaid with the net cash
proceeds of any sales of RMT's assets, and, in the event of a company sale, the
loan is required to be prepaid in full. A prepayment or acceleration of the loan
requires RMT to pay to the lenders (i) a make-whole amount, and (ii) the
deferred set-up fee set forth above. A partial prepayment of the loan requires
RMT to pay a pro rata portion of the make-whole amount and deferred set-up fee.

LETTER OF CREDIT FACILITY -- $400 MILLION

The $400 million letter of credit facility expires July 2003 and is secured
by substantially all of Williams' Midstream Gas & Liquids assets and the equity
of substantially all of the Midstream Gas & Liquids subsidiaries and the
subsidiaries which own the refinery assets. It is also guaranteed by many of
Williams' subsidiaries, except for Transcontinental Gas Pipe Line, Texas Gas,
Northwest Pipeline and Williams Energy Partners L.P. Letters of credit totaling
$396.8 million have been issued by the participating financial institutions
under this facility at December 31, 2002. Significant covenants under the terms
of this facility are the same as previously described within Revolving credit
facilities.

AMENDMENTS TO OTHER OUTSTANDING DEBT AGREEMENTS

An additional $159 million of preexisting public securities were also
ratably secured in accordance with the indentures covering those securities with
the same assets used to secure the revolving credit facility and the $400
million letter of credit facility.

During 2002, the terms of the Snow Goose Associates, L.L.C. (Snow Goose)
$560 million priority return structure and the terms of the Piceance Production
Holdings LLC (Piceance) $100 million priority return structure, both previously
classified as preferred interest in consolidated subsidiaries, were amended.
These amendments resulted in new payment terms that changed the nature of the
transactions; hence, the remaining outstanding preferred interests of $224
million and $78.5 million, respectively, are classified as debt at December 31,
2002. See Note 12 for further information.

The terms of various operating lease agreements were also amended. These
leases are secured by the related leased assets and are now reflected as capital
leases totaling $207 million, of which $67 million is included in liabilities of
discontinued operations on the Consolidated Balance Sheet at December 31, 2002.
See Leases-Lessee below for further discussion.

The terms of the amended Piceance and lease agreements described above,
three amended term loan agreements with $448.2 million outstanding at December
31, 2002, and pre-existing letters of credit with $55.8 million outstanding at
December 31, 2002, require prepayment of amounts outstanding and posting of cash
collateral as Williams completes asset sales.

Credit facilities and letters of credit referred to above along with Snow
Goose agreements are guaranteed by at least one of the following: Williams
(Parent), Williams Gas Pipeline Company, L.L.C. and/or Holdings. These
guarantees expire as the corresponding principal balances are repaid in 2003
through 2006. The total guaranteed under these agreements was $1.1 billion as of
December 31, 2002.

OTHER

Pursuant to completion of a consent solicitation during first-quarter 2002
with WCG Note Trust Note holders, Williams recorded $1.4 billion of long-term
debt obligations. In July 2002, Williams acquired substantially all of the WCG
Note Trust Notes by exchanging $1.4 billion of Williams Senior Unsecured 9.25
percent notes due March 2004. In November 2002, Williams acquired the remaining
outstanding WCG Note Trust Notes (see Note 2).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In May 2002, Energy Marketing & Trading entered into an agreement which
transferred the rights to certain receivables in exchange for cash. Due to the
structure of the agreement, Energy Marketing & Trading accounted for this
transaction as debt collateralized by the claims. The $78.7 million of debt is
classified as current.

OTHER ISSUANCES AND RETIREMENTS

In addition to the items previously discussed, significant issuances and
retirements of long-term debt, including capital leases, and excluding amounts
under revolving credit agreements, for the year ended December 31, 2002 are as
follows:

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

(1) Paid due to being subject to redemption at par in 2002.

On March 4,2003, Northwest Pipeline completed an offering of $175 million
of 8.125 percent senior notes due 2010.

Terms of certain subsidiaries' borrowing arrangements with lenders limit
the transfer of funds to Williams (Parent). At December 31, 2002, approximately
$526 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
$156 million at December 31, 2002.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Aggregate minimum maturities of long-term debt, excluding capital leases,
for each of the next five years are as follows:

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

(1) Includes $1.1 billion of 6.5 percent notes due 2007 (FELINE PACS) due to the
remarketing provisions previously described, that have the potential of
Williams reacquiring the notes in 2005 through a foreclosure on its security
interest in the notes.

Cash payments for interest (net of amounts capitalized) were as follows:
2002 -- $905 million; 2001 -- $572 million; and 2000 -- $581 million.

LEASES-LESSEE

Future minimum annual rentals under noncancelable operating leases as of
December 31, 2002, are payable as follows:

Total rent expense was $102 million in 2002, $91 million in 2001, and $95
million in 2000.

In July 2002, Williams amended the terms of an operating lease with a
special-purpose entity owned by third parties through which Williams leases an
offshore oil and gas pipeline and an onshore gas processing plant. The amended
terms caused the lease to be reclassified as a capital lease within the
Midstream Gas & Liquids segment under the criteria established in SFAS No. 13.
The lease is secured by leased assets with a net book value of $174.3 million as
of December 31, 2002. The lease term includes a five-year base term with an
optional five-year renewal upon the mutual agreement of the lessor and lessee.

Williams provides a residual value guarantee on the leased assets. Williams
also has an option to purchase the leased assets during the lease term at an
amount approximating the lessors' cost. 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 guarantee.

As a result of the adoption of FASB Interpretation No. 46 in 2003, the
special-purpose entity lessor will be included in the 2003 consolidated
financial statements of Williams. The impact of the consolidation is not
expected to be material.

At December 31, 2002, gross property, plant and equipment recorded under
the capital lease was $178.5 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Future minimum capital lease payments as of December 31, 2002 are:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 12. PREFERRED INTERESTS IN CONSOLIDATED SUBSIDIARIES

In 2001 and 2002 Williams owned 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. For 2001, the preferred ownership
interest in each entity is reflected in the preferred interest in consolidated
subsidiaries caption of the Consolidated Balance Sheet. As a result of changes
to the underlying agreements in 2002, any remaining outside preferred ownership
interest at December 31, 2002, is reflected within debt. 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 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, 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 on 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 obligation 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.

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. The initial priority return period was set to expire in December
2005.

During first-quarter 2002, the terms of the priority return were amended.
Significant terms of the amendment include elimination of covenants regarding
Williams' credit ratings, modifications of certain Canadian interest coverage
covenants and a requirement to amortize the outside investor's preferred
interest with equal principal payments due each quarter and the final payment in
April 2003. In addition, Williams provided a financial guarantee of the Arctic
Fox note payable to Snow Goose which, in turn, is the source of the priority
returns. Based on the terms of the amendment, the remaining balance due of $224
million is classified as long-term debt due within one year on Williams'
Consolidated Balance Sheet at December 31, 2002. Priority returns prior to this
amendment are included in preferred returns and minority interest in income of
consolidated subsidiaries in the Consolidated Statement of Operations.

Significant covenants, other than those noted previously, 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

141

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

flow each quarter that is at least three times greater than amounts payable to
the outside investor in Snow Goose for that quarter.

PICEANCE PRODUCTION HOLDINGS LLC

In December 2001, Williams formed 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. At December 31, 2002, the outside investor amount was $78.5 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 quarterly priority
distributions beginning in January 2002, based upon an adjustable rate structure
currently approximating 2.9 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 periods through demand loans. Following Williams' credit
ratings decline to levels below BBB- by Standard & Poor's and Baa3 by Moody's
Investors Service or below BB+ by Standard & Poor's or below Ba1 by Moody's
Investors Service, Williams is now prevented from using demand loans, and
therefore excess cash will be retained between distribution periods. Also, the
existing demand loans were repaid by Williams and replaced by other permitted
assets. 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.

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 was 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 was scheduled to expire in September 2003. In July 2002,
the downgrade of Williams' senior unsecured rating below BB by Standard & Poor's
or Ba1 by Moody's Investors Service, resulted in an early retirement of
substantially all the outside investors' ownership interest. However, the
structure remains in place.

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 included 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

December 2003, $60 million in third-party receivables guaranteed by Williams,
and approximately $204 million in other various assets. While no event of
default arose from a downgrade of Williams' unsecured credit rating below Baa3
by Moody's Investors Service and below BBB- by Standard & Poor's, Williams no
longer is able to substitute demand loans for existing assets. The outside
investor was entitled to quarterly priority distributions based upon an
adjustable rate structure, in addition to a portion of the participation in the
operating results of Castle. Williams purchased the outside investors interest
in December 2002.

NOTE 13. STOCKHOLDERS' EQUITY

Concurrent with the sale of Kern River to MidAmerican Energy Holdings
Company (MEHC), Williams issued approximately 1.5 million shares of 9 7/8
percent cumulative convertible preferred stock to MEHC for $275 million. The
terms of the preferred stock allow the holder to convert, at any time, one share
of preferred stock into 10 shares of Williams common stock at $18.75 per share.
Preferred shares have a liquidation preference equal to the stated value of
$187.50 per share plus any dividends accumulated and unpaid. Dividends on the
preferred stock are payable quarterly. Preferred dividends for the year ended
December 31, 2002, include $69.4 million associated with the accounting for a
preferred security that contains a conversion option that is beneficial to the
purchaser at the time the security was issued. This is accounted for as a
noncash dividend (reduction to retained earnings) and results from the
conversion price being less than the market price of Williams common stock on
the date the preferred stock was issued. The reduction in retained earnings was
offset by an increase in capital in excess of par value.

In January 2002, Williams issued $1.1 billion of 6.5 percent notes payable
2007 which are subject to remarketing in 2004. Attached to these notes is an
equity forward contract requiring the holder to purchase Williams common stock
at the end of three years. The note and equity forward contract are bundled as
units, called FELINE PACS, and were sold in a public offering for $25 per unit.
At the end of three years, the holder is required to purchase for $25, one share
of Williams common stock provided the average price of Williams common stock
does not exceed $41.25 per share for a 20 trading day period prior to
settlement. If the average price over that period exceeds $41.25 per share, the
number of shares issued in exchange for $25 will be equal to one share
multiplied by the quotient of $41.25 divided by the average price over that
period. The holder of the equity forward contract can settle the contract early
in the event Williams is involved in a merger in which at least 30 percent of
the proceeds received by Williams shareholders is cash. In this event the holder
will be entitled to pay the purchase price and receive the kind and amount of
securities they would have received had they settled the equity forward contract
immediately prior to the acquisition. In addition to the 6.5 percent interest
payment on the notes, Williams also makes a contract adjustment payment related
to the equity forward contract of 2.5 percent annually during the three year
term of the contract. The present value of the total of the contract adjustment
payments at the date the FELINE PACS were issued was $76.7 million and was
recorded as a liability and a reduction to capital in excess of par at that
time.

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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

NOTE 14. STOCK-BASED COMPENSATION

Williams has several plans that provide or have provided for
common-stock-based awards to employees and to non-employee directors. Effective
May 16, 2002, Williams' shareholders approved a new plan that will provide
common-stock-based awards going forward to both employees and non-employee
directors. Options outstanding in all prior plans remain in those plans with
their respective terms and provisions. The new plan permits the granting of
various types of awards including, but not limited to, stock options, restricted
stock and deferred stock. Awards may be granted for no consideration other than
prior and future services or based on certain financial performance targets
being achieved. The purchase price per share for stock options may not be less
than the market price of the underlying stock on the date of grant. Stock
options generally become exercisable after three years from the date of the
grant and can be 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, 2002, 57.8 million shares of Williams
common stock were reserved for issuance pursuant to existing and future stock
awards, of which 14.8 million shares were available for future grants (18.2
million at December 31, 2001).

The prior plans, from which no further grants are expected, permitted the
granting of various types of awards including, but not limited to, stock
options, stock appreciation rights, restricted stock and deferred stock. Awards
were 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 were
not less than the market price of the underlying stock on the date of grant.
Stock options under these prior plans generally became 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 under the
prior plans expire 10 years after grant.

Prior to November 14, 2001, the stock option loan programs for the Williams
1996 Stock Plan, Williams 1990 Stock Plan, Williams 1988 Stock Option Plan for
Non-Employee Directors and Williams 1985 Stock Option Plan allowed Williams to
loan money to participants to exercise stock options using stock certificates as
collateral. Effective November 14, 2001, Williams no longer issues new loans
under the stock option loan programs. Current loan holders were offered a
one-time opportunity in January 2002 to refinance outstanding loans at a market
rate of interest commensurate with the borrower's credit standing. The
refinancing is 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 will remain
in force until maturity in the event of the employee's termination. Williams
continues to hold the collateral shares and can review the borrower's financial
position at any time. The variable rate of interest on the loans of participants
who elected new terms was determined at the signing of the promissory note and
is based on 1.75 percent plus the current three-month London Interbank Offered
Rate (LIBOR). The rate is subject to change every three months beginning with
the first three-month anniversary of the promissory note.

If a current loan holder did not elect to refinance, the loans remain
outstanding under the original terms with no refinancing at maturity. Under the
original terms of the loan, the interest rate is based on the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

minimum applicable federal rates required to avoid imputed income, interest
payments are due annually, the principal is due at the end of either a three-or
five-year loan term, and if the participant leaves Williams during the loan
period, they are required to pay the loan balance and any accrued interest
within 30 days of termination. The total amount of loans outstanding at December
31, 2002 and 2001, was approximately $30.3 million (net of a $5 million
allowance) and $38.1 million, respectively.

The following summary reflects stock option activity for Williams common
stock and related information for 2002, 2001 and 2000:

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

(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, 2002:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The estimated fair value at date of grant of options for Williams common
stock granted in 2002, 2001 and 2000, using the Black-Scholes option pricing
model, is as follows:

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 is disclosed under Employee stock-based awards in Note 1.

Williams granted deferred shares of approximately 2,738,000 in 2002,
1,423,000 in 2001 and 332,000 in 2000. Deferred shares are valued at the date of
award, and the weighted-average grant date fair value of the shares granted was
$12.26 in 2002, $40.84 in 2001 and $39.13 in 2000. Approximately $31 million,
$22 million and $11 million was recognized as expense for deferred shares of
Williams in 2002, 2001 and 2000, 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 499,000 in
2002, 260,000 in 2001 and 140,000 in 2000, of the deferred shares previously
granted.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 15. 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, restricted cash and notes payable: The carrying
amounts reported in the balance sheet approximate fair value due to the
short-term maturity of these instruments with the exception of the RMT note
payable for which Williams used the expertise of outside investment banking
firms to assist with the estimate of fair value.

Retained interest in accounts receivable sold to SPEs: The carrying
amounts reported in the balance sheet for December 31, 2001 approximate fair
value. Fair value was 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.

Notes and other noncurrent receivables, margin deposits and deposits
received from customers relating to energy trading and hedging activities: The
carrying amounts reported in the balance sheet approximate fair value as these
instruments have interest rates approximating market or maturities of less than
three years.

Investment in WCG: The carrying amount reflects write-downs of the WCG
investment to zero (see Note 2). Fair value at December 31, 2001 was calculated
based on the year-end closing price of WCG common stock.

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, 2002 and 2001, 73 percent and 81
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.

Energy derivatives and other energy-related contracts: Derivatives and
other energy-related contracts utilized in trading activities include forward
contracts, futures contracts, option contracts, swap agreements, physical
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,
transmission 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, while other transactions are executed where quoted market prices
are not available or the contracts extend into periods for which quoted market
prices are not available. See Note 1 regarding Energy commodity risk management
and trading activities and revenues and Derivative instruments and hedging
activities including interest rate swaps for further discussion about
determining fair value for energy contracts.

Foreign currency hedges: 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.

Interest-rate derivatives: 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 derivatives.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

(a) These investments and long-term receivables due from affiliated companies
are primarily in non-publicly traded companies for which it is not
practicable to estimate fair value.

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

(c) Includes $1.1 billion related to the WCG Note Trust Notes and $600 million
related to the WCG fiber optic network lease guarantee.

(d) Includes $20.0 million and $7.6 million of assets related to discontinued
operations in 2002 and 2001, respectively.

(e) Includes $(19.7) million and $(11.8) million of liabilities related to
discontinued operations in 2002 and 2001, respectively.

(f) At December 31, 2001, Williams had interest rate swaps to mitigate its
interest rate risk in its energy trading portfolio which were included in
energy risk management and trading assets and liabilities.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

GUARANTEES

In addition to the guarantees and payment obligations discussed elsewhere
in these footnotes (see Notes 2, 3 and 16), Williams has issued guarantees and
other similar arrangements with off-balance sheet risk as discussed below.

In 2001, Williams sold its investment in Ferrellgas Partners L.P. senior
common units (Ferrellgas units). As part of the sale, Williams became party to a
put agreement whereby the purchaser's lenders can unilaterally require Williams
to repurchase the units upon nonpayment by the purchaser of its term loan due to
its lender or failure or default by Williams under any of its debt obligations
greater than $60 million. The maximum potential obligation under the put
agreement at December 31, 2002, was $91.5 million. Williams' contingent
obligation decreases as purchaser's payments are made to the lender. Collateral
and other recourse provisions include the outstanding Ferrellgas units and a
guarantee from Ferrellgas Partners L.P. to cover any shortfall from the sale of
the Ferrellgas units at less than face value. The proceeds from the liquidation
of the Ferrellgas units combined with the Ferrellgas Partners' guarantee should
be sufficient to cover any required payment by Williams. 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. No
amounts have been accrued for this contingent obligation as management believes
it is not probable that Williams would be required to perform under this
obligation.

In connection with the 1993 public offering of units in the Williams Coal
Seam Gas Royalty Trust (Royalty Trust), Exploration & Production entered a gas
purchase contract for the purchase of the natural gas in which the Royalty Trust
holds a net profits interest. Under this agreement, Exploration & Production
guarantees a minimum purchase price that the Royalty Trust will realize in the
calculation of its net profits interest. Exploration and Production has an
annual option to discontinue this minimum purchase price guarantee and pay
solely based on an index price. The maximum potential future exposure associated
with this guarantee is not determinable because it is dependent upon natural gas
prices and production volumes. No amounts have been accrued for this contingent
obligation, as the index price continues to exceed the minimum purchase price.

In connection with the 1987 sale of certain real estate assets associated
with its Tulsa headquarters, Williams guaranteed 70 percent of the principal and
interest payments through 2007 on revenue bonds issued by the purchaser to
finance those assets. In the event that future operating results from these
assets are not sufficient to make the principal and interest payments, Williams
is required to fund that short-fall. The maximum potential future payments under
this guarantee are $8.6 million, all of which is accrued at December 31, 2002.

In connection with the construction of a joint venture pipeline project,
Williams guaranteed 50 percent of the joint venture's project financing.
Williams' maximum potential liability under this guarantee is $9.7 million at
December 31, 2002. This guarantee expires March 2005 and no amounts have been
accrued at December 31, 2002.

Williams provided credit support to a crude oil trading joint venture in
the form of performance guarantees for the benefit of the trading
counterparties. These guarantees, which would have required Williams to make
payments in the event of nonperformance by the joint venture under the crude oil
purchase and sale contracts, expired or were terminated in early 2003. Although
the maximum potential future payments would vary based on commodity prices,
Williams' guarantees were capped at a total of $338 million. This joint venture
is no longer active and no amounts were accrued for these guarantees at December
31, 2002.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

OTHER FINANCIAL INSTRUMENTS

Through July 25, 2002 Williams, through wholly owned bankruptcy remote
subsidiaries, sold certain trade accounts receivable to special purpose entities
(SPEs) in a securitization structure requiring annual renewal. Williams acted as
the servicing agent for the sold receivables and received a servicing fee
approximating the fair value of such services. 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. For 2002 and 2001, Williams received cash proceeds from the
SPEs of approximately $4.7 billion and $12.8 billion, respectively. The sales of
these receivables resulted in a charge to results of operations of approximately
$4 million and $17 million in 2002 and 2001, respectively. The retained interest
in accounts receivable sold to the SPEs was subject to credit risk to the extent
that these receivables were not collected. On July 25, 2002, these agreements
expired and were not renewed. See Concentration of credit risk below.

DERIVATIVES AND ENERGY-RELATED CONTRACTS

Energy risk management and trading activities

Williams, through Energy Marketing & Trading and the natural gas liquids
trading operations (reported in the Midstream Gas & Liquids segment), has energy
commodity risk management and trading operations that enter into energy and
energy-related contracts to provide price-risk management services associated
with the energy industry to its customers, including power, natural gas, refined
products, natural gas liquids and crude oil. Contracts utilized in energy
commodity risk management and trading activities include forward contracts,
futures contracts, option contracts, swap agreements, physical commodity
inventories, 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, transmission and power
tolling contracts. In addition, Energy Marketing & Trading enters into interest
rate swap agreements and credit default swaps to manage the interest rate and
credit risk in its energy portfolio. During 2002, Williams began managing its
interest rate risk, including the interest rate and credit risk in Energy
Marketing & Trading's energy portfolio, on an enterprise basis by the corporate
parent. Energy Marketing & Trading also directly entered into third-party
interest rate futures agreements to mitigate interest rate risk. These futures
are included within energy risk management and trading assets and liabilities.
See Note 1 for a description of the accounting valuation for these energy
commodity risk management and trading activities. The net gain or (loss)
recognized in revenues from the price-risk management and trading activities was
a $(109) million net loss in 2002 and net gains of $1,696 million and $1,285.1
million in 2001 and 2000, respectively.

Futures contracts are commitments to either purchase or sell a commodity at
a future date for a specified price and are generally settled in cash, but may
be settled through delivery of the underlying commodity. Exchange-traded or
over-the-counter markets providing quoted prices in active periods are available
and other market indicators where quoted prices are not available exist for the
futures contracts entered into by Energy Marketing & Trading and the natural gas
liquids trading operations (reported in the Midstream Gas & Liquids segment).
The fair value of these contracts is based on quoted prices.

Swap agreements call for Energy Marketing & Trading and the natural gas
liquids trading operations (reported in the Midstream Gas & Liquids segment), 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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Certain of Energy Marketing & Trading and the natural gas liquids trading
operations (reported in the Midstream Gas & Liquids segment) 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 and the natural gas liquids trading
operations (reported in the Midstream Gas & Liquids segment) buy and sell
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, transmission and power tolling contracts.
Transportation and transmission contracts provide Energy Marketing & Trading the
right, but not the obligation, to transport/transmit physical quantities of
natural gas or refined products or electricity 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/transmission capacity is used and
a variable payment component for shipments actually made during the month.
Storage contracts provide Energy Marketing & Trading the right, but not the
obligation, to store physical quantities of gas. Energy Marketing & Trading
enters full requirements arrangements which are structured to manage natural gas
and power supply requirements, service load growth, manage unplanned outages and
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 fixed fee
and a variable fee based on usage.

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. In situations where Energy Marketing & Trading has
received current information from negotiation activities with potential buyers
of these contracts that they believe to be representative of the market, the
information is considered in the determination of the fair value of the
contract.

Interest-rate swap and futures agreements, including those with the parent,
are used to manage the interest rate risk in the energy trading portfolio. Under
these swap agreements, Energy Marketing & Trading pays a fixed rate and receives
a variable rate on the notional amount of the agreements. Financial futures
contracts are commitments to either purchase or sell a financial instrument,
such as a Eurodollar deposit, U.S. Treasury bond or U.S. Treasury note, at a
future date for a specified price and are generally settled in cash, but may be
settled through delivery of the underlying instrument. 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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The valuation of the contracts entered into by Energy Marketing & Trading
and the natural gas liquids trading operations (reported in the Midstream Gas &
Liquids segment) 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 and the natural gas liquids
trading operations (reported in the Midstream Gas & Liquids segment) estimate
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 market volatility and liquidity 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 and the natural gas liquids trading operations
(reported in the Midstream Gas & Liquids segment) 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 and
the natural gas liquids trading operations (reported in the Midstream Gas &
Liquids segment) 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.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The gross forward contract credit exposure from energy trading and
price-risk management activities for Energy Marketing & Trading and the natural
gas liquids trading operations (reported in the Midstream Gas & Liquids segment)
as of December 31, 2002 and 2001 is summarized below.

Energy Marketing & Trading and the natural gas liquids trading operations
(reported in the Midstream Gas & Liquids segment) assess their credit exposure
on a net basis when appropriate and contractually allowed. The net forward
credit exposure from energy trading and price-risk management activities as of
December 31, 2002 and 2001 is summarized below.

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

(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 or 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 or Moody's
Investor's Service does not rate this counterparty. However, recent bond
issuances by this counterparty have been rated as investment grade by the
various rating agencies. This counterparty has been included in the
"investment grade" column based upon contractual credit requirements in the
event of assignment or novation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Energy commodity cash flow hedges

Williams is also exposed to market risk from changes in energy commodity
prices within Exploration & Production and Petroleum Services and the
non-trading operations of Energy Marketing & Trading and Midstream Gas &
Liquids. 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 and crude oil 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 and crude oil
market prices, Williams enters into natural gas and crude oil futures contracts
and swap agreements to fix the price of anticipated sales and purchases of
natural gas and crude oil.

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. There were no forecasted transactions hedged subsequent to
December 31, 2002 related to the Midsouth refinery. Additionally, hedge
accounting related to the Alaska refinery was discontinued when forecasted
transactions were no longer probable because of the refinery's anticipated sale
in 2003.

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. Hedge accounting was
discontinued for one of the electric generation facilities due to the sale of
the facility which closed in February 2003.

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 $.5 million
of losses and $.7 million of gains from hedge ineffectiveness are included in
revenues and costs and operating expenses, respectively, in the Consolidated
Statement of Operations during 2002. Approximately $1 million of gains from
hedge ineffectiveness is included in revenues in the Consolidated Statement of
Operations during 2001. Hedge accounting was discontinued and net gains of $43
million were reclassified out of accumulated other comprehensive income and
recognized in the Consolidated Statement of Operations during 2002 as a result
of it becoming probable that certain forecasted transactions would not occur. No
hedges were discontinued during 2001 as a result of it becoming probable that
the forecasted transaction will not occur. For 2002 and 2001, there were no
derivative gains or losses excluded from the assessment of hedge effectiveness.
There are approximately $83 million and $142 million of pre-tax gains related to
terminated derivatives included in accumulated other comprehensive income at
December 31, 2002 and 2001, respectively. The 2002 amounts will be recognized
into net income as the hedged transactions occur. As of December 31, 2002,
Williams had hedged future cash flows associated with anticipated energy
commodity purchases and sales for up to 13 years, and, based on recorded values
at December 31, 2002, approximately $42 million of net gains (net of income tax
provision of $26 million) will be reclassified into earnings within the next
year offsetting net losses that will be realized in earnings from previous
unfavorable market movements associated with the underlying hedged transactions.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 $8 million and $5 million of net gains
from hedge ineffectiveness was recognized in costs and operating expenses in the
Consolidated Statement of Operations during 2002 and 2001, respectively. There
were no derivative gains or losses excluded from the assessment of hedge
effectiveness. During third-quarter 2002, Williams discontinued the fair value
hedges related to refined products. Fair value hedges for crude oil will
continue until the completion of the Midsouth refinery sale.

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. As a result of the
completion of the sale of the Midsouth refinery during first-quarter 2003, these
derivatives have been discontinued.

Williams' operations associated with the production of natural gas enter
into basis swap agreements fixing the price differential between the Rocky
Mountain natural gas prices and Gulf Coast natural gas prices as part of their
overall natural gas price risk management program to reduce risk of declining
natural gas prices in basins with limited pipeline capacity to other markets.
Certain of these basis swaps do not qualify for hedge accounting treatment under
SFAS No. 133; hence, the net change in fair value of these derivatives
representing unrealized gains and losses is recognized in earnings currently as
revenues 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 was designated as a cash
flow hedge and was expected to be highly effective over the period of the hedge.
Hedge accounting was discontinued effective October 1, 2002 because the hedge is
no longer expected to be highly effective. Gains and losses from the change in
fair value of the derivative prior to October 1, 2002, 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 2002 or
2001 as a result of it becoming probable that the forecasted transaction will
not occur. The $2.4 million of net losses (net of income tax benefits of $1.5
million) deferred in other comprehensive income (loss) at December 31, 2002,
will be reclassified into earnings during 2003 as the note receivable impacts
earnings.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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, 2002
or 2001.

During 2002 Williams began managing its interest rate risk on an enterprise
basis by the corporate parent. The more significant of these risks relate to its
debt instrument as stated above, and its energy risk management and trading
portfolio. To facilitate the management of the risk, entities within Williams
may enter into derivative instruments (usually swaps) with the corporate parent.
The corporate parent determines the level, term and nature of derivative
instruments entered into with external parties. At December 31, 2002, these
external derivative instruments did not qualify for hedge accounting per SFAS
No. 133 and therefore are marked to market, the effect of which is shown as
interest rate swap loss in the Consolidated Statement of Operations below
operating income. At December 31, 2002, the loss totaled approximately $124.2
million.

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, 2002 and 2001:

Natural gas customers include pipelines, distribution companies, producers,
gas marketers and industrial users primarily located in the eastern,
northwestern and midwestern 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. Petroleum products customers include wholesale,
commercial, governmental, industrial and individual consumers and independent
dealers located primarily in Alaska and the Gulf Coast region of the United
States. Collection of the retained

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

interest in accounts receivable sold to the SPEs was dependent on the collection
of the receivables. The accounts receivable sold to SPEs were 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, 2002, approximately $230 million of certain power
receivables from the ISO and the California Power Exchange have not been paid
(compared to $388 million at December 31, 2001). Williams believes that it has
appropriately reflected the collection and credit risk associated with
receivables and trading assets in its statement of position and results of
operations at December 31, 2002. Also approximately 5,400 megawatts of Energy
Marketing & Trading's tolling portfolio are subject to agreements with
subsidiaries of the AES Corporation. The ability of Energy Marketing & Trading
to realize future estimated fair values may be significantly affected by the
ability of such parties to perform as contractually required.

Additionally, one counterparty has disputed a settlement amount related to
the liquidation of a trading position with Energy Marketing & Trading. The
amount of settlement is in excess of $100 million payable to Energy Marketing &
Trading. The matter is being arbitrated.

NOTE 16. 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 $9
million for potential refund as of December 31, 2002.

Williams Energy Marketing & Trading Company (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 2002, the FERC
issued an order which provided that, for the period between October 2, 2000 and
December 31, 2002, the FERC 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. On November 20, 2002, pursuant to an order from the 9th
Circuit, FERC issued an order permitting the California parties to conduct
additional discovery into market manipulation by sellers in the California
markets. The California parties sought this discovery in order to potentially
expand the scope of the refunds. The California parties had until March 3, 2003,
to submit evidence on market manipulation. Williams and other sellers will also
submit comments to the additional evidence. The judge issued his findings in the
refund case on December 12, 2002. Under these findings, Williams' refund
obligation to the California ISO is $192 million, excluding emissions costs and
interest. The judge found that Williams' refund obligation to the California PX
is $21.5 million, excluding interest. However, the judge found that the ISO owes
Williams $246.8 million, excluding interest, and that the PX owes Williams $31.7
million, excluding interest, and $2.9 million in charge backs. The judge's
findings do not include the $18 million in emissions costs that the judge found
Williams is entitled to use as an offset to refund liability, and the judge's
refund amounts are not based on final mitigated market clearing prices. FERC has
not acted on the proposed change to the gas methodology.

In an 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 was in effect from June 20,
2001 through September 30, 2002, established a market clearing price for spot
sales in all hours of the day that was based on the bid of the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

highest-cost gas-fired California generating unit that was needed to serve the
Independent System Operator's (ISO's) load. When generation operating reserves
fell 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 was 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 was
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
megawatt hour during emergency periods, and these maximum prices remained
unchanged throughout summer and fall 2001. Revisions to the plan for the
post-September 30, 2002, period were provided on July 17, 2002, as discussed
below.

On December 19, 2001, the FERC reaffirmed its June 19 order 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 would 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. On July 9,
2002, the ISO's operating reserve levels dropped below seven percent for a full
operating hour, during which the ISO declared a Stage 1 System Emergency
resulting in a new Market Clearing Price cap of $57.14/MWh under the FERC's
rules. On July 11, 2002, the FERC issued an order that the existing price
mitigation formula be replaced with a hard price cap of $91.87/MWh for spot
markets operated in the West (which is the level of price mitigation that
existed prior to the July 9, 2002 events that reduced the cap), to be effective
July 12, 2002. The cap expired September 30, 2002, but the cap was later
extended by FERC to October 30, 2002.

On July 17, 2002, the FERC issued its first order on the California ISO's
proposed market redesign. Key elements of the order include (1) maintaining
indefinitely the current must-offer obligation across the West; (2) the adoption
of Automatic Mitigation Procedures (AMP) to identify and limit excessive bids
and local market power within California, (bids less than $91.87/MWh will not be
subject to AMP); (3) a West-wide spot market bid cap of $250/MWh, beginning
October 1, 2002, and continuing indefinitely; (4) required the ISO to expedite
the following market design elements and requiring them to be filed by October
21, 2002: (a) creation of an integrated day-ahead market; (b) ancillary services
market reforms; and (c) hour-ahead and real-time market reforms; and (5) the
development of locational marginal pricing (LMP). The FERC reaffirmed these
elements in an order issued October 9, 2002, with the following clarification:
(a) generators may bid above the ISO cap, but their bids cannot set the market
clearing price and they will be subject to justification and refund, (b) if the
market clearing price is projected to be above $91.87 per MWh in any zone,
automatic mitigation will be triggered in all zones, (c) the 10 percent
creditworthiness adder will be removed effective October 31, 2002. On January
17, 2003, FERC clarified that bids below $91.87 per MWh are not entitled to a
safe harbor from mitigation, and where a seller is subject to the must-offer
obligation but fails to submit a bid, the ISO may impose a proxy bid. On October
31, 2002, FERC found that the ISO has not explained how it will treat generators
that are running at minimum load and dispatched for instructed energy. On
December 2, 2002, the ISO proposed to pay for energy at minimum load the
uninstructed energy price even when a unit is dispatched for instructed energy.
Williams protested on January 2, 2003, arguing that the ISO's proposal fails to
keep sellers whole.

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
California Electricity Oversight Board (CEOB) made a similar filing on February
27, 2002. The FERC set the complaint for hearing on April 25, 2002, but held the
hearing in

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abeyance pending settlement discussions before a FERC judge. The FERC also
ordered that the higher public interest test will apply to the contracts. The
FERC commented that the state has a very heavy burden to carry in proving its
case. On July 17, 2002, the FERC denied rehearing of the April 25, 2002, order
that set for hearing California's challenges to the long-term contracts entered
into between the state and several suppliers, including Energy Marketing &
Trading. The settlement discussions noted above have resulted in Williams
entering into a settlement agreement with the State of California and other
non-Federal parties that includes renegotiated long-term energy contracts. These
contracts are made up of block energy sales, dispatchable products and a gas
contract. The original contract contained only block energy sales. The
settlement does not extend to criminal matters or matters of willful fraud, but
will resolve civil complaints brought by the California Attorney General against
Williams that are discussed below and the State of California's refund claims
that are discussed above. Pursuant to the settlement, Williams also will provide
consideration of $147 million over eight years and six gas powered electric
turbines. In addition, the settlement is intended to resolve ongoing
investigations by the States of California, Oregon and Washington. The
settlement was reduced to writing and executed on November 11, 2002. The
settlement closed on December 31, 2002, after FERC issued an order granting
Williams' motion for partial dismissal from the refund proceedings. The
dismissal affects Williams' refund obligations to the settling parties, but not
to other parties, such as investor-owned utilities. Pursuant to the settlement,
the CPUC and CEOB filed on January 13, 2003, a motion to withdraw their
complaints against Williams regarding the original block energy sales contract.
Private class action plaintiffs also executed the settlement. Various court
filings and approvals are necessary to make the settlement effective as to
plaintiffs and to terminate the class actions as to Williams.

On May 2, 2002, PacifiCorp filed a complaint against Energy Marketing &
Trading seeking relief from rates contained in three separate confirmation
agreements between PacifiCorp and Energy Marketing & Trading (known as the
Summer 2002 90-Day Contracts). PacifiCorp filed similar complaints against three
other suppliers. PacifiCorp alleges that the rates contained in the contracts
are unjust and unreasonable. Energy Marking & Trading filed its answer on May
22, 2002, requesting that the FERC reject the complaint and deny the relief
sought. On June 28, 2002, the FERC set PacifiCorp's complaints for hearing, but
held the hearing in abeyance pending the outcome of settlement judge
proceedings. If the case goes to hearing, the FERC stated that PacifiCorp will
bear a heavy burden of proving that the extraordinary remedy of contract
modification is justified. The FERC set a refund effective date of July 1, 2002.
The hearing was conducted December 13 through December 20, 2002, at FERC. The
judge issued an initial decision on February 27, 2003 dismissing the complaints.
Williams expects this decision to be appealed to the FERC.

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, retroactive to May 1, 2000, and
possibly earlier.

On March 14, 2001, the FERC issued a Show Cause Order directing Energy
Marketing & Trading 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. As a result of federal
court orders, FERC released the data it obtained from Williams that gave rise to
the show cause order.

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On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking
(NOPR) 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. The FERC invited interested parties to comment
on the NOPR. On April 25, 2002, the FERC issued its staff analysis of the NOPR
and the comments received. The staff analysis proposes redefining the definition
of energy affiliates to exclude affiliated transmission providers. On May 21,
2002, the FERC held a public conference concerning the NOPR and the FERC invited
the submission of additional comments. If adopted, these new standards would
require the adoption of new compliance measures by certain Williams
subsidiaries.

On December 11, 2002, the FERC staff informed Transco of a number of issues
the FERC staff identified during the course of a formal, nonpublic investigation
into the relationship between Transco and its marketing affiliate, Energy
Marketing & Trading. The FERC staff asserted that Energy Marketing & Trading
personnel had access to Transco data bases and other information, and that
Transco had failed to accurately post certain information on its electronic
bulletin board. Williams, Transco and Energy Marketing & Trading did not agree
with all of the FERC staff's allegations and furthermore believe that Energy
Marketing & Trading did not profit from the alleged activities. Nevertheless, in
order to avoid protracted litigation, on March 13, 2003, Williams, Transco and
Energy Marketing & Trading executed a settlement of this matter with the FERC
staff. An Order approving the settlement was issued by the FERC on March 17,
2003. Pursuant to the terms of the settlement agreement, Transco will pay a
civil penalty in the amount of $20 million, beginning with a payment of $4
million within thirty (30) days of the date the FERC Order approving the
settlement becomes final. If no requests for rehearing are filed, the first
payment would be due by May 16, 2003, and $4 million payments on or before the
first, second, third and fourth anniversaries of the first payment. As a result
of the settlement agreement, effective December 31, 2002, Transco recorded a
charge to income and established a liability of $17 million on a discounted
basis to reflect the future payments to be made over the next four years. In
addition, Transco will provide notice to its merchant sales service customers
that it will be terminating such services when it is able to do so under the
terms of any applicable contracts and FERC certificates authorizing such
services. Most of these sales are made through a Firm Sales (FS) program, and
under this program Transco must provide two-year advance notice of termination.
Therefore, Transco will notify the FS customers of its intention to terminate
the FS service effective April 1, 2005. As part of the settlement, Energy
Marketing & Trading has agreed, subject to certain exceptions, that it will not
enter into new transportation agreements that would increase the transportation
capacity it holds on certain affiliated interstate gas pipelines, including
Transco. Finally, Transco and certain affiliates have agreed to the terms of a
compliance plan designed to ensure future compliance with the provisions of the
settlement agreement and the FERC's rules governing the relationship of Transco
and Energy Marketing & Trading.

On July 17, 2002, the FERC issued a Notice of Inquiry to seek comments on
its negotiated rate policies and practices. The FERC states that it is
undertaking a review of the recourse rate as a viable alternative and safeguard
against the exercise of market power of interstate gas pipelines, as well as the
entire spectrum of issues related to its negotiated rate program. The FERC
requested that interested parties respond to various questions related to the
FERC's negotiated rate policies and practices. Williams' Gas Pipeline companies
have negotiated rates under the FERC's existing negotiated rate programs and
participated in comments filed in this proceeding by Williams in support of the
FERC's existing negotiated rate program.

On August 1, 2002, the FERC issued a NOPR that proposes restrictions on
various types of cash management program employed by companies in the energy
industry, such as Williams and its subsidiaries. In

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addition to stricter guidelines regarding the accounting for and documentation
of cash management or cash pooling programs, the FERC proposal, if made final,
would preclude public utilities, natural gas companies and oil pipeline
companies from participating in such programs unless the parent company and its
FERC-regulated affiliate maintain investment-grade credit ratings and that the
FERC-regulated affiliate maintain stockholders equity of at least 30 percent of
total capitalization. Williams' and its regulated gas pipelines' current credit
ratings are not investment grade. Williams participated in comments in this
proceeding on August 28, 2002, by the Interstate Natural Gas Association of
America. On September 25, 2002, the FERC convened a technical conference to
discuss the issues raised in the comments filed by parties in this proceeding.

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 (Enron) (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 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. Williams is cooperating with all data requests
received in this proceeding. On May 8, 2002, Williams received an additional set
of data requests from the FERC related to a disclosure by Enron of certain
trading practices in which it may have been engaged in the California market. On
May 21, and May 22, 2002, the FERC supplemented the request inquiring as to
"wash" or "round trip" transactions. Williams responded on May 22, 2002, May 31,
2002, and June 5, 2002, to the data requests. On June 4, 2002, the FERC issued
an order to Williams to show cause why its market-based rate authority should
not be revoked as the FERC found that certain of Williams' responses related to
the Enron trading practices constituted a failure to cooperate with the staff's
investigation. Williams subsequently supplemented its responses to address the
show cause order. On July 26, 2002, Williams received a letter from the FERC
informing Williams that it had reviewed all of Williams' supplemental responses
and concluded that Williams responded to the initial May 8, 2002 request.

In response to an article appearing in the New York Times on June 2, 2002,
containing allegations by a former Williams employee that it had attempted to
"corner" the natural gas market in California, and at Williams' invitation, the
FERC is conducting an investigation into these allegations. Also, the Commodity
Futures Trading Commission (CFTC) and the U.S. Department of Justice (DOJ) are
conducting an investigation regarding gas and power trading and have requested
information from Williams in connection with this investigation.

Williams disclosed on October 25, 2002, that certain of its gas traders had
reported inaccurate information to a trade publication that published gas price
indices. On November 8, 2002, Williams received a subpoena from a federal grand
jury in Northern California seeking documents related to Williams' involvement
in California markets, including its reporting to trade publications for both
gas and power transactions. Williams is in the process of completing its
response to the subpoena. The CFTC's and the DOJ's investigations into this
matter are continuing.

On May 31, 2002, Williams received a request from the Securities and
Exchange Commission (SEC) to voluntarily produce documents and information
regarding "round-trip" trades for gas or power from January 1, 2000, to the
present in the United States. On June 24, 2002, the SEC made an additional
request for information including a request that Williams address the amount of
Williams' credit, prudency and/or other reserves associated with its energy
trading activities and the methods used to determine or calculate these

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reserves. The June 24, 2002, request also requested Williams' volumes, revenues,
and earnings from its energy trading activities in the Western U.S. market.
Williams has responded to the SEC's requests.

On July 3, 2002, the ISO announced fines against several energy producers
including Williams, for failure to deliver electricity in 2001 as required. The
ISO fined Williams $25.5 million, which will be offset against Williams' claims
for payment from the ISO. Williams believes the vast majority of fines are not
justified and has challenged the fines pursuant to the FERC -- approved process
contained in the ISO tariff.

On December 3, 2002, an administrative law judge at the FERC issued an
initial decision in Transcontinental Gas Pipe Line Corporation's general rate
case which, among other things, rejects the recovery of the costs of Transco's
Mobile Bay expansion project from its shippers on a "rolled-in" basis and finds
that incremental pricing for the Mobile Bay expansion project is just and
reasonable. The initial decision does not address the issue of the effective
date for the change to incremental pricing, although Transco's rates reflecting
recovery of the Mobile Bay expansion project costs on a "rolled-in" basis have
been in effect since September 1, 2001. The administrative law judge's initial
decision is subject to review by the FERC. Energy Marketing & Trading holds
long-term transportation capacity on the Mobile Bay expansion project. If the
FERC adopts the decision of the administrative law judge on the pricing of the
Mobile Bay expansion project and also requires that the decision be implemented
effective September 1, 2001, Energy Marketing & Trading could be subject to
surcharges of approximately $22 million for prior periods, in addition to
increased costs going forward.

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,
2002, these subsidiaries had accrued liabilities totaling approximately $31
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 and Texas Gas have identified
polychlorinated biphenyl contamination in air compressor systems, soils and
related properties at certain compressor station sites. Transcontinental Gas
Pipe Line and Texas Gas 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 Texas Gas and Transcontinental Gas Pipe
Line. Texas Gas and Transcontinental Gas Pipe Line likewise had accrued
liabilities for these costs which are included in the $31 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 addition to its Gas Pipelines, Williams and its subsidiaries, including
those reported in discontinued operations, 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

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former propane marketing operations primarily related to soil and groundwater
contamination. In addition, Williams owns a discontinued petroleum refining
facility that is being evaluated for potential remediation efforts. At December
31, 2002, Williams and its subsidiaries, including those reported in
discontinued operations, had accrued liabilities totaling approximately $52
million for these costs. Williams and its subsidiaries, including those reported
in discontinued operations, accrue 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, 2002, Williams and its subsidiaries,
including those reported in discontinued operations, had accrued receivables
totaling $1 million.

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, 2002, Williams had
approximately $9 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 from July 1, 1998 through July 2, 2001.
In November 2001, Williams furnished its response.

In 2002, Williams Refining & Marketing, LLC (Williams Refining) submitted
to the EPA a self-disclosure letter indicating noncompliance with the EPA's
benzene waste "NESHAP" regulations. This unintentional noncompliance had
occurred due to a regulatory interpretation that resulted in under-counting the
total annual benzene level at the Memphis refinery. Also in 2002, the EPA
conducted an all-media audit of the Memphis refinery. The EPA anticipates
releasing a report of its audit findings in mid-2003. The EPA will likely assess
a penalty on Williams Refining due to the benzene waste NESHAP issue, but the
amount of any such penalty is not known. On March 4, 2003, Williams completed
the sale of the Memphis refinery, and Williams is obligated to indemnify the
purchaser for any such penalty.

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.
Transcontinental Gas Pipe Line, through its agent Williams Energy Marketing &
Trading, continues to purchase gas under contracts which extend, in some cases,
through the life of the associated gas reserves. Certain of these contracts
contain royalty indemnification provisions which have no carrying value.
Producers have received and may receive other demands, which could result in
claims pursuant to royalty indemnification provisions. Indemnification for
royalties will depend on, among other things, the specific lease provisions
between the producer and the lessor and the terms of the agreement between the
producer and either Transcontinental Gas Pipe Line or Texas Gas. Consequently,
the potential maximum future payments under such indemnification provisions
cannot be determined.

As a result of the settlements, Transcontinental Gas Pipe Line has been
sued by certain producers seeking indemnification from Transcontinental Gas Pipe
Line. 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 were 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

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petition for review. As a result, Transcontinental Gas Pipe Line recorded a
pre-tax charge to income for the year ended December 31, 2001, in the amount of
$37 million ($18 million was 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 filed a motion for rehearing which
was denied, thereby concluding this matter. In May 2002, Transcontinental Gas
Pipe Line paid the producer the amount of the judgment and accrued interest.
Transcontinental Gas Pipe Line is currently defending two lawsuits in which
producers have asserted damages, including interest calculated through December
31, 2002, of approximately $18 million. 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 FERC Order 528.

On June 8, 2001, fourteen 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
fourteen Williams entities named as defendants in the lawsuit. 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. On August 19, 2002,
the defendants' motion to dismiss on nonjurisdictional grounds was denied. On
September 17, 2002, the plaintiffs filed a motion for class certification. The
Williams entities joined with other defendants in contesting certification of
the class and this issue with the personal jurisdiction motion remain pending.

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. In connection with its sale of Kern River, the Company agreed to
indemnify the purchaser for any liability relating to this claim, including
legal fees. The maximum amount of future payments that Williams could
potentially be required to pay under this indemnification depends upon the
ultimate resolution of the claim and cannot currently be determined. No amounts
have been accrued for this indemnification. Grynberg has also filed claims
against approximately 300 other energy companies and alleged that the defendants
violated the False Claims Act in connection with the measurement, royalty
valuation and purchase of hydrocarbons. The relief sought was 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 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. On October 9, 2002,
the court granted a motion to dismiss Grynberg's royalty valuation claims.
Grynberg's measurement claims remain pending against Williams and the other
defendants.

On August 6, 2002, Jack J. Grynberg, and Celeste C. Grynberg, Trustee on
Behalf of the Rachel Susan Grynberg Trust, and the Stephen Mark Grynberg Trust,
served The Williams Companies and Williams Production RMT Company with a
complaint in the District Court in and for the City of Denver, State of
Colorado. The complaint alleges that the defendants have used mismeasurement
techniques that distort the BTU heating content of natural gas, resulting in the
alleged underpayment of royalties to Grynberg and other independent natural gas
producers. The complaint also alleges that defendants inappropriately took
deductions from the gross value of their natural gas and made other royalty
valuation errors. Theories for relief include breach of contract, breach of
implied covenant of good faith and fair dealing, anticipatory repudiation,
declaratory relief, equitable accounting, civil theft, deceptive trade
practices, negligent misrepresentation, deceit based on fraud, conversion,
breach of fiduciary duty, and violations of the state racketeering statute.
Plaintiff is seeking actual damages of between $2 million and $20 million based
on interest rate variations, and punitive damages in the amount of approximately
$1.4 million dollars. On October 7, 2002, the Williams

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defendants filed a motion to stay the proceedings in this case based on the
pendency of the False Claims Act litigation discussed in the preceding
paragraph.

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 and its subsidiaries were dismissed from
all of the cases, except one. The parties in the only remaining case in which
Williams or its subsidiaries are named as defendants have agreed on the
settlement documents, which provide that Williams and its subsidiaries will be
dismissed with prejudice before consummating the settlement. Williams is
awaiting return of the executed documents and the dismissal. The settlement does
not obligate Williams or its subsidiaries to pay any monies to the remaining
plaintiff.

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 Energy Marketing & Trading, 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
administratively consolidated in San Diego County Superior Court. As part of a
comprehensive settlement with the State of California and other parties,
Williams and the lead plaintiffs in these suits have resolved the claims. While
the settlement is final as to the State of California, the San Diego Superior
Court must still approve it as to the plaintiff ratepayers.

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 and fourteen executive
officers, including Energy Marketing & Trading and Williams' then current
officers Keith Bailey, Chairman and CEO of Williams, Steve Malcolm, President
and CEO of Williams Energy Services and an Executive Vice President of Williams,
and Bill Hobbs, Senior Vice President 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 administratively consolidated with the other class actions in San
Diego Superior Court. As part of a comprehensive settlement with the State of
California and other parties, Williams and the lead plaintiffs in these suits
have resolved the claims. While the settlement is final as to the State of
California, the San Diego Superior Court must still approve it as to the
plaintiffs in this suit.

On October 5, 2001, a 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. Private plaintiffs have also
brought five similar cases against Williams and others on similar grounds. These
suits have all been removed to federal court, and plaintiffs are seeking to
remand the cases to state court. In January, 2003, the federal district court
granted the plaintiffs' motion to remand the case to San Diego Superior Court,
but on February 20, 2003, the United States Court of Appeals for the Ninth
Circuit, on its own motion, stayed the remand order pending its review of an
appeal of the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

remand order by certain defendants. As part of a comprehensive settlement with
the State of California and other parties, Williams and the lead plaintiffs in
these suits have resolved the claims. While the settlement is final as to the
State of California, once the jurisdictional issue is resolved, either the San
Diego Superior Court or the United States District Court for the Southern
District of California must still approve the settlement as to the plaintiff
ratepayers and taxpayers.

On March 11, 2002, the California Attorney General filed a civil complaint
in San Francisco Superior Court against Williams and three other sellers of
electricity alleging unfair competition relating to sales of ancillary power
services between 1998 and 2000. The complaint seeks restitution, disgorgement
and civil penalties of approximately $150 million in total. This case has been
removed to federal court. On April 9, 2002, the California Attorney General
filed a civil complaint in San Francisco Superior Court against Williams and
three other sellers of electricity alleging unfair and unlawful business
practices related to charges for electricity during and after 2000. The maximum
penalty for each violation is $2,500 and the complaint seeks a total fine in
excess of $1 billion. These cases have been removed to federal court. Motions to
remand have been denied. Finally, the California Attorney General has indicated
he may file a Clayton Act complaint against AES Southland and Williams relating
to AES Southland's acquisition of Southern California generation facilities in
1998, tolled by Williams. Williams believes the complaints against it are
without merit. As part of a comprehensive settlement with the State of
California and other parties, Williams and the plaintiffs in these suits have
resolved the claims. The settlement is final, and the complaint has been
withdrawn.

Numerous shareholder class action suits have been filed against Williams in
the United States District Court for the Northern District of Oklahoma. The
majority of the suits allege that Williams and co-defendants, WCG and certain
corporate officers, have acted jointly and separately to inflate the stock price
of both companies. Other suits allege similar causes of action related to a
public offering in early January 2002, known as the FELINE PACS offering. These
cases were filed against Williams, certain corporate officers, all members of
the Williams board of directors and all of the offerings' underwriters. These
cases have all been consolidated and an order has been issued requiring separate
amended consolidated complaints by Williams and WCG equity holders. The amended
complaint of the WCG securities holders was filed on September 27, 2002, and the
amended complaint of the WMB securities holders was filed on October 7, 2002. In
addition, four 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. A motion to consolidate these
suits has been approved. Williams and other defendants have filed motions to
dismiss each of these suits and oral arguments on the motions will be held in
April 2003. Derivative shareholder suits have been filed in state court in
Oklahoma, all based on similar allegations. On August 1, 2002, a motion to
consolidate and a motion to stay these suits pending action by the federal court
in the shareholder suits was approved.

On July 26, 2002, Williams entered into a Settlement Agreement with its
former telecommunications subsidiary, WCG, the official committee of unsecured
creditors, and Leucadia, whereby Williams settled its claims against WCG in
exchange for $180 million cash for the sale of its claims to Leucadia and the
sale of the Williams Technology Center to WCG. The settlement closed into escrow
on October 15, 2002, and was finalized on December 2, 2002. This matter is
discussed more fully in Note 2.

On April 26, 2002, the Oklahoma Department of Securities issued an order
initiating an investigation of Williams and WCG regarding issues associated with
the spin-off of WCG and regarding the WCG bankruptcy. Williams has committed to
cooperate fully in the investigation.

On November 30, 2001, Shell Offshore, Inc. filed a complaint at the FERC
against Williams Gas Processing -- Gulf Coast Company, L.P. (WGP), Williams Gulf
Coast Gathering Company (WGCGC), Williams Field Services Company (WFS) and
Transcontinental Gas Pipe Line Corporation (Transco), alleging concerted actions
by the affiliates frustrating the FERC's regulation of Transco. The alleged
actions

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THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

are related to offers of gathering service by WFS and its subsidiaries on the
recently spundown and deregulated North Padre Island offshore gathering system.
On September 5, 2002, the FERC issued an order reasserting jurisdiction over
that portion of the North Padre Island facilities previously transferred to WFS.
The FERC also determined an unbundled gathering rate for service on these
facilities which is to be collected by Transco. Transco, WGP, WGCGC and WFS
believe their actions were reasonable and lawful and have sought rehearing of
the FERC's order.

On October 23, 2002, Western Gas Resources, Inc. and its subsidiary, Lance
Oil and Gas Company, Inc. filed suit against Williams Production RMT Company in
District Court for Sheridan, Wyoming, claiming that the merger of Barrett
Resources Corporation and Williams triggered a preferential right to purchase a
portion of the coal bed methane development properties owned by Barrett in the
Powder River Basin of northeastern Wyoming. In addition, Western claims that the
merger triggered certain rights of Western to replace Barrett as operator of
those properties. Mediation efforts were not successful in resolving the
dispute. The Company believes that the claims have no merit.

Williams Alaska Petroleum, Inc. (WAPI) is actively engaged in
administrative litigation being conducted jointly by the FERC and the Regulatory
Commission of Alaska concerning the Trans-Alaska Pipeline System (TAPS) Quality
Bank. Primary issues being litigated include the appropriate valuation of the
naphtha, heavy distillate, vacuum gas oil and residual product cuts within the
TAPS Quality Bank as well as the appropriate retroactive effects of the
determinations. WAPI's interest in these proceedings is material as the matter
involves claims by crude producers and the State of Alaska for retroactive
payments plus interest from WAPI in the range of $150 million to $200 million in
aggregate. Because of the complexity of the issues involved, however, the
outcome cannot be predicted within certainty nor can the likely result be
quantified.

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

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
protection. Williams has filed its proofs of claim prior to the court-ordered
October 15, 2002, bar date. 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. During
2002, Energy Marketing & Trading sold rights to certain Enron receivables to a
third party in exchange for $24.5 million in cash. The $24.5 million was
recorded within the trading revenues in first-quarter 2002.

Energy Marketing & Trading has paid and received various settlement amounts
in conjunction with the liquidation of trading positions in 2002. Additionally,
one counterparty has disputed a settlement amount related to the liquidation of
a trading position with Energy Marketing & Trading and the amount of settlement
is in excess of $100 million payable to Energy Marketing & Trading. The matter
is being arbitrated.

SUMMARY

Litigation, arbitration, regulatory matters and environmental matters are
subject to inherent uncertainties. Were an unfavorable ruling to occur, there
exists the possibility of a material adverse impact on the net income of the
period in which the ruling occurs. Management, including internal counsel,
currently believes

167

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

that the ultimate resolution of the foregoing matters, taken as a whole and
after consideration of amounts accrued, insurance coverage, recovery from
customers or other indemnification arrangements, will not have a materially
adverse effect upon Williams' future financial position.

COMMITMENTS

Energy Marketing & Trading has entered into certain contracts giving it the
right to receive fuel conversion services as well as certain other services
associated with electric generation facilities that are currently in operation
throughout the continental United States. At December 31, 2002, annual estimated
committed payments under these contracts range from approximately $60 million to
$462 million, resulting in total committed payments over the next 20 years of
approximately $8 billion.

NOTE 17. RELATED PARTY TRANSACTIONS

LEHMAN BROTHERS HOLDINGS, 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. In third-quarter 2002, RMT, a wholly owned subsidiary, entered into a
$900 million short-term Credit Agreement dated July 31, 2002, with certain
lenders, including a subsidiary of Lehman Brothers Inc. (see Note 11). Included
in interest accrued on the Consolidated Statement of Operations for 2002 are
$154.1 million of interest expense, including amortization of deferred set-up
fees related to the RMT note. As of December 31, 2002, the amount payable
related to the RMT note and related interest was approximately $1 billion. In
addition, Williams paid $39.6 million and $27 million to Lehman Brothers Inc. in
2002 and 2001, respectively, primarily for underwriting fees related to debt and
equity issuances as well as strategic advisory and restructuring success fees.

AMERICAN ELECTRIC POWER COMPANY, INC.

American Electric Power Company, Inc. (AEP) is a related party as a result
of a director that serves on both Williams' and AEP's board of directors.
Williams' Energy Marketing & Trading segment engaged in forward and physical
power and gas trading activities with AEP. Net revenues from AEP were $133.9
million in 2002. At December 31, 2002, amounts due from and due to AEP were
$96.4 million and $331.3 million, respectively.

EXXON MOBIL CORPORATION

Exxon Mobil Corporation was a related party as a result of a director that
serves on both Williams' and Exxon Mobil Corporation's board of directors.
Transactions with Exxon Mobil Corporation result primarily from the purchase and
sale of crude oil, refined products and natural gas liquids in support of crude
oil, refined products and natural gas liquids trading activities and strategies
as well as revenues generated from gathering and processing activities.
Aggregate revenues, including those reported on a net basis, from this customer
were $217.6 million, $38.9 million and $10.2 million in 2002, 2001 and 2000,
respectively, while aggregate purchases from this customer were $15.6 million,
$6.4 million and $69.9 million in 2002, 2001 and 2000, respectively. Amounts due
from Exxon Mobil were $22.1 million and $8.3 million as of December 31, 2002 and
2001, respectively. Amounts due to Exxon Mobil were $66.9 million and $140.3
million as of December 31, 2002 and 2001, respectively.

168

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 18. ACCUMULATED OTHER COMPREHENSIVE INCOME

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

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 2). In addition, the balances at December 31 in
the previous table

169

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

include components of accumulated other comprehensive income that are related to
discontinued operations. The amounts related to discontinued operations for the
years ended December 31 are as follows:

NOTE 19. SEGMENT DISCLOSURES

SEGMENTS AND RECLASSIFICATION OF OPERATIONS

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 and certain activities previously
reported within the International segment.

Effective July 1, 2002, management of certain operations previously
conducted by Energy Marketing & Trading, the previously reported International
segment and Petroleum Services was transferred to Midstream Gas & Liquids. These
operations included natural gas liquids trading, activities in Venezuela and a
petrochemical plant, respectively. Segment amounts have been restated for all
periods presented to reflect these changes.

On April 11, 2002, Williams Energy Partners L.P., a partially owned and
consolidated entity of Williams, acquired Williams Pipe Line, an operation
within Petroleum Services. Accordingly, Williams Pipe Line's operations have
been transferred from the Petroleum Services segment to the Williams Energy
Partners segment and the segment information is reflected as such for all
periods presented.

Segment amounts for 2001 and 2000 reflect the reclassification of the
International segment to other.

SEGMENTS -- PERFORMANCE MEASUREMENT

Williams currently 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.

In first-quarter 2002, Williams began managing its interest rate risk on an
enterprise basis by the corporate parent. The more significant of these risks
relate to its debt instruments and its energy risk management and trading
portfolio. To facilitate the management of the risk, entities within Williams
may enter into derivative instruments (usually swaps) with the corporate parent.
Generally, the level, term and nature of derivative instruments entered into
with external parties were determined by the corporate parent. Energy Marketing
& Trading has entered into intercompany interest rate swaps with the corporate
parent, the effect of which is included in Energy Marketing & Trading's segment
revenues and segment profit (loss) as shown in the reconciliation within the
following tables. The results of interest rate swaps with external

170

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

counterparties are shown as interest rate swap loss in the Consolidated
Statement of Operations below operating income.

The majority of energy commodity hedging by the Exploration & Production
and Petroleum 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 counterparty performance risks associated with unrelated third
parties.

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, goodwill
and other intangible assets.

In 2001, one of Energy Marketing & Trading's customers exceeded 10 percent
of Williams' revenues with sales of approximately $937 million. In 2002 and
2000, there were no customers who exceeded 10 percent of Williams' revenues.

171

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.

172

THE WILLIAMS COMPANIES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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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.

Energy Marketing & Trading's net revenues can vary quarter to quarter based
on the timing of origination activities and market movements of commodity
prices, interest rates and counterparty credit worthiness impacting the
determination of fair value contracts. Energy Marketing & Trading's net segment
revenues were $355.0 million, $(278.6) million, $(290.2) million and $128.6
million for the first, second, third and fourth quarters respectively for 2002.

Net loss for fourth-quarter 2002 includes the following items which are
pre-tax:

- $85.0 million net revenue impact related to the settlement of Energy
Marketing & Trading contracts with the State of California

- $44.7 million impairment of the Worthington generation facility at
Energy Marketing & Trading (see Note 4)

- $50.8 million loss accruals and impairments of other power related
assets at Energy Marketing & Trading (see Note 4)

- $17.0 million charge associated with a FERC settlement (see Note 16)

- $115.0 million impairment of Canadian assets at Midstream Gas &
Liquids (see Note 4)

174

THE WILLIAMS COMPANIES, INC

QUARTERLY FINANCIAL DATA -- (CONTINUED)

- $18.4 million impairment of Alaska assets at Petroleum Services (see
Note 4)

- $19.2 million income from discontinued operations (see Note 2)

- $172.0 million loss from discontinued operations for impairments and
net losses on sales (see Note 2)

Net loss for third-quarter 2002 includes the following items which are
pre-tax:

- $10.5 million loss accruals related to commitments for certain assets
previously planned to be used in power projects at Energy Marketing &
Trading (see Note 4)

- $11.6 million net write-down pursuant to the sale of Williams' equity
interest in a Canadian and U.S. gas pipeline, at Gas Pipeline (see
Note 3)

- $143.9 million gain related to the sale of certain natural gas
production properties at Exploration & Production (see Note 4)

- $58.5 million gain on sale of Williams' investment in a Lithuanian oil
refinery, pipeline and terminal complex, which was included in the
previously reported International segment (see Note 3)

- $22.9 million charge included in continuing operations related to
estimated losses from an assessment of the recoverability of WCG
related receivables (see Note 2)

- $22.5 million income from discontinued operations (see Note 2)

- $231.4 million loss from discontinued operations for impairments and
net losses on sales (see Note 2)

Net loss for second-quarter 2002 includes the following items which are
pre-tax:

- $57.5 million impairment of goodwill due to deteriorating market
conditions in the merchant energy sector at Energy Marketing & Trading
(see Note 4)

- $58.9 million of loss accruals related to commitments for certain
assets previously planned to be used in power projects and write-offs
associated with a terminated power plant project at Energy Marketing &
Trading (see Note 4)

- $31.8 million impairment of other power related assets at Energy
Marketing & Trading (see Note 4)

- $12.3 million write-down of Gas Pipeline's investment in a pipeline
project which was cancelled in 2002 (see Note 3)

- $27.4 million benefit which reflects a contractual construction
completion fee received by Williams whose operations are accounted for
under the equity method of accounting (see Note 3)

- $15.0 million charge included in continuing operations related to
estimated losses from an assessment of the recoverability of WCG
related receivables (see Note 2)

- $29.4 million of expense was recorded for Williams' early retirement
option

- $20.8 million income from discontinued operations (see Note 2)

- $71.1 million loss from discontinued operations for impairments and
net losses on sales (see Note 2)

175

THE WILLIAMS COMPANIES, INC

QUARTERLY FINANCIAL DATA -- (CONTINUED)

Net income for first-quarter 2002 includes the following items which are
pre-tax:

- $232.0 million charge included in continuing operations related to
estimated losses from an assessment of the recoverability of WCG
related receivables (see Note 2)

- $52.5 million income from discontinued operations (see Note 2)

- $38.1 million loss from discontinued operations for impairments and
net losses on sales (see Note 2)

Energy Marketing and Trading's net segment revenues for first, second,
third and fourth quarters of 2001 were $598.2 million, $337.7 million, $493.1
million and $276.6 million respectively. Energy Marketing and Trading's revenues
can vary as discussed above.

Net loss for fourth-quarter 2001 includes the following items which are
pre-tax:

- $130.0 million decrease to revenues and an approximate $4 million
charge to bad debt expense related to Williams' estimated net exposure
for the Enron bankruptcy at Energy Marketing & Trading and Gas
Pipeline, respectively (see Note 16)

- $13.3 million impairment charge for the termination of a plant
expansion at Energy Marketing & Trading (see Note 4)

- $37.4 million charge resulting from an unfavorable court decision in
one of Transcontinental Gas Pipe Line's royalty claims proceedings
(see Note 16)

- $213.0 million charge included in continuing operations related to
estimated losses from an assessment of the recoverability of WCG
related receivables (see Note 2)

- $57.7 million income from discontinued operations (see Note 2)

- $2,023.9 million loss from discontinued operations for impairments and
net losses on sales (see Note 2)

Net income for third-quarter 2001 includes the following items which are
pre-tax:

- $23.3 million charge related to the write-down of certain equity and
cost basis investments at Energy Marketing & Trading (see Note 3)

- $70.9 million charge included in continuing operations related to
estimated losses from an assessment of the recoverability of WCG
related receivables (see Note 2)

- $65.2 million income from discontinued operations (see Note 2)

Net income for second-quarter 2001 includes the following items which are
pre-tax:

- $72.1 million gain from the sale of certain convenience stores at
Petroleum Services (see Note 4)

- $10.9 million impairment loss related to certain south Texas
non-regulated gathering and processing assets at Midstream Gas &
Liquids (see Note 4)

- $27.5 million gain on sale of Williams' limited partnership interest
in Northern Border Partners, L.P. at Gas Pipeline (see Note 3)

- $77.6 million income from discontinued operations (see Note 2)

176

THE WILLIAMS COMPANIES, INC

QUARTERLY FINANCIAL DATA -- (CONTINUED)

Net income for first-quarter 2001 includes the following items which are
pre-tax:

- $11.2 million impairment charge related to Petroleum Services'
end-to-end mobile computing systems business (see Note 4)

- $233.8 million loss from discontinued operations (see Note 2)

177

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES
(UNAUDITED)

The following information pertains to the Williams' 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 and Mid-continent 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 5.2 percent and 3.1 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 for 2002 and 2001 does not
include approximately $1 billion of goodwill related to the purchase of
Barrett Resources Corp. (Barrett) in 2001.

- Proved properties include capitalized costs for oil and gas leaseholds
holding proved reserves; development wells and related equipment and
facilities (including uncompleted development well costs); 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

- 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 during 2001.

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THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES -- (CONTINUED)

- 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.

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 purchasers.
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.

179

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES -- (CONTINUED)

- Exploration expenses include unsuccessful exploratory dry hole costs,
leasehold impairment, geological and geophysical expenses and the cost of
retaining undeveloped leaseholds.

- Depreciation, depletion and amortization includes depreciation of support
equipment.

PROVED RESERVES

- The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation
S-X) as the estimated quantities of crude oil, natural gas, and natural
gas liquids which geological and engineering data demonstrate with
reasonable certainty are recoverable in future years from known
reservoirs under existing economic and operating conditions. Williams'
proved reserves consist of two categories, proved developed reserves and
proved undeveloped reserves. Proved developed reserves are currently
producing wells and wells awaiting minor sales connection expenditure,
recompletion, additional perforations or borehole stimulation treatments.
Proved undeveloped reserves are those reserves which are expected to be
recovered from new wells on undrilled acreage or from existing wells
where a relatively major expenditure is required for recompletion. Proved
reserves on undrilled acreage are limited to those drilling units
offsetting productive units that are reasonably certain of production
when drilled or where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation.

- Natural gas reserves are computed at 14.73 pounds per square inch
absolute and 60 degrees Fahrenheit. Crude oil reserves are insignificant
and have been included in the proved reserves on a basis of billion cubic
feet equivalents (Bcfe).

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES

The following is based on the estimated quantities of proved reserves and
the year-end prices and costs. The average year end natural gas prices used in
the following estimates were $3.85, $2.31 and $9.17 per mmcfe at December 31,
2002, 2001 and 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. Of the $1,215 million of future
development costs, $147 million, $186 million and $197 million are estimated to
be spent in 2003, 2004 and 2005, respectively.

Numerous uncertainties are inherent in estimating volumes and the value of
proved reserves and in projecting future production rates and timing of
development expenditures. Such reserve estimates are subject

180

THE WILLIAMS COMPANIES, INC.

SUPPLEMENTAL OIL AND GAS DISCLOSURES -- (CONTINUED)

to change as additional information becomes available. The reserves actually
recovered and the timing of production may be substantially different from the
reserve estimates.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

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

181

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 amounts included in the liability for
Guarantees and payment obligations related to Williams Communications
Group, Inc. at December 31, 2001 (see Note 2 of Notes to Consolidated
Financial Statements).

(f) Included in revenue.

(g) Reflects a reclassification of the reserve related to Enron from Price-risk
management credit reserves to Allowance for doubtful accounts -- Accounts
and notes receivable (see Note 16 of Notes to Consolidated Financial
Statements) and amounts related to acquisitions of businesses.

(h) Reflects a reclassification of the reserve related to Enron from Price-risk
management credit reserves to Allowance for doubtful accounts -- Accounts
and notes receivable (see Note 16 of Notes to consolidated Financial
Statements).

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

None

182

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information regarding our directors and nominees for director required
by Item 401 of Regulation S-K will be presented under the heading "Election of
Directors" in our Proxy Statement prepared for the solicitation of proxies in
connection with our Annual Meeting of Stockholders for 2003 (the "Proxy
Statement"), which information is incorporated by reference herein. Information
regarding our executive officers is presented as Item 4A 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 will be
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 will be 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 AND
RELATED STOCKHOLDER MATTERS

The information regarding the security ownership of certain beneficial
owners and management required by Item 403 of Regulation S-K will be presented
under the headings "Security Ownership of Certain Beneficial Owners and
Management" in the Proxy Statement, which information is incorporated by
reference herein.

The information regarding our Equity Compensation Stock Plans required by
Item 201(d) of Regulation S-K will be presented under the heading "Equity
Compensation Stock Plans" in our Proxy Statement prepared for the solicitation
of proxies in connection with our Annual Meeting of Stockholders for 2003 (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 will be presented under the heading
"Certain Relationships and Related Transactions" in the Proxy Statement, which
information is incorporated by reference herein.

ITEM 14. CONTROLS AND PROCEDURES

An evaluation of the effectiveness of the design and operation of our
disclosure controls and procedures (as defined in Rule 13a-14(c) and 15d-14(c)
of the Securities Exchange Act) was performed within the 90 days prior to the
filing date of this report. This evaluation was performed under the supervision
and with the participation of our management, including our Chief Executive
Officer and Acting Chief Financial Officer. Based upon that evaluation, our
Chief Executive Officer and Acting Chief Financial Officer concluded that these
disclosure controls and procedures are effective.

There have been no significant changes in our internal controls or other
factors that could significantly affect internal controls since the certifying
officers' most recent evaluation of those controls.

183

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) 1 and 2.

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.

INDEX TO EXHIBITS

184

185

186

187

188

189

190

191

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

* 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. During fourth-quarter 2002, Williams filed an Item
5 Form 8-K on October 24, 2002, and an Item 9 Form 8-K on the following dates:
October 24, 25 and 30 (2 Form 8-Ks filed on this date), November 8, 12, 15 and
26 and December 5, 17 and 19, 2002.

(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.

192

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/ BRIAN K. SHORE
------------------------------------
Brian K. Shore
Attorney-in-fact

Date: March 19, 2003

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.

193

194

CERTIFICATIONS

I, Steven J. Malcolm, certify that:

1. I have reviewed this annual report on Form 10-K of The Williams
Companies, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14), for the registrant and have:

a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

b) Evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and

c) Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

By: /s/ STEVEN J. MALCOLM
------------------------------------
Steven J. Malcolm
President and Chief Executive
Officer
(Principal Executive Officer)

Date: March 19, 2003

195

I, Gary R. Belitz, certify that:

1. I have reviewed this annual report on Form 10-K of The Williams
Companies, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14), for the registrant and have:

a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

b) Evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and

c) Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

By: /s/ GARY R. BELITZ
------------------------------------
Gary R. Belitz
Acting Chief Financial Officer
(Principal Financial Officer) and
Controller
(Principal Accounting Officer)

Date: March 19, 2003

196

INDEX TO EXHIBITS