WILLIAMS COMPANIES INC - 10-Q Quarterly Report

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

FORM 10-Q
(Mark One)

(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2002
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OR

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

For the transition period from to
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Commission file number 1-4174
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THE WILLIAMS COMPANIES, INC.
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(Exact name of registrant as specified in its charter)

DELAWARE 73-0569878
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(State of Incorporation) (IRS Employer Identification Number)

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

Registrant's telephone number: (918) 573-2000
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NO CHANGE
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Former name, former address and former fiscal year,
if changed since last report.

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 the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date.

Class Outstanding at July 31, 2002
- -------------------------- ----------------------------
Common Stock, $1 par value 516,512,571 Shares

The Williams Companies, Inc.
Index

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

Forward-looking statements can be identified by words such as
"anticipates," "believes," "expects," "planned," "scheduled" or similar
expressions. Although Williams believes these forward-looking statements are
based on reasonable assumptions, statements made regarding future results are
subject to a number of assumptions, uncertainties and risks that may cause
future results to be materially different from the results stated or implied in
this document. Additional information about issues that could lead to material
changes in performance is contained in The Williams Companies, Inc.'s 2001
Form 10-K.

1

The Williams Companies, Inc.
Consolidated Statement of Operations
(Unaudited)

*Certain amounts have been restated or reclassified as described in Note 2 of
Notes to Consolidated Financial Statements.

See accompanying notes.

2

The Williams Companies, Inc.
Consolidated Balance Sheet
(Unaudited)

* Certain amounts have been restated or reclassified as described in Note 2 of
Notes to Consolidated Financial Statements.

See accompanying notes.

3

The Williams Companies, Inc.
Consolidated Statement of Cash Flows
(Unaudited)

* Amounts have been restated or reclassified as described in Note 2 of Notes to
Consolidated Financial Statements.

** Includes cash and cash equivalents of discontinued operations of
$9.7 million, $23.7 million and $224.2 million at December 31, 2001,
June 30, 2001 and December 31, 2000, respectively.

See accompanying notes.

4

The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)

1. General

Recent Developments

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 during the first
quarter of 2002 to strengthen its balance sheet. During the second quarter, the
results of the energy marketing and trading business were not profitable
reflecting market movements against its portfolio and an absence of origination
activities. These unfavorable conditions were in large part a result of market
concerns about Williams' credit and liquidity situation and limited this
business' ability to manage market risk and exercise hedging strategies as
market liquidity deteriorated. Subsequent to June 30, 2002, Williams' credit
ratings were lowered below investment grade and it was unable to complete a
renewal of its unsecured short-term bank credit facility. Following these
events, Williams sold assets in July 2002 receiving net proceeds of
approximately $1.5 billion, obtained secured credit facilities totaling $1.3
billion and amended its $700 million revolving credit facility to a secured
basis. The effect of these transactions will be recorded in the third quarter of
2002. The Company has also reduced projected levels of capital expenditures and
is considering selling other assets in the future to provide additional
financial flexibility and liquidity. The board of directors reduced the
quarterly dividend on common stock for the third quarter from the prior level of
$.20 per share to $.01 per share. On August 1, 2002, Williams also announced its
intentions to reduce its commitment to the energy marketing and trading
business. This reduction could be realized by entering into a joint venture with
a third party or sale of a portion or all of the marketing and trading
portfolio. Additional information on these events is discussed in Note 18 and in
Management's Discussion and Analysis included in this Form 10-Q.

Other

The accompanying interim consolidated financial statements of The Williams
Companies, Inc. (Williams) do not include all notes in annual financial
statements and therefore should be read in conjunction with the consolidated
financial statements and notes thereto in Williams' Current Report on Form 8-K
dated May 28, 2002. The accompanying financial statements have not been audited
by independent auditors, but include all normal recurring adjustments and
others, including asset impairments and loss accruals, which, in the opinion of
Williams' management, are necessary to present fairly its financial position at
June 30, 2002, its results of operations for the three and six months ended June
30, 2002 and 2001, and its cash flows for the six months ended June 30, 2002 and
2001.

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.

2. Basis of presentation

On March 27, 2002, Williams completed the sale of one of its Gas Pipeline
segments, Kern River Gas Transmission (Kern River), to MidAmerican Energy
Holdings Company (MEHC). Accordingly, the accompanying consolidated financial
statements and notes reflect the results of operations, financial position and
cash flows of Kern River as discontinued operations. Unless indicated otherwise,
the information in the Notes to Consolidated Financial Statements relates to the
continuing operations of Williams (see Note 7).

Certain other statement of operations, balance sheet and cash flow amounts
have been reclassified to conform to the current classifications. Additionally,
certain segment amounts have been reclassified as a result of transfers of
management effective April 11, 2002 and July 1, 2002 (see Note 16).

3. Asset sales, impairments and other accruals

Williams offered an enhanced-benefit early retirement option to certain
employee groups. The deadline for electing the early retirement option was April
26, 2002. The three and six months ended June 30, 2002, reflects $30 million of
expense associated with the early retirement, of which $24 million is recorded
in selling, general and administrative expenses and the remaining in general
corporate expenses.

In a Form 8-K filed on May 28, 2002, Williams announced a plan that is
designed to further improve the company's financial position and more narrowly
focus its business strategy within its major business units. Part of this plan
includes the generation of $1.5 billion to $3 billion of proceeds from the sale
of assets or businesses. Williams is evaluating the assets and/or businesses
that fit within its new, more narrowly focused business strategy, and has
identified certain assets and/or businesses that are more-likely-than-not to be
disposed of before the end of their previously estimated useful lives. These
assets and/or businesses did not meet the criteria to be classified as held for
sale at June 30, 2002, and were evaluated for recoverability on a held-for-use
basis pursuant to Statement of Financial Accounting Standards (SFAS) No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets." A
probability-weighted approach was used to consider the likelihood of possible
outcomes including sale in the near term and hold for the remaining estimated
useful life. For those assets and/or businesses that were not recoverable based
on undiscounted cash flows, an impairment loss was recognized in second-quarter
2002 based on management's estimate of fair value.

In March 2002, Williams announced its intentions to sell its soda ash
mining facility located in Colorado, which was previously written-down to
estimated fair value at December 31, 2001, and in April 2002, Williams initiated
a reserve-auction process. As this process and negotiations with interested
parties progressed, new information regarding estimated fair value became
available. As a result, an additional impairment loss of $44.1 million was
recognized in second-quarter 2002 by the International segment. Management's
estimate of fair value used to calculate the impairment loss was based on
discounted cash flows assuming sale of the facility in 2002.

During second-quarter 2002, Williams identified the travel centers as a
business that does not fit within the new business strategy and began actively
marketing that business for sale. Probability-weighted undiscounted cash flows
for asset recoverability were estimated on a facility-by-facility basis. Fair
value estimates for the travel centers with an indicated impairment were based
on management's estimate of discounted cash flows using a probability-weighted
approach which considered the likelihood of sale and related sale proceeds and
the possibility of holding

5

Notes (Continued)

the asset for its remaining estimated useful life. The $27 million loss
recognized in second-quarter 2002 by Petroleum Services includes both impairment
charges related to stores owned by Williams and liability accruals associated
with a residual value guarantee of certain travel centers under an operating
lease which, due to certain July 2002 amendments, will be accounted for as a
capital lease beginning in July 2002.

Additionally, as Williams has more narrowly focused its business strategy
and reduced planned capital spending, certain projects will not be further
developed. As a result, Williams has written-off capitalized costs and accrued
for estimated costs associated with termination of these projects. The $83.7
million Energy Marketing & Trading charge includes write-offs associated with a
terminated power plant project and accruals for commitments for certain assets
that were previously planned to be used in power projects. Gas Pipelines' $7.5
million charge relates to the write-off of a cancelled pipeline construction
project. In addition, Gas Pipeline also had an equity investment in another
pipeline project which was cancelled resulting in a $12.3 million charge
included in equity earnings (losses) (see Note 5).

Energy Marketing & Trading recognized a $57.5 million goodwill impairment
loss in second-quarter 2002 reflecting 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 as reflected in the financial statements combined with the
estimated fair value of contracts with affiliates that have not been marked to
market. The fair value of these contracts was estimated using a discounted cash
flow model with natural gas pricing assumptions based on current market
information.

Significant gains or losses from asset sales, impairments and other
accruals included in other (income) expense - net within segment costs and
expenses are included in the following table. With the exception of the $12.3
million charge at Gas Pipeline, the table includes those impairments and other
accruals previously discussed.

4. Receivables from Williams Communications Group, Inc. and other related
information

Background

At December 31, 2001, Williams had financial exposure from WCG of $375
million of receivables and $2.21 billion of guarantees and payment obligations.
Williams determined it was probable it would not fully realize the $375 million
of receivables, and it would be required to perform under its $2.21 billion of
guarantees and payment obligations. Williams developed an estimated range of
loss related to its total WCG exposure and management believed that no loss
within that range was more probable than another. For 2001, Williams recorded
the $2.05 billion minimum amount of the range of loss from its financial
exposure to WCG, which was 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

6

Notes (Continued)

operations of $1.84 billion included a $1.77 billion minimum amount of the
estimated range of loss from performance on $2.21 billion of guarantees and
payment obligations. The charge to continuing operations of $213 million
included estimated losses from an assessment of the recoverability of the
carrying amounts of the $375 million of receivables and a remaining $25 million
investment in WCG common stock.

Williams, prior to the spinoff of WCG, 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. 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. With the exception of the March and September 2002 interest
payments, totaling $115 million, WCG, through a subsidiary, remains obligated to
reimburse Williams for any payments Williams makes in connection with the Notes.

Williams also provided a guarantee of WCG's obligations under a 1998
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 the lessor's cost of
$750 million. On March 8, 2002, WCG exercised its option to purchase the covered
network assets. On March 29, 2002, Williams funded the purchase price of $754
million and became entitled to an unsecured note from WCG for the same amount.
Pursuant to the terms of an agreement between Williams and WCG's revolving
credit facility lenders, the liability of WCG to compensate Williams for funding
the purchase is subordinated to the interests of WCG's revolving credit facility
lenders and will not mature any earlier than one year after the maturity of
WCG's revolving credit facility.

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

2002 Evaluation

At June 30, 2002, Williams has receivables and claims from WCG of $2.15
billion arising from Williams affirming its payment obligation on the $1.4
billion of WCG Note Trust Notes and Williams paying $754 million under the WCG
lease agreement. At June 30, 2002, Williams also has $356 million of previously
existing receivables. In second-quarter 2002, Williams recorded in continuing
operations a pre-tax charge of $15 million related to WCG, including an
assessment of the recoverability of its receivables and claims from WCG. For the
six months ended June 30, 2002, Williams has recorded in continuing operations
pre-tax charges of $247 million related to the recovery of these receivables and
claims. At June 30, 2002, Williams estimates that approximately $2.2 billion of
the $2.5 billion of receivables from WCG are not recoverable.

On April 22, 2002, WCG filed for bankruptcy protection under Chapter 11 of
the U.S. Bankruptcy Code. Williams has filed proofs of claim in the bankruptcy
proceedings for all amounts due Williams from WCG. On May 1, 2002 Williams was
selected by the U.S. Trustee to serve on the Official Committee of Unsecured
Creditors in the WCG bankruptcy. The committee formed a subcommittee, which
excludes Williams, to investigate what rights and remedies, if any, the
creditors may have against Williams relating to its dealings with WCG. Prior to
the bankruptcy filing Williams entered into an agreement with WCG in which
Williams agreed not to object to a plan of reorganization submitted by WCG in
its bankruptcy if that plan provides for WCG to assume its obligations under
certain service agreements and the sale-leaseback transaction involving the
Williams Technology Center and aircraft with Williams and for Williams' other
claims to be treated as general unsecured claims with treatment substantially
identical to the treatment of claims by WCG's bondholders. On July 26, 2002,
Williams executed a Settlement Agreement with WCG, the Official Committee of
Unsecured Creditors and Leucadia National Corporation (Leucadia). On July 30,
2002, WCG filed with the bankruptcy court an Amended Plan of Reorganization and
an Amended Disclosure Statement which, among other things, implement the
provisions of the Settlement Agreement. The Settlement Agreement, amended on
August 13, 2002, included agreements where Williams will sell $2.26 billion of
its claims against WCG to Leucadia for $180 million and sell the Williams
Technology Center and certain related assets to WCG for $145 million comprised
of a $45 million 18-month note and a $100 million 7.5 year note. Both notes will
be secured by a first lien on the assets sold to WCG. The Amended Disclosure
Statement and Plan were filed by WCG with the bankruptcy court to reflect the
August 13, 2002 amendment. The Settlement Agreement also provides for a release
in favor of Williams of all claims by WCG and of certain claims that could be
asserted by bondholders and other creditors. The Settlement Agreement satisfies
the conditions of the pre-bankruptcy agreement with WCG. The transactions
contemplated by the Settlement Agreement are subject to approval of the
bankruptcy court and other parties and would close after such approval and after
satisfaction of all conditions therein. Certain parties filed objections to
portions of the Amended Disclosure Statement and certain parties may file
objections to portions of the Amended Plan. On August 13, 2002, the bankruptcy
court approved the Amended Disclosure Statement and Plan, set September 19, 2002
as the voting deadline for the Amended Plan, and set the confirmation hearing
for September 25, 2002. The hearing before the bankruptcy court on the amended
Settlement Agreement will be held on August 22, 2002. Competing reorganization
alternatives may also impact the final outcome of the Settlement Agreement.

At June 30, 2002, Williams estimated recoveries of its receivables and
claims against WCG based on the agreements included in the Settlement Agreement.
Williams believes the transactions contemplated by these agreements provide the
most relevant information available to estimate the recovery of its receivables
and claims from WCG, as they represent third party transactions that Williams
management has accepted.

7

Notes (Continued)

Prior to second-quarter 2002, Williams had estimated the recovery of its
receivables from WCG by performing a financial analysis and utilizing the
assistance of external legal counsel and an external financial and restructuring
advisor. In preparing its financial analysis, Williams and its external
financial and restructuring advisor considered the overall market condition of
the telecommunications industry, financial projections provided by WCG, the
potential impact of a bankruptcy on WCG's financial performance, the nature of
the proposed restructuring as detailed in WCG's bankruptcy filing and various
issues discussed in negotiations prior to WCG's bankruptcy filing.

Actual recoveries may ultimately differ from currently estimated recoveries
as the settlement agreements could be voided or amended as issues or challenges
may be raised in the bankruptcy proceedings prior to finalization of the plan.
If the settlement agreements were voided or amended, Williams' actual recoveries
could differ from currently estimated recoveries as numerous factors will affect
any recovery, including the form of consideration that Williams may receive from
WCG's restructuring under bankruptcy, WCG's future performance, the length of
time WCG remains in bankruptcy, customer reaction to WCG's bankruptcy filing,
challenges to Williams' claims which may be raised in the bankruptcy
proceedings, negotiations among WCG's secured creditors, its unsecured creditors
and Williams, and the resolution of any related claims, issues or challenges
that may be raised in the bankruptcy proceedings.

5. Investing income (loss)

Estimated loss on realization of amounts due from Williams Communications
Group, Inc.

In second-quarter 2002, Williams recorded in continuing operations an
additional pre-tax charge of $15 million related to WCG, including an assessment
of the recoverability of certain receivables and claims from WCG. For the six
months ended June 30, 2002, Williams has recorded in continuing operations
pre-tax charges of $247 million related to the recoverability of these
receivables and claims (see Note 4).

Other

Other investing income for the three and six months ended June 30, 2002 and
2001, is as follows:

* Item also included in segment profit (loss).

Equity earnings (losses) for the three and six months ended June 30, 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 Pipeline Natural Gas System (Gulfstream), an interstate natural gas
pipeline subject to Federal Energy Regulatory Commission (FERC) regulations and
an equity affiliate of Williams. The fee paid by Gulfstream and 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.

Also included in equity earnings (losses) for the three and six months
ended June 30, 2002, is a $12.3 million write-down of Gas Pipeline's investment
in a pipeline project which was cancelled in the second-quarter 2002.

8

Notes (Continued)

6. Provision (benefit) for income taxes

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

The effective income tax rate for the three and six months ended June 30,
2002, is less than the federal statutory rate due primarily to the impairment of
goodwill which is not deductible for income tax purposes and reduces the tax
benefit of the pre-tax loss.

The effective income tax rate for the three and six months ended June 30,
2001, is greater than the federal statutory rate due primarily to the effect of
state income taxes.

7. 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 will be recognized as income from
discontinued operations in third-quarter 2002. In accordance with the provisions
related to discontinued operations within SFAS No. 144, the results of
operations, financial position and cash flows for Kern River have been reflected
in the accompanying consolidated financial statements and notes as discontinued
operations.

Williams Communications Group, Inc.

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 on April 23,
2001. In accordance with Accounting Principles Board Opinion (APB) 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 and cash flows for WCG have
been reflected in the accompanying Consolidated Statement of Operations and
Consolidated Statement of Cash Flows and notes as discontinued operations.

See Note 4 for information regarding events in 2002 related to WCG.

9

Notes (Continued)

Summarized results of discontinued operations for the three and six months
ended June 30, 2002 and 2001, are as follows:

8. Earnings (loss) per share

Basic and diluted earnings (loss) per common share are computed as follows:

For the three and six months ended June 30, 2002, diluted earnings (loss)
per share is the same as the basic calculation. The inclusion of any stock
options and convertible preferred stock would be antidilutive as Williams
reported a loss from continuing operations for these periods. As a result,
approximately .6 million and 1.3 million weighted-average stock options for the
three and six months ended June 30, 2002, respectively, that otherwise would
have been included, were excluded from the computation of diluted earnings per
common share. Additionally, approximately 14.7 million and 7.8 million
weighted-average shares for the three and six months ended June 30, 2002,
respectively, related to the assumed conversion of 9 7/8 percent cumulative
convertible preferred stock have been excluded from the computation of diluted
earnings per common share.

10

Notes (Continued)

9. Restricted cash

The current and noncurrent restricted cash is primarily invested in
short-term money market accounts with financial institutions and an insurance
company. Restricted cash within current assets is collateral in support of a
financial guarantee and letters of credit. The contractual obligation requiring
a significant portion of this collateral expires December 2002. The contractual
obligations requiring the remaining collateral pertain to current operations.
Restricted cash within noncurrent assets is collateral in support of surety
bonds underwritten by an insurance company. Williams does not expect this cash
to be released within the next twelve months.

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.

10. Inventories

Inventories at June 30, 2002 and December 31, 2001 are as follows:

11. Debt and banking arrangements

The following discussions relate to Williams' debt and related facilities
as of and for the six months ended June 30, 2002. See Note 18 for the
significant changes to Williams' debt and related facilities, including certain
operating leases, which occurred subsequent to June 30, 2002.

Notes payable

At June 30, 2002, Williams had a $2.2 billion commercial paper program
which was backed by a short-term bank-credit facility with zero outstanding
under this program. The commercial paper program and the short-term credit
facility expired July 24, 2002. In addition, Williams has entered into various
short-term credit agreements with amounts outstanding totaling $711 million at
June 30, 2002. The weighted-average interest rate on these notes at June 30,
2002 was 3.7 percent. During July 2002, $300 million of the balance was repaid.
The remaining $411 million matures in October 2002, and is payable by Williams
Energy Partners L.P.

11

Notes (Continued)

Debt

Long-term debt at June 30, 2002 and December 31, 2001, is as follows:

(1) At June 30, 2002, including the effect of interest rate swaps.

(2) $400 million of 6.75% notes, payable 2016, putable/callable in 2006 and
$1.1 billion of 6.5% notes payable 2007, subject to remarketing in 2004.

Williams' December 31, 2001, long-term debt included $300 million of
commercial paper, $300 million of short-term debt obligations and $244 million
of long-term debt obligations due within one year, which would have otherwise
been classified as current, but were classified as noncurrent based on Williams'
intent and ability to refinance on a long-term basis. At June 30, 2002, $275
million of current debt obligations of Transcontinental Gas Pipe Line have been
classified as noncurrent based on Transcontinental Gas Pipe Line's July 2002
issuance of $325 million of 8.875 percent long-term debt obligations due 2012.

Under the terms of Williams' $700 million revolving credit agreement,
Northwest Pipeline, Transcontinental Gas Pipe Line and Texas Gas Transmission
have access to various amounts of the facility, while Williams (Parent) has
access to all unborrowed amounts. Interest rates vary with current market
conditions. The provisions of this agreement relating to financial ratios and
other covenants were modified subsequent to June 30, 2002. See Note 18 for
changes to this facility, which is now a secured facility, subsequent to June
30, 2002. Additionally, certain Williams subsidiaries have revolving credit
facilities with a total capacity of $116 million at June 30, 2002. One such
facility, totalling $31 million, has subsequently been terminated.

Pursuant to completion of a consent solicitation during first-quarter 2002
with WCG Note Trust holders, Williams recorded $1.4 billion of long-term debt
obligations which mature in March 2004 and bear an interest rate of 8.25 percent
(see Note 4). Subsequent to June 30, 2002, Williams completed an exchange of
Williams 9.25 percent notes due March 2004 for substantially all of these
securities.

In March 2002, the terms of a Williams $560 million priority return
structure, previously classified as preferred interest in consolidated
subsidiaries, were amended. The amendment provided for the outside investor's
preferred interest to be redeemed in equal quarterly installments through April
2003 (see Note 13). The interest rate varies based on LIBOR plus an applicable
margin and was 2.57 percent at June 30, 2002. Based on the new payment terms,
the preferred interest was reclassified to debt, of which $448 million is
classified as long-term debt due within one year at June 30, 2002. In April
2002, $112 million was redeemed.

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.

12

Notes (Continued)

In addition to the items discussed above, significant long-term debt
issuances and retirements, other than amounts under revolving credit agreements,
for the six months ended June 30, 2002 are as follows:

(1) Subject to redemption at par in 2002.

Williams' ratio of net debt to consolidated net worth plus net debt, as
defined in Williams' Current Report on Form 8-K dated May 28, 2002, was 63.5
percent at June 30, 2002, as compared to 61.5 percent at December 31, 2001.

12. 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 $178
million for potential refund as of June 30, 2002.

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

Williams Energy Marketing & Trading 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 2000, the FERC
issued an order which provided that, for the period between October 2, 2000 and
December 31, 2002, it may order refunds from Williams and other similarly
situated companies if the FERC finds that the wholesale markets in California
are unable to produce competitive, just and reasonable prices or that market
power or other individual seller conduct is exercised to produce an unjust and
unreasonable rate. Beginning on March 9, 2001, the FERC issued a series of
orders directing Williams and other similarly situated companies to provide
refunds for any prices charged in excess of FERC-established proxy prices in
January, February, March, April and May 2001, or to provide justification for
the prices charged during those months. According to these orders, Williams'
total potential refund liability for January through May 2001 is approximately
$30 million. Williams has filed justification for its prices with the FERC and
calculated its refund liability under the methodology used by the FERC to
compute refund amounts at approximately $11 million. On July 25, 2001, the FERC
issued an order establishing a hearing to establish the facts necessary to
determine refunds under the approved methodology. On August 13, 2002, the FERC
issued its preliminary findings as to its investigation into Western markets
(discussed below), which call into question the gas price methodology
established in the July 25, 2001 order. Any change from the July 25, 2001
methodology would likely result in increased refund liability for Energy
Marketing & Trading. Refunds will cover the period of October 2, 2000 through
June 20, 2001. They will be paid as offsets against outstanding bills and are
inclusive of any amounts previously noticed for refund for that period. The
judge presiding over the refund proceedings is expected to issue his findings in
November 2002. The FERC will subsequently issue a refund order based on these
findings.

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 will be in effect from June
20, 2001 through September 30, 2002, establishes a market clearing price for
spot sales in all hours of the day that is based on the bid of the highest-cost
gas-fired California generating unit that is needed to serve the Independent
System Operator's (ISO's) load. When generation operating reserves fall below
seven percent in California (a "reserve deficiency period"), absent cost-based
justification for a higher price, the maximum price that Williams may charge for
wholesale spot sales in the WSCC is the market clearing price. When generation
operating reserves rise to seven percent or above in California, absent
cost-based

13

Notes (Continued)

justification for a higher price, Williams' maximum price will be limited to 85
percent of the highest hourly price that was in effect during the most recent
reserve deficiency period. This methodology initially resulted in a maximum
price of $92 per megawatt hour during non-emergency periods and $108 per
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 and July 25 orders
with certain clarifications and modifications. It also altered the price
mitigation methodology for spot market transactions for the WSCC market for the
winter 2001 season and set the period maximum price at $108 per megawatt hour
through April 30, 2002. Under the order, this price would be subject to being
recalculated when the average gas price rises by a minimum factor of ten percent
effective for the following trading day, but in no event will the maximum price
drop below $108 per megawatt hour. The FERC also upheld a ten percent addition
to the price applicable to sales into California to reflect credit risk. 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 will expire when the currently effective West-wide
mitigation plan expires on September 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 California Public Utilities Commission (CPUC) filed a complaint with
the FERC on February 25, 2002, seeking to void or, alternatively, reform a
number of the long-term power purchase contracts entered into between the State
of California and several suppliers in 2001, including Energy Marketing &
Trading. The CPUC alleges that the contracts are tainted with the exercise of
market power and significantly exceed "just and reasonable" prices. The
Electricity Oversight Board made a similar filing on February 27, 2002. The FERC
set the complaint for hearing on April 25, 2002, but held the hearing in
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. Energy Marketing & Trading will appeal the order. The settlement
discussions noted above have resulted in Williams reaching a settlement in
principle with the State of California on a global settlement that includes a
renegotiated long-term energy contract. The settlement will also resolve
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. In addition, the settlement will resolve ongoing investigations by the
States of California, Oregon and Washington. The settlement is subject to
documentation and approval by various courts and agencies.

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.
Should the matter go to hearing, a final decision should be issued by May 31,
2003.

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

14

Notes (Continued)

facilities in California for a limited period. On April 30, 2001, the FERC
issued an Order approving a settlement of this proceeding. The settlement
terminated the proceeding without making any findings of wrongdoing by Williams.
Pursuant to the settlement, Williams agreed to refund $8 million to the ISO by
crediting such amount against outstanding invoices. Williams also agreed to
prospective conditions on its authority to make bulk power sales at market-based
rates for certain limited facilities under which it has call rights for a
one-year period. Williams also has been informed that the facts underlying this
proceeding are also under investigation by a California Grand Jury.

On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking
(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 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 has
requested that interested parties respond to various questions related to the
FERC's negotiated rate policies and practices.

On August 1, 2002, the FERC issued a NOPR that proposes restrictions on the
type of cash management program employed by Williams and its subsidiaries. In
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. The FERC is seeking public comments by August
22, 2002.

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 recent 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 they 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) is conducting an investigation regarding gas
and power trading in Western markets and has requested information from Williams
in connection with this investigation.

On May 31, 2002, Williams received a request from the Securities and
Exchange Commission (SEC) to

15

Notes (Continued)

voluntarily produce documents and information regarding any prearranged or
contemporaneous buy and sell ("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
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 is in the process of responding to the SEC's requests.

On March 20, 2002, the California Attorney General filed a complaint with
the FERC alleging that Williams and all other sellers of power in California
have failed to comply with federal law requiring the filing of rates and charges
for power. While the FERC rejected the complaint that the market-based rate
filing requirements violate the Federal Power Act, it directed the refiling of
quarterly reports for periods after October 2000 to include transaction specific
information.

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.

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 June 30,
2002, these subsidiaries had accrued liabilities totaling approximately $32
million for these costs.

Certain Williams subsidiaries, including Texas Gas and Transcontinental Gas
Pipe Line, have been identified as potentially responsible parties (PRP) at
various Superfund and state waste disposal sites. In addition, these
subsidiaries have incurred, or are alleged to have incurred, various other
hazardous materials removal or remediation obligations under environmental laws.
Although no assurances can be given, Williams does not believe that these
obligations or the PRP status of these subsidiaries will have a material adverse
effect on its financial position, results of operations or net cash flows.

Transcontinental Gas Pipe Line, Texas Gas and Williams Gas Pipelines
Central (Central) have identified polychlorinated biphenyl contamination in air
compressor systems, soils and related properties at certain compressor station
sites. Transcontinental Gas Pipe Line, Texas Gas and Central have also been
involved in negotiations with the U.S. Environmental Protection Agency (EPA) and
state agencies to develop screening, sampling and cleanup programs. In addition,
negotiations with certain environmental authorities and other programs
concerning investigative and remedial actions relative to potential mercury
contamination at certain gas metering sites have been commenced by Central,
Texas Gas and Transcontinental Gas Pipe Line. As of June 30, 2002, Central had
accrued a liability for approximately $8 million, representing the current
estimate of future environmental cleanup costs to be incurred over the next six
to ten years. Texas Gas and Transcontinental Gas Pipe Line likewise had accrued
liabilities for these costs which are included in the $32 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.

Williams Energy Services (WES) and its subsidiaries also accrue
environmental remediation costs for its natural gas gathering and processing
facilities, petroleum products pipelines, retail petroleum and refining
operations and for certain facilities related to former propane marketing
operations primarily related to soil and groundwater contamination. In addition,
WES owns a discontinued petroleum refining facility that is being evaluated for
potential remediation efforts. At June 30, 2002, WES and its subsidiaries had
accrued liabilities totaling approximately $36 million for these costs. WES
accrues receivables related to environmental remediation costs based upon an
estimate of amounts that will be reimbursed from state funds for certain
expenses associated with underground storage tank problems and repairs. At June
30, 2002, WES and its subsidiaries 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 June 30, 2002, Williams had approximately
$10 million accrued for such excess costs. The actual costs incurred will depend
on the actual amount and extent of contamination discovered, the final cleanup
standards mandated by the EPA or other governmental authorities, and other
factors.

16

Notes (Continued)

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

Other legal matters

In connection with agreements to resolve take-or-pay and other contract
claims and to amend gas purchase contracts, Transcontinental Gas Pipe Line and
Texas Gas each entered into certain settlements with producers which may require
the indemnification of certain claims for additional royalties which the
producers may be required to pay as a result of such settlements. As a result of
such settlements, Transcontinental Gas Pipe Line is currently defending two
lawsuits brought by producers. In another case, 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 petition for review. As a result,
Transcontinental Gas Pipe Line recorded a fourth-quarter 2001 pre-tax charge to
income (loss) 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 Texaco the amount of the judgment plus accrued interest. In the other
cases, producers have asserted damages, including interest calculated through
December 31, 2001, of $16.3 million. Producers have received and may receive
other demands, which could result in additional claims. Indemnification for
royalties will depend on, among other things, the specific lease provisions
between the producer and the lessor and the terms of the settlement between the
producer and either Transcontinental Gas Pipe Line or Texas Gas. Texas Gas may
file to recover 75 percent of any such additional amounts it may be required to
pay pursuant to indemnities for royalties under the provisions of Order 528.

On June 8, 2001, 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 November 2001,
Williams, along with other Coordinating Defendants, filed a motion to dismiss
under Rules 9b and 12b of the Kansas Rules of Civil Procedure. In January 2002,
most of the Williams defendants, along with a group of Coordinating Defendants,
filed a motion to dismiss for lack of personal jurisdiction. The court has not
yet ruled on these motions. In the next several months, the Williams entities
will join with other defendants in contesting certification of the plaintiff
class.

In 1998, the United States Department of Justice (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 liability
relating to this claim. Grynberg has also filed claims against approximately 300
other energy companies and alleges that the defendants violated the False Claims
Act in connection with the measurement and purchase of hydrocarbons. The relief
sought is an unspecified amount of royalties allegedly not paid to the federal
government, treble damages, a civil penalty, attorneys' fees, and costs. On
April 9, 1999, the DOJ announced that it was declining to intervene in any of
the Grynberg qui tam cases, including the action filed against the Williams
entities in the United States District Court for the District of Colorado. On
October 21, 1999, the Panel on Multi-District Litigation transferred all of the
Grynberg qui tam cases, including those filed against Williams, to the United
States District Court for the District of Wyoming for pre-trial purposes.
Motions to dismiss the complaints filed by various defendants, including
Williams, were denied on May 18, 2001.

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

17

Notes (Continued)

$20 million based on interest rate variations, and punitive damages in the
amount of approximately $1.4 million dollars. Williams will vigorously defend
against the claims and does not believe they have merit.

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 reached a settlement
in principle and are in the process of drafting the settlement documents. 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
coordinated in San Diego County Superior Court.

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

On May 17, 2001, the DOJ advised Williams that it had commenced an
antitrust investigation relating to an agreement between a subsidiary of
Williams and AES Southland alleging that the agreement limits the expansion of
electric generating capacity at or near the AES Southland plants that are
subject to a long-term tolling agreement between Williams and AES Southland. In
connection with that investigation, the DOJ has issued two Civil Investigative
Demands to Williams requesting answers to certain interrogatories and the
production of documents. Williams is cooperating with the investigation.

On October 5, 2001, 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. Five similar cases have also
been brought by private plaintiffs 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.

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.

18

Notes (Continued)

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.

Since January 29, 2002, Williams is aware of numerous shareholder class
action suits that have been filed in the United States District Court for the
Northern District of Oklahoma. The majority of the suits allege that Williams
and co-defendants, 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. Williams does not anticipate any immediate
action by the Court in these actions. These cases have all been consolidated and
an order has been issued requiring separate amended consolidated complaints by
Williams and Williams Communications equity holders. 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.
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.

Williams was selected by the U.S. Trustee to serve on the Official
Committee of Unsecured Creditors in the WCG bankruptcy. At its initial meeting,
the committee formed a subcommittee creditors committee, which excludes
Williams, to investigate what rights and remedies, if any, the creditors may
have against Williams relating to its dealings with WCG. Williams has entered
into an agreement with WCG in which Williams agreed not to object to a plan of
reorganization submitted by WCG in its bankruptcy if that plan provides (i) for
WCG to assume its obligations under certain service agreements and the sale
leaseback transaction with Williams and (ii) for Williams' other claims to be
treated as general unsecured claims with treatment substantially identical to
the treatment of claims by WCG's bondholders. This matter is discussed more
fully in Note 4.

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 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 are related to offers of gathering service by
WFS and its subsidiaries on the recently spundown and deregulated offshore
pipeline system, the North Padre Island gathering system. By order of the FERC
the matter was heard before an administrative law judge in April 2002. On June
4, 2002, the administrative law judge issued an initial decision finding that
the affiliates acted in concert to frustrate the FERC's regulation of Transco
and recommending that the FERC reassert jurisdiction over the North Padre Island
gathering system. Transco, WGP and WFS believe their actions were reasonable and
lawful and submitted briefs taking exceptions to the initial decision. FERC has
yet to act.

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. The court has not set a date within which claims may be filed.
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 first-quarter 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 is recorded within the
trading revenues in first-quarter 2002.

19

Notes (Continued)

Summary

While no assurances may be given, Williams, based on advice of counsel,
does not believe that the ultimate resolution of the foregoing matters, taken as
a whole and after consideration of amounts accrued, insurance coverage, recovery
from customers or other indemnification arrangements, will have a materially
adverse effect upon Williams' future financial position, results of operations
or cash flow requirements.

Commitments

Energy Marketing & Trading has entered into certain contracts giving it 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. At June 30, 2002, annual estimated committed payments
under these contracts range from approximately $53 million to $462 million,
resulting in total committed payments over the next 20 years of approximately
$8 billion.

13. Preferred interests in consolidated subsidiaries

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. The initial priority return
structure was originally scheduled 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 is
classified as long-term debt due within one year on Williams' Consolidated
Balance Sheet at June 30, 2002. Priority returns prior to this amendment are
included in preferred returns and minority interest in income of consolidated
subsidiaries on the Consolidated Statement of Income.

Subsequent to June 30, 2002, the $135 million preferred interest in
Williams Risk Holdings L.L.C. was redeemed following the downgrades in Williams'
credit ratings in July 2002. Additionally, terms of the $200 million preferred
interest in Castle Associates L.P. and the $100 million preferred interest in
Piceance Production Holdings LLC were amended subsequent to June 30, 2002, and
as a result the $200 million and $100 million, respectively, will be classified
as debt beginning in July 2002.

14. Stockholders' equity

Concurrent with the sale of Kern River to 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 six months ended June 30, 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

20

Notes (Continued)

$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.

21

Notes (Continued)

15. Comprehensive income (loss)

Comprehensive income (loss) is as follows:

Components of other comprehensive income (loss) before minority interest
and taxes related to discontinued operations are as follows:

22

Notes (Continued)

16. 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.

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. Segment amounts have been restated 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 for which segment information has been restated for all prior
periods presented.

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. 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.
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 below. The results of
interest rate swaps with external counter parties are shown as interest rate
swap loss in the Consolidated Statement of Operations below operating income
(loss).

The majority of energy commodity hedging by the Energy Services' business
units is done through intercompany derivatives with Energy Marketing & Trading
which, in turn, enters into offsetting derivative contracts with unrelated third
parties. Energy Marketing & Trading bears the counterparty performance risks
associated with unrelated parties.

The decrease in Energy Marketing & Trading's total assets, as reflected on
page 26, is due primarily to a decline in the fair value of the energy risk
management and trading portfolio.

The following tables reflect the reconciliation of revenues and operating
income (loss) as reported in the Consolidated Statement of Operations to segment
revenues and segment profit (loss).

23

Notes (Continued)

16. Segment disclosures (continued)

24

Notes (Continued)

16. Segment disclosures (continued)

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

25

Notes (Continued)

16. Segment disclosures (continued)

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

26

Notes (Continued)

17. Recent accounting standards

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 142, "Goodwill and Other Intangible Assets." Williams adopted this Statement
effective January 1, 2002. This Statement addresses accounting and reporting
standards for goodwill and other intangible assets. Under the provisions of this
Statement, goodwill and intangible assets with indefinite useful lives are no
longer amortized, but will be tested annually for impairment. Based on
management's estimate of the fair value of the operating unit's goodwill there
was no impairment upon adoption of this Standard at January 1, 2002.

In second-quarter 2002, 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, gains and losses
from debt extinguishments will not be accounted for as extraordinary items.

Also in second-quarter 2002, 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 Emerging Issues Task Force 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)." This Statement
requires that a liability for a cost associated with an exit or disposal
activity be recognized and measured initially at fair value only when the
liability is incurred. The provisions of the Statement are effective for exit or
disposal activities that are initiated after December 31, 2002. The effect of
this standard on Williams' results of operations and financial position is being
evaluated.

18. Subsequent events

Subsequent to June 30, 2002, Williams announced that it expected to report
a substantial net loss for second-quarter 2002 which included a significant
operating loss from Energy Marketing & Trading and asset impairment charges. In
addition, the board of directors reduced the quarterly dividend on Williams'
common stock from $.20 per share to $.01 per share. The major credit rating
agencies followed these announcements by downgrading Williams' credit rating
below investment grade levels. Concurrent with these events, Williams was unable
to complete a renewal of its unsecured short-term bank credit facility. Williams
responded to these events with a concentrated effort to complete certain asset
sales and obtain secured credit facilities in order to raise funds to meet
current debt obligations and provide for other liquidity requirements. The asset
sales and secured credit facilities are discussed below.

Asset Sales

In August 2002, Williams announced the sale for cash of the following
assets as part of its previously announced financial strengthening plan:

o 98 percent of Mid-America Pipeline, a 7,226-mile natural gas liquids
pipeline system

o 98 percent of its 80 percent ownership interest in Seminole Pipeline,
a 1,281-mile natural gas liquids pipeline system

o Jonah field natural gas production properties in Wyoming, which
represented approximately 11 percent of total reserves at December 31,
2001

o Natural gas production properties in the Anadarko Basin

o Cove Point liquefied natural gas facility and 87-mile pipeline in
Maryland

o Hugoton natural gas gathering system in Kansas

27

Notes (Continued)

Except for the sale of the Cove Point assets, which is expected to close
September 2002, each of these sale transactions closed in July 2002. The major
classes of assets and liabilities included in the Consolidated Balance Sheet as
of June 30, 2002, for these asset groups are as follows:

Secured credit facilities

Subsequent to June 30, 2002, Williams obtained a $400 million letter of
credit facility, a $900 million short-term loan (discussed below) and amended
its existing $700 million revolving credit facility. The $400 million letter of
credit facility which expires July 2003 and the $700 million revolving credit
facility, which expires July 2005, are secured by the bulk 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. These facilities also have the benefit of guarantees from most of
Williams' subsidiaries, not including Transcontinental Gas Pipe Line, Texas Gas
or Northwest Pipeline. Additionally, the company is no longer required to make a
"no material adverse change" representation prior to borrowings under the $700
million revolving credit facility. An additional $159 million of public
securities were also ratably secured with the same assets in accordance with the
indentures covering those securities. Additionally, as Williams completes
certain asset sales the $700 million commitment from participating banks in the
revolving credit facility will ultimately be reduced to $400 million and various
other preexisting debt will be paid down. Transcontinental Gas Pipe Line, Texas
Gas and Northwest Pipeline continue as participating borrowers in this facility.
Significant new covenants under these agreements include: (i) restrictions on
the creation of new subsidiaries, (ii) broader restrictions on pledging assets
to other creditors, (iii) a covenant that the ratio of interest expense plus
cash flow to interest expense be greater than 1.5 to 1, (iv) a limit on
dividends on common stock paid by Williams in any quarter of $6.25 million, (v)
certain restrictions on declaration or payment of dividends on preferred stock
issued after July 30, 2002, (vi) a limit on investments in others of $50 million
annually and (vii) 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.

Williams Production RMT Company (RMT), a wholly owned subsidiary, entered
into a $900 million Credit Agreement dated as of July 31, 2002 (the "closing
date"), with certain lenders including a subsidiary of Lehman Brothers, Inc., a
related party. The loan is guaranteed by Williams, Williams Production Holdings
LLC (Holdings) and certain RMT subsidiaries. It is also secured by the capital
stock and assets of Holdings and certain of RMT's subsidiaries. The loan matures
on July 25, 2003, and bears interest payable quarterly at the Eurodollar rate
plus 4 percent per annum (5.824 percent at closing), plus additional interest of
14 percent per annum, which is accrued and added to the principal balance.

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 (a "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 term loans.
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 of greater than 1.5
to 1, (ii) a fixed charge coverage ratio 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.

RMT must be sold within 75 days of a parent liquidity event which requires
that Williams maintain actual and projected liquidity (a) at any time from the
closing date through the 180th day thereafter, of $600 million; (b) at any time
thereafter through and including the maturity date, of $750 million; and (c) at
any time after the maturity date, of $200 million. Liquidity projections must be
provided weekly until the maturity date. Each projection covers a period
extending 12 months from the report date. The loan is also required to be
prepaid with the net cash proceeds of any sale of RMT's assets, and, in the
event

28

Notes (Continued)

of a company sale, the loan is required to be prepaid in full. Any prepayment
or acceleration of the loan requires RMT to pay to lenders (i) a make-whole
amount, and (ii) the deferred set up fee set forth above.

Additionally, Williams amended certain other financing facilities and
agreements totaling $1.9 billion which provided the lenders thereunder with
guarantees from Williams Gas Pipeline Company, L.L.C. and Williams Production
Holdings LLC and certain lenders with a ratable share of proceeds from future
asset sales to reduce certain of these facilities. These facilities and
agreements include the preferred interest in Castle Associates LP, $600 million
of term loans, certain letters of credit, two operating lease agreements with
special purpose entities, the preferred interest in Piceance Production Holdings
LLC and the preferred interest in Snow Goose Associates, L.L.C. which is
currently classified as debt. As a result of the changes to the two operating
lease agreements, these leases will be reported as capitalized leases as of July
31, 2002. If these leases were treated as capitalized lease obligations at June
30, 2002, assets and long-term debt would increase by approximately $287
million. Additionally, the preferred interest in Castle Associates L.P. and
Piceance Production Holdings LLC will be reported as debt as of July 31, 2002.

29

ITEM 2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATION

RECENT EVENTS

As a result of credit issues facing the Company and the assumption of
payment obligations and performance on guarantees associated with WCG, Williams
announced plans during first-quarter 2002 to strengthen its balance sheet and
support retention of its investment grade ratings. The plan 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. In addition, "ratings triggers" exposure
for potential acceleration of debt payment and redemption of preferred interests
was substantially reduced to $182 million at March 31, 2002 ($135 million of
which was redeemed subsequent to June 30, 2002).

During the second quarter, Williams experienced liquidity issues, 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 still were maintained as
investment grade for the balance of the quarter. In June, Williams announced a
$500 million reduction in its working capital and liquidity commitments to its
Energy Marketing & Trading business and reduced its work force accordingly.
Later in June, Williams announced its intentions to offer for sale its two
refineries and related assets, with the expectation of closing such sales by the
end of 2002.

Subsequent to the end of the second quarter, Williams announced that it
would have a substantial net loss for the quarter. 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 from deteriorating energy trading market conditions in the second
quarter. In addition, Williams announced asset impairments and cost write-offs,
in 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 cents per share to 1 cent per share. The major rating agencies downgraded
Williams credit rating to below investment grade reflecting the uncertainty
associated with the trading business, short-term cash requirements facing the
Company 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 did obtain two secured
facilities totaling $1.3 billion, including a letter of credit facility for $400
million, and amended its existing $700 million revolving credit facility to a
secured basis which expires July 2005. These borrowing facilities include
pledges of certain assets and contain financial ratios and other covenants that
must be maintained (see Note 18). If such provisions of the agreements are not
maintained, then amounts outstanding can become due immediately and payable.
Williams believes that these financings and the proceeds received from recent
asset sales have significantly improved the company's liquidity for the balance
of the year. In addition, Williams is pursuing the sale of other assets to
enhance liquidity. The sales are anticipated to close during the second half of
2002.

Following the credit rating downgrade in July, 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. It also announced the sale of certain liquified natural gas assets for
approximately $217 million. This transaction is expected to close in September.
In addition to its refineries and related assets, Williams has also announced
that it is considering selling its gas pipeline unit known as Central and its
Western Canada gathering and natural gas extraction assets. During the second
quarter, a review for impairment was performed on certain assets that were being
considered for possible sale, including an assessment of the more likely than
not probabilities of sale for each asset. Impairments were recorded in the
second quarter totaling approximately $71 million reflecting management's
estimate of the fair value of these assets based on information available at the
time. Williams has numerous assets which could be sold that exceed the
previously announced target of $1.5 billion to $3 billion range of proceeds to
be generated from asset sales. The specific assets that will be sold and the
timing of such sales are dependent on various factors, including negotiations
with prospective buyers, regulatory approvals, industry conditions and the
short-and long-term liquidity requirements of the Company. While management
believes it has considered all relevant information in assessing for potential
impairments, the ultimate sales price for assets which may be sold in the future
may result in an additional impairment or a loss.

30

Management's Discussion & Analysis (Continued)

The operating results of Energy Marketing & Trading are adversely affected
by several factors, including Williams' overall liquidity and credit ratings
which impact Energy Marketing & Trading's ability to enter into price risk
management and hedging activities. The credit rating downgrades have also
triggered certain Energy Marketing & Trading contractual provisions, including
providing counterparties with adequate assurance, margin, credit enhancement, or
credit replacement. Successful completion of the agreement in principle reached
in July regarding the global settlement with the State of California and other
parties would eliminate certain outstanding complaints and litigation and
resolve claims for refunds to the FERC filed in connection with its power
activities in California (see Note 12). As currently proposed, the settlement
would also provide for a new long-term power sales contract with the state in
addition to other settlement provisions. For further discussions regarding
Energy Marketing & Trading's business and its fair value of energy contracts,
see the Fair Value of Energy Risk Management and Trading activities on page 45.
The energy trading sector has experienced deteriorating conditions because of
credit and regulatory concerns, and these have significantly reduced Energy
Marketing & Trading's ability to attract new business. These market conditions
plus the unwillingness of counterparties to enter into new business with Energy
Marketing & Trading will affect results in the future and could result in
additional operating losses. On August 1, 2002, Williams announced its intention
to further reduce its commitment and exposure to its energy marketing and risk
management business. This reduction could be realized by entering into a joint
venture arrangement with a third party or a sale of a portion or all of the
marketing and trading portfolio. It is possible that Williams, in order to
generate levels of liquidity it needs in the future, would be willing to accept
amounts for a portion or its entire portfolio that are less than its carrying
value at June 30, 2002.

At June 30, 2002, Williams has maturing long-term debt totaling $920
million for the remainder of the current year and $1,148 million during 2003.
The Company's available liquidity to meet these requirements and fund a reduced
level of capital expenditures will be dependent on several items, including the
cash flows of retained businesses, the amount of proceeds raised from the sale
of assets 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 in the future and recently
negotiated secured credit facilities, Williams currently believes that it has
the financial resources and liquidity to meet future cash requirements for the
balance of the year.

The new secured credit facilities require Williams to meet certain
covenants and limitations as well as maintain certain financial ratios (see
Note 18). 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 must be reduced from the proceeds of
asset sales and minimum levels of current and future liquidity have been
established.

GENERAL

On March 27, 2002, Williams completed the sale of one of its Gas Pipeline
segments, Kern River Gas Transmission (Kern River), to MidAmerican Energy
Holdings Company (MEHC). Accordingly, the results of operations for Kern River
have been reflected in the consolidated financial statements as discontinued
operations. (see Note 7).

Unless otherwise indicated, the following discussion and analysis of
results of operations, financial condition and liquidity relates to the
continuing operations of Williams and should be read in conjunction with the
consolidated financial statements and notes thereto included in Item 1 of this
document and Exhibit 99(b) of Williams' Current Report on Form 8-K dated May 28,
2002, which includes financial statements that reflect Kern River as
discontinued operations.

31

Management's Discussion & Analysis (Continued)

RESULTS OF OPERATIONS

Consolidated Overview

The following table and discussion is a summary of Williams' consolidated
results of operations. The results of operations by segment are discussed in
further detail beginning on page 34.

Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001

Williams' revenue decreased $765.7 million, or 26 percent, due primarily to
lower revenues associated with energy risk management and trading activities at
Energy Marketing & Trading. Also contributing were lower refined product sales
prices and volumes at the refineries, lower travel center and Alaska convenience
stores sales and the absence of $77 million of revenue related to the 198
convenience stores sold in May 2001 within Petroleum Services and lower natural
gas liquids sales prices and lower revenue from natural gas liquids trading
operations within Midstream Gas & Liquids. Partially offsetting these decreases
was an increase in revenues at Exploration & Production resulting from higher
net production volumes.

Segment costs and expenses, including selling, general and administrative
expenses, increased $98.5 million, or 4 percent, due to impairment charges, loss
accruals and write-offs of $141.2 million within Energy Marketing & Trading,
$44.1 million related to Colorado soda ash mining operations within
International, $27 million related to the travel centers within Petroleum
Services and $7.5 million related to a cancelled project at Gas Pipeline, as
well as the benefit in 2001 of a $72.1 million pre-tax gain on the sale of the
convenience stores. Selling, general and administrative expenses increased $39.4
million due primarily to an additional $24 million of costs related to an
enhanced-benefit early retirement option offered to certain employee groups and
$11 million higher expenses at Exploration & Production. Partially offsetting
these increases were lower petroleum products costs and the absence of $76
million in costs related to the 198 convenience stores sold at Petroleum
Services and lower costs related to the natural gas liquids trading operations
within Midstream Gas & Liquids.

Operating income (loss) decreased $871.3 million, due primarily to lower
net revenues associated with energy risk management and trading activities at
Energy Marketing & Trading, the absence of the 2001 gain from the 198
convenience stores sold, decreased operating profit from refining and marketing
operations within Petroleum Services and the 2002

32

Management's Discussion & Analysis (Continued)

impairment charges noted above, partially offset by the contribution of
increased production volumes at Exploration & Production. Included in operating
income (loss) are general corporate expenses, which increased $7 million, or 26
percent, due primarily to costs related to the enhanced-benefit early retirement
option.

Interest accrued - net increased $121.3 million, or 81 percent due
primarily to the $98 million effect of higher borrowing levels including the
impact of the $1.4 billion of long-term obligations related to WCG (see Note
11), the $3 million effect of higher average interest rates and $15 million of
higher debt amortization expense related to higher debt levels. In light of the
recent credit ratings downgrades and the secured credit facilities obtained
subsequent to June 30, 2002, interest expense in the near term is expected to
increase at least $100 million per quarter until debt levels are reduced.

In first-quarter 2002, Williams began managing its interest rate risk on an
enterprise basis by the corporate parent. The results of interest rate swaps
with external counter parties were losses of $83.2 million in second-quarter
2002 (see Note 16).

Investing income (loss) increased $4.8 million due primarily to $27 million
higher earnings on equity investments, largely offset by the $15 million
estimated loss on realization of amounts due from WCG (see Note 4) and an $8
million decrease in interest income related to lower margin deposits.

Other income - net increased $17.7 million due primarily to an $11 million
gain at Gas Pipeline associated with the disposition of securities received
through a mutual insurance company reorganization and a decrease in losses from
the sales of receivables to special purpose entities.

The provision (benefit) for income taxes decreased $375.5 million due
primarily to lower pre-tax income. The effective income tax rate for the three
months ended June 30, 2002, is less than the federal statutory rate due
primarily to the impairment of goodwill which is not deductible for income tax
purposes and which reduces the tax benefit of the pre-tax loss. The effective
income tax rate for the three months ended June 30, 2001, is greater than the
federal statutory rate due primarily to the effect of state income taxes.

Income (loss) from discontinued operations for second-quarter 2001 of $10.7
million reflects the after-tax results of operations of Kern River.

Six Months Ended June 30, 2002 vs. Six Months Ended June 30, 2001

Williams' revenue decreased $1,494.3 million, or 24 percent, due primarily
to lower revenues associated with energy risk management and trading activities
at Energy Marketing & Trading, lower refined product sales prices at the
refineries, lower travel center and Alaska convenience store sales and the
absence of $182 million of revenue related to the 198 convenience stores sold in
May 2001 within Petroleum Services. Also contributing were lower natural gas
liquids sales prices and lower natural gas liquids trading operations revenue
within Midstream Gas & Liquids. Partially offsetting these decreases was an
increase in revenues at Exploration & Production resulting from higher net
production volumes.

Segment costs and expenses, including selling, general and administrative
expenses, decreased $529.7 million, or 11 percent, due to lower petroleum
products costs, lower travel center/convenience store costs reflecting the
absence of the 198 convenience stores sold in May 2001, lower shrinkage, fuel
and replacement gas purchases related to processing activities within Midstream
Gas & Liquids and lower costs related to the natural gas liquids trading
operations within Midstream Gas & Liquids. Partially offsetting these decreases
were impairment charges, loss accruals and write-offs of $141.2 million within
Energy Marketing & Trading, $44.1 million related to Colorado soda ash mining
operations within International, $27 million related to the travel centers
within Petroleum Services and $7.5 million related to a canceled project at Gas
Pipeline as well as the benefit in 2001 of a $72.1 million pre-tax gain on the
sale of the convenience stores.

Operating income (loss) decreased $980.5 million, or 69 percent, due
primarily to lower net revenues associated with energy risk management and
trading activities at Energy Marketing & Trading, the absence of the 2001 gain
from the 198 convenience stores sold and decreased operating profit from
refining and marketing operations within Petroleum Services and the 2002
impairment charges noted above partially offset by increased production volumes
at Exploration & Production. Included in operating income (loss) are general
corporate expenses, which increased $15.9 million, or 28 percent, due primarily
to a $6 million increase in advertising costs and $6 million of expense related
to the enhanced-benefit early retirement options offered to certain employee
groups.

33

Management's Discussion & Analysis (Continued)

Interest accrued - net increased $162.7 million, or 51 percent due
primarily to the $149 million effect of higher borrowing levels and $18 million
of higher debt amortization expense related to higher debt levels. The increases
were slightly offset by the $12 million effect of lower average interest rates
and by $9 million lower interest expense related to deposits received from
customers relating to energy risk management and trading and hedging activities.

In first-quarter 2002, Williams began managing its interest rate risk on an
enterprise basis by the corporate parent. The results of interest rate swaps
with external counter parties were losses of $73 million (see Note 16).

Investing income (loss) decreased $245.1 million due substantially to the
$247 million estimated loss on realization of amounts due from WCG (see Note 4),
a $23 million decrease in interest income related to margin deposits and a $5
million decrease in dividend income due to the sale of Ferrellgas Partners L.P.
senior common units in second-quarter 2001. Slightly offsetting these decreases
are higher equity earnings of $36.8 million due primarily to the $27.4 million
contractual construction completion fee received by a Gas Pipeline equity
investment (see Note 5).

Preferred returns and minority interest in income of consolidated
subsidiaries decreased $10 million, or 21 percent, due primarily to a $15
million decrease in preferred returns of Snow Goose reflecting lower interest
rates for the first-quarter 2002 and the fact that the preferred interest is now
characterized as debt due to the first quarter amendment (see Note 11) and a $4
million decrease in preferred returns related to the second-quarter 2001
redemption of Williams obligated mandatory redeemable preferred securities of
Trust. Partially offsetting these decreases was a $9 million increase related to
minority interest associated with Williams Energy Partners.

Other income - net increased $8.4 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 and a $7
million decrease in losses from the sales of receivables to special purpose
entities. Partially offsetting these increases was an $8 million loss related to
the early retirement of remarketable notes in first-quarter 2002.

The provision (benefit) for income taxes decreased $521.3 million due
primarily to lower pre-tax income. The effective income tax rate for the six
months ended June 30, 2002, is less than the federal statutory rate due
primarily to the impairment of goodwill which is not deductible for income tax
purposes and which reduces the tax benefit of pre-tax loss. The effective income
tax rate for the six months ended June 30, 2001, is greater than the federal
statutory rate due primarily to the effect of state income taxes.

Income (loss) from discontinued operations for 2002 of $15.5 million is the
after-tax loss related to the sale of Kern River, partially offset by its
results of operations for first-quarter 2002. The $157 million loss from
discontinued operations for 2001 includes the after-tax loss from WCG operations
of $179.1 million and after-tax income of $22.1 million from the operations of
Kern River.

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 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 8) increased by
approximately 32 million from June 30, 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 loss per share from continuing
operations in 2002 of approximately $.04 per share.

RESULTS OF OPERATIONS-SEGMENTS

Williams is currently organized into three industry groups: Energy
Marketing & Trading, Gas Pipeline and Energy Services (includes Exploration &
Production, International, Midstream Gas & Liquids, Petroleum Services, and
Williams Energy Partners). Williams currently evaluates performance based upon
segment profit (loss) from operations (see Note 16). Segment profit of the
operating companies may vary by quarter. Energy Marketing & Trading's results
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 of contracts.

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 current and prior period amounts and the following discussions
reflect these changes.

34

Management's Discussion & Analysis (Continued)

On April 11, 2002, Williams Energy Partners L.P., a partially owned and
consolidated entity of Williams, acquired Williams Pipe Line, an operation
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. Also in the first quarter of 2002, management
of APCO Argentina was transferred from the 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

Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001

ENERGY MARKETING & TRADING'S revenues decreased $616.3 million, or 182
percent, due primarily to a $616.5 million decrease in risk management and
trading revenues. During second-quarter 2002, Energy Marketing & Trading's
results were in general adversely affected by the impact of market movements
against its portfolio and an absence of new 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 market
concerns regarding Williams' credit and liquidity and internal efforts to
preserve liquidity.

The $616.5 million decrease in risk management and trading revenues is due
primarily to a decrease of $550.2 million in the natural gas and power
portfolios and a $68.2 million decrease in the petroleum products portfolio. The
$550.2 million decrease in the natural gas and power portfolio includes a $339.5
million decrease in new transaction origination compared to second-quarter 2001.
This decline is reflective of the minimal amount of new transaction origination
as a result of the deterioration of market liquidity and Williams' limited
credit capacity. The decline in value of the natural gas and power portfolio is
also a result of higher natural gas prices and lower power prices that led to
significantly reduced spark spreads in the northeast and southeast regions. The
$68.2 million decrease in the petroleum products portfolio was driven by a
decline in market liquidity combined with a reduction in crude and unleaded
prices. Additionally, the natural gas and power and the refined products
portfolio were also impacted by the general market deterioration and credit
degradation in the energy trading sector which had the effect of reducing
contract valuations as market liquidity declined and corporate bond spreads
deteriorated.

Other (income) expense-net in 2002 includes $83.7 million of net loss
accruals and write-offs primarily associated with commitments for certain
terminated power projects. Of this amount, $50 million was associated with a
reduction to fair value of certain power equipment for which management made the
second-quarter decision to sell rather than utilize in power development
projects. The balance primarily represents an accrual for costs associated with
leased power generation equipment that management determined in the second
quarter of 2002 will not be utilized. Also included in other (income)
expense-net in 2002 is a $57.5 million partial goodwill impairment resulting
from deteriorating market conditions during the second quarter (see Note 3).

Segment profit decreased by $759.7 million due primarily to the $616.5
million reduction of trading revenues and the $141.2 million of items discussed
above in other (income) expense-net.

Energy Marketing & Trading's future results will be affected by the
reduction in liquidity available to them from their parent, the willingness of
counterparties to enter into transactions with Energy Marketing & Trading, the
liquidity of the markets in which Energy Marketing & Trading transacts and the
overall credit worthiness of other counterparties in the industry segment.
Because credit rating agencies no longer consider Williams as an investment
grade rated company, in some instances, Williams is required to provide
additional adequate assurances in the form of cash or credit support to enter
into price risk management transactions. With the decision to continue to reduce
Williams' financial commitment and exposure to the trading business, it is
likely that Energy Marketing & Trading's portfolio will have greater exposure to
market movements which could result in

35

Management's Discussion & Analysis (Continued)

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 assessment related to the future value of
its forward positions. The effects of these items on Energy Marketing &
Trading's results will adversely affect results in the future. Williams will
also continue to evaluate the carrying value of Energy Marketing & Trading's
goodwill in light of recent developments.

Williams announced on August 1, 2002, its intention to reduce its
commitment to the energy marketing and trading business, which could be in
several forms. Williams continues to pursue several opportunities to sell all or
a portion of its portfolio. It also continues to discuss with certain parties
joint venturing arrangements. It is not possible at this time to predict the
ultimate outcome of these discussions or to estimate the sales proceeds that
might be received if such transactions occur. It is possible that Williams, in
order to generate levels of liquidity it needs in the future, would be willing
to accept amounts for a portion or its entire portfolio that is lower than the
carrying value at June 30, 2002.

Issues in the Western Marketplace

At June 30, 2002, Energy Marketing & Trading had net accounts receivable
recorded of approximately $231 million for power sales to the California
Independent System Operator and the California Power Exchange Corporation
(CPEC). While the amount recorded reflects management's best estimate of
collectibility, future events or circumstances could change those estimates.

As discussed in Rate and Regulatory Matters and Related Litigation in Note
12 of the Notes to Consolidated Financial Statements, the FERC and the DOJ have
issued orders or initiated actions which involve Energy Marketing & Trading
related to California and the western states electric power industry. In
addition to these federal agency actions, a number of federal and state
initiatives addressing the issues of the California electric power industry are
also ongoing and may result in restructuring of various markets in California
and elsewhere. Discussions in California and other states have ranged from
threats of re-regulation to suspension of plans to move forward with
deregulation. Allegations have also been made that the wholesale price increases
resulted from the exercise of market power and collusion of the power generators
and sellers, such as Williams. These allegations have resulted in multiple state
and federal investigations as well as the filing of class-action lawsuits in
which Williams is a named defendant. Williams' 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,
Williams is attempting to resolve many of these disputes through settlement and
has reached a settlement in principle with the State of California on a global
settlement that includes a renegotiated long-term energy contract. The
settlement will also resolve complaints brought by the California Attorney
General against Williams and the State of California's refund claims. In
addition, the settlement will resolve ongoing investigations by the States of
California, Oregon, and Washington. The settlement is subject to documentation
and approval by various courts and agencies. (see Other Legal Matters in Note
12) There can be no assurance that these initiatives, investigations and
proceedings will not have an adverse effect on Williams' results of operations
or financial condition.

Six Months Ended June 30, 2002 vs. June 30, 2001

ENERGY MARKETING & TRADING'S revenues decreased $859.5 million, or 92
percent, due primarily to an $861.2 million decrease in risk management and
trading revenues. As noted previously, Energy Marketing & Trading's results were
in general adversely affected by its limited ability to manage or hedge its
portfolio against adverse market movements due to a lack of market liquidity,
the market's concerns regarding Williams credit and liquidity, and internal
efforts to preserve liquidity.

The $861.2 million decrease in risk management and trading revenues is due
primarily to a decrease of $961 million in the natural gas and power portfolios,
partially offset by a $71.6 million increase in the petroleum products
portfolio. The $961 million decrease in the natural gas and power portfolio
includes a $218 million decrease due to the minimal amount of new transaction
origination in second-quarter 2002. The decline in value of the natural gas and
power portfolio is also a result of the impact of lower market volatility than
was present during the first half of 2001 and to higher natural gas prices and
lower power prices that led to reduced spark spreads in the northeast and
southeast regions in the second quarter of 2002. The $71.6 million increase in
the petroleum products portfolio was due primarily to $118.8 million resulting
from origination of transactions during the first quarter of 2002 partially
offset by a decrease in the value of the refined products storage and
transportation portfolios during the second quarter of 2002. The natural gas and
power portfolio and the refined products portfolio were also impacted in
second-quarter 2002 by the general market deterioration and credit degradation
in the energy trading sector had the effect of reducing structured contract
valuations as market liquidity declined and corporate bond spreads deteriorated.

Selling, general, and administrative expenses decreased by $42.4 million or
27 percent. This cost reduction is primarily due to lower variable compensation
levels associated with reduced segment profit and the effect in 2002 of
modifications to the variable compensation plan.

Other (income) expense-net in 2002 includes the $83.7 million of net loss
accruals and write-offs discussed above and the $57.5 million partial goodwill
impairment also discussed above.

Segment profit (loss) decreased by $966.1 million or 129 percent, due
primarily to the $861.2 million reduction of trading revenues and the $141.2
million of non-recurring items discussed in other (income) expense - net above,
partially offset by the decrease in selling, general and administrative expense.

36

Management's Discussion & Analysis (Continued)

GAS PIPELINE

Three Months Ended June 30, 2002 vs. June 30, 2001

GAS PIPELINE'S revenues increased $13 million, or 4 percent, due primarily
to $11 million higher demand revenues on the Transco system resulting from new
expansion projects and new rates effective September 1, 2001, $8 million from
environmental mitigation credit sales and services and $4 million higher
transportation revenues on the Texas Gas system. Partially offsetting these
increases were $8 million lower gas exchange imbalance settlements (offset in
costs and operating expenses) and $3 million lower storage revenues.

Costs and operating expenses increased $14.3 million, or 8 percent, due
primarily to 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 $8 million of higher depreciation expense due to
increased property, plant and equipment placed into service on the Transco
system, partially offset by $8 million lower gas exchange imbalance settlements
(offset in revenues).

General and administrative costs increased $17 million, or 32 percent, due
primarily to $11 million in early retirement pension costs and $2 million of
increased long-term disability costs.

Other (income) expense - net in 2002 includes a $7.5 million write-off of a
cancelled pipeline project. Other (income) expense - net in 2001 includes a
$27.5 million pre-tax gain from the sale of Williams' limited partnership
interest in Northern Border Partners, L.P.

Segment profit, which includes equity earnings, decreased $24.3 million, or
13 percent, due primarily to the $35 million unfavorable change in other
(income) expense - net, as discussed above, and $17 million higher general and
administrative costs discussed previously, partially offset by $29.3 million
higher equity earnings. The $29.3 million increase in equity earnings includes a
$27.4 million benefit in 2002 reflecting a 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 increase reflects a $14 million increase from
Gulfstream primarily related to interest capitalized on the Gulfstream pipeline
project in accordance with FERC regulations. Partially offsetting these
increases to equity earnings was a $12.3 million write-down of Gas Pipeline's
investment in a pipeline project that has been cancelled.

Subsequent to second-quarter 2002, Williams announced that it agreed to
sell its Cove Point liquefied natural gas (LNG) facility and 87-mile pipeline
for $217 million in cash to a subsidiary of Dominion Resources. The Cove Point
LNG facility is currently used for storage and to serve customers during peak
periods of demand, while the pipeline is used to serve customers year-round. The
terminal is located on more than 1,000 acres of land on the western shore of the
Chesapeake Bay. The sale is expected to close mid-September 2002. Revenues for
the

37

Management's Discussion & Analysis (Continued)

three and six months ended June 30, 2002 related to Cove Point were
approximately $5.7 million and $8.6 million, respectively. In addition, Williams
also announced it is considering the sale of the 6,000 mile natural gas pipeline
system known as Central Gas Pipeline System. Revenues for the three and six
months ended June 30, 2002, for the Central Gas Pipeline System were $41 million
and $80 million, respectively.

Transcontinental Gas Pipe Line and Texas Gas have various regulatory
proceedings pending. As of June 30, 2002, approximately $178 million has been
accrued for potential refund. As a result of rulings in certain of these
proceedings, Williams anticipates recording revenues in third-quarter 2002 of
approximately $39 million to $41 million.

Six Months Ended June 30, 2002 vs. June 30, 2001

GAS PIPELINE'S revenues increased $14.8 million, or 2 percent, due
primarily to $19 million higher demand revenues on the Transco system resulting
from new expansion projects and new rates effective September 1, 2001 and $9
million from environmental mitigation credit sales and services. Partially
offsetting these increases were $11 million lower recovery of tracked costs
which are passed through to customers (offset in costs and operating expenses
and general and administrative costs) and $3 million lower storage revenue.

Costs and operating expenses increased $16 million, or 4 percent, due
primarily to 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 $12 million higher depreciation expense due to
increased property, plant and equipment placed into service, partially offset by
$8 million lower tracked costs which are passed through to customers (offset in
revenues).

General and administrative costs increased $14 million, or 12 percent, due
primarily to $11 million in early retirement pension costs and $2 million of
increased long-term disability costs, partially offset by $3 million lower
tracked costs (offset in revenues).

Other (income) expense - net in 2002 includes a $7.5 million write-off of a
cancelled pipeline project. Other (income) expense - net in 2001 includes a
$27.5 million pre-tax gain from the sale of Williams' limited partnership
interest in Northern Border Partners, L.P.

Segment profit, which includes equity earnings, decreased $10.8 million, or
3 percent, due primarily to the $35 million unfavorable impact of the other
(income) expense - net items discussed above and $14 million higher general and
administrative costs discussed previously. These decreases in segment profit
were partially offset by $40.6 million higher equity investment earnings. The
$40.6 million increase in equity earnings includes the $27.4 million benefit in
2002 related to the contractual construction completion fee received by an
equity affiliate discussed above. Additionally, the equity earnings increase
reflects a $26 million increase from Gulfstream primarily related to interest
capitalized on the Gulfstream pipeline project in accordance with FERC
regulations. Partially offsetting these increases to equity earnings was a $12.3
million write-down of Gas Pipeline's investment in a pipeline project that has
been cancelled.

ENERGY SERVICES

EXPLORATION & PRODUCTION

Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001

EXPLORATION & PRODUCTION'S revenues increased $123.6 million, or 115
percent, due primarily to $105 million higher production revenues. The $105
million increase in production revenues includes $114 million associated with an
increase in net production volumes partially offset by $9 million from decreased
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 Barrett Resources Corporation (Barrett).
Approximately 83 percent of production in the second quarter of 2002 was hedged.
Exploration & Production has contracts that hedge approximately 80 percent of
estimated production for the remainder of the year before consideration of the
asset sales discussed below. These hedges are entered into with Energy Marketing
& Trading which, in turn, enters into offsetting derivative contracts with
unrelated third parties. Energy Marketing & Trading

38

Management's Discussion & Analysis (Continued)

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.
Under accounting guidance, the other comprehensive income related to a
terminated contract remains in accumulated other comprehensive income and is
recognized as the underlying volumes are produced. During the second quarter of
2002, approximately $9 million related to the terminated contracts was
recognized as revenues while $62 million remains in accumulated other
comprehensive income at June 30, 2002.

Segment costs and operating expenses increased $66 million, including an
$11 million increase in selling, general and administrative expenses due
primarily to the addition of Barrett operations. Segment costs and operating
expenses increased due primarily to the addition of the former Barrett
operations, comprised primarily of depletion, depreciation and amortization and
lease operating expenses.

Segment profit increased $50.2 million due primarily to increased
production volumes.

Subsequent to June 30, 2002, Exploration & Production initiated and
completed the sale of Exploration & Production's Jonah Field natural gas
production properties in Wyoming to EnCana Oil & Gas (USA) Inc. Exploration &
Production also completed the sale of substantially all of its natural gas
production properties in the Anadarko Basin to Chesapeake Exploration Limited
Partnership . The sales generated approximately $308 million in net cash
proceeds. The company expects to recognize a gain from these sales which will be
recorded in the third quarter of 2002. Revenues for the three and six months
ended June 30, 2002, related to these properties were approximately $22 million
and $40 million, respectively.

Six Months Ended June 30, 2002 vs. Six Months Ended June 30, 2001

EXPLORATION & PRODUCTION'S revenues increased $208.9 million, or 84
percent, due primarily to $210 million higher production revenues, $7 million in
unrealized gains from the mark-to-market financial instruments related to basis
differentials on natural gas production partially offset by $18 million lower
gas management revenues. The $210 million increase in production revenues
includes $270 million associated with an increase in net production volumes,
partially offset by $60 million from decreased 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
Barrett. Approximately 82 percent of production through the second quarter of
2002 was hedged. Through the second quarter of 2002, approximately $18 million
related to the Enron terminated contracts discussed above was recognized as
revenues. At June 30, 2002, the contracted future hedge contracts are at prices
that averaged above the spot market, resulting in an unrealized gain of $93
million (including $62 million related to the terminated contracts as discussed
previously) reflected in accumulated other comprehensive income within
stockholders' equity. This is a decrease from the unrealized gain at December
31, 2001, due to an increase in natural gas prices.

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 marketing 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.

Segment costs and operating expenses increased $97 million, including a $20
million increase in selling, general and administrative expenses due primarily
to the addition of Barrett operations. Segment costs and operating expenses
increased due primarily to costs related to the former Barrett operations,
comprised primarily of depletion, depreciation and amortization and lease
operating expenses, and $5 million higher production-related taxes partially
offset by $18 million lower gas management costs and $5 million lower costs from
International activities.

Segment profit increased $101.3 million due primarily to increased
production volumes, partially offset by $10 million lower earnings from equity
investments.

39

Management's Discussion & Analysis (Continued)

INTERNATIONAL

Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001

INTERNATIONAL'S segment loss increased $47.5 million due primarily to a
$44.1 million impairment charge related to the Colorado soda ash mining
operations and a $4 million increase in equity losses from the Lithuania
refinery, pipeline and terminal investment. The $44.1 million impairment charge,
which is included in other (income) expense-net, is reflective of management's
estimate of fair value which was based on discounted cash flows assuming sale of
the facility in 2002 (see Note 3). This impairment is in addition to a $170
million impairment recorded in fourth-quarter 2001.

During first-quarter 2002, Williams management announced plans to initiate
a reserve-price auction of its interest in Colorado soda ash mining operations
mentioned above, in an effort to monetize all or part of its investment.
Williams expects to complete the reserve-price auction process during
third-quarter 2002.

On June 17, 2002 the Lithuania refinery completed an agreement with YUKOS
Oil Company (YUKOS) and the Lithuanian government whereby a wholly owned
subsidiary of YUKOS has become a shareholder in the Lithuania refinery. YUKOS
contributed $75 million of equity and loaned another $75 million to the refinery
in return for an approximate 27 percent ownership interest. The Lithuanian
government provided a guaranty for the $75 million loan. In addition, YUKOS
signed a 10-year crude oil supply agreement with the refinery. This transaction
diluted Williams's ownership interest in the refinery from 33 percent to
approximately 27 percent.

Six Months Ended June 30, 2002 vs. Six Months Ended June 30, 2001

INTERNATIONAL'S segment loss increased $46.9 million due primarily to the
$44.1 million impairment charge discussed above related to the Colorado soda ash
mining operations and a $5 million increase in equity losses from the Lithuania
refinery, pipeline and terminal investment. Slightly offsetting these losses was
$5 million lower operating losses from soda ash mining operations.

MIDSTREAM GAS & LIQUIDS

Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001

MIDSTREAM GAS & LIQUIDS' revenues decreased $39.8 million, or 7 percent,
due primarily to $49 million lower revenues related to the natural gas liquids
trading operations, $9 million lower natural gas liquids sales from processing
activities and $8 million lower revenues from gathering activities, partially
offset by a $19 million increase in revenue from a gas compression facility in
Venezuela which began operations in August 2001 and $10 million higher natural
gas liquids sales from fractionation activities. The $49 million decrease in
natural gas liquids trading operations revenues reflects decreased natural gas
liquids prices coupled with certain activities previously recorded on a gross
basis which are now accounted for on a net basis. The $9 million lower natural
gas liquids sales from processing activities reflects $45 million from a 21
percent decrease in natural gas liquid sales prices largely offset by $37
million from a 21 percent increase in natural gas liquids volumes.

Costs and operating expenses decreased $51 million, or 12 percent, due
primarily to lower expenses related to the natural gas liquids trading
operations of $36 million, $12 million lower shrinkage, fuel and replacement gas
purchases

40

Management's Discussion & Analysis (Continued)

relating to processing activities and $6 million lower power costs from the
natural gas liquids pipelines. The $36 million lower expense related to the
natural gas liquids trading operations is due primarily to the reporting of
certain costs net within revenue in 2002 as discussed above. Slightly offsetting
these decreases were increased costs of $8 million associated with a gas
compression facility in Venezuela which began operations in August 2001.

Included in other (income) expense - net within segment costs and expenses
for 2001 is a $10.9 million impairment loss related to management's
second-quarter 2001 decision and commitment to sell certain south Texas
non-regulated gathering and processing assets. The $10.9 million charge
represented the impairment of the assets to fair value based on expected
proceeds from the sale. In second-quarter 2002, a $4.8 million charge was
recognized representing the impairment of assets to fair value associated with
the sale of the Kansas-Hugoton natural gas gathering system. This sale closed
during third quarter 2002.

Segment profit increased $20.1 million, or 31 percent, due primarily to $11
million of segment profit from the gas compression facility in Venezuela, $10
million higher products margin from the fractionation activities, $9 million
from higher average per-unit natural gas liquids margins and $7 million higher
transportation revenues combined with decreased power costs from the natural gas
liquids pipelines. Also contributing was $3.6 million in equity earnings in 2002
versus $5.6 million of equity losses in 2001 reflecting improved results from
the Discovery pipeline project. These increases were partially offset by $12
million lower margins from natural gas liquids trading activity and $8 million
lower gathering revenues.

Subsequent to second quarter 2002, Williams announced the sale of 98
percent of Mapletree LLC and 98 percent of E-Oaktree, LLC to Enterprise Products
Partners L.P. Mapletree owns all of Mid-America Pipeline, a 7,226-mile natural
gas liquids pipeline system. E-Oaktree owns 80 percent of the Seminole Pipeline,
a 1,281-mile natural gas liquids pipeline system. Revenues for the three and six
months ended June 30, 2002 related to Mid-America Pipeline and Seminole were
approximately $69 million and $141 million, respectively. The sale generated
$1.1 billion in net cash proceeds. Williams expects to recognize a gain from the
sale which will be recorded in the third quarter 2002. In addition, the Kansas
Hugoton natural gas gathering system was sold to FrontStreet Hugoton LLC, an
affiliate of FrontStreet Partners, LLC. Williams received approximately $80
million in cash.

Six Months Ended June 30, 2002 vs. Six Months Ended June 30, 2001

MIDSTREAM GAS & LIQUIDS' revenues decreased $236.2 million, or 19 percent,
due primarily to $113 million lower natural gas liquids sales from processing
activities, $94 million lower revenues related to the natural gas liquids
trading operations, $29 million lower revenues from processing activities due
primarily to lower processing rates from Canadian activities, $29 million lower
natural gas liquids sales from fractionation activities and $14 million lower
gathering revenues due primarily to decreased volumes. These decreases were
partially offset by $39 million increased revenues from the gas compression
facility in Venezuela which began operations in August 2001 and $11 million
higher transportation revenues associated with pipeline operations. The liquids
sales decrease reflects $200 million from 39 percent lower average natural gas
liquids sales prices, partially offset by $87 million from a 21 percent increase
in volumes sold. The $94 million decrease in natural gas liquids trading
operations reflects decreased natural gas liquids prices coupled with certain
activities previously recorded on a gross basis which are now accounted for on a
net basis.

Costs and operating expenses decreased $295 million, or 29 percent, due
primarily to $166 million lower shrinkage, fuel and replacement gas purchases
relating to processing activities, $90 million lower expenses related to the
natural gas liquids trading operations, $39 million lower liquid purchases
related to fractionation activities and $13 million lower power expense related
to natural gas liquids pipelines. The $90 million lower expense related to the
natural gas liquids trading operations is due primarily to the reporting of
certain costs net within revenue in 2002 and lower costs related to lower
volumes sold. Slightly offsetting these decreases were $15 million of increased
costs associated with the gas compression facility in Venezuela which began
operations in August 2001.

Included in other (income) expense - net within segment costs and expenses
for 2001 is the $10.9 million impairment loss related to certain south Texas
non-regulated gathering and processing assets. In second-quarter 2002, a $4.8
million charge was recognized representing the impairment of assets to fair
value associated with the sale of the Kansas-Hugoton natural gas gathering
system which closed in third-quarter 2002.

41

Management's Discussion & Analysis (Continued)

Segment profit increased $68.4 million, or 66 percent, due primarily to $33
million from higher average per-unit natural gas liquids margins, $24 million of
segment profit from the gas compression facility in Venezuela, $23 million from
higher transportation revenues combined with decreased power costs from the
natural gas liquids pipelines and $10 million higher products margins from
fractionation activities. Also contributing to the increase in segment profit
was $5.2 million in equity earnings in 2002 versus $12.8 million of equity
losses in 2001. The improvement is primarily due to the Discovery pipeline
project. These increases were partially offset by $14 million lower revenue from
gathering activities, $13 million lower processing margins primarily due to
lower processing rates and $9 million higher general and administrative
expenses.

PETROLEUM SERVICES

Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001

PETROLEUM SERVICES' revenues decreased $307.7 million, or 21 percent, due
primarily to $138 million lower refining and marketing revenues, $155 million
lower travel center/convenience store sales and $20 million lower bio-energy
sales, slightly offset by $48 million lower intrasegment sales, which are
eliminated and primarily relate to sales from refining and marketing to travel
center/convenience stores.

The $138 million decrease in refining and marketing revenues is due
primarily to a 13 percent lower average refined product sales prices. The $155
million decrease in travel center/convenience store sales reflects a $78 million
decrease in revenues related to travel centers and Alaska convenience stores and
the absence of $77 million in revenues related to the 198 convenience stores
sold in May 2001. The $78 million decrease in revenues of the travel centers and
Alaska convenience stores primarily reflects $55 million from a 25 percent
decrease in diesel sales volumes and $27 million from a 12 percent decrease in
average diesel and gasoline sales prices, partially offset by a $6 million
increase in gasoline sales volumes. The decrease in diesel sales volumes
includes the impact of the discontinuance of a diesel volume incentive program.
The $20 million decrease in bio-energy sales reflects a $28 million decrease
from lower average ethanol sales prices partially offset by an $8 million
increase from higher ethanol sales volumes.

Costs and operating expenses decreased $254 million, or 18 percent, due
primarily to $97 million lower refining and marketing costs and $157 million
lower travel center/convenience store costs, partially offset by a $48 million
increase in external costs due to decreased intrasegment purchases as discussed
above, which are eliminated. The $97 million decrease in refining and marketing
costs includes a $193 million decrease consisting primarily of lower crude
supply costs and other per unit cost of sales from the refineries, partially
offset by $101 million increase in the cost of refined product purchased for
resale. The $157 million decrease in travel center and Alaska convenience store
costs reflects the absence of $76 million in costs related to the 198
convenience stores sold in May 2001 and $82 million decrease in costs for the
travel centers and Alaska convenience stores. The $82 million decrease reflects
$53 million from decreased diesel sales volumes, $27 million from lower average
gasoline and diesel purchase prices and $8 million lower store operating and
merchandise costs, offset by a $5 million increase in gasoline purchase volumes.

Other (income) expense - net in 2002 includes $27 million in loss accruals
and impairment charges related to certain travel centers (see Note 3). Other
(income) expense - net in 2001 includes a $72.1 million pre-tax gain from the
sale of convenience stores in May 2001.

Segment profit decreased $150.8 million to a $20.7 million segment loss due
primarily to the net unfavorable effect of the items discussed above in other
(income) expense - net and the $45 million lower operating profit from refining
and marketing operations due primarily to narrowing crack spreads.

As previously discussed, Williams has begun to more narrowly focus its
business strategy within its major business units. The refining and marketing
operations are businesses that have been announced as possible assets to be
sold. In addition, the travel centers, Alaska convenience stores, and bio-energy
operations are also businesses that may be sold in the future.

42

Management's Discussion & Analysis (Continued)

Six Months Ended June 30, 2002 vs. Six Months Ended June 30, 2001

PETROLEUM SERVICES' revenues decreased $699.9 million, or 25 percent, due
primarily to $444 million lower refining and marketing revenues, $335 million
lower travel center/convenience store sales and $21 million lower bio-energy
sales, slightly offset by $107 million lower intrasegment sales, which are
eliminated and primarily relate to sales from refining and marketing to travel
center/convenience stores.

The $444 million decrease in refining and marketing revenues includes $412
million resulting from 21 percent lower average refined product sales prices and
$32 million from a decrease in refined product volumes sold. The $335 million
decrease in travel center/convenience store sales reflects a $153 million
decrease in revenues related to travel centers and Alaska convenience stores and
the absence of $182 million in revenues related to the 198 convenience stores
sold in May 2001. The $153 million decrease in revenues of the travel centers
and Alaska convenience stores primarily reflects $95 million from a 23 percent
decrease in diesel sales volumes and $63 million from a 14 percent decrease in
average diesel and gasoline sales prices, partially offset by an $8 million
increase in gasoline sales volumes. The $21 million decrease in bio-energy sales
reflects $45 million lower average ethanol sales prices, partially offset by $20
million higher ethanol sales volumes.

Costs and operating expenses decreased $642.9 million, or 24 percent, due
primarily to $396 million lower refining and marketing costs, $339 million lower
travel center/convenience store costs and $8 million lower bio-energy product
and operating costs, partially offset by $107 million increase in external costs
due to decreased intrasegment purchases discussed above, which are eliminated.
The $396 million decrease in refining and marketing costs includes a $342
million decrease from lower crude supply costs and other per unit cost of sales
from the refineries and a $48 million decrease in the cost of refined product
purchased for resale. The $339 million decrease in travel center and Alaska
convenience store costs reflects the absence of $181 million in costs related to
the 198 convenience stores sold in May 2001 and a $160 million decrease in costs
for the travel centers and Alaska convenience stores. The $160 million decrease
reflects $64 million from lower gasoline and diesel purchase prices and $91
million from decreased diesel purchase volumes and $12 million lower store
operating and merchandise costs, partially offset by $7 million in increased
gasoline purchase volumes.

Other (income) expense - net in 2002 includes $27 million in loss accruals
and impairment charges related to certain travel centers (see Note 3). Other
(income) expense - net in 2001 includes a $72.1 million pre-tax gain from the
sale of convenience stores in May 2001. Also included in other (income) expense
- - net in 2001 is an $11.2 million impairment charge related to an end-to-end
mobile computing systems business.

Segment profit decreased $137.4 million, or 93 percent, due primarily to
the net unfavorable effect related to the items noted above in other (income)
expense - net and the $54 million lower operating profit from refining and
marketing operations due primarily to narrowing crack spreads.

WILLIAMS ENERGY PARTNERS

Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001

WILLIAMS ENERGY PARTNERS' revenue increased $1.7 million, or 2 percent, due
primarily to $2 million higher revenues from transportation activities, a marine
facility acquired in October 2001, and two inland terminals acquired in June
2001, partially offset by lower ammonia transportation revenues. Segment profit
decreased $4.2 million, or 12 percent, due primarily to a $3 million increase in
selling, general and administrative expenses incurred by the general partner.

43

Management's Discussion & Analysis (Continued)

Six Months Ended June 30, 2002 vs. Six Months Ended June 30, 2001

WILLIAMS ENERGY PARTNERS' revenue decreased $3.8 million, or 2 percent, due
primarily to $10 million lower commodity sales from transportation activities,
partially offset by $4 million higher revenues from a marine facility acquired
in October 2001 and two inland terminals acquired in June 2001.

Costs and operating expenses decreased $11 million due primarily to $14
million lower costs from transportation activities consisting primarily of $10
million lower product costs.

Segment profit for both periods was comparable despite the overall
favorable impact of the revenue increase and the decrease in costs and operating
expenses which were offset by higher selling, general and administrative
expenses incurred by the general partner.

44

Management's Discussion & Analysis (Continued)

FAIR VALUE OF ENERGY RISK MANAGEMENT AND TRADING ACTIVITIES

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) decreased $343 million during
second-quarter 2002 and $84 million year-to-date. The following table reflects
the changes in fair value between December 31, 2001 and June 30, 2002.

(1) 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 the fair value of contracts outstanding and
decrease in cash; premiums received result in an initial decrease in
the fair value of contracts outstanding and an increase in cash. The
underlying values of the options associated with the premium payments
are also included in the fair value of contracts outstanding.

45

Management's Discussion & Analysis (Continued)

The following tables reconcile the changes in fair value of energy risk
management and trading contracts during first and second quarter 2002 to energy
risk management trading revenues for those periods.

Change in fair value during first-quarter 2002 $ 259
Net option premiums received 271
Recognized losses included in the fair value of contracts
outstanding at December 31, 2001
expected to be realized during the period (173)
Gains in interest rate hedges (1) 28
Other unrealized losses not included in the change in fair value (12)
------
Revenues recognized but not realized during first quarter 2002 $ 373
Revenues recognized and realized during first quarter 2002 (5)
------
ENERGY RISK MANAGEMENT AND TRADING REVENUES DURING FIRST QUARTER 2002 $ 368

Change in fair value during second quarter 2002 $ (343)
Net option premiums paid (23)
Recognized losses included in the fair value of contracts
outstanding at March 31, 2002
expected to be realized during the period 243
Losses in interest rate hedges (1) (115)
Other unrealized losses not included in the change in fair value (32)
------
Revenues recognized but not realized during second quarter 2002 $ (270)
Revenues recognized and realized during second quarter 2002 (8)
------
ENERGY RISK MANAGEMENT AND TRADING REVENUES DURING SECOND QUARTER 2002 $ (278)

(1) Energy Marketing & Trading, through Williams, enters into interest rate
derivatives to mitigate the associated interest rate risk from the fair
value of the long-dated energy and energy-related contracts by fixing
the interest rate inherent in the portfolio of contracts.

46

Management's Discussion & Analysis (Continued)

The charts below reflect the fair value of energy risk management and
trading contracts for Energy Marketing & Trading and the natural gas liquids
trading operations now reported in the Midstream Gas & Liquids segment at
December 31, 2001, March 31, 2002, and June 30, 2002 by valuation methodology
and the year in which the recorded fair value is expected to be realized.

(1) A significant portion of the value expected to be realized relates to
a contract within the California power market. The terms of this
agreement provide for the sale of power at prices ranging from $62.50
to $87.00 per megawatt hour over a ten-year period at variable volumes
up to 1,400 megawatts per hour. On July 26, 2002 Williams announced
that it had reached an agreement in principle with the State of
California and other parties including the States of Washington and
Oregon on a global settlement that is expected to result in a new
long-term energy contract between Williams and the State of
California. Further discussion of this settlement is included on page
14.

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

Energy Marketing & Trading manages the risk assumed from providing energy
risk management services to its customers. This risk results from exposure to
energy commodity prices, volatility and correlation of commodity prices, the
portfolio position of the contracts, liquidity of the market in which the
contract is transacted, interest rates, and counterparty performance and credit.
Energy Marketing & Trading seeks to diversify its portfolio in managing the
commodity price risk in the transactions that it executes in various markets and
regions by executing offsetting contracts to manage the commodity price risk in
accordance with parameters established in its trading policy. However, as noted
previously, during the second quarter of 2002, Energy Marketing & Trading was
significantly constrained in its ability to manage or hedge its portfolio
against adverse market movements according to the aforementioned methodology due
to a lack of market liquidity, the market's concerns regarding Williams credit
and liquidity, and internal efforts to preserve liquidity.

Subsequent to June 30, 2002 and in response to factors such as recent
downgrades to below-investment grade by the credit rating agencies and
difficulties in obtaining financing facilities, the Company announced a
significant reduction in its financial commitment to the Energy Marketing &
Trading segment and is consequently evaluating opportunities to sell or
liquidate Energy Marketing & Trading's trading portfolio or to form a joint
venture around the Energy Marketing and Trading unit with another party. As a
result of this decision, the ultimate realization of the estimated fair value of
Energy Marketing & Trading's portfolio under this strategy may vary from the
amount of the Company's estimate at June 30, 2002.

47

Management's Discussion & Analysis (Continued)

FINANCIAL CONDITION AND LIQUIDITY

LIQUIDITY

Williams' liquidity comes from both internal and external sources. Certain
of those sources are available to Williams (parent) and certain of its
subsidiaries. Available cash equivalent investments at June 30, 2002, were $498
million, as compared to $1.1 billion at December 31, 2001. Subsequent to June
30, 2002, Williams' credit ratings were downgraded to levels considered below
investment grade by the major rating agencies. Following these downgrades,
Williams' liquidity became strained as Williams was unable to complete a renewal
of its unsecured short-term bank credit facility which supported the $2.2
billion commercial paper program. Williams responded to these events with a
concentrated effort to complete certain asset sales and obtain secured credit
facilities in order to raise funds to meet maturing debt obligations and provide
liquidity that should provide sufficient funding for at least the balance of the
year. In addition, the board of directors reduced the quarterly dividend on
common stock from $.20 per share to $.01 per share. After consideration of the
asset sales and the secured credit facilities which closed subsequent to June
30, 2002, Williams' sources of liquidity consist primarily of the following:

o $700 million available under Williams' $700 million unsecured bank credit
facility at June 30, 2002, as compared to $700 million under an unsecured
bank credit facility at December 31, 2001. This facility was amended to
provide security interests to the participating banks and will reduce to
$400 million as assets are sold (see Note 18).

o A new $400 million secured short-term letter of credit agreement which
expires July 29, 2003.

o $900 million from a one-year borrowing arrangement secured by substantially
all of the oil and gas interests of Williams Production RMT Company (see
Note 18).

o Approximately $1.5 billion of cash proceeds from the sale of substantially
all of its natural gas liquids pipeline systems and certain exploration and
production properties.

o $325 million from the issuance of debt at Transcontinental Gas Pipe Line in
July 2002. These funds will primarily be used to extinguish $150 million of
variable interest rate debt, which was retired on July 31, 2002, and $125
million of fixed rate debt which matures in September 2002.

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

The amounts above do not take into account the significant uses of cash or
facilities that have occurred through August 9, 2002:

o Retirement of $300 million in Notes Payable on July 30, 2002.

o Retirement of $150 million of variable interest rate debt at
Transcontinental Gas Pipe Line on July 31, 2002.

o Retirement of $350 million of 6.2 percent notes on July 31, 2002.

o Redemption of $135 million in preferred interest on August 8, 2002 which
was accelerated due to the credit rating downgrade.

o Planned utilization of a significant portion of $400 million letter of
credit facility.

o Funding of approximately $665 million of cash collateral and margin
deposits (through August 12, 2002) which were required under certain
contracts.

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. In addition, there are outstanding subsidiary
registration statements filed with the Securities and Exchange Commission for
Northwest Pipeline, Texas Gas Transmission and Transcontinental Gas Pipe Line
(each a wholly owned subsidiary of Williams). As of August 9, 2002,
approximately $450 million of shelf availability remains under these outstanding
registration statements which may be used to issue a variety of debt or equity
securities. Interest rates and market conditions will affect amounts borrowed,
if any, under these arrangements.

Capital and investment expenditures for 2002 are estimated to total
approximately $2.2 billion. Williams expects to fund capital and investment
expenditures, debt payments and working-capital requirements through (1) cash
generated from operations, (2) the use of the available portion of Williams'
$700 million bank-credit facility, and/or (3) the sale or disposal of existing
assets.

48

Management's Discussion & Analysis (Continued)

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 levels of decline in Williams' credit ratings given by Moody's
Investor's Service, Standard & Poor's and Fitch Ratings (rating agencies).
Performance by Williams under these terms included potential acceleration of
debt payment and redemption of preferred interests totaling $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 13). The
amount related to potential acceleration of debt payment and redemption of
preferred interests was reduced to $182 million at March 31, 2002. As a result
of the credit rating downgrades in July 2002, Williams redeemed $135 million of
preferred interests on August 1, 2002 and plans to repay a $47 million loan by
the end of August.

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 will require
alternate credit support under certain existing agreements. In addition,
Williams will be required to fund margin requirements pursuant to industry
standard derivative agreements with cash, letters of credit or other negotiable
instruments. Subsequent to June 30, 2002, Williams and its subsidiaries have
been notified that cash, letters of credit or other negotiable instruments would
be required under terms of certain contracts. Through August 12, 2002, Williams
has provided approximately $665 million in cash, including prepayments for crude
oil for the refineries and margin requirements. Williams continues to negotiate
on other notifications for significant levels.

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

As disclosed in Williams Current Report on Form 8-K dated May 28, 2002,
Williams has operating lease agreements with two special purpose entities
(SPE's). The operating lease agreements are with respect to certain Williams
travel center stores, offshore oil and gas pipelines and an onshore gas
processing plant. As a result of changes to these agreements in conjunction with
the secured financing facilities completed in July 2002, these agreements no
longer qualify for operating lease treatment and as such will be reflected as
capital leases beginning in July 2002. If these agreements were treated as
capital leases at June 30, 2002, assets and long-term debt would increase by
$287 million.

At June 30, 2002, 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.

WCG and significant events since December 31, 2001 regarding 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.
Williams determined it was probable it would not fully realize the $375 million
of receivables and it would be required to perform under its $2.21 billion of
guarantees and payment obligations. Williams developed an estimated range of
loss related to its total WCG exposure and management believed that no loss
within that range was more probable than another. For 2001, Williams recorded
the $2.05 billion minimum amount of the range of loss from its financial
exposure to WCG, which was 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
of $1.84 billion included a $1.77 billion minimum amount of the estimated range
of loss from performance on $2.21 billion of guarantees and payment obligations.
The charge to continuing operations of $213 million included estimated losses
from an assessment of the recoverability of the carrying amounts of the $375
million of receivables and a $25 million investment in WCG common stock.

Williams, prior to the spinoff of WCG, 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. 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. With the exception of the March and September 2002 interest
payments, totaling $115 million, WCG, through a subsidiary, remains obligated to
reimburse Williams for any payments Williams makes in connection with the Notes.

49

Management's Discussion & Analysis (Continued)

Williams also provided a guarantee of WCG's obligations under a 1998
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 the lessor's cost of
$750 million. On March 8, 2002, WCG exercised its option to purchase the covered
network assets. On March 29, 2002, Williams funded the purchase price of $754
million and became entitled to an unsecured note from WCG for the same amount.
Pursuant to the terms of an agreement between Williams and WCG's revolving
credit facility lenders, the liability of WCG to compensate Williams for funding
the purchase is subordinated to the interests of WCG's revolving credit facility
lenders and will not mature any earlier than one year after the maturity of
WCG's revolving credit facility.

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

2002 EVALUATION

At June 30, 2002, Williams had receivables and claims from WCG of $2.15
billion arising from Williams affirming its payment obligation on the $1.4
billion of WCG Note Trust Notes and Williams paying $754 million under the WCG
lease agreement. At June 30, 2002, Williams also has $356 million of previously
existing receivables. In second-quarter 2002, Williams recorded in continuing
operations a pre-tax charge of $15 million related to WCG, including an
assessment of the recoverability of its receivables and claims from WCG. For the
six months ended June 30, 2002, Williams has recorded in continuing operations
pre-tax charges of $247 million related to recovery of these receivables and
claims. At June 30, 2002, Williams estimates that approximately $2.2 billion of
the $2.5 billion of receivables from WCG are not recoverable.

See Note 4 for further discussion of Williams' estimate of recoverability
including terms of the Settlement Agreement between Williams, WCG, the Official
Committee of Unsecured Creditors and Leucadia National Corporation.

OPERATING ACTIVITIES

In March 2002, WCG exercised its option to purchase certain network assets
under an operating lease agreement 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.
In return, Williams became entitled to receive an instrument of unsecured debt
from WCG in the same amount. Williams recorded an additional pre-tax charge of
$232 million and $15 million in first and second quarter 2002, respectively,
related to its assessment of the recoverability of certain receivables from WCG
(see Note 4).

During 2002, Williams was required to establish surety bonds with various
insurance companies and provide cash collateral in support of letters of credit
due to downgrades by credit rating agencies. These bonds are reported as current
and noncurrent restricted cash in the balance sheet and totalled approximately
$271 million at June 30, 2002.

During second-quarter 2002, Williams recorded approximately $154 million in
provisions for losses on property and other assets. Those provisions consisted
primarily of a partial impairment of goodwill at Energy Marketing & Trading and
an impairment related to the soda ash mining operations.

During second-quarter 2002, Williams made a $55 million contribution to its
pension plan. Due to the decline of the stock market in recent months, the plan
assets have decreased from the values at year end. If the recent stock market
trend continues, it is likely that Williams would need to contribute additional
cash to the pension plan.

FINANCING ACTIVITIES

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.

50

Management's Discussion & Analysis (Continued)

In April 2002, Williams Energy Partners L.P., a partially owned and
consolidated entity of Williams, borrowed $700 million from a group of
institutions. These proceeds were primarily used to acquire Williams Pipe Line,
a wholly owned subsidiary of Williams. In May 2002, Williams Energy Partners
L.P. issued approximately 8 million common units at $37.15 per unit resulting in
approximately $283 million of net proceeds that were used to reduce the $700
million loan. Williams Energy Partners L.P. expects to refinance the June 30,
2002 balance of $411 million in short-term debt with long-term debt financing.

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.

On March 27, 2002, concurrent with its sale of Kern River to MEHC, Williams
issued approximately 1.5 million shares of 9.875 percent cumulative convertible
preferred stock for $275 million. Dividends on the preferred stock are payable
quarterly (see Note 14).

In July 2002, Williams reduced the quarterly dividend on common stock 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.

For financing activities subsequent to June 30, 2002, see discussions in
the Liquidity section on page 48 and Note 18 on page 27.

Williams' long-term debt to debt-plus-equity ratio was 68.1 percent at June
30, 2002, compared to 59.9 percent at December 31, 2001 (excluding Kern River
debt). If short-term notes payable and long-term debt due within one year are
included in the calculations, these ratios would be 71.8 percent at June 30,
2002 and 65.5 percent at December 31, 2001. Additionally, the long-term debt to
debt-plus-equity ratio as calculated for covenants under certain debt agreements
was 63.5 percent at June 30, 2002 as compared to 61.5 percent at December 31,
2001.

INVESTING ACTIVITIES

Williams has contributed approximately $122 million and $81 million towards
the development of the Gulfstream joint venture project, a Williams equity
investment, during the first and second quarter, respectively, of 2002.

Proceeds from the sales of businesses include $434.6 million related to the
sale of Kern River on March 27, 2002.

In July 2002, Williams received $32.5 million plus interest, related to the
portion of the sales prices that was contingent upon Kern River receiving a
certificate from the FERC. This certificate was received in July 2002.

COMMITMENTS

The table below summarizes the maturity or redemption by year of the notes
payable, long-term debt and preferred interests in consolidated subsidiaries
outstanding at June 30, 2002 by period. This table does not reflect the $900
million borrowing arrangement which matures July 2003.

- ----------

(1) As of August 9, 2002, $904 million has been paid on these obligations.

(2) Subsequent to June 30, 2002, terms of certain operating leases were changed
and as a result, will be considered capitalized leases. This amount was
$287 million at June 30, 2002, and will be included in debt in third
quarter 2002.

(3) Includes $1.1 billion of 6.5% notes, payable 2007, subject to remarketing
in 2004.

(4) Includes $400 million of 6.75% notes, payable 2016, putable/callable in
2006.

OTHER

As disclosed in the March 31, 2002 Form 10-Q, if lump sum payments from the
pension plan reaches settlement accounting threshold, Williams will need to
recognize certain unrecognized net losses which could increase pension expense
in third or fourth quarter of 2002 by $25 million to $35 million. This entire
expense would be recognized at such time that the settlement accounting
threshold is met.

51

Management's Discussion & Analysis (Continued)

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

INTEREST RATE RISK

Williams' interest rate risk exposure associated with the debt portfolio
was impacted by new debt issuances in first-quarter 2002. In January 2002,
Williams issued $1.1 billion of 6.5 percent notes payable 2007 (see Note 11). In
February 2002, $240 million of 6.125 percent notes were retired. In March 2002,
Williams issued $850 million of 8.75 percent notes due 2032 and $650 million of
8.125 percent notes due 2012. Also in March 2002, the terms of a $560 million
priority return structure classified as preferred interest in consolidated
subsidiaries were amended. Based on the new payment terms of the amendment, the
remaining balance due has been reclassified from preferred interests in
consolidated subsidiaries to long-term debt due within one year (see Note 13).
The interest rate varies based on LIBOR plus an applicable margin and was 2.57
percent at June 30, 2002.

Pursuant to the completion of a consent solicitation during first-quarter
2002 with WCG Note Trust holders, Williams recorded $1.4 billion of long-term
debt obligations which mature in March 2004 and bear an interest rate of 8.25
percent. Subsequent to June 30, 2002, Williams completed an exchange of Williams
9.25 percent notes due March 2004 for substantially all of these securities (see
Note 4). In May 2002, Williams Energy Partners entered into a $700 million
short-term debt obligation which matures in October 2002. The interest rate
varies based on the Eurodollar rate plus 2.5 percent for the first 120 days of
the short-term debt obligation and, thereafter, at the Eurodollar rate plus 4
percent. This rate was 4.3 percent at June 30, 2002. In July 2002,
Transcontinental Gas Pipe Line issued $325 million of 8.875 percent long-term
debt obligations due 2012. Subsequent to June 30, 2002, Williams obtained a $900
million secured short-term loan. The borrowing accrues interest at a 14 percent
interest rate plus a variable rate which is currently 5.82 percent.

COMMODITY PRICE RISK

At June 30, 2002, the value at risk for the Energy Marketing & Trading
operations and the natural gas liquids trading operations now reported in the
Midstream Gas & Liquids segment was $74.5 million compared to $75.2 million at
March 31, 2002. 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.

52

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The information called for by this item is provided in Note 12 Contingent
liabilities and commitments included in the Notes to Consolidated Financial
Statements included under Part I, Item 1. Financial Statements of this report,
which information is incorporated by reference into this item.

Item 2. Changes in Securities and Use of Proceeds

Pursuant to the terms of the new credit facilities entered into on July 31,
2002, Williams is restricted from declaring and paying dividends in any quarter
the aggregate amount of which would be greater than $6.25 million. This
restriction does not limit Williams' ability to declare and pay dividends on
preferred stock issued prior to July 31, 2002, nor does it limit the ability of
Williams Energy Partners, L.P. to make distributions to its unit holders
pursuant to the terms of its partnership agreement.

The terms of the 9.875 percent cumulative convertible preferred stock issued to
MEHC (see Note 14) prohibit Williams from declaring and paying dividends on its
common stock or any other parity preferred stock if dividends on the 9.875
percent cumulative convertible preferred stock are in arrears. Dividends on all
parity preferred stock not paid in full must be paid pro rata.

Item 4. Submission of Matters to a Vote of Security Holders

The Annual Meeting of Stockholders of the Company was held on May 16, 2002. At
the Annual Meeting, five individuals were elected as directors of the Company
and eight individuals continue to serve as directors pursuant to their prior
election. The Williams Companies, Inc. 2002 Incentive Plan was approved, and the
appointment of Ernst & Young LLP as the independent auditor of the Company for
2002 was ratified.

A tabulation of the voting at the Annual Meeting with respect to the matters
indicated is as follows:

Election of Directors

Approval of The Williams Companies, Inc. 2002 Incentive Plan

Ratification of Appointment of Independent Auditors

Item 6. Exhibits and Reports on Form 8-K

(a) The exhibits listed below are filed as part of this report:

Exhibit 4.1--Indenture dated as of July 3, 2002 between
Transcontinental Gas Pipe Line Corporation and Citibank, N.A. as
trustee, for the Series A and Series B 8-7/8% Notes due July 15,
2012

Exhibit 10.1--Purchase Agreement between E-Birchtree, LLC and
Enterprise Products Operating L.P. dated as of July 31, 2002.

Exhibit 10.2--Purchase Agreement between E-Birchtree, LLC and
E-Cypress, LLC dated as of July 31, 2002.

Exhibit 10.3--$900,000,000 Credit Agreement dated as of July 31,
2002, among The Williams Companies, Inc., Williams Production
Holdings LLC, Williams Production RMT Company, as Borrower, the
Several Lenders from time to time parties thereto, Lehman
Brothers Inc., as Lead Arranger and Book Manager, and Lehman
Commercial Paper Inc., as Syndication Agent and Administrative
Agent.

Exhibit 10.4--Guarantee and Collateral Agreement made by The
Williams Companies, Inc., Williams Production Holdings LLC,
Williams Production RMT Company and certain of its Subsidiaries
in favor of Lehman Commercial Paper Inc., as Administrative
Agent, dated as of July 31, 2002.

Exhibit 10.5--Termination Agreement between The Williams
Companies, Inc. and Keith E. Bailey dated May 1, 2002.

Exhibit 10.6--Security Agreement dated as of July 31, 2002, among
The Williams Companies, Inc. and each of the Subsidiaries which
is a signatory hereto or which subsequently becomes a party
hereto in favor of Citibank, N.A., as collateral trustee for the
benefit of the holders of the Secured Obligations.

Exhibit 10.7--Pledge Agreement dated as of July 31, 2002, among
The Williams Companies, Inc. and each of the Subsidiaries which
is a signatory hereto or which subsequently becomes a party
hereto in favor of Citibank, N.A., as collateral trustee for the
benefit of the holders of the Secured Obligations.

Exhibit 10.8--Guaranty dated as of July 31, 2002 by Williams Gas
Pipeline Company, L.L.C. in favor of the Financial Institutions.

Exhibit 10.9--Collateral Trust Agreement among The Williams
Companies, Inc., and certain of its Subsidiaries, as Debtors, and
Citibank, N.A., as Collateral Trustee, dated as of July 31, 2002.

Exhibit 10.10--Form of Guaranty dated as of July 31, 2002 by each
of the entities named on the signature pages hereto in favor of
Citibank, N.A., as surety administrative agent for the Financial
Institutions.

Exhibit 10.11--Form of Subordinated Guaranty dated as of July 31,
2002 by Williams Production Holdings LLC in favor of the
Financial Institutions.

Exhibit 10.12--Consent and Fourth Amendment to the Credit
Agreement dated as of July 31, 2002 among the Borrowers party to
the Credit Agreement, the Banks from time to time party to the
Credit Agreement, the Co-Syndication Agents as named therein, the
Documentation Agent as named therein and Citibank, N.A., as agent
for the Banks.

Exhibit 10.13--U.S. $400,000,000 Credit Agreement dated as of
July 31, 2002 among The Williams Companies, Inc., as Borrower,
Citicorp USA, Inc., as Agent and Collateral Agent, Bank of
America N.A., as Syndication Agent, Citibank, N.A. and Bank of
America N.A., as Issuing Banks, the Banks named herein, as Banks,
and Salomon Smith Barney Inc., as Arranger.

Exhibit 12--Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividend Requirements

Exhibit 99.1--Certification pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 by Steven J. Malcolm, Chief Executive Officer of The
Williams Companies, Inc.

Exhibit 99.2--Certification pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 by Jack D. McCarthy, Chief Financial Officer of The Williams
Companies, Inc.

(b) During second-quarter 2002, the Company filed a Form 8-K on April
1, 2002; April 15, 2002; April 25, 2002; April 26, 2002; May 3,
2002; May 22, 2002 (filed two Form 8-K's this date); May 28, 2002
(filed two Form 8-K's this date); June 6, 2002; June 12, 2002;
June 24, 2002 (filed two Form 8-K's this date); and June 28,
2002, which reported significant events under Item 5 of the Form
and included the Exhibits required by Item 7 of the Form.

53

SIGNATURE

Pursuant to the requirements 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)

/s/ Gary R. Belitz
-----------------------------
Gary R. Belitz
Controller
(Duly Authorized Officer and
Principal Accounting Officer)

August 14, 2002

INDEX TO EXHIBITS