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, 2003
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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
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Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). 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, 2003
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Common Stock, $1 par value 517,954,889 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," "could,"
"continues," "estimates," "forecasts," "might," "potential," "projects" 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 2002 Form
10-K.

1

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

*Certain amounts have been 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 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 $2.6
million, $85.6 million, $71.3 million and $60.7 million at June 30, 2003,
December 31, 2002, June 30, 2002 and December 31, 2001, respectively.

See accompanying notes.

4

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

1. General
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Company outlook

As discussed in The Williams Companies, Inc.'s (Williams or the Company)
Form 10-K for the year ended December 31, 2002, events in 2002 and the last half
of 2001 significantly impacted the Company's operations, both past and future.
On February 20, 2003, Williams outlined its planned business strategy for the
next several years which management believes to be a comprehensive response to
the events which have impacted the energy sector and Williams during 2002. The
plan focuses on retaining a strong, but smaller, portfolio of natural gas
businesses and bolstering Williams' liquidity through additional asset sales,
strategic levels of financing at the Williams and subsidiary levels and
additional reductions in its operating costs. The plan is designed to provide
Williams with a clear strategy to address near-term and medium-term liquidity
issues and further de-leverage the company with the objective of returning to
investment grade status, while retaining businesses with favorable returns and
opportunities for growth in the future. As part of this plan, Williams expects
to generate proceeds, net of related debt, of nearly $4 billion from asset sales
during 2003 and 2004. During the first half of 2003, Williams received $2.4
billion in net proceeds from the sales of assets and businesses, including the
retail travel centers, the Midsouth refinery, Texas Gas Transmission
Corporation, Williams' general partnership interest and limited partner
investment in Williams Energy Partners, Williams' interest in Williams
Bio-Energy L.L.C., certain natural gas exploration and production properties in
Kansas, Colorado and New Mexico and Williams' interest in the Rio Grande
Pipeline. As previously announced, the Company intends to reduce its commitment
to the Energy Marketing & Trading business, which may be realized by entering
into a joint venture with a third party or through the sale of a portion or all
of the marketing and trading portfolio. Additionally, through the six month
period ended June 30, 2003, Energy Marketing & Trading has sold contracts for
proceeds totaling approximately $206 million.

During second-quarter 2003, Williams issued $300 million of 5.5 percent
junior subordinated convertible debentures due 2033 and $800 million of 8.625
percent notes due 2010, and a Williams subsidiary received proceeds from a $500
million term loan due 2007. Portions of the proceeds from these debt issues,
borrowings and asset sales were used to redeem $275 million of preferred stock,
the RMT note payable (including deferred fees and interest) (see Note 10) and
$888 million of other long-term debt that matured or required payments from the
proceeds of asset sales.

As of June 30, 2003, the Company has maturing notes payable and long-term
debt through first-quarter 2004 totaling approximately $1.8 billion, consisting
largely of $1.4 billion of Williams senior unsecured 9.25 percent notes. The
Company anticipates that cash on hand, proceeds from additional asset sales and
cash flows from retained businesses will enable the Company to meet its
liquidity needs.

Other

The accompanying interim consolidated financial statements of 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' Annual Report on Form 10-K. The accompanying unaudited financial
statements include all normal recurring adjustments and others, including asset
impairments, loss accruals, and the change in accounting principles which, in
the opinion of Williams' management, are necessary to present fairly its
financial position at June 30, 2003, its results of operations for the three and
six months ended June 30, 2003 and 2002 and cash flows for the six months ended
June 30, 2003 and 2002.

During the second quarter of 2003 Energy Marketing & Trading corrected the
accounting treatment previously given to certain third party derivative
contracts during 2002 and 2001. As a result, Energy Marketing & Trading
recognized $80.7 million of revenue for the second quarter 2003 attributable to
prior periods. Approximately $46.6 million of this revenue relates to a
correction of net energy trading assets for certain derivative contract
terminations occurring in 2001. The remaining $34.1 million relates to net
gains on certain other derivative contracts entered into in 2002 and 2001 which
the Company now believes that it should not have deferred as a component of
other comprehensive income due to the incorrect designation of these contracts
as cash flow hedges. Management, after consultation with its independent
auditor, concluded that the effect of the previous accounting treatment was not
material to prior periods, expected 2003 results and trend of earnings.

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.

5

Notes (Continued)

2. Basis of presentation
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In accordance with the provisions related to discontinued operations within
Statement of Financial Accounting Standard (SFAS) No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," the accompanying consolidated
financial statements and notes reflect the results of operations, financial
position and cash flows of the following components as discontinued operations
(see Note 6):

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

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

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

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

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

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

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

o Texas Gas Transmission Corporation, previously one of Gas Pipeline's
segments

o Williams' general partnership interest and limited partner investment
in Williams Energy Partners, previously the Williams Energy Partners
segment

o Refining, retail and pipeline operations in Alaska, part of the
previously reported Petroleum Services segment

o Gulf Liquids New River Project LLC, previously part of the Midstream
Gas & Liquids segment

o Natural gas properties in the Hugoton and Raton basins, previously
part of the Exploration & Production segment.

Unless indicated otherwise, the information in the Notes to the
Consolidated Financial Statements relates to the continuing operations of
Williams. Williams expects that other components of its business may be
classified as discontinued operations in the future as those operations are sold
or classified as held-for-sale.

Certain other statement of operations, balance sheet and cash flow amounts
have been reclassified to conform to the current classifications.

3. Changes in accounting policies and cumulative effect of change in accounting
principles
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Energy commodity risk management and trading activities and revenues

Effective January 1, 2003, Williams adopted Emerging Issues Task Force
(EITF) Issue No. 02-3, "Issues Related to Accounting for Contracts Involved in
Energy Trading and Risk Management Activities." The Issue rescinded EITF Issue
No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities." Issue No. 02-3 precludes fair value accounting for
energy trading contracts that are not derivatives pursuant to SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," and for
commodity trading inventories. As a result of initial application of this Issue
in first-quarter 2003, Williams reduced energy risk management and trading
assets (including inventories) by $2,159.2 million, energy risk management and
trading liabilities by $925.3 million and net income by $762.5 million (net of a
$471.4 million benefit for income taxes). Of this amount, approximately $755
million relates to Energy Marketing & Trading's portion with the remainder
relating to Midstream Gas & Liquids. The reduction of net income is reported as
a cumulative effect of a change in accounting principle. The change resulted
primarily from power tolling, load serving, transportation and storage contracts
not meeting the definition of a derivative and no longer being reported at fair
value.

The power tolling, load serving, transportation and storage contracts are
now accounted for on an accrual basis. Under this model, revenues for sales of
products are recognized in the period of delivery. Revenues and costs associated
with these non-derivative energy contracts, other non-derivative activities and
physically settled derivative contracts are reflected gross in revenues and
costs and operating expenses in the Consolidated Statement of Operations
beginning January 1, 2003. This change significantly impacts the presentation of
revenues and costs and operating expenses. Physical commodity inventories
previously reflected at fair value are now stated at average cost, not in excess
of market. Derivative energy contracts are reflected at fair value, and gains
and losses due to changes in fair value of derivatives not designated as hedges
under SFAS No. 133 are reflected net in revenues. Derivative energy contracts
are classified in the Consolidated Balance Sheet as current and noncurrent
assets and current and noncurrent liabilities based on the timing of expected
future cash flows used in determining fair value of individual contracts. In
addition, derivative assets and liabilities on the Consolidated Balance Sheet
include a net asset representing the fair value of certain derivative contracts
at the time that Energy Marketing & Trading elected the normal purchases and
sales exclusion in accordance with SFAS No. 133. The approximately $500 million
fair value of these contracts at the time the election was made will be realized
into earnings over the remaining periods of the contracts' term in accordance
with the estimated cash flows of the contracts at the time of election. As of
June 30, 2003, the remaining terms of contracts for which the normal purchases
and sales exclusion has been elected ranges from approximately 4 to 8 years.

6

Notes (Continued)

Asset retirement obligations

Effective January 1, 2003, Williams adopted SFAS No. 143, "Accounting for
Asset Retirement Obligations." This Statement requires that the fair value of a
liability for an asset retirement obligation be recognized in the period in
which it is incurred if a reasonable estimate of fair value can be made, and
that the associated asset retirement costs be capitalized as part of the
carrying amount of the long-lived asset. The Statement also amends SFAS No. 19,
"Financial Accounting and Reporting by Oil and Gas Producing Companies." As
required by the new standard, Williams recorded liabilities equal to the present
value of expected future asset retirement obligations at January 1, 2003. The
obligations relate to producing wells, offshore platforms, underground storage
caverns and gas gathering well connections. At the end of the useful life of
each respective asset, Williams is legally obligated to plug both producing
wells and storage caverns and remove any related surface equipment, to dismantle
offshore platforms, and to cap certain gathering pipelines at the wellhead
connection and remove any related surface equipment. The liabilities are
partially offset by increases in property, plant and equipment, net of
accumulated depreciation, recorded as if the provisions of the Statement had
been in effect at the date the obligation was incurred. As a result of the
adoption of SFAS No. 143, Williams recorded a long-term liability of $33.4
million; property, plant and equipment, net of accumulated depreciation, of
$24.8 million and a credit to earnings of $1.2 million (net of a $.1 million
benefit for income taxes) reflected as a cumulative effect of a change in
accounting principle. Williams also recorded a $9.7 million regulatory asset for
retirement costs of dismantling offshore platforms expected to be recovered
through regulated rates. In connection with adoption of SFAS No. 143, Williams
changed its method of accounting to include salvage value of equipment related
to producing wells in the calculation of depreciation. The impact of this change
is included in the amounts discussed above. Williams has not recorded
liabilities for pipeline transmission assets, processing and refining assets,
and gas gathering systems pipelines. A reasonable estimate of the fair value of
the retirement obligations for these assets cannot be made as the remaining life
of these assets is not currently determinable. Had the Statement been adopted at
the beginning of 2002, the impact to Williams' income from continuing operations
and net income would have been immaterial. There would have been no impact on
earnings per share.

7

Notes (Continued)

4. Asset sales, impairments and other items
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Williams evaluates its equity investments for impairment when events or
changes in circumstances indicate, in management's judgment, that the carrying
value of such assets may have experienced an other-than-temporary decline in
value. When evidence of loss in value has occurred, management's estimate of
fair value of the investment is compared to the carrying value of the investment
to determine whether an impairment has occurred. If the estimated fair value is
less than the carrying cost and the decline in value is considered other than
temporary, the excess of the carrying cost over the fair value is recognized in
the financial statements as an impairment.

Judgments and assumptions are inherent in management's assessment of
whether there has been any evidence of a loss in value that warrants an
estimation of fair value. Judgments and assumptions are also inherent in
management's estimate of an investment's fair value used to determine whether a
loss in value has occurred and to measure the amount of impairment to recognize.
In addition, judgements and assumptions are involved in determining if the
decline in value is other than temporary. The use of alternate judgments and/or
assumptions could result in the recognition of different levels of impairment
charges in the financial statements.

Significant gains or losses from asset sales, impairments and other items
included in other (income) expense - net within segment costs and expenses and
investing income (loss) are included in the following table.

8

Notes (Continued)

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

The effective income tax rate for the three and six months ended June 30,
2003, is greater than the federal statutory rate due primarily to the financial
impairment of certain investments, capital losses generated for which valuation
allowances were established and nondeductible expenses.

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 benefit
of the pretax loss.

6. Discontinued operations
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During 2002, Williams began the process of selling assets and/or businesses
to address liquidity issues. The businesses discussed below represent components
of Williams that have been sold or approved for sale by the board of directors
as of June 30, 2003; therefore, their results of operations (including any
impairments, gains or losses), financial position and cash flows have been
reflected in the consolidated financial statements and notes as discontinued
operations.

Summarized results of discontinued operations for the three and six months
ended June 30, 2003 and 2002 are as follows:

9

Notes (Continued)

Summarized assets and liabilities of discontinued operations as of June 30,
2003 and December 31, 2002, are as follows:

HELD FOR SALE AT JUNE 30, 2003

Soda ash operations

In March 2002, Williams announced its intention to sell its soda ash mining
facility located in Colorado. During third-quarter 2002, Williams' board of
directors approved a plan authorizing management to negotiate and facilitate a
sale of its interest in the soda ash operations pursuant to terms of a proposed
sales agreement. The soda ash facility was previously written-down to its
estimated fair value less cost to sell at December 31, 2002. This estimate was
reflective of terms of the negotiations to sell the operations. During 2003,
ongoing sale negotiations continue to provide new information regarding
estimated fair value. As a result, additional impairment charges of $5 million
and $11.1 million were recognized during the first and second quarters of 2003,
respectively. These impairments and a $44.1 million second-quarter 2002
impairment are included in (impairments) and gain (loss) on sales in the
preceding table. Williams believes that these ongoing negotiations provide
sufficient evidence that it remains committed to its plan to sell the soda ash
operations within one year. Therefore, soda ash operations continue to be
presented as held for sale. The soda ash operations were part of the previously
reported International segment.

Alaska refining, retail and pipeline operations

The company is currently engaged in negotiations to sell its Alaska
refinery and related assets. During first-quarter 2003, management revised its
assessment of the estimated fair value of these assets, reflective of recent
information obtained through continuing sales negotiations, using a
probability-weighted approach. As a result, an impairment charge of $8 million
was recognized in first-quarter 2003 and is included in (impairments) and gain

10

Notes (Continued)

(loss) on sales in the preceding table. During second-quarter 2003, Williams'
board of directors approved a plan authorizing management to negotiate and
facilitate a sale of these operations. A sale is expected to be completed within
one year. These operations were part of the previously reported Petroleum
Services segment.

Gulf Liquids New River Project LLC

Williams' Gulf Liquids operations have been identified as assets not
related to the new, more narrowly focused business. During second-quarter 2003,
Williams' board of directors approved a plan authorizing management to negotiate
and facilitate a sale of these assets. An impairment charge of $92.6 million was
recognized during second-quarter 2003 to reduce the carrying cost of the
long-lived assets to management's estimate of fair value less estimated costs to
sell the assets, and is included in (impairments) and gain (loss) on sales in
the preceding table. Fair value was estimated based on a discounted cash flow
analysis. The sale of these operations is expected to be completed within one
year. These operations were part of the Midstream Gas & Liquids segment.

2003 COMPLETED TRANSACTIONS

Williams Energy Partners

On June 17, 2003, Williams completed the sale of its 100 percent general
partnership interest and 54.6 percent limited partner investment in Williams
Energy Partners for approximately $512 million in cash and assumption by the
purchasers of $570 million in debt. Williams recognized a gain of $275.6 million
on the sale, which is included in (impairments) and gain (loss) on sales in the
preceding table, and deferred an additional $113 million associated with
Williams' indemnifications of the purchasers under the sales agreement. Williams
has indemnified the purchasers for a variety of matters, including obligations
that may arise associated with environmental contamination relating to
operations prior to April 2002 and identified prior to April 2008 (see Note 11).

Bio-energy facilities

On May 30, 2003, Williams completed the sale of its bio-energy operations
to Morgan Stanley Capital Partners for approximately $59 million in cash. The
December 31, 2002 carrying value reflected the estimated fair value less cost to
sell. During second-quarter 2003, Williams recognized an additional loss on the
sale of $6.4 million which is included in (impairments) and gain (loss) on sales
in the preceding table. These operations were part of the previously reported
Petroleum Services segment.

Texas Gas

On May 16, 2003, Williams completed the sale of its Texas Gas Transmission
Corporation for $795 million in cash and the assumption by the purchaser of $250
million in existing Texas Gas debt. This business was evaluated for
recoverability on a held-for-use basis pursuant to SFAS No. 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets," at March 31, 2003. A $109
million impairment charge was recorded in first-quarter 2003 reflecting the
excess of the carrying cost of the long-lived assets over management's estimate
of fair value, and is included in (impairments) and gain (loss) on sales in the
preceding table. Fair value was based on management's assessment of the expected
sales price pursuant to the purchase and sale agreement. No significant gain or
loss was recognized on the sale. Texas Gas was a segment within Gas Pipeline.

Natural gas properties

During second-quarter 2003, Williams completed the sale of natural gas
exploration and production properties in the Raton Basin in southern Colorado
and the Hugoton Embayment of the Anadarko Basin in southwestern Kansas. This
sale included all of Williams' interests within these basins. A $39.9 million
gain on the sale was recognized in the second quarter of 2003 and is included in
(impairments) and gain (loss) on sale in the preceding table. These properties
were part of the Exploration & Production segment.

11

Notes (Continued)

Midsouth refinery and related assets

On March 4, 2003, Williams completed the sale of its refinery and other
related operations located in Memphis, Tennessee to Premcor, Inc. for
approximately $455 million in cash. These assets were previously written down by
$240.8 million to their estimated fair value less cost to sell at December 31,
2002. A gain on sale of $4.7 million was recognized in the first quarter of
2003. During the second quarter of 2003, Williams recognized a $24.7 million
gain on the sale of an earn-out agreement retained by Williams in the sale of
the refinery. This agreement would have allowed Williams to potentially receive
up to an additional $75 million over the next seven years depending on refining
margins. These gains are included in (impairments) and gain (loss) on sale in
the preceding table. These operations were part of the previously reported
Petroleum Services segment.

Williams travel centers

On February 27, 2003, Williams completed the sale of the travel centers to
Pilot Travel Centers LLC for approximately $189 million in cash. The December
31, 2002 carrying value reflected the estimated fair value less cost to sell. A
second-quarter 2002 impairment of $27 million is reflected in (impairments) and
gain (loss) on sale in the preceding table. No significant gain or loss was
recognized on the sale. These operations were part of the previously reported
Petroleum Services segment.

2002 COMPLETED TRANSACTIONS

Kern River

On March 27, 2002, Williams completed the sale of its Kern River pipeline
for $450 million in cash and the assumption by the purchaser of $510 million in
debt. As part of the agreement, $32.5 million of the purchase price was
contingent upon Kern River receiving a certificate from the FERC to construct
and operate a future expansion. This certificate was received in July 2002, and
the contingent payment plus interest was recognized as income from discontinued
operations in third-quarter 2002. Included as a component of (impairments) and
gain (loss) on sales in the preceding table is a pre-tax loss of $38.1 million
for the six months ended June 30, 2002. Kern River was a segment within Gas
Pipeline.

Mid-America and Seminole Pipelines

On August 1, 2002, Williams completed the sale of its 98 percent interest
in Mid-America Pipeline and 98 percent of its 80 percent ownership interest in
Seminole Pipeline for $1.2 billion. The sale generated net cash proceeds of
$1.15 billion. These assets were part of the Midstream Gas & Liquids segment.

Central

On November 15, 2002, Williams completed the sale of its Central natural
gas pipeline for $380 million in cash and the assumption by the purchaser of
$175 million in debt. Central was a segment within Gas Pipeline.

12

Notes (Continued)

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

For the three and six months ended June 30, 2003, approximately 11.3 million
and 13 million weighted average shares, 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 as their
inclusion would be antidilutive. The preferred stock was redeemed in June 2003.

For the six months ended June 30, 2003, approximately 5.2 million
weighted-average shares related to the assumed conversion of convertible
debentures, as well as the related interest, were excluded from the computation
of diluted earnings per common share as their inclusion would be antidilutive.

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.

13

Notes (Continued)

8. Stock-based compensation
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Employee stock-based awards are accounted for under Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
(APB 25) and related interpretations. Fixed-plan common stock options
generally do not result in compensation expense because the exercise price
of the stock options equals the market price of the underlying stock on the
date of grant. The following table illustrates the effect on net income and
earnings per share if the company had applied the fair value recognition
provisions of SFAS No. 123 "Accounting for Stock-Based Compensation."

Pro forma amounts for 2003 include compensation expense from Williams
awards made in 2003, 2002 and 2001. Pro forma amounts for 2002 include
compensation expense from certain Williams awards made in 1999 and compensation
expense from Williams awards made in 2002 and 2001.

Since compensation expense for stock options is recognized over the future
years' vesting period for pro forma disclosure purposes and additional awards
are generally made each year, pro forma amounts may not be representative of
future years' amounts.

On May 15, 2003, Williams' shareholders approved a stock option exchange
program. Under this exchange program, eligible Williams employees were given a
one-time opportunity to exchange certain outstanding options for a
proportionately lesser number of options at an exercise price to be determined
at the grant date of the new options. Surrendered options were cancelled June
26, 2003, and replacement options will be granted no earlier than six months and
one day after the cancellation date of each surrendered option. Under APB 25,
Williams will not recognize any expense pursuant to the stock option exchange.
However, for purposes of pro forma disclosures, Williams will recognize
additional expense related to these new options and the remaining expense on the
cancelled options.

14

Notes (Continued)

9. Inventories
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Inventories at June 30, 2003 and December 31, 2002 are as follows:

Effective January 1, 2003, Williams adopted EITF Issue No. 02-3 (see Note
3). As a result, Williams reduced the recorded value of natural gas in
underground storage by $37 million, refined products by $2.9 million and natural
gas liquids by $1 million.

15

Notes (Continued)

10. Debt and banking arrangements
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NOTES PAYABLE AND LONG-TERM DEBT

Notes payable and long-term debt at June 30, 2003 and December 31, 2002,
are as follows:

(1) At June 30, 2003.

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

Notes payable at December 31, 2002, included a $921.8 million secured note
(the RMT note payable) of Williams Production RMT Company (RMT), which was
repaid in May 2003 with proceeds from asset sales and proceeds from a $500
million new long-term debt obligation (described below under "Issuances and
Retirements").

Williams ensures that the interest rates received by foreign lenders under
various loan agreements are not reduced by taxes by providing for the
reimbursement of any domestic taxes required to be paid by the foreign lender.
The maximum potential amount of future payments under these indemnifications is
based on the related borrowings; they generally continue indefinitely unless
limited by the underlying tax regulations; and they have no carrying value.
Williams has never been called upon to perform under these indemnifications.

REVOLVING CREDIT AND LETTER OF CREDIT FACILITIES

On June 6, 2003, Williams entered into a two-year $800 million
revolving credit facility, primarily for the purpose of issuing letters of
credit. Williams, Northwest Pipeline and Transco have access to all unborrowed
amounts. The facility must be secured by cash and/or acceptable government
securities with a market value of at least 105 percent of the then outstanding
aggregate amount available for drawing under all letters of credit, plus the
aggregate amount of all loans then outstanding. The restricted cash and
investments used as collateral are classified on the balance sheet as current or
non-current based on the expected termination date of the underlying debt or
letters of credit. The new credit facility replaces a $1.1 billion credit line
entered into in July 2002 that was comprised of a

16

Notes (Continued)

$700 million secured revolving credit facility and a $400 million secured letter
of credit facility. The previous agreements were secured by substantially all of
the company's Midstream Gas & Liquids assets. The new agreement releases these
assets as collateral. The interest rate on the new agreement is variable at the
London InterBank Offered Rate (LIBOR) plus .75 percent. At June 30, 2003,
letters of credit totaling $387 million have been issued by the participating
financial institutions under this facility and no revolving credit loans were
outstanding. At June 30, 2003, the amount of restricted investments securing
this facility was $461.1 million, which collateralized the facility at 119.25
percent.

ISSUANCES AND RETIREMENTS

On May 28, 2003, Williams issued $300 million of 5.5 percent junior
subordinated convertible debentures due 2033. These notes, which are callable by
the Company after seven years, are convertible at the option of the holder into
Williams common stock at a conversion price of approximately $10.89 per share.
The proceeds were used to redeem all of the outstanding 9 7/8 percent
cumulative-convertible preferred shares (see Note 12).

On May 30, 2003, Williams entered into a $500 million secured,
subsidiary-level note due May 30, 2007, at a floating interest rate of six-month
LIBOR plus 3.75 percent (totaling 4.9 percent at June 30, 2003). This loan
refinances a portion of the RMT note discussed above. Williams' Exploration &
Production interests in the U.S. Rocky Mountains had secured the RMT note
payable and will now serve as security on the new loan. Significant covenants on
the borrowers, RMT and Williams Production Holdings LLC (Holdings) (parent of
RMT), include: (i) an interest coverage ratio computed on a consolidated RMT
basis of greater than 3 to 1, (ii) a ratio of the present value of future cash
flows of proved reserves, discounted at ten percent, based on the most recent
engineering report to total senior secured debt, computed on a consolidated RMT
basis, of greater than 1.75 to 1, (iii) a limitation on restricted payments and
(iv) a limitation on intercompany indebtedness.

On June 10, 2003, Williams issued $800 million of 8.625 percent senior
unsecured notes due 2010. The notes were issued under the company's $3 billion
shelf registration statement. Significant covenants include: i) limitation on
certain payments, including a limitation on the payment of quarterly dividends
to no greater than $.02 per common share, ii) limitation on additional
indebtedness and issuance of preferred stock unless the Fixed Charge Coverage
Ratio for the Company's most recently ended four full fiscal quarters is at
least 2.0 to 1, determined on a proforma basis; iii) limitation on asset sales,
unless the consideration is at least equal to fair market value and at least 75
percent of the consideration received is in the form of cash or cash
equivalents; iv) a limitation on the use of proceeds from permitted asset sales;
and v) a limitation on transactions with affiliates. These restrictions may be
lifted if certain conditions, including Williams attaining an investment grade
rating from both Moody's Investor's Services and Standard & Poor's, are met.

A summary of significant long-term debt, including capital leases,
issuances and retirements, as well as the items listed above, for the six months
ended June 30, 2003, are as follows:

17

Notes (Continued)

11. 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 $11
million for potential refund as of June 30, 2003.

Williams Energy Marketing & Trading Company (Energy Marketing & Trading)
subsidiaries are engaged in power marketing in various geographic areas,
including California. Prices charged for power by Williams and other traders and
generators in California and other western states have been challenged in
various proceedings including those before the FERC. In December 2002, the FERC
issued an order which provided that, for the period between October 2, 2000 and
December 31, 2002, the FERC may order refunds from Williams and other similarly
situated companies if the FERC finds that the wholesale markets in California
were unable to produce competitive, just and reasonable prices or that market
power or other individual seller conduct was exercised to produce an unjust and
unreasonable rate. The judge issued his findings in the refund case on December
12, 2002. Under these findings, Williams' refund obligation to the California
Independent System Operator (ISO) is $192 million, excluding emissions costs and
interest. The judge found that Williams' refund obligation to the California
Power Exchange (PX) is $21.5 million, excluding interest. However, the judge
found that the ISO owes Williams $246.8 million, excluding interest, and that
the PX owes Williams $31.7 million, excluding interest, and $2.9 million in
charge backs. The judge's findings do not include the $18 million in emissions
costs that the judge found Williams is entitled to use as an offset to the
refund liability, and the judge's refund amounts are not based on final
mitigated market clearing prices. On March 26, 2003, the FERC acted to largely
adopt the judge's order with a change to the gas methodology used to set the
clearing price. As a result, Energy Marketing & Trading recorded, in the first
quarter of 2003, a charge for refund obligations of $37 million and recorded
interest income related to amounts due from the counterparties of $33 million.
Pursuant to an order from the 9th Circuit, FERC permitted the California parties
to conduct additional discovery into market manipulation by sellers in the
California markets. The California parties sought this discovery in order to
potentially expand the scope of the refunds. On March 3, 2003, the California
parties submitted evidence from this discovery on market manipulation. Williams
and other sellers submitted comments to the additional evidence on March 20,
2003. The FERC is considering this evidence and is expected to issue further
guidance later this year.

In an order issued June 19, 2001, the FERC implemented a revised price
mitigation and market monitoring plan for wholesale power sales by all suppliers
of electricity, including Williams, in spot markets for a region that includes
California and ten other western states (the "Western Systems Coordinating
Council," or "WSCC"). In general, the plan, which was in effect from June 20,
2001 through September 30, 2002, established a market clearing price for spot
sales in all hours of the day that was based on the bid of the highest-cost
gas-fired California generating unit that was needed to serve the ISO's load.
When generation operating reserves fell below seven percent in California (a
"reserve deficiency period"), absent cost-based justification for a higher
price, the maximum price that Williams could charge for wholesale spot sales in
the WSCC was the market clearing price. When generation operating reserves rose
to seven percent or above in California, absent cost-based justification for a
higher price, Williams' maximum price was limited to 85 percent of the highest
hourly price that was in effect during the most recent reserve deficiency
period. This methodology initially resulted in a maximum price of $92 per
megawatt hour during non-emergency periods and $108 per megawatt hour during
emergency periods. These maximum prices remained unchanged throughout summer and
fall 2001. Revisions to the plan for the post-September 30, 2002, period were
provided on July 17, 2002, as discussed below.

On December 19, 2001, the FERC reaffirmed its June 19 order with certain
clarifications and modifications. It also altered the price mitigation
methodology for spot market transactions for the WSCC market for the winter 2001
season and set the period maximum price at $108 per megawatt hour through April
30, 2002. Under the order, this price would be subject to being recalculated
when the average gas price rises by a minimum factor of ten percent effective
for the following trading day, but in no event would the maximum price drop
below $108 per megawatt hour. The FERC also upheld a ten percent addition to the
price applicable to sales into California to reflect credit risk. On July 9,
2002, the ISO's operating reserve levels dropped below seven percent for a full
operating hour, during which the ISO declared a Stage 1 System Emergency
resulting in a new Market Clearing Price cap of $57.14/MWh under the FERC's
rules. On July 11, 2002, the FERC issued an order that the existing price
mitigation formula be replaced with a hard price cap of $91.87/MWh for spot
markets operated in the West (which is the level of price mitigation that
existed prior to the July 9, 2002 events that reduced the cap), to be effective
July 12, 2002. The cap expired September 30, 2002, but the cap was later
extended by FERC to October 30, 2002.

18

Notes (Continued)

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) a requirement that the ISO
expedite the following market design elements and requiring them to be filed by
October 21, 2002: (a) creation of an integrated day-ahead market; (b) ancillary
services market reforms; and (c) hour-ahead and real-time market reforms; and
(5) the development of locational marginal pricing (LMP). The FERC reaffirmed
these elements in an order issued October 9, 2002, with the following
clarification: (a) generators may bid above the ISO cap, but their bids cannot
set the market clearing price and they will be subject to justification and
refund, (b) if the market clearing price is projected to be above $91.87 per MWh
in any zone, automatic mitigation will be triggered in all zones, (c) the 10
percent creditworthiness adder will be removed effective October 31, 2002. On
January 17, 2003, FERC clarified that bids below $91.87 per MWh are not entitled
to a safe harbor from mitigation, and where a seller is subject to the
must-offer obligation but fails to submit a bid, the ISO may impose a proxy bid.
On October 31, 2002, FERC found that the ISO has not explained how it will treat
generators that are running at minimum load and dispatched for instructed
energy. On December 2, 2002, the ISO proposed to pay for energy at minimum load
the uninstructed energy price even when a unit is dispatched for instructed
energy. Williams protested on January 2, 2003, arguing that the ISO's proposal
fails to keep sellers whole.

In a separate but related proceeding, 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.

The California Public Utilities Commission (CPUC) filed a complaint with
the FERC on February 25, 2002, seeking to void or, alternatively, reform a
number of the long-term power purchase contracts entered into between the State
of California and several suppliers in 2001, including Energy Marketing &
Trading. The CPUC alleges that the contracts are tainted with the exercise of
market power and significantly exceed "just and reasonable" prices. The
California Electricity Oversight Board (CEOB) made a similar filing on February
27, 2002. The FERC set the complaint for hearing on April 25, 2002, but held the
hearing in abeyance pending settlement discussions before a FERC judge. The FERC
also ordered that the higher public interest test will apply to the contracts.
The FERC commented that the state has a very heavy burden to carry in proving
its case. On July 17, 2002, the FERC denied rehearing of the April 25, 2002,
order that set for hearing California's challenges to the long-term contracts
entered into between the state and several suppliers, including Energy Marketing
& Trading. The settlement discussions noted above resulted in Williams entering
into a settlement agreement with the State of California and other non-Federal
parties that includes renegotiated long-term energy contracts. These contracts
are made up of block energy sales, dispatchable products and a gas contract. The
original contract contained only block energy sales. The settlement does not
extend to criminal matters or matters of willful fraud, but will resolve civil
complaints brought by the California Attorney General against Williams that are
discussed below and the State of California's refund claims that are discussed
above. In addition, the settlement is intended to resolve ongoing investigations
by the States of California, Oregon and Washington. The settlement was reduced
to writing and executed on November 11, 2002. The settlement closed on December
31, 2002, after FERC issued an order granting Williams' motion for partial
dismissal from the refund proceedings. The dismissal affects Williams' refund
obligations to the settling parties, but not to other parties, such as
investor-owned utilities. Pursuant to the settlement, the CPUC and CEOB filed a
motion on January 13, 2003 to withdraw their complaints against Williams
regarding the original block energy sales contract. On June 26, 2003, the FERC
granted the CPUC and CEOB joint motion to withdraw their respective complaints
against Williams. Private class action and other civil plaintiffs also executed
the settlement. Various court filings and approvals are necessary to make the
settlement effective as to plaintiffs and to terminate the class actions as to
Williams. As of June 30, 2003, pursuant to the terms of the settlement, Williams
has transferred ownership of six LM6000 gas powered electric turbines, has made
one payment of $42 million to the California Attorney General, and has funded a
$15 million fee and expense fund associated with civil actions that are subject
to the settlement. An additional $105 million remains to be paid to the
California Attorney General (or his designee) over the next seven years, with
the final payment of $15 million due on January 1, 2010.

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

19

Notes (Continued)

outcome of settlement judge proceedings. The FERC set a refund effective date of
July 1, 2002. The hearing was conducted December 13 through December 20, 2002,
at FERC. The judge issued an initial decision on February 27, 2003 dismissing
the complaints. This decision was appealed to the FERC and FERC affirmed the
Administrative Law Judge (ALJ).

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

On December 11, 2002, the FERC staff informed Transcontinental Gas Pipe
Line Corporation (Transco) of a number of issues the FERC staff identified
during the course of a formal, nonpublic investigation into the relationship
between Transco and its marketing affiliate, Energy Marketing & Trading. The
FERC staff asserted that Energy Marketing & Trading personnel had access to
Transco data bases and other information, and that Transco had failed to
accurately post certain information on its electronic bulletin board. Williams,
Transco and Energy Marketing & Trading did not agree with all of the FERC
staff's allegations and furthermore believe that Energy Marketing & Trading did
not profit from the alleged activities. Nevertheless, in order to avoid
protracted litigation, on March 13, 2003, Williams, Transco and Energy Marketing
& Trading executed a settlement of this matter with the FERC staff. An Order
approving the settlement was issued by the FERC on March 17, 2003. No requests
for rehearing of the March 17, 2003 order were filed; therefore, the order
became final on April 16, 2003. Pursuant to the terms of the settlement
agreement, Transco will pay a civil penalty in the amount of $20 million,
beginning with a payment of $4 million within thirty (30) days of the date the
FERC Order approving the settlement becomes final. The first payment was made on
May 16, 2003, and the subsequent $4 million payments are due on or before the
first, second, third and fourth anniversaries of the first payment. Transco
recorded a charge to income and established a liability of $17 million in 2002
on a discounted basis to reflect the future payments to be made over the next
four years. In addition, Transco has provided notice to its merchant sales
service customers that it will be terminating such services when it is able to
do so under the terms of any applicable contracts and FERC certificates
authorizing such services. Most of these sales are made through a Firm Sales
(FS) program, and under this program Transco must provide two-year advance
notice of termination. Therefore, Transco notified the FS customers of its
intention to terminate the FS service effective April 1, 2005. As part of the
settlement, Energy Marketing & Trading has agreed, subject to certain
exceptions, that it will not enter into new transportation agreements that would
increase the transportation capacity it holds on certain affiliated interstate
gas pipelines, including Transco. Finally, Transco and certain affiliates have
agreed to the terms of a compliance plan designed to ensure future compliance
with the provisions of the settlement agreement and the FERC's rules governing
the relationship of Transco and Energy Marketing & Trading.

On August 1, 2002, the FERC issued a Notice of Proposed Rulemaking (NOPR)
that proposed restrictions on various types of cash management programs employed
by companies in the energy industry, such as 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 have precluded 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 maintains stockholders equity of at least 30 percent of
total capitalization. Williams' and its regulated gas pipelines' current credit
ratings are not investment grade. Williams participated in comments in this
proceeding on August 28, 2002, by the Interstate Natural Gas Association of
America. On September 25, 2002, the FERC convened a technical conference to
discuss the issues raised in the comments filed by parties in this proceeding.
On June 26, 2003, the FERC issued an Interim Rule (Order No. 634), which
requires FERC-regulated entities to have their cash management programs in
writing and to have all such programs specify (i) the duties and
responsibilities of administrators and participants, (ii) the methods for
calculating interest and for allocating interest and expenses, and (iii)
restrictions on borrowing from the programs. The Interim Rule was effective on
August 7, 2003. The Interim Rule also seeks industry comment on new reporting
requirements that would require FERC-regulated entities to file their cash
management programs with the FERC and to notify the FERC when their proprietary
capital ratio drops below 30 percent of total capitalization and when it
subsequently returns to or exceeds 30 percent. This Interim Rule replaces the
earlier NOPR on cash management described above.

20

Notes (Continued)

On February 13, 2002, the FERC issued an Order Directing Staff
Investigation commencing a proceeding titled Fact-Finding Investigation of
Potential Manipulation of Electric and Natural Gas Prices. Through the
investigation, the FERC intends to determine whether "any entity, including
Enron Corporation (Enron) (through any of its affiliates or subsidiaries),
manipulated short-term prices for electric energy or natural gas in the West or
otherwise exercised undue influence over wholesale electric prices in the West
since January 1, 2000, resulting in potentially unjust and unreasonable rates in
long-term power sales contracts subsequently entered into by sellers in the
West." This investigation does not constitute a Federal Power Act complaint;
rather, the results of the investigation will be used by the FERC in any
existing or subsequent Federal Power Act or Natural Gas Act complaint. The FERC
Staff is directed to complete the investigation as soon as "is practicable."
Williams, through many of its subsidiaries, is a major supplier of natural gas
and power in the West and, as such, anticipates being the subject of certain
aspects of the investigation. Williams is cooperating with all data requests
received in this proceeding. On May 8, 2002, Williams received an additional set
of data requests from the FERC related to a disclosure by Enron of certain
trading practices in which it may have been engaged in the California market. On
May 21, and May 22, 2002, the FERC supplemented the request inquiring as to
"wash" or "round trip" transactions. Williams responded on May 22, 2002, May 31,
2002, and June 5, 2002, to the data requests. On June 4, 2002, the FERC issued
an order to Williams to show cause why its market-based rate authority should
not be revoked as the FERC found that certain of Williams' responses related to
the Enron trading practices constituted a failure to cooperate with the staff's
investigation. Williams subsequently supplemented its responses to address the
show cause order. On July 26, 2002, Williams received a letter from the FERC
informing Williams that it had reviewed all of Williams' supplemental responses
and concluded that Williams responded to the initial May 8, 2002 request.

In response to an article appearing in the New York Times on June 2, 2002,
containing allegations by a former Williams employee that it had attempted to
"corner" the natural gas market in California, and at Williams' invitation, the
FERC is conducting an investigation into these allegations. Also, the Commodity
Futures Trading Commission (CFTC) and the U.S. Department of Justice (DOJ) are
conducting an investigation regarding gas and power trading and have requested
information from Williams in connection with this investigation.

Williams disclosed on October 25, 2002, that certain of its gas traders had
reported inaccurate information to a trade publication that published gas price
indices. On November 8, 2002, Williams received a subpoena from a federal grand
jury in Northern California seeking documents related to Williams' involvement
in California markets, including its reporting to trade publications for both
gas and power transactions. Williams is in the process of completing its
response to the subpoena. The DOJ's investigation into this matter is
continuing. On July 29, 2003, Williams reached a settlement with the CFTC where
in exchange for $20 million, the CFTC closed its investigation and Williams did
not admit or deny allegations that it had engaged in false reporting or
attempted manipulation.

On March 26, 2003, FERC issued an order addressing Enron trading practices,
the allegation of cornering the gas market, and the gas price index issue. The
March 26, 2003 order cleared Williams on the issue of cornering the market and
contemplated or established further proceedings on the other two as to Williams
and numerous other market participants. These proceedings resulted in a show
cause order to Williams and others regarding specific practices alleged by an
ISO report that various companies engaged in.

On May 31, 2002, Williams received a request from the Securities and
Exchange Commission (SEC) to voluntarily produce documents and information
regarding "round-trip" trades for gas or power from January 1, 2000, to the
present in the United States. On June 24, 2002, the SEC made an additional
request for information including a request that Williams address the amount of
Williams' credit, prudency and/or other reserves associated with its energy
trading activities and the methods used to determine or calculate these
reserves. The June 24, 2002, request also requested Williams' volumes, revenues,
and earnings from its energy trading activities in the Western U.S. market.
Williams has responded to the SEC's requests.

On July 3, 2002, the ISO announced fines against several energy producers
including Williams, for failure to deliver electricity in 2001 as required. The
ISO fined Williams $25.5 million, which will be offset against Williams' claims
for payment from the ISO. Williams believes the vast majority of fines are not
justified and has challenged the fines pursuant to the FERC approved process
contained in the ISO tariff.

On December 3, 2002, an administrative law judge at the FERC issued an
initial decision in Transco's general rate case which, among other things,
rejects the recovery of the costs of Transco's Mobile Bay expansion project from
its shippers on a "rolled-in" basis and finds that incremental pricing for the
Mobile Bay expansion project is just and reasonable. The initial decision does
not address the issue of the effective date for the change to incremental
pricing, although Transco's rates reflecting recovery of the Mobile Bay
expansion project costs on a "rolled-in" basis have been in effect since
September 1, 2001. The administrative law judge's initial decision is subject to
review by the FERC. Energy Marketing & Trading holds long-term transportation
capacity on the Mobile Bay expansion project. If the FERC adopts the decision of
the administrative law judge on the pricing of the Mobile Bay expansion project
and also requires that the decision be implemented effective September 1, 2001,
Energy Marketing & Trading could be subject to surcharges of approximately $32
million, excluding interest, through June 30, 2003, in addition to increased
costs going forward.

21

Notes (Continued)

ENVIRONMENTAL MATTERS

Continuing operations

Since 1989, Transco has had studies under way to test certain of its
facilities for the presence of toxic and hazardous substances to determine to
what extent, if any, remediation may be necessary. Transco has responded to data
requests 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, 2003, Transco had accrued liabilities totaling approximately $30
million for these costs.

Transco has identified polychlorinated biphenyl contamination (PCB) in air
compressor systems, soils and related properties at certain compressor station
sites. Transco has 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, Transco commenced negotiations with
certain environmental authorities and other programs concerning investigative
and remedial actions relative to potential mercury contamination at certain gas
metering sites. Transco had accrued liabilities for these costs which are
included in the $30 million liability mentioned above.

Williams and its subsidiaries also accrue environmental remediation costs
for its natural gas gathering and processing facilities primarily related to
soil and groundwater contamination. At June 30, 2003, Williams and its
subsidiaries had accrued liabilities totaling approximately $10 million for
these costs.

Actual costs incurred for these matters 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.

Former operations, including operations classified as discontinued

In connection with the sale of certain assets and businesses, Williams has
retained responsibility through indemnification of the purchasers for
environmental liabilities existing at the time the sale was consummated,
including former fertilizer operations, propane marketing operations, retail
petroleum and refining operations, petroleum products pipelines and related
facilities, exploration and production operations and mining operations.

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, 2003, Williams had approximately $9
million accrued for such excess costs.

At June 30, 2003, Williams had accrued environmental liabilities totaling
approximately $15 million related to its (1) Alaska refining, retail and
pipeline operations currently classified as held for sale, (2) potential
indemnification obligations to purchasers of its former retail petroleum and
refining operations, and (3) former propane marketing operations, petroleum
products and natural gas pipelines, a discontinued petroleum refining facility
and exploration and production and mining operations. These costs include (1)
certain conditions at specified locations related primarily to soil and
groundwater contamination and (2) any penalty assessed on Williams Refining &
Marketing, LLC (Williams Refining) associated with noncompliance with EPA's
benzene waste "NESHAP" regulations. In 2002, Williams Refining submitted to the
EPA a self-disclosure letter indicating noncompliance with those regulations.
This unintentional noncompliance had occurred due to a regulatory interpretation
that resulted in under-counting the total annual benzene level at Williams
Refining's Memphis refinery. Also in 2002, the EPA conducted an all-media audit
of the Memphis refinery. The EPA anticipates releasing a report of its audit
findings in 2003. The EPA will likely assess a penalty on Williams Refining due
to the benzene waste NESHAP issue, but the amount of any such penalty is not
known. In connection with the sale of the Memphis refinery in March 2003,
Williams indemnified the purchaser for any such penalty.

As part of its June 17, 2003 sale of Williams Energy Partners (see Note 6),
Williams indemnified the purchaser for (1) environmental cleanup costs resulting
from certain conditions, primarily soil and groundwater contamination, at
specified locations, to the extent such costs exceed a specified amount and (2)
currently unidentified environmental contamination relating to operations prior
to April of 2002 and identified prior to April of 2008. No amounts have been
accrued by Williams for such costs as of June 30, 2003; however, Williams
deferred approximately $113 million of the gain on the sale associated with
Williams' indemnifications, including environmental indemnifications, of the
purchaser under the sales agreement.

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

22

Notes (Continued)

Certain Williams' subsidiaries 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.

Actual costs incurred for these matters 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.

OTHER LEGAL MATTERS

In connection with agreements to resolve take-or-pay and other contract
claims and to amend gas purchase contracts, Transco entered into certain
settlements with producers which may require the indemnification of certain
claims for additional royalties which the producers may be required to pay as a
result of such settlements. Transco, through its agent Energy Marketing &
Trading, continues to purchase gas under contracts which extend, in some cases,
through the life of the associated gas reserves. Certain of these contracts
contain royalty indemnification provisions which have no carrying value.
Producers have received and may receive other demands, which could result in
claims pursuant to royalty indemnification provisions. Indemnification for
royalties will depend on, among other things, the specific lease provisions
between the producer and the lessor and the terms of the agreement between the
producer and Transco. Consequently, the potential maximum future payments under
such indemnification provisions cannot be determined.

As a result of these settlements, Transco has been sued by certain
producers seeking indemnification from Transco. Transco is currently defending
two lawsuits in which producers have asserted damages, including interest
calculated through June 30, 2003, of approximately $18 million. In one of these
cases, at the conclusion of a trial on July 11, 2003, the judge ruled from the
bench in Transco's favor. It is expected that the judge will enter a formal
judgment reflecting his bench ruling in the near future. This case accounts for
approximately $10 million of the $18 million claimed in the two cases.

On June 8, 2001, fourteen Williams entities were named as defendants in a
nationwide class action lawsuit which had been pending against other defendants,
generally pipeline and gathering companies, for more than one year. The
plaintiffs allege that the defendants, including the Williams defendants, have
engaged in mismeasurement techniques that distort the heating content of natural
gas, resulting in an alleged underpayment of royalties to the class of producer
plaintiffs. In September 2001, the plaintiffs voluntarily dismissed two of the
fourteen Williams entities named as defendants in the lawsuit. In January 2002,
most of the Williams defendants, along with a group of Coordinating Defendants,
filed a motion to dismiss for lack of personal jurisdiction and other grounds.
On August 19, 2002, the defendants' motion to dismiss on nonjurisdictional
grounds was denied. On September 17, 2002, the plaintiffs filed a motion for
class certification. The Williams entities joined with other defendants in
contesting certification of the class. On April 10, 2003, the court denied the
plaintiffs' motion for class certification. The motion to dismiss for lack of
personal jurisdiction remains pending. On May 13, 2003, plaintiffs filed a
motion for leave to file a fourth amended petition and on July 29, 2003, the
court granted the motion. The amended petition deletes all but two of the
Williams defendants.

In 1998, the DOJ informed Williams that Jack Grynberg, an individual, had
filed claims in the United States District Court for the District of Colorado
under the False Claims Act against Williams and certain of its wholly owned
subsidiaries. In connection with its sales of Kern River and Texas Gas, the
Company agreed to indemnify the purchasers for any liability relating to this
claim, including legal fees. The maximum amount of future payments that Williams
could potentially be required to pay under these indemnifications depends upon
the ultimate resolution of the claim and cannot currently be determined. No
amounts have been accrued for these indemnifications. Grynberg has also filed
claims against approximately 300 other energy companies and alleged that the
defendants violated the False Claims Act in connection with the measurement,
royalty valuation and purchase of hydrocarbons. The relief sought was an
unspecified amount of royalties allegedly not paid to the federal government,
treble damages, a civil penalty, attorneys' fees, and costs. On April 9, 1999,
the DOJ announced that it was declining to intervene in any of the Grynberg qui
tam cases, including the action filed against the Williams entities in the
United States District Court for the District of Colorado. On October 21, 1999,
the Panel on Multi-District Litigation transferred all of the Grynberg qui tam
cases, including those filed against Williams, to the United States District
Court for the District of Wyoming for pre-trial purposes. On October 9, 2002,
the court granted a motion to dismiss Grynberg's royalty valuation claims.
Grynberg's measurement claims remain pending against Williams and the other
defendants.

On August 6, 2002, Jack J. Grynberg, and Celeste C. Grynberg, Trustee on
Behalf of the Rachel Susan Grynberg Trust, and the Stephen Mark Grynberg Trust,
served The Williams Companies and Williams Production RMT Company with a
complaint in the District Court in and for the City of Denver, State of
Colorado. The complaint alleges that the defendants have used mismeasurement
techniques that distort the BTU heating content of natural

23

Notes (Continued)

gas, resulting in the alleged underpayment of royalties to Grynberg and other
independent natural gas producers. The complaint also alleges that defendants
inappropriately took deductions from the gross value of their natural gas and
made other royalty valuation errors. Theories for relief include breach of
contract, breach of implied covenant of good faith and fair dealing,
anticipatory repudiation, declaratory relief, equitable accounting, civil theft,
deceptive trade practices, negligent misrepresentation, deceit based on fraud,
conversion, breach of fiduciary duty, and violations of the state racketeering
statute. Plaintiff is seeking actual damages of between $2 million and $20
million based on interest rate variations, and punitive damages in the amount of
approximately $1.4 million dollars. On October 7, 2002, the Williams defendants
filed a motion to stay the proceedings in this case based on the pendency of the
False Claims Act litigation discussed in the preceding paragraph.

Williams and certain of its subsidiaries are named as defendants in various
putative, nationwide class actions brought on behalf of all landowners on whose
property the plaintiffs have alleged WilTel Communications Group, Inc. (WilTel)
installed fiber-optic cable without the permission of the landowners. Williams
and its subsidiaries have been dismissed from all of the cases.

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

On May 2, 2001, the Lieutenant Governor of the State of California and
Assemblywoman Barbara Matthews, acting in their individual capacities as members
of the general public, filed suit against five companies and fourteen executive
officers, including Energy Marketing & Trading and Williams' then current
officers Keith Bailey, Chairman and CEO of Williams, Steve Malcolm, President
and CEO of Williams Energy Services and an Executive Vice President of Williams,
and Bill Hobbs, Senior Vice President of Williams Energy Marketing & Trading, in
Los Angeles Superior State Court alleging State Antitrust and Fraudulent and
Unfair Business Act Violations and seeking injunctive and declaratory relief,
civil fines, treble damages and other relief, all in an unspecified amount. This
case is being administratively consolidated with the other class actions in San
Diego Superior Court. As part of a comprehensive settlement with the State of
California and other parties, Williams and the lead plaintiffs in these suits
have resolved the claims. While the settlement is final as to the State of
California, the San Diego Superior Court must still approve it as to the
plaintiffs in this suit.

On October 5, 2001, a suit was filed on behalf of California taxpayers and
electric ratepayers in the Superior Court for the County of San Francisco
against the Governor of California and 22 other defendants consisting of other
state officials, utilities and generators, including Energy Marketing & Trading.
The suit alleges that the long-term power contracts entered into by the state
with generators are illegal and unenforceable on the basis of fraud, mistake,
breach of duty, conflict of interest, failure to comply with law, commercial
impossibility and change in circumstances. Remedies sought include rescission,
reformation, injunction, and recovery of funds. Private plaintiffs have also
brought five similar cases against Williams and others on similar grounds. These
suits have all been removed to federal court, and plaintiffs are seeking to
remand the cases to state court. In January 2003, the federal district court
granted the plaintiffs' motion to remand the case to San Diego Superior Court,
but on February 20, 2003, the United States Court of Appeals for the Ninth
Circuit, on its own motion, stayed the remand order pending its review of an
appeal of the remand order by certain defendants. As part of a comprehensive
settlement with the State of California and other parties, Williams and the lead
plaintiffs in these suits have resolved the claims. While the settlement is
final as to the State of California, once the jurisdictional issue is resolved,
either the San Diego Superior Court or the United States District Court for the
Southern District of California must still approve the settlement as to the
plaintiff ratepayers and taxpayers.

Numerous shareholder class action suits have been filed against Williams in
the United States District Court for the Northern District of Oklahoma. The
majority of the suits allege that Williams and co-defendants, WilTel 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
Williams' board of directors and all of the offerings' underwriters. These cases
have all been consolidated and an order has been issued requiring separate
amended consolidated complaints by Williams and WilTel equity holders. The
amended

24

Notes (Continued)

complaint of the WilTel securities holders was filed on September 27, 2002, and
the amended complaint of the WMB securities holders was filed on October 7,
2002. This amendment added numerous claims related to Energy Marketing &
Trading. In addition, four class action complaints have been filed against
Williams, the members of its board of directors and members of Williams'
Benefits and Investment Committees under the Employee Retirement Income Security
Act (ERISA) by participants in Williams' 401(k) plan. A motion to consolidate
these suits has been approved. Williams and other defendants have filed motions
to dismiss each of these suits. Oral arguments on the motions were held in April
2003. On July 14, 2003, the Court dismissed Williams and its Board, but not the
members of the Benefits and Investment Committees. A decision in the shareholder
suits is pending. Derivative shareholder suits have been filed in state court in
Oklahoma, all based on similar allegations. On August 1, 2002, a motion to
consolidate and a motion to stay these suits pending action by the federal court
in the shareholder suits was approved.

On April 26, 2002, the Oklahoma Department of Securities issued an order
initiating an investigation of Williams and WilTel regarding issues associated
with the spin-off of WilTel and regarding the WilTel bankruptcy. Williams has
committed to cooperate fully in the investigation.

On November 30, 2001, Shell Offshore, Inc. filed a complaint at the FERC
against Williams Gas Processing -- Gulf Coast Company, L.P. (WGP), Williams Gulf
Coast Gathering Company (WGCGC), Williams Field Services Company (WFS) and
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
North Padre Island offshore gathering system. On September 5, 2002, the FERC
issued an order reasserting jurisdiction over that portion of the North Padre
Island facilities previously transferred to WFS. The FERC also determined an
unbundled gathering rate for service on these facilities which is to be
collected by Transco. Transco, WGP, WGCGC and WFS believe their actions were
reasonable and lawful and sought rehearing of the FERC's order which was denied
by the FERC on May 15, 2003. Transco, WGP, WGCGC and WFS have each filed
petitions for review of the FERC's orders with the U.S. Court of Appeals for the
District of Columbia. They also filed a joint motion to consolidate their
appeals.

On October 23, 2002, Western Gas Resources, Inc. and its subsidiary, Lance
Oil and Gas Company, Inc., filed suit against Williams Production RMT Company in
District Court for Sheridan, Wyoming, claiming that the merger of Barrett
Resources Corporation and Williams triggered a preferential right to purchase a
portion of the coal bed methane development properties owned by Barrett in the
Powder River Basin of northeastern Wyoming. In addition, Western claims that the
merger triggered certain rights of Western to replace Barrett as operator of
those properties. Mediation efforts are continuing and a trial date has been set
for July 2004. The Company believes that the claims have no merit.

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

Energy Marketing & Trading has paid and received various settlement amounts
in conjunction with the liquidation of trading positions during 2002 and the
first six months of 2003. One counterparty, American Electric Power Company,
Inc. (AEP), disputed a settlement amount related to the liquidation of a trading
position with Energy Marketing & Trading that was initially calculated to be in
excess of $100 million payable to Energy Marketing & Trading. Arbitration was
initiated to resolve this dispute. On June 5, 2003, Energy Marketing & Trading
and AEP executed a settlement agreement resolving the dispute, pursuant to which
AEP paid Energy Marketing & Trading $90 million. AEP is a related party as a
result of a director who serves on both Williams' and AEP's board of directors.

Pursuant to various purchase and sale agreements relating to divested
businesses and assets, Williams has indemnified certain purchasers against
liabilities that they may incur with respect to the businesses and assets
acquired from Williams. The indemnities provided to the purchasers are customary
in sale transactions and are contingent upon the purchasers incurring
liabilities that are not otherwise recoverable from third parties. The
indemnities generally relate to breach of warranties, tax, historic litigation,
personal injury, environmental matters, right of way and other representations
provided by Williams. At June 30, 2003, Williams does not expect any of the
indemnities provided pursuant to the sales agreements to have a material impact
on Williams' future financial position. However, if a claim for indemnity is
brought against Williams in the future, it may have a material adverse effect on
the net income of the period in which the claim is made.

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

25

Notes (Continued)

SUMMARY

Litigation, arbitration, regulatory matters and environmental matters are
subject to inherent uncertainties. Were an unfavorable ruling to occur, there
exists the possibility of a material adverse impact on the net income of the
period in which the ruling occurs. Management, including internal counsel,
currently believes that the ultimate resolution of the foregoing matters, taken
as a whole and after consideration of amounts accrued, insurance coverage,
recovery from customers or other indemnification arrangements, will not have a
materially adverse effect upon Williams' future financial position.

COMMITMENTS

Energy Marketing & Trading has entered into certain contracts giving it the
right to receive fuel conversion services as well as certain other services
associated with electric generation facilities that are currently in operation
throughout the continental United States. At June 30, 2003, Energy Marketing &
Trading's estimated committed payments under these contracts are $206 million
for the remainder of 2003, range from approximately $391 million to $421 million
annually through 2017 and decline over the remaining five years to $57 million
in 2022. Total committed payments under these contracts over the next 20 years
are approximately $7 billion.

GUARANTEES

In 2001, Williams sold its investment in Ferrellgas Partners L.P. senior
common units (Ferrellgas units). As part of the sale, Williams became party to a
put agreement whereby the purchaser's lenders can unilaterally require Williams
to repurchase the units upon nonpayment by the purchaser of its term loan due to
its lender or failure or default by Williams under any of its debt obligations
greater than $60 million. The maximum potential obligation under the put
agreement at June 30, 2003, was $51.5 million. Williams' contingent obligation
decreases as purchaser's payments are made to the lender. Collateral and other
recourse provisions include the outstanding Ferrellgas units and a guarantee
from Ferrellgas Partners L.P. to cover any shortfall from the sale of the
Ferrellgas units at less than face value. The proceeds from the liquidation of
the Ferrellgas units combined with the Ferrellgas Partners' guarantee should be
sufficient to cover any required payment by Williams. The put agreement expires
December 30, 2005. There have been no events of default and the purchaser has
performed as required under payment terms with the lender. No amounts have been
accrued for this contingent obligation as management believes it is not probable
that Williams would be required to perform under this obligation.

In connection with the 1993 public offering of units in the Williams Coal
Seam Gas Royalty Trust (Royalty Trust), Exploration & Production entered a gas
purchase contract for the purchase of natural gas in which the Royalty Trust
holds a net profits interest. Under this agreement, Exploration & Production
guarantees a minimum purchase price that the Royalty Trust will realize in the
calculation of its net profits interest. Exploration & Production has an annual
option to discontinue this minimum purchase price guarantee and pay solely based
on an index price. The maximum potential future exposure associated with this
guarantee is not determinable because it is dependent upon natural gas prices
and production volumes. No amounts have been accrued for this contingent
obligation as the index price continues to exceed the minimum purchase price.

In connection with the 1987 sale of certain real estate assets associated
with its Tulsa headquarters, Williams guaranteed 70 percent of the principal and
interest payments through 2007 on revenue bonds issued by the purchaser to
finance those assets. In the event that future operating results from these
assets are not sufficient to make the principal and interest payments, Williams
is required to fund that short-fall. The maximum potential future payments under
this guarantee are $6.8 million, all of which is accrued at June 30, 2003. On
July 14, 2003, Williams deposited its 70 percent share ($6.8 million) with the
trustee, satisfying its entire remaining obligation.

In connection with the construction of a joint venture pipeline project,
Williams guaranteed, through a put agreement, certain portions of the joint
venture's project financing in the event of nonpayment by the joint venture.
Williams' maximum potential liability under this guarantee, based on the
outstanding project financing at June 30, 2003, is $29.3 million. As additional
borrowings are made under the project financing facility, Williams' maximum
potential exposure will increase. This guarantee expires in March 2005, and no
amounts have been accrued at June 30, 2003.

Discovery Pipeline (Discovery) is a joint venture gas gathering and
processing system. Williams has provided a guarantee in the event of
nonperformance on 50 percent of Discovery's debt obligations, or approximately
$126.9 million at June 30, 2003. Performance under the guarantee generally would
occur upon a failure of payment by the financed entity or certain events of
default related to the guarantor. These events of default primarily relate to
bankruptcy and/or insolvency of the guarantor. The guarantee expires upon the
maturity of the debt obligation at the end of 2003, and no amounts have been
accrued as of June 30, 2003.

26

Notes (Continued)

Williams has provided performance guarantees in the event of nonpayment by
WilTel on certain lease performance obligations of WilTel that extend through
2042 and have a maximum potential exposure of approximately $52 million.
Williams' exposure declines systematically throughout the remaining term of
WilTel's obligations. At June 30, 2003, Williams has an accrued liability of
$46.9 million for this guarantee.

Williams has provided guarantees on behalf of certain partnerships in which
Williams has an equity ownership interest. These generally guarantee operating
performance measures and the maximum potential future exposure cannot be
determined. These guarantees continue until Williams withdraws from the
partnerships. No amounts have been accrued at June 30, 2003.

Williams remains guarantor under certain performance guarantees for an entity
sold earlier in 2003. These guarantees are expected to expire or be terminated
during 2003. The maximum potential future payments under these guarantees total
$144 million. No amounts have been accrued for these contingent obligations, as
management believes it is highly unlikely that Williams will be required to
perform under these agreements.

12. Stockholders' equity
- --------------------------------------------------------------------------------

On June 10, 2003, Williams redeemed all of the outstanding 9 7/8 percent
cumulative-convertible preferred shares for approximately $289 million, plus
$5.3 million for accrued dividends. These shares were repurchased with proceeds
from a private placement of 5.5 percent junior subordinated convertible
debentures due 2033 (see Note 10).

27

Notes (Continued)

13. Comprehensive income (loss)
- --------------------------------------------------------------------------------

Comprehensive income (loss) is as follows:

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

28

Notes (Continued)

14. Segment disclosures
- --------------------------------------------------------------------------------

Segments

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. The Petroleum Services segment is now reported within Other as a
result of the Alaska refinery and related assets being reflected as discontinued
operations. Segment amounts have been restated to reflect this change. Other
primarily consists of corporate operations, and certain continuing operations
previously reported within the International and Petroleum Services segments.

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 including gains/losses on
impairments related to investments accounted for under the equity method.
Intersegment sales are generally accounted for as if the sales were to
unaffiliated third parties, that is, at current market prices.

Energy Marketing & Trading has entered into intercompany interest rate
swaps with the corporate parent, the effect of which is included in Energy
Marketing & Trading's segment revenues and segment profit (loss) as shown in the
reconciliation within the following tables. The results of interest rate swaps
with external counterparties are shown as interest rate swap loss in the
Consolidated Statement of Operations below operating income (loss).

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

The following 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).

29

Notes (Continued)

14. Segment disclosures (continued)
- --------------------------------------------------------------------------------

* Prior to January 1, 2003, Energy Marketing & Trading intercompany cost of
sales, which were netted in revenues consistent with fair-value accounting,
exceeded intercompany revenue. Beginning January 1, 2003, Energy Marketing &
Trading intercompany cost of sales are no longer netted in revenues due to
adoption of EITF Issue No. 02-3 (see Note 3).

30

Notes (Continued)

14. Segment disclosures (continued)

* Prior to January 1, 2003, Energy Marketing & Trading intercompany cost of
sales, which were netted in revenues consistent with fair-value accounting,
exceeded intercompany revenue. Beginning January 1, 2003, Energy Marketing
& Trading intercompany cost of sales are no longer netted in revenues due
to adoption of EITF Issue No. 02-3 (see Note 3).

31

Notes (Continued)

14. Segment disclosures (continued)

15. Recent accounting standards
- --------------------------------------------------------------------------------

Effective July 1, 2003, Williams adopted FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities." The Interpretation defines a
variable interest entity (VIE) as an entity in which equity investors do not
have the characteristics of a controlling financial interest or do not have
sufficient equity at risk for the entity to finance its activities without
additional subordinated financial support from other parties. The investments or
other interests that will absorb portions of the VIE's expected losses if they
occur or receive portions of the VIE's expected residual returns if they occur
are called variable interests. Variable interests may include, but are not
limited to, equity interests, debt instruments, beneficial interests, derivative
instruments and guarantees. The Interpretation requires an entity to consolidate
a VIE if that entity will absorb a majority of the VIE's expected losses if they
occur, receive a majority of the VIE's expected residual returns if they occur,
or both. If no party will absorb a majority of the expected losses or expected
residual returns, no party will consolidate the VIE. The Interpretation also
requires disclosure of significant variable interests in unconsolidated VIE's.
The Interpretation is effective for all new variable interest entities created
or acquired after January 31, 2003. For variable interest entities created
or acquired prior to February 1, 2003, the provisions of the Interpretation
must be applied for the first interim or annual period beginning after
June 15, 2003. The effect of the adoption of the Interpretation is not
material to the consolidated financial statements.

16. Subsequent events
- --------------------------------------------------------------------------------

In August 2003, Williams announced sales of assets completed subsequent to
June 30, 2003, and agreements to sell various assets for cash proceeds in excess
of $80 million. These assets include:

o The West Stoddart natural gas processing plant in Western Canada,
which is part of Midstream Gas & Liquids,

o Williams' 20 percent ownership interest in the West Texas LPG Pipeline
Limited Partnership which transports natural gas liquids in Texas and
is part of Midstream Gas & Liquids,

o Distributed-generation units and an associated third-party contract,
which is part of Energy Marketing & Trading, and

o Refined products management operations, which are part of the Other
segment.

In August 2003, Williams also announced it had agreed to terminate a
long-term power contract with Allegheny Energy Supply Company, LLC, a subsidiary
of Allegheny Energy, Inc., for cash consideration of $128 million payable to
Williams. The agreement is subject to certain conditions, including a provision
that Allegheny successfully complete the sale of its energy supply agreement
with the California Department of Water Resources. Allegheny has announced an
agreement for the sale of that contract.

32

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

RECENT EVENTS AND COMPANY OUTLOOK

On February 20, 2003, Williams outlined its planned business strategy for
the next few years. Williams believes it to be a comprehensive response to the
events that have impacted the energy sector and Williams during 2002. The plan
focuses on retaining a strong, but smaller, portfolio of natural gas businesses
and bolstering Williams' liquidity through additional asset sales, strategic
levels of financing at the Williams and subsidiary levels and additional
reductions in its operating costs. The plan is designed to provide Williams with
a clear strategy to address near-term and medium-term liquidity issues and
further de-leverage the company with the objective of returning to investment
grade status, while retaining businesses with favorable returns and
opportunities for growth in the future.

Williams, at June 30, 2003, has maturing notes payable and long-term debt
totaling approximately $1.8 billion through the first quarter of 2004. The
maturing notes and long-term debt are expected to be repaid with cash on hand,
proceeds from asset sales and cash flows from operations. During second-quarter
2003, Williams repaid the RMT note payable of approximately $1.15 billion (which
included certain contractual fees and deferred interest) which was due in July
2003. A portion of the RMT note payable was refinanced by the issuance of $500
million secured, subsidiary-level financing at a floating rate of the six-month
London Interbank Offered Rate (LIBOR) plus 3.75 percent (totaling 4.9 percent at
June 30, 2003). Also during second-quarter 2003, Williams issued $800 million of
8.625 percent senior unsecured notes due 2010. Williams intends to use the net
proceeds from the $800 million offering to improve corporate liquidity, for
general corporate purposes, and for payment of maturing debt obligations,
including the partial repayment of the company's senior unsecured 9.25 percent
notes due March 2004. Additionally, Williams issued $300 million of 5.5 percent
junior subordinated convertible debentures due 2033 and utilized the proceeds to
redeem all of the outstanding 9 7/8 percent cumulative-convertible preferred
stock for approximately $289 million, plus $5.3 million for accrued dividends.
The new convertible debentures provide Williams with more favorable terms, which
on an annual basis result in approximately $17 million in lower after-tax
carrying costs compared with the preferred convertible shares. Williams also
obtained a new $800 million revolving credit facility that is collateralized by
purchased government securities and/or cash and will be utilized mainly for
issuance of letters of credit. This new facility enabled the release of the
midstream assets that served as security for the previous credit facilities.
Long-term debt, excluding the current portion, at June 30, 2003 was
approximately $11.2 billion. See the Liquidity section for a maturity schedule
of the long-term debt.

As part of the asset sales portion of the plan, Williams expects to
generate proceeds, net of related debt, of nearly $4 billion from asset sales
during 2003 and 2004. For the six months ended June 30, 2003, Williams had
received approximately $2.4 billion in net proceeds from the sales of assets and
businesses, including the retail travel centers, the Midsouth refinery,
bio-energy operations, Texas Gas Transmission Corporation, Williams' general
partnership interest and limited partner investment in Williams Energy Partners,
and certain natural gas exploration and production properties in Kansas,
Colorado, and New Mexico. The additional assets and/or businesses expected to be
sold in 2003 and 2004 include the Alaska refinery and related assets, certain
assets within Midstream Gas & Liquids, the soda ash mining operations and
various other assets. The specific assets 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 Williams. While management believes it has considered
all relevant information in assessing for potential impairments, the ultimate
sales price for assets that may be sold and the final decisions in the future
may result in additional impairments or losses and/or gains.

Williams continues its efforts to reduce its commitment to the Energy
Marketing & Trading business. As part of these efforts, Energy Marketing &
Trading has focused on managing its existing contractual commitments, while
pursuing potential dispositions and restructuring of certain of its long-term
contracts. For the six month period ended June 30, 2003, Energy Marketing &
Trading has sold contracts resulting in cash proceeds of approximately $206
million. Although management currently believes that the Company has the
financial resources and liquidity to meet the expected cash requirements of
Energy Marketing & Trading, the Company continues to pursue several specific
transactions with interested parties involving the sales of portions of Energy
Marketing & Trading's portfolio and would consider the sale or joint venture of
all of the portfolio.

The Company's available liquidity to meet maturing debt requirements and
fund a reduced level of capital expenditures will be dependent on several
factors, including available cash on hand, the cash flows of retained
businesses, the amount of proceeds raised from the sale of assets previously
mentioned, the price of natural gas and capital spending. Future cash flows from
operations may also be affected by the timing and nature of the sale of

33

Management's Discussion & Analysis (Continued)

assets. Because of recent and anticipated asset sales, cash on hand, potential
external financings, and available secured credit facilities, Williams currently
believes that it has, or has access to, the financial resources and liquidity to
meet future cash requirements.

GENERAL

In accordance with the provisions related to discontinued operations within
Statement of Financial Accounting Standard (SFAS) No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," the consolidated financial
statements and notes in Item 1 reflect the results of operations, financial
position and cash flows, through the date of sale as applicable, of the
following components as discontinued operations (see Note 6):

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

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

o Texas Gas Transmission Corporation, previously one of Gas
Pipeline's segments

o Natural gas properties in the Hugoton and Raton basins,
previously part of the Exploration & Production segment

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

o Gulf Liquids New River Project LLC, previously part of the
Midstream Gas & Liquids segment

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

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

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

o Refining, retail and pipeline operations in Alaska, part of the
previously reported Petroleum Services segment

o Williams' general partnership interest and limited partner
investment in Williams Energy Partners, previously the Williams
Energy Partners segment

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

Unless indicated otherwise, the following discussion and analysis of
results of operations, financial condition and liquidity relates to the current
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 Williams' Annual Report on Form 10-K.

CRITICAL ACCOUNTING POLICIES & ESTIMATES

As noted in the 2002 Annual Report on Form 10-K, Williams' financial
statements reflect the selection and application of accounting policies that
require management to make significant estimates and assumptions. One of the
critical judgment areas in the application of our accounting policies noted in
the Form 10-K is the revenue recognition of energy risk management and trading
operations. As a result of the application of the conclusions reached by the
Emerging Issues Task Force in Issue No. 02-3, "Issues related to Accounting for
Contracts Involved in Energy Trading and Risk Management Activities," the
methodology for revenue recognition related to energy risk management and
trading activities changed January 1, 2003. Williams initially applied the
consensus effective January 1, 2003 and reported the initial application as a
cumulative effect of a change in accounting principle. See Note 3 for a
discussion of the impacts to Williams' financial statements as a result of
applying this consensus.

34

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 following this consolidated overview discussion.

Three Months Ended June 30, 2003 vs. Three Months Ended June 30, 2002

Williams' revenue increased $3 billion due primarily to increased revenues
at Energy Marketing & Trading and Midstream Gas & Liquids as a result of the
adoption of Emerging Issues Task Force (EITF) Issue No. 02-3, "Issues Related to
Accounting for Contracts Involved in Energy Trading & Risk Management
Activities," which requires that revenues and cost of sales from non-derivative
contracts and certain physically settled derivative contracts be reported on a
gross basis. As permitted by EITF Issue No. 02-3, prior year amounts have not
been restated. Prior to the adoption of EITF Issue No. 02-3 on January 1, 2003,
revenues and costs of sales related to non-derivative contracts and certain
physically settled derivative contracts were reported in revenues on a net
basis. Revenues at Energy Marketing & Trading increased $3.1 billion and
Midstream Gas & Liquids' revenues increased $300 million. During the second
quarter of 2003, Energy Marketing & Trading corrected the accounting treatment
previously given to certain third party derivative contracts during 2002 and
2001, resulting in the recognition of $80.7 million in revenues in the second
quarter 2003 attributable to prior periods. Refer to Note 1 to the financial
statements for further information. These corrections relate to the fair value
of these derivative contracts and do not represent current period actual cash
flows.

Costs and operating expenses increased $2.6 billion due primarily to the
impact of reporting certain costs gross at Energy Marketing & Trading and
Midstream Gas & Liquids, as discussed above.

Selling, general and administrative expenses decreased $45.8 million due
primarily to the absence of $21 million of costs related to an enhanced benefit
early retirement option offered to certain employee groups in 2002 and reduced
staffing levels at Energy Marketing & Trading.

35

Management's Discussion & Analysis (Continued)

Other (income) expense - net in 2003 reflects a $175 million gain from the
sale of an Energy Marketing & Trading contract and $91.5 million in net gains
from the sale of Exploration & Production's interests in natural gas properties.
Partially offsetting these gains in 2003 was a $25.5 million charge at Northwest
Pipeline to write-off capitalized software development costs for a service
delivery system following a decision not to implement the system and a $20
million charge related to a settlement by Energy Marketing & Trading with the
Commodity Futures Trading Commission (CFTC) (see Note 11). Other (income)
expense - net in 2002 includes $141.2 million of impairment charges, loss
accruals, and write-offs within Energy Marketing & Trading, including a partial
impairment of goodwill.

General corporate expenses decreased $12.3 million, or 36 percent, due
primarily to lower advertising expenses and charitable contributions.

Operating income (loss) improved by $889.8 million from a $208.4 million
loss in 2002 to $681.4 million of income in 2003. The increase results primarily
from a $779.2 million improvement at Energy Marketing & Trading and $91.5
million in net gains on sales of certain properties at Exploration & Production.

Interest accrued - net increased $147.4 million, or 60 percent, due
primarily to $120 million of interest expense, including amortization of fees,
on the RMT note payable (see Note 10), $21 million higher amortization expense
of deferred debt issuance costs, and $12 million of interest expense within
Energy Marketing & Trading related to a FERC ruling. A $22 million decrease in
interest expense reflecting lower average borrowing levels of long-term debt in
2003 was offset by a $19 million increase in interest expense reflecting higher
average interest rates on long-term debt in 2003. The $21 million of higher
amortization expense of deferred debt issuance costs reflects $14.5 million in
accelerated amortization of costs related to the termination of the revolving
credit agreement that was replaced in June 2003 (see Note 10).

In 2002, Williams began entering into interest rate swaps with external
counter parties primarily in support of the energy-trading portfolio (see Note
14). The decline in market value of these swaps was $77.1 million lower in 2003
than 2002. The total notional amount of these swaps is approximately $300
million at June 30, 2003 as compared to a notional amount at June 30, 2002 of
approximately $1.5 billion.

Investing income (loss) for the three months ended June 30, 2003 and 2002
consisted of the following components:

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

Equity earnings for the three months ended June 30, 2002 includes $27.4
million of income reflecting a contractual construction completion fee received
by an equity affiliate that served as the general contractor on the Gulfstream
Pipeline Natural Gas System (Gulfstream) project. Additionally, the decrease in
equity earnings for the three months ended June 30, 2003 as compared to 2002
reflects $16 million lower equity earnings from Gulfstream. Equity earnings for
2002 includes net equity income of $3.6 million related to equity method
investments that were sold during 2002. The $15 million loss provision in 2002
is related to the estimated recoverability of receivables from WilTel
Communications Group, Inc. (formerly Williams Communications Group, Inc.). The
$42.4 million impairment in 2003 relates to the investment in equity and debt
securities of Longhorn Partners Pipeline LP, and the $12.3 million impairment in
2002 relates to a write down of Gas Pipeline's investment in a pipeline project
which was cancelled in second-quarter 2002. Impairment of cost based investments
in 2003 includes a $13.5 million impairment of an investment in a company
holding phosphate reserves.

36

Management's Discussion & Analysis (Continued)

Minority interest in income and preferred returns of consolidated
subsidiaries in 2003 is lower than 2002 due to the absence of preferred returns
totaling $5.5 million on the preferred interests in Castle Associates L.P.,
Arctic Fox, L.L.C., Piceance Production Holdings L.L.C., and in Williams' Risk
Holdings L.L.C. which were reclassified as debt in the third-quarter of 2002
with the exception of Arctic Fox, L.L.C., which was reclassified as debt in
April 2002.

Other income - net in 2003 includes a $38.2 million foreign currency
translation gain on a Canadian dollar denominated note receivable offset by a
$30.3 million derivative loss on a forward contract to fix the U.S. dollar
principal cash flows from this note. Other income - net in 2002 includes an $11
million gain at Gas Pipeline associated with the disposition of securities
received through a mutual insurance company reorganization.

The provision (benefit) for income taxes was unfavorable by $283.8 million
due primarily to a pre-tax income in 2003 as compared to a pre-tax loss for
2002. The effective income tax rate for the three months ended June 30, 2003 is
greater than the federal statutory rate due primarily to the financial
impairment of certain investments and capital losses generated for which
valuation allowances were established and nondeductible expenses. 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 reduces the tax benefit of the pretax
loss.

Preferred stock dividends in 2003 includes $13.8 million associated with
accounting for the premium paid on the redemption in May 2003 of the 9 7/8
percent cumulative-convertible preferred shares (see Note 12).

Six Months Ended June 30, 2003 vs. Six Months Ended June 30, 2002

Williams' revenue increased $6.7 billion due primarily to increased
revenues at Energy Marketing & Trading and Midstream Gas & Liquids as a result
of the adoption of EITF Issue No. 02-3, which requires that revenues and cost of
sales from non-derivative contracts and certain physically settled derivative
contracts be reported on a gross basis. As permitted by EITF Issue No. 02-3,
prior year amounts have not been restated. Prior to the adoption of EITF Issue
No. 02-3 on January 1, 2003, revenues and costs of sales related to
non-derivative contracts and certain physically settled derivative contracts
were reported in revenues on a net basis. Energy Marketing & Trading's revenues
increased $6.6 billion and Midstream Gas & Liquids' revenues increased $1
billion. The increase in revenues at Midstream Gas & Liquids includes a $236
million higher Canadian revenues and $128 million higher domestic gathering and
processing revenues. Offsetting these revenue increases at the operating units
was $948.9 million higher intercompany eliminations primarily as a result of
intercompany costs that were previously netted in Energy Marketing & Trading's
revenues prior to EITF Issue No. 02-3. During the second quarter of 2003, Energy
Marketing & Trading corrected the accounting treatment previously given to
certain third party derivative contracts during 2002 and 2001, resulting in the
recognition of $80.7 million in revenues in the second quarter 2003 attributable
to prior periods. Refer to Note 1 to the financial statements for further
information. These corrections relate to the fair value of these derivative
contracts and do not represent current period actual cash flows.

Costs and operating expenses increased $6.5 billion due primarily to the
impact of reporting certain costs gross at Energy Marketing & Trading and
Midstream Gas & Liquids, as discussed above. Costs and operating expenses at
Energy Marketing & Trading increased $6.5 billion. Costs and operating expenses
at Midstream Gas & Liquids also increased due to $210 million and $59 million
higher fuel and shrink costs at Canadian and domestic processing facilities,
respectively.

Selling, general and administrative expenses decreased $62.4 million due
primarily to reduced staffing levels at Energy Marketing & Trading and the
absence of $21 million of costs related to an enhanced benefit early retirement
option offered to certain employee groups in 2002.

Other (income) expense - net in 2003 reflects a $175 million gain from the
sale of an Energy Marketing & Trading contract and $91.5 million in net gains
from the sale of Exploration & Production's interests in natural gas properties.
Partially offsetting these gains was a $25.5 million charge at Northwest
Pipeline to write-off capitalized software development costs for a service
delivery system following a decision not to implement and a $20 million charge
related to a settlement by Energy Marketing & Trading with the CFTC (see Note
11). Other (income) expense - net in 2002 includes $141.2 million of impairment
charges, loss accruals, and write-offs within Energy Marketing & Trading,
including a partial impairment of goodwill.

General corporate expenses decreased $27.6 million, or 38 percent, due
primarily to lower advertising costs and charitable contributions.

Operating income (loss) increased $608.7 million due primarily to a $375.7
million improvement at Energy Marketing & Trading, $91.5 million in net gains on
sales of certain properties at Exploration & Production and a $78.6 million
increase at Midstream Gas & Liquids primarily from domestic gathering and
processing operations.

37

Management's Discussion & Analysis (Continued)

Interest accrued - net increased $289 million, or 65 percent, due primarily
to $209 million of interest expense, including amortization of fees, on the RMT
note payable (see Note 10), $34 million higher amortization expense of deferred
debt issuance costs, and $12 million of interest expense within Energy Marketing
& Trading related to a FERC ruling. The increase also reflects the $48 million
effect of higher average interest rates on long-term debt in 2003 offset
slightly by the $9 million effect of lower average borrowing levels of long-term
debt. The $34 million higher amortization expense of deferred debt issuance
costs reflects $14.5 million in accelerated amortization of costs related to the
termination of the revolving credit agreement that was replaced in June 2003
(see Note 10).

In 2002, Williams began entering into interest rate swaps with external
counter parties primarily in support of the energy-trading portfolio (see Note
14). The decline in market value of these swaps was $64.1 million lower in 2003
that in 2002. The total notional amount of these swaps is approximately $300
million at June 30, 2003 as compared to a notional amount at June 30, 2002 of
approximately $1.5 billion.

Investing income (loss) for the six months ended June 30, 2003 and 2002
consisted of the following components:

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

Equity earnings decreased $55.5 million due primarily to $27 million lower
equity earnings from Gulfstream and the absence of a $27.4 million benefit in
2002 related to the contractual construction completion fee received by an
equity affiliate, that served as the general construction on the Gulfstream
project. The $247 million loss provision in 2002 was related to the estimated
recoverability of receivables from WilTel Communications Group, Inc. The $42.4
million impairment in 2003 relates to the investment in equity and debt
securities of Longhorn Partners Pipeline LP, and the $12.3 million impairment in
2002 relates to a write down of Gas Pipeline's investment in a pipeline project
that was cancelled in second-quarter 2002. Impairment of cost based investments
in 2003 includes a $13.5 million impairment of an investment in a company
holding phosphate reserves, a $12 million impairment of Algar Telecom S.A. and a
$5.6 million impairment of various international investments. Each of these
impairments results from management's determination that there was an other than
temporary decline in the estimated fair value of each investment. Interest
income and other increased $51.7 million due primarily to a $37.2 million
increase at Energy Marketing & Trading comprised primarily of interest income as
a result of recent FERC proceedings, a $5 million increase in interest income
from advances to equity affiliates and a $3 million increase in interest from
margin deposits.

Minority interest in income and preferred returns of consolidated
subsidiaries in 2003 is lower than 2002 due primarily to the absence of
preferred returns totaling $13 million on the preferred interests in Castle
Associates L.P., Arctic Fox, L.L.C., Piceance Production Holdings L.L.C., and in
Williams' Risk Holdings L.L.C. which were reclassified as debt in third-quarter
2002 with the exception of Arctic Fox, L.L.C., which was reclassified as debt in
April 2002.

Other income - net in 2003 includes a $67.4 million foreign currency
transaction gain on a Canadian dollar denominated note receivable offset by a
$47 million derivative loss on a forward contract to fix the U.S. dollar
principal cash flows from this note. Other income-net in 2002 includes an $11
million gain at Gas Pipeline associated with the disposition of securities
received through a mutual insurance company reorganization offset by a $8
million loss related to early retirement of remarketable notes.

The provision (benefit) for income taxes was $232.9 million unfavorable in
2003 due primarily to pre-tax income in 2003 as compared to a pre-tax loss for
2002. The effective income tax rate for the six months ended June 30, 2003, is
greater than the federal statutory rate due primarily to the financial
impairment of certain investments and capital losses generated for which
valuation allowances were established and nondeductible expenses.

38

Management's Discussion & Analysis (Continued)

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 reduces the tax benefit of
the pre-tax loss.

Cumulative effect of change in accounting principles reduced net income for
2003 by $761.3 million due to a $762.5 million charge related to the adoption of
EITF Issue No. 02-3 (see Note 3), slightly offset by $1.2 million related to the
adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations" (see
Note 3).

Preferred stock dividends in 2002 reflects the impact of $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.

RESULTS OF OPERATIONS-SEGMENTS

Williams is currently organized into the following segments: Energy
Marketing & Trading, Gas Pipeline, Exploration & Production, and Midstream Gas &
Liquids. Due to completed and anticipated asset sales, Williams Energy Partners
and Petroleum Services are no longer reportable segments as most of the
operations comprising these segments are now reported in discontinued
operations. Williams currently evaluates performance based upon several measures
including segment profit (loss) from operations (see Note 14). Segment profit of
the operating companies may vary by quarter. The following discussions relate to
the results of operations of Williams' segments.

ENERGY MARKETING & TRADING

Three Months Ended June 30, 2003 vs. Three Months Ended June 30, 2002

ENERGY MARKETING & TRADING'S revenues and cost of sales increased by $3.2
billion and $2.7 billion, respectively, which equates to an increase in gross
margin of $512.9 million. This significant increase in revenues and cost of
sales is primarily a result of the adoption of EITF Issue No. 02-3, which
requires that revenues and cost of sales from non-derivative energy contracts
and certain physically settled derivative contracts be reported on a gross
basis. Prior to the adoption of EITF Issue No. 02-3 on January 1, 2003, revenues
related to non-derivative energy contracts were reported on a net basis in
trading revenues. As permitted by EITF Issue No. 02-3, prior year amounts have
not been restated.

On October 25, 2002, the EITF concluded on Issue No. 02-3, which rescinded
Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities," under which all energy trading contracts, derivative and
non-derivative energy, were required to be valued at fair value with the net
change in fair value of these contracts representing unrealized gains and losses
reported in income currently and recorded as revenues in the Consolidated
Statement of Operations. Energy contracts include forward contracts, futures
contracts, options contracts, swap agreements, commodity inventories, short-and
long-term purchase and sale commitments, which involve physical delivery of an
energy commodity and energy-related contracts, such as transportation, storage,
full requirements, load serving and power tolling contracts. Energy-related
contracts that are not considered to be derivatives under SFAS No. 133 are no
longer presented on the balance sheet at fair value. These contracts are now
reported under the accrual method of accounting. In addition, trading
inventories are no longer marked to market but are reported on a lower of cost
or market basis. Upon adoption of this new standard on January 1, 2003, Energy
Marketing & Trading recorded an adjustment as a cumulative effect of change in
accounting principle to remove the previously reported fair value of
non-derivative energy contracts from the balance sheet. Energy Marketing &
Trading's portion of this change in accounting principle was approximately $755
million on an after-tax basis (see Note 3) and was recognized in first-quarter
2003. Prior year amounts have not been restated as permitted by EITF Issue No.
02-3.

39

Management's Discussion & Analysis (Continued)

Energy Marketing & Trading's revenues increased by $3.2 billion primarily
as a result of the new gross reporting requirements as discussed above. Energy
Marketing & Trading's gross margin increased $512.9 million principally due to
$506.4 million higher power and natural gas gross margin, $53.4 million higher
petroleum products gross margin, and $6.2 million higher European gross margin,
slightly offset by $53.4 million lower emerging products gross margin.

The power and natural gas gross margin increased from a margin loss of $213
million in 2002 to a $293.4 million gross margin in 2003, an increase of $506.4
million. The $293.4 million gross margin in 2003 is primarily comprised of a
$57.5 million accrual loss and a $302.9 million mark-to-market gain. The accrual
loss of $57.5 million is primarily related to reduced revenues resulting from
narrow spark spreads on the tolling portfolio that do not exceed
contractually-obligated capacity payments. Approximately $218.2 million of the
$302.9 million gain is related to mark to market gains on power and gas
positions that were entered into to economically hedge long-term structured
transactions that are now accounted for on an accrual basis. These
mark-to-market gains are primarily a result of increased gas prices on long
natural gas positions. In 2002, all energy-related trading contracts, including
tolling and full requirements contracts, were marked to market. In 2003, with
the implementation of EITF Issue No. 02-3 as discussed above, these
non-derivative energy-related trading contracts were accounted for on an accrual
basis. Therefore, while in 2002 the impact of narrower spark spreads in future
periods on the fair value of certain power tolling portfolios was reflected in
earnings, in 2003, the earnings for these types of non-derivative contracts are
reported on an accrual basis. Therefore, any forward gains or losses resulting
from changes in fair value are excluded from current earnings for non-derivative
contracts, whereas the changes in the forward value of certain derivatives
contracts continue to be included in earnings. Additionally, in second-quarter
2003, Energy Marketing & Trading began accounting for certain of its power and
gas derivatives contracts under the accrual method of accounting as a result of
an election to account for the contracts under the normal purchases and sales
exception available under SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities." These contracts were previously marked to market with
changes in fair value reported within earnings. During the second quarter of
2003, Energy Marketing & Trading corrected the accounting treatment previously
given to certain third party derivative contracts during 2002 and 2001,
resulting in the recognition of $80.7 million in revenues in the second quarter
2003 attributable to prior periods. Refer to Note 1 to the financial statements
for further information. These corrections relate to the fair value of these
derivative contracts and do not represent current period actual cash flows.

The petroleum products portfolio gross margin improved from a gross margin
loss of $73.7 million in 2002 to a gross margin loss of $20.3 million in 2003.
This $53.4 million improvement was impacted by the implementation of EITF Issue
No. 02-3. The petroleum products portfolio was adversely affected in 2002 by a
decrease in the fair value of refined products storage and transportation
portfolios. In second-quarter 2003, however, these non-derivative contracts were
accounted for on an accrual basis and accordingly earnings do not reflect
changes in fair value.

The $6.2 million increase in European gross margin is due to the absence of
trading activity in second-quarter 2003 as a result of the wind-down of the
European trading operations. These operations generated a $6.2 million loss in
second-quarter 2002.

The $53.4 million decrease in emerging products gross margin is primarily
attributable to falling interest rates on forward interest rate positions that
are marked to market.

Selling, general, and administrative expenses decreased by $19.3 million,
or 30 percent. This cost reduction is primarily due to the impact of staff
reductions in the Energy Marketing & Trading business segment. Energy Marketing
& Trading employed approximately 265 employees at June 30, 2003, compared with
approximately 900 employees at June 30, 2002.

Other (income) expense -- net increased $312.2 million. This increase is
due primarily to $175 million gain from the sale of an energy trading contract
in 2003 and the effect in 2002 of $83.7 million of impairments and loss accruals
associated with certain terminated power projects and a $57.5 million partial
goodwill impairment. The increase was partially offset by a $20 million charge
in 2003 for the settlement reached with the Commodity Futures Trading Commission
subsequent to quarter end (see Note 11).

Segment profit increased $845.5 million due primarily to increased power,
natural gas, petroleum products and European gross margins, decreased selling,
general and administrative expenses and improved other (income) expense - net,
partially offset by decreased emerging products gross margin as discussed above.

40

Management's Discussion & Analysis (Continued)

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

In July 2003, Energy Marketing & Trading reached an agreement in principle
to terminate one of its long-term energy trading contracts in exchange for a
cash payment of $128 million from the counterparty to the contract. This
contract is accounted for on a fair value basis. The agreement is contingent
upon certain events, but if consummated in its present form, the transaction
could result in realization of an amount significantly in excess of fair value
as estimated at June 30, 2003.

Six Months Ended June 30, 2003 vs. Six Months Ended June 30, 2002

ENERGY MARKETING & TRADING'S revenues and cost of sales increased by $6.6
billion and $6.5 billion, respectively, which equates to an increase in gross
margin of $74.9 million. This significant increase in revenues and cost of sales
is primarily a result of the adoption of EITF Issue No. 02-3 and rescinding of
EITF Issue No. 98-10, as discussed previously.

Energy Marketing & Trading's gross margin increased $74.9 million
principally due to $227.9 million higher power and natural gas gross margin,
offset by $82.1 million lower emerging products gross margin, $64.3 million
lower petroleum products gross margin, and $6.5 million lower European gross
margin.

The power and natural gas gross margin increased from a margin loss of
$12.3 million in 2002 to a $215.6 million gross margin in 2003, an improvement
of $227.9 million. The $215.6 million gross margin in 2003 is primarily
comprised of a $80 million accrual loss and a $293.1 million mark to market
gain. The accrual loss of $80 million is primarily related to reduced revenues
resulting from narrow spark spreads on the tolling portfolio that do not exceed
contractually-obligated capacity payments. Approximately $232.5 million of the
$293.1 million gain is related to mark-to-market gains on power and gas
positions that were entered into to economically hedge long-term structured
transactions that are now accounted for on an accrual basis. These mark to
market gains are primarily a result of increased gas prices on long natural gas
positions. In 2002, all energy-related trading contracts, including tolling and
full requirements contracts, were marked to market. In 2003, with the
implementation of EITF Issue No. 02-3 as discussed previously, these
non-derivative energy-related trading contracts were accounted for on an accrual
basis. Therefore, while in 2002 the impact of narrower spark spreads on the fair
value of certain power tolling portfolios was reflected in earnings, in 2003,
the earnings for these types of contracts are reported on an accrual basis.
Therefore, any forward gains or losses resulting from changes in fair value are
excluded from current earnings for non-derivative contracts, whereas the changes
in forward value of certain derivatives contracts continue to be included in
earnings. Additionally, in second-quarter 2003, Energy Marketing & Trading
began accounting for certain of its power and gas derivatives contracts under
the accrual method of accounting as a result of an election to account for the
contracts under the normal purchases and sales exception available under SFAS
No. 133, Accounting for Derivative Instruments and Hedging Activities." These
contracts were previously marked to market with changes in fair value reported
within earnings. During the second quarter of 2003, Energy Marketing & Trading
corrected the accounting treatment previously given to certain third party
derivative contracts during 2002 and 2001, resulting in the recognition of $80.7
million in revenues in the second quarter 2003 attributable to prior periods.
Refer to Note 1 to the financial statements for further information. These
corrections relate to the fair value of these derivative contracts and do not
represent current period actual cash flows. The effect of these events is
partially offset by an $84 million decrease in power and gas revenues from the
origination of significant new long-term transactions in 2002 and a $37 million
adjustment in first quarter 2003 to increase the liability for rate refunds
associated with 2003 FERC rulings relative to California power and natural gas
markets.

41

Management's Discussion & Analysis (Continued)

The petroleum products portfolio gross margin decreased from $46.8 million
in 2002 to a margin loss of $17.5 million in 2003. This decrease of $64.3
million was primarily attributable to a $118.8 million decrease in revenues from
the origination of significant new long-term transactions in 2002 partially
offset by the impact of the implementation of EITF Issue No. 02-3 in 2003. The
petroleum products portfolio was adversely affected in 2002 by a decrease in the
forward value of refined products storage and transportation portfolios.
Pursuant to EITF Issue No. 02-3, these same non-derivative storage and
transportation contracts were required to be treated on an accrual basis in
2003, resulting in a comparatively higher gross margin attributable to these
contracts.

The $6.5 million decrease in European gross margin is due to the absence of
trading activity in 2003 as a result of the wind-down of the European trading
operations as compared to a $6.5 million gross margin recognized in 2002. The
$82.1 million decrease in emerging products gross margin is primarily
attributable to falling interest rates on forward interest rate positions that
are marked to market.

Selling, general, and administrative expenses decreased by $33.9
million, or 30 percent. This cost reduction is due primarily to the impact of
staff reductions in the Energy Marketing & Trading business segment.

Other (income) expense -- net increased $312.7 million. This increase is
primarily due to $175.0 million gain from the sale of an energy trading contract
in 2003 and the effect in 2002 of $83.7 million of impairments and loss accruals
associated with certain terminated power projects and a $57.5 million partial
goodwill impairment. The increase was partially offset by a $20 million charge
in 2003 for the settlement reached with the CFTC subsequent to quarter end (see
Note 11).

Segment profit increased $426 million due primarily to increased power and
natural gas gross margin, decreased selling, general and administrative expenses
and improved other (income) expense- net, partially offset by decreased
petroleum products, European and emerging products gross margins as discussed
above.

GAS PIPELINE

On April 14, 2003, Williams announced that it had signed a definitive
agreement to sell Texas Gas Transmission Corporation (Texas Gas) to Loews
Pipeline Holding Corp., a unit of Loews Corporation. The sale closed on May 16,
2003. Williams received $793 million in cash and the buyer assumed $250 million
in debt. Pursuant to current accounting guidance, the operations of Texas Gas
have been classified as discontinued operations.

For the purposes of second-quarter 2003 reporting, Gas Pipeline's
continuing operations include Northwest Pipeline Corporation, Transcontinental
Gas Pipe Line Corporation, a 50 percent interest in the Gulfstream Natural Gas
System, L.L.C. and other joint venture interstate and intrastate natural gas
pipeline systems. Certain assets sold during 2002 are included in the 2002
results. These assets include Cove Point, a general partner interest in Northern
Border, and our 14.6 percent interest in Alliance Pipeline. These assets
represented $2.2 million and $5.7 million of revenues for the three months and
six months ended June 30, 2002, respectively, and $4.9 million and $12.4 million
of segment profit for the three and six months ended June 30, 2002,
respectively. Financial results related to Kern River, Central, (both sold
during 2002), and Texas Gas are included in discontinued operations.

Three Months Ended June 30, 2003 vs. Three Months Ended June 30, 2002

GAS PIPELINE'S revenues increased $21.5 million, or 7 percent, due
primarily to $17 million higher demand revenues on the Transco system resulting
from new expansion projects (MarketLink, Momentum and Sundance) and higher
transportation rates in connection with rate proceedings that became effective
in late 2002, and $8 million on the Northwest Pipeline system primarily from new
projects (Gray's Harbor, Centralia, and Chehalis). Partially offsetting these
increases were $4 million lower storage demand revenues due to lower demand
charges as a result

42

Management's Discussion & Analysis (Continued)

of lower rates in connection with Transco's rate proceedings that became
effective in late 2002 and $3 million lower cash-out sales related to gas
imbalance settlements (offset in costs and operating expenses).

Cost and operating expenses increased $4 million, or 2 percent, due
primarily to $7 million higher depreciation expense due to increased property,
plant and equipment placed into service, partially offset by $3 million lower
cash-out sales related to gas imbalance settlements (offset in revenues).

General and administrative costs decreased $17 million, or 36 percent, due
primarily to $11 million of early retirement pension cost in 2002.

Other (income) expense--net in 2003 includes a $25.5 million charge at
Northwest Pipeline to write-off capitalized software development costs for a
service delivery system following a decision not to implement. Subsequent to the
implementation of the same system at Transco in the second quarter of 2003 and a
determination of the unique and additional programming requirements that would
be needed to complete the system at Northwest Pipeline, management determined
that the system would not be implemented at Northwest Pipeline.

Segment profit, which includes equity earnings and income (loss) from
investment (included in investing income), decreased $27.2 million reflecting
$49.6 million lower equity earnings and the $25.5 million charge discussed
previously. These items were partially offset by the higher revenues and lower
general and administrative expenses discussed above and the absence of the $12.3
million 2002 write-off of Gas Pipeline's investment in a cancelled pipeline
project (income (loss) from investments). The $49.6 million decrease in equity
earnings is due primarily to a $27.4 million benefit in 2002 related to the
contractual construction completion fee received by an equity affiliate and $16
million lower equity earnings from Gulfstream Natural Gas System primarily
related to the absence in 2003 of interest capitalized on internally generated
funds as allowed by FERC regulations during construction. The pipeline was
placed into service during second-quarter 2002. Also, the decrease in equity
earnings reflects the absence of $6 million of equity earnings following the
October 2002 sale of Gas Pipeline's 14.6 percent ownership in Alliance Pipeline.

Six Months Ended June 30, 2003 vs. Six Months Ended June 30, 2002

GAS PIPELINE'S revenues increased $39.8 million, or 7 percent, due
primarily to $33 million higher demand revenues on the Transco system resulting
from new expansion projects (MarketLink, Momentum and Sundance) and higher rates
authorized under Transco's rate proceedings that became effective in late 2002
and $10 million on the Northwest Pipeline system resulting from new projects
(Gary's Harbor, Centralia, and Chehalis). In addition to these increases was a
$9 million higher recovery of tracked costs which are passed through to
customers (offset in costs and operating expenses). Partially offsetting these
increases were $11 million lower cash-out sales related to gas imbalance
settlements (offset in costs and operating expenses) and $8 million lower
storage demand revenues due to lower charges as a result of lower rates in
connection with Transco's rate proceedings that became effective in late 2002.

Cost and operating expenses decreased $12 million, or 4 percent, due
primarily to $12 million lower fuel expense on Transco due primarily to pricing
differentials on the volumes of gas used in operation and $11 million lower
cash-out sales related to gas imbalance settlements (offset in revenues). These
decreases were partially offset by $8 million higher depreciation expense due to
increased property, plant and equipment placed into service and $7 million
higher tracked costs which are passed through to customers (offset in revenues).

General and administrative costs decreased $20 million, or 24 percent, due
primarily to the absence of $11 million of 2002 early retirement pension costs
and reductions to employee-related benefits accruals.

Other (income) expense--net in 2003 includes a $25.5 million charge at
Northwest Pipeline to write-off capitalized software development costs for a
service delivery system following a decision not to implement. Subsequent to the
implementation of the same system at Transco in the second quarter of 2003 and a
determination of the unique and additional programming requirements that would
be needed to complete the system at Northwest Pipeline, management determined
that the system would not be implemented at Northwest Pipeline.

Segment profit, which includes equity earnings and income (loss) from
investments (included in investing income), decreased $10.7 million, or 4
percent, due to $67.4 million lower equity earnings and the $25.5 million charge
at Northwest Pipeline discussed previously. These decreases to segment profit
were partially offset by $39.8 million higher revenues, $12 million lower costs
and operating expenses and $20 million lower general and administrative costs
discussed above, as well as the absence of a $12.3 million 2002 write-off of
Gas Pipeline's investment in a cancelled pipeline project (income (loss) from
investment). The $67.4 million decrease to equity earnings reflects $27 million
lower equity earnings from the Gulfstream Natural Gas System, the absence of a
$27.4 million benefit in 2002 related to the contractual construction completion
fee received by an equity affiliate and the

43

Management's Discussion & Analysis (Continued)

absence of $12 million of equity earnings following the October 2002 sale of Gas
Pipeline's 14.6 percent ownership in Alliance Pipeline. The lower earnings for
Gulfstream Natural Gas System were primarily due to the absence in 2003 of
interest capitalized on internally generated funds as allowed by the FERC during
construction. The pipeline was placed into service during second-quarter 2002.

EXPLORATION & PRODUCTION

On February 20, 2003, Williams announced that it was evaluating the sale of
additional assets including selected Exploration & Production properties. During
second-quarter 2003, Williams completed a substantial portion of the targeted
asset sales from the Exploration & Production segment which included sales of
properties located primarily in Kansas, Colorado and New Mexico. The targeted
properties for sale, including the completed sales, represented approximately 16
percent of Williams' proved domestic reserves at December 31, 2002. Exploration
& Production has received net proceeds of approximately $417 million resulting
in net pre-tax gains of approximately $131.4 million, including $39.9 million of
pre-tax gains reported in discontinued operations related to the interests in
the Raton and Hugoton basins. The results of operations and gains on sales for
the Raton and Hugoton properties have been classified as discontinued
operations. The following discussion relates to the continuing operations of
Exploration & Production.

Two regulatory decisions during second-quarter 2003 will allow for Williams
to increase its recoverable natural gas reserves in two key areas of the U.S.
Rocky Mountain region. Approval from the Colorado Oil & Gas Conservation
Commission on a proposed plan for 10-acre bottom hole spacing will allow for the
drilling of more than 550 natural gas wells over the next decade in Colorado's
Piceance Basin. These additional wells are expected to substantially increase
the company's proved undeveloped reserves for that basin. A decision by the
Bureau of Land Management provides guidelines for developing coalbed natural gas
on federal lands in the Powder River Basin in Wyoming. Williams plans to drill
or participate in approximately 750 new Powder River wells in 2003, consistent
with its current capital spending plan.

Three Months Ended June 30, 2003 vs. Three Months Ended June 30, 2002

EXPLORATION & PRODUCTION'S revenues decreased $20.8 million, or 9 percent,
due primarily to $10 million lower domestic production revenues and $9 million
lower domestic gas management revenues (costs related to these revenues also
decreased by $9 million). The decrease in domestic production revenues reflects
$16 million lower revenues related to an 11 percent decrease in net domestic
production volumes, partially offset by $6 million higher revenues from
increased net realized average prices for production (including the effect of
hedge positions). The decrease in production volumes primarily results from the
sales of properties in 2002 and 2003, partially offset by increased production
volumes for properties retained. Approximately 84 percent of all domestic
production during second-quarter 2003 was hedged. Exploration & Production has
contracts that hedge approximately 95 percent of estimated production for the
remainder of 2003 at prices that average $3.72 per mcfe at the basin level.
These contracts are entered into with Energy Marketing & Trading which in turn
enters into offsetting derivative contracts with unrelated third parties.
Generally, Energy Marketing & Trading bears the counterparty performance risks
associated with unrelated third parties. Exploration & Production also has
derivative contracts with Energy Marketing & Trading that no longer qualify for
hedge accounting treatment (as a result of asset sales) or were never designated
in hedge relationships. The changes in fair value of these contracts are
recognized in revenues. The total impact, realized and unrealized, of these
instruments on 2003 revenues was a $15 million gain as compared to a $7 million
gain in 2002.

Domestic gas management revenues consist primarily of marketing activities
within the Exploration & Production segment that are not a direct part of the
results of operations for producing activities. These non-producing activities
include acquisition and disposition of other working interest and royalty
interest gas and the movement of gas from the wellhead to the tailgate of the
respective plants for sale to Energy Marketing & Trading or third parties.

44

Management's Discussion & Analysis (Continued)

Costs and expenses, including selling, general and administrative expenses,
decreased $15 million, including $6 million lower depreciation, depletion and
amortization expense, $9 million lower domestic gas management expenses and $2
million lower lease operating expense. The decreased depreciation, depletion and
amortization expense is due to the previously discussed asset sales. These
decreases were partially offset by $4 million higher operating taxes.

Other (income) expense - net includes approximately $91.5 million in net
gains on sales of assets during 2003, which are discussed above.

Segment profit increased $86.3 million due to the net gains on the sales of
assets which are discussed above.

Six Months Ended June 30,2003 vs. Six Months Ended June 30, 2002

EXPLORATION & PRODUCTION'S revenues increased $1.3 million, or less than
one percent. A favorable change in fair value of derivative contracts with
Energy Marketing & Trading that no longer qualify for hedge accounting treatment
(due to asset sales) or were never designated in hedge relationships was
substantially offset by $14 million lower domestic production revenues. The
total impact, realized and unrealized, of the non hedge derivative contracts on
2003 revenues was a $23 million gain as compared to $7 million of gains in 2002.
The $14 million lower domestic production revenues reflect $30 million lower
revenues due to a 9 percent decrease in net domestic production volumes,
partially offset by $16 million higher revenues from increased net realized
average prices for production (including the effect of hedge positions). The
decrease in production volumes primarily results from the sales of properties in
2002 and 2003, partially offset by increased production volumes for properties
retained. Approximately 86 percent of all domestic production during the first
six months of 2003 was hedged.

Costs and expenses, including selling, general and administrative expenses,
increased $3 million including $11 million higher operating taxes and $2 million
higher lease operating expenses, largely offset by $6 million lower exploration
expenses. The lower exploration expenses reflect the current focus of the
company on developing proved properties while reducing exploratory activities.

Other (income) expense - net includes approximately $91.5 million in net
gains on sales of assets during 2003, which were discussed previously.

Segment profit increased $93.6 million due primarily to the $91.5 million
in net gains on the sales of assets, which are discussed above.

MIDSTREAM GAS & LIQUIDS

Williams has announced its intention to sell certain Midstream Gas &
Liquids assets, including certain operations in Canada. Future asset sales would
have the effect of lowering revenues in periods following their sale. Williams'
board of directors has approved a plan authorizing management to negotiate and
facilitate the sale of the assets of Gulf Liquids New River Project LLC (Gulf
Liquids). The operations of Gulf Liquids have been classified as discontinued
operations.

Three Months Ended June 30,2003 vs. Three Months Ended June 30, 2002

MIDSTREAM GAS & LIQUIDS' revenues increased $300 million, or 68 percent,
due primarily to a $194 million effect of a change in the reporting of natural
gas liquids trading activities for which costs are no longer netted in revenues
as a result of the application of EITF Issue No. 02-3, combined with an $83
million increase in Canadian revenues and a $16 million increase in domestic
gathering and processing revenues. The increase in Canadian revenues is due
primarily to $80 million higher liquids sales resulting from an increase in
liquids sales prices at existing processing and fractionation facilities and
increased liquids sales volumes and prices at the olefins fractionation facility
that began operations at the end of the first quarter 2002. The increase in
domestic gathering and processing revenues is due primarily to a $24 million
increase in new deepwater fee-based and liquids sales

45

Management's Discussion & Analysis (Continued)

operations that were entering service and increasing operations during
second-quarter 2002, $5 million higher revenues resulting from additional
gathering volumes within the Gulf Coast regulated gathering system due primarily
to higher volumes contributed from deepwater fields and a $6 million increase
from new fee-based contractual arrangements around an existing Gulf Coast
facility. Offsetting these increases in domestic gathering and processing were
$7 million lower liquids sales from western and Gulf Coast facilities and $9
million lower gathering revenues following the sale of the Kansas-Hugoton
gathering system in third-quarter 2002. The decline in liquid sales from western
and Gulf Coast facilities is due primarily to lower liquids sales volumes as a
result of lower processing economics partially offset by an increase in liquids
sales prices within both regions.

Costs and operating expenses increased $294 million, or 84 percent, due
primarily to the $194 million effect of the change in reporting certain costs of
natural gas liquids trading activities discussed above. Costs and expenses were
also impacted by higher fuel and shrink costs at Canadian facilities of $84
million due primarily to higher gas prices. Also contributing to the increase in
costs was a $13 million increase in product feedstock costs at the ethylene
production facility within the Gulf Coast and $4 million in higher depreciation
expense due primarily to the new deepwater operations. Slightly offsetting these
increases were $16 million lower operating, maintenance and other costs within
western gathering and processing facilities due in part to the third-quarter
2002 sale of the Kansas Hugoton gathering system and an overall decrease in
maintenance spending and other operating costs. Domestic fuel and shrink costs
were $29 million higher at western processing facilities. This increase was
substantially offset by lower fuel and shrink costs at Gulf Coast facilities
primarily due to the decline in liquids production volumes.

Included in other (income) expense - net within segment costs and expenses
in 2003 are $6 million in impairment charges primarily related to impairments
taken on two domestic processing facilities. Included in other (income) expense
- - net within segment costs and expenses in 2002, was a $4.8 million charge
representing the impairment of assets to fair value associated with the sale of
the Kansas Hugoton natural gas gathering system.

Segment profit, which includes income (loss) from investments (included in
investment income (loss) on the Consolidated Statement of Operations), increased
$.7 million. Segment profit reflects a $12 million increase in domestic
gathering and processing operations, $4 million in lower general and
administrative costs within trading operations and a $4.8 million gain on the
sale of the equity investment in Rio Grande pipeline (income (loss) from
investments). These increases to segment profit were offset by a $14 million
decline in Gulf Coast olefins operating profit due primarily to higher feedstock
costs and lower production volumes at the ethylene production facility and a $9
million decline in operating profits from Canadian operations due primarily to
unfavorable liquids margins during the quarter. The $12 million increase in
domestic gathering and processing operations is due primarily to a $17 million
increase resulting from new deepwater fee-based and liquid sales operations
combined with the impact of additional gathering volumes within the Gulf Coast
regulated gathering system, new fee-based contractual arrangements at a Gulf
Coast facility, and lower maintenance spending and other operating costs.
Offsetting these increases is a $10 million decline in liquid sales margins from
western processing facilities resulting from lower sales volumes and rising fuel
and shrink costs, a $8.5 million impairment of an equity investment in Aux Sable
and a $7 million decrease in equity earnings. The rising fuel and shrink costs
in this region are attributable to the overall rising price of gas combined with
a reversal of the favorable basis differential for gas in Wyoming that was
experienced in first-quarter 2003 as additional transportation capacity out of
Wyoming has provided new markets for gas from this region. Liquids sales margins
from Gulf Coast facilities are relatively unchanged and remain at or near break
even levels as a result of poor processing economics due primarily to rising gas
prices. Poor processing economics in the Gulf Coast are being mitigated by new
contractual arrangements and other provisions that provide compensation for
processing gas in an uneconomic environment in order for customer's gas to
achieve pipeline quality standards. The decrease in equity earnings is due
primarily to operating losses generated from our investment in Aux Sable
combined with the impact of a $4 million charge associated with an accounting
adjustment recorded by Discovery.

Segment profit within Venezuela has remained relatively unchanged during
the period. The economic and political situation within Venezuela remains fluid
and volatile but has not significantly impacted the operations or cash flow at
Midstream's owned facilities. Contracts with PDVSA at these facilities provide
for payment in U.S. dollars and contain provisions that provide for adjustments
for inflation and minimum volume guarantees if the plants are operational.

46

Management's Discussion & Analysis (Continued)

Six Months Ended June 30, 2003 vs. Six Months Ended June 30, 2002

MIDSTREAM GAS & LIQUIDS' revenues increased $1,031 million, or 123 percent,
due primarily to a $664 million effect of a change in the reporting of natural
gas liquids trading activities for which costs are no longer netted in revenues
as a result of the application of EITF Issue No. 02-3, combined with a $236
million increase in Canadian revenues and a $128 million increase in domestic
gathering and processing revenues. The increase in Canadian revenues is due
primarily to $221 million higher liquids sales from processing and fractionation
facilities resulting from higher liquids sales prices at existing processing and
fractionation facilities and increased liquids sales volumes and prices at a new
olefin fractionation facility that began operations at the end of the first
quarter 2002. The increase in domestic gathering and processing revenues is due
primarily to $88 million higher liquids sales at western processing facilities
resulting from increased sales volumes and prices during the first quarter. Also
contributing to the increase is $65 million from new deepwater operations which
includes $24 million in liquids sales from a deepwater gas processing facility
that went into service in 2002. Partially, offsetting these increases is a $20
million decline in gathering revenues resulting from the sale of the Kansas
Hugoton gathering system in the third-quarter 2002.

Costs and operating expenses increased $954 million, or 144 percent, due
primarily to the $664 million effect of the change in reporting certain costs of
natural gas liquids trading activities discussed above. Costs and expenses were
also impacted by higher fuel and shrink costs at domestic and Canadian
processing facilities of $59 million and $210 million, respectively. The
increase in domestic fuel and shrink prices is largely due to higher natural gas
prices and production volumes. The increase in Canadian fuel and shrink costs is
due primarily to higher natural gas prices and increased operations at the new
olefins fractionation facility (Canada). Also contributing to the increase is
$32 million in product feedstock costs at the ethylene production facility
within the Gulf Coast, $17 million in Canadian depreciation and operations and
maintenance costs due primarily to full operation in 2003 at the new olefins
fractionation facility and $9 million in depreciation expense from domestic
gathering and processing facilities due primarily to the new deepwater
operations. Offsetting these increases is a $35 million decline in operating,
maintenance and other costs within western gathering and processing facilities
due in part to the sale of the Kansas Hugoton gathering system in third-quarter
2002 and an overall decrease in maintenance spending and other operating costs.

Segment profit, which includes income (loss) from investments (included in
investment income (loss) on the Consolidated Statement of Operations), increased
$63.7 million due primarily to an $81 million increase in operating profit from
domestic gathering and processing operations and the $4.8 million gain on the
sale of the equity investment in Rio Grande pipeline during second-quarter 2003
(income (loss) from investments). Partially offsetting these increases were a
$14 million decline in Canadian operating profit, an $8 million decline in
olefins operating profit and a $5 million decline in operating profit from
Venezuelan operations. The increase in domestic gathering and processing profits
is due primarily to a $22 million increase in liquids sales margins from
domestic processing plants within the western United States as a result of
higher natural gas liquids sales prices and a favorable basis differential for
natural gas within Wyoming which had the effect of lower fuel and shrink prices
at processing facilities in this region during the first quarter of 2003. This
favorable basis differential tightened during the second quarter of 2003 as new
transportation capacity for natural gas from this region had the effect of
increasing fuel and shrink costs and lowering margins in the region during
second-quarter 2003. Also contributing to the increase in domestic gathering and
processing profits was $35 million associated with new deepwater operations, as
well as the incremental profitability resulting from additional gathering
volumes, new fee-based contractual arrangements, and lower maintenance spending
and other operating costs. Offsetting the increases in domestic gathering and
processing operating profit is a $10 million decline in equity earnings from
Discovery pipeline and an $8.5 million impairment of the equity investment in
Aux Sable (income loss from investments). The decline in the equity earnings of
Discovery reflects a $12 million charge associated with adjustments recorded by
Discovery primarily to expense certain amounts previously capitalized during
periods prior to Williams becoming the operator. The decline in Canadian
operating results includes $8 million bad debt expense associated with a single
customer. The decline in Gulf Cost olefins profits is due primarily to higher
feedstock prices and lower production volumes at the ethylene fractionation
facility. The decline in Venezuelan segment profit is due primarily to curtailed
operations resulting from a fire at one of the high-pressure gas compression
facilities in February 2003, partially offset by an improvement in equity
earnings from Accroven and lower foreign currency exchange losses in the first
quarter of 2003 as a result of currency exchange controls in place within
Venezuela.

47

Management's Discussion & Analysis (Continued)

OTHER

Other segment loss for the three and six months ended June 2003 includes a
$42.4 million impairment related to the investment in equity and debt securities
of Longhorn Partners Pipeline, LP. The impairment results from management's
determination that there has been an other than temporary decline in estimated
fair value of the investments.

FAIR VALUE OF ENERGY RISK MANAGEMENT AND TRADING ACTIVITIES

The chart below reflects the fair value of energy trading derivatives for
Energy Marketing & Trading and Midstream Gas & Liquids that have been assessed
to be trading contracts, separated by the year in which the recorded fair value
is expected to be realized. As of December 31, 2002, Energy Marketing & Trading
reported a net asset of approximately $1,632 million related to the fair value
of energy risk management and trading contracts. With the adoption of EITF Issue
No. 02-3 on January 1, 2003, approximately $1,193 million of that pre-tax fair
value pertained to non-derivative energy contracts, and this amount was reversed
through a cumulative adjustment from a change in accounting principle. Trading
contracts include those derivative contracts that have not been designated as or
do not qualify as SFAS No. 133 hedges and that are held to provide price risk
management services to third party customers. These contracts are accounted for
using the mark to market accounting method. As reported in the Form 10-Q for
March 31, 2003, all derivative contracts that had not been designated as or did
not qualify as SFAS No. 133 hedges were presented as trading contracts. However,
consistent with Williams' continued evaluation of its future involvement in the
merchant power and generation business, derivative contracts have been
reevaluated for trading versus non-trading classification at June 30, 2003 on a
contract by contract basis. The table of trading contracts presented below
includes only those contracts that do not hedge or mitigate Energy Marketing &
Trading's or Midstream Gas & Liquids' own long-term structured contract
positions and which were entered into to provide risk management services to
third parties. Also, the table below does not reflect the fair value of
non-derivative energy contracts which was reversed in the cumulative accounting
change adjustment recorded in the first quarter of 2003.

(In millions)

Energy Marketing & Trading holds a substantial portfolio of non-trading
derivative contracts. Certain of these have not been designated as or do not
qualify as SFAS No. 133 hedges, and are accounted for using the mark to market
method of accounting. As of June 30, 2003 the fair value of these non-trading
derivative contracts was a net asset of $803.1 million. Energy Marketing &
Trading also holds a number of SFAS No. 133 cash flow hedges on behalf of other
business units, hedges associated with owned generation assets, and other
miscellaneous hedges. As of June 30, 2003 the fair value of these hedges was a
net liability of approximately $281.9 million. Various other business units
within Williams also possess certain SFAS No. 133 hedge liabilities of
approximately $24.9 million.

48

Management's Discussion & Analysis (Continued)

Estimates and assumptions regarding counterparty performance and credit risk
considerations

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

Risks surrounding counterparty performance and credit could ultimately impact
the amount and timing of the cash flows expected to be realized. Energy
Marketing & Trading and Midstream Gas & Liquids continually assess this risk and
have credit protection within various agreements to call on additional
collateral support in the event of changes in the creditworthiness of the
counterparty. Additional collateral support could include letters of credit,
payment under margin agreements, guarantees of payment by creditworthy parties,
or in some instances, transfers of the ownership interest in natural gas
reserves or power generation assets. In addition, Energy Marketing & Trading and
Midstream Gas & Liquids enter into netting agreements to mitigate counterparty
performance and credit risk.

The gross forward credit exposure from Energy Marketing & Trading's and
Midstream Gas & Liquids' derivative contracts as of June 30, 2003 is summarized
as below.

In addition to the gross Energy Marketing & Trading and Midstream Gas &
Liquids derivative exposure discussed above, other business units within
Williams possess an additional $30 million in gross derivative asset exposure.

Energy Marketing & Trading and Midstream Gas & Liquids assess their credit
exposure on a net basis when appropriate and contractually allowed. The net
forward credit exposure from Energy Marketing & Trading's and Midstream Gas &
Liquids' derivative contracts as of June 30, 2003 is summarized as below.

- ----------

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

49

Management's Discussion & Analysis (Continued)

(b) One counterparty within the California power market represents
greater than ten percent of derivative assets and is included in
"investment grade." Standard & Poor's and Moody's Investor's
Service do not currently rate this counterparty. This
counterparty has been included in the "investment grade" column
based upon contractual credit requirements in the event of
assignment or novation.

The overall net credit exposure from derivative contracts of $1,067.4
million at June 30, 2003, represents an overall decrease in derivative credit
exposure of approximately 13 percent on a comparable basis from December 31,
2002. In 2002 and 2003 Energy Marketing & Trading closed out various trading
positions and as a result has not suffered significant losses due to recent
bankruptcy filings of certain counterparties in second-quarter 2003. In
addition, Energy Marketing and Trading settled a dispute with a counterparty in
second-quarter 2003 and received $90 million in cash while recognizing an
insignificant loss for the settlement in second-quarter 2003. Credit
constraints, declines in market liquidity, and financial instability of market
participants, are expected to continue and potentially worsen in 2003. Continued
liquidity and credit constraints of Williams may also significantly impact
Energy Marketing & Trading's ability to manage market risk and meet contractual
obligations.

Electricity and natural gas markets, in California and elsewhere, continue
to be subject to numerous and wide-ranging federal and state regulatory
proceedings and investigations, as well as civil actions, regarding among other
things, market structure, behavior of market participants, market prices, and
reporting to trade publications. Energy Marketing & Trading may be liable for
refunds and other damages and penalties as a part of these actions. Each of
these matters as well as other regulatory and legal matters related to Energy
Marketing & Trading are discussed in more detail in Note 11 to the Consolidated
Financial Statements. The outcome of these matters could affect the
creditworthiness and ability to perform contractual obligations of Energy
Marketing & Trading as well as the creditworthiness and ability to perform
contractual obligations of other market participants.

FINANCIAL CONDITION AND LIQUIDITY

LIQUIDITY

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

o Cash-equivalent investments at the corporate level of $2.8
billion at June 30, 2003, as compared to $1.3 billion at December
31, 2002.

o Cash and cash-equivalent investments of various international and
domestic entities of $437 million at June 30, 2003 as compared to
$352 million at December 31, 2002.

o Cash generated from sales of assets.

o Cash generated from operations.

o $413 million available under Williams' new revolving credit
facility at June 30, 2003. This new facility is primarily for the
purpose of issuing letters of credit and must be collateralized
at 105 percent of the level utilized (see Note 10). At December
31, 2002, Williams had a combined $480 million available under
the previous revolving and letter of credit facilities.

Williams has an effective shelf registration statement with the Securities
and Exchange Commission that enables it to issue up to $3 billion of a variety
of debt and equity securities. Subsequent to the $800 million issuance of senior
unsecured securities on June 10, 2003, the current availability under this shelf
registration is $2.2 billion.

In addition, there are outstanding registration statements filed with the
Securities and Exchange Commission for Williams' wholly owned subsidiaries:
Northwest Pipeline and Transcontinental Gas Pipe Line. As of August 11, 2003,
approximately $350 million of shelf availability remains under these outstanding
registration statements and may be used to issue a variety of debt securities.
Interest rates, market conditions, and industry conditions will affect amounts
raised, if any, in the capital markets. On March 4, 2003, Northwest Pipeline
completed an offering of $175 million of 8.125 percent senior notes due 2010.
The $350 million of shelf availability mentioned above was not affected by this
offering.

50

Management's Discussion & Analysis (Continued)

Capital and investment expenditures for 2003 are estimated to total
approximately $1 billion. Williams expects to fund capital and investment
expenditures, debt payments and working-capital requirements through (1) cash on
hand, (2) cash generated from operations, (3) the sale of assets, and/or (4)
amounts available under Williams' revolving credit facility.

Outlook

Williams expects to generate proceeds, net of related debt, of nearly $4
billion from asset sales during 2003 and 2004. Through June 30, 2003, Williams
has received $2.4 billion in net proceeds from asset sales and its board of
directors has approved resolutions that authorized management to negotiate and
facilitate the sales of the assets of Gulf Liquids New River Project LLC and
Williams' Alaska operations. Williams has also reached agreements to sell
certain additional natural gas exploration and production properties in Utah for
$49 million. In August 2003, Williams announced sales of assets completed
subsequent to June 30, 2003, and agreements to sell various assets for cash
proceeds in excess of $80 million. These assets include:

o The West Stoddart natural gas processing plant in Western Canada,
which is part of Midstream Gas & Liquids,

o Williams' 20 percent ownership interest in West Texas LPG
Pipeline Limited Partnership which transports natural gas liquids
in Texas and is part of Midstream Gas & Liquids,

o Distributed-generation units and an associated third-party
contract, which is part of Energy Marketing & Trading, and

o Refined products management operations, which are part of the
Other segment.

The nearly $4 billion targeted level of assets sales does not include any
proceeds from sales of contracts within Energy Marketing & Trading. Any proceeds
from sales of contracts would be additive to the assets sales. For the six month
period ended June 30, 2003, Energy Marketing & Trading has sold contracts for
proceeds totaling approximately $206 million. In August 2003, Williams also
announced that it had agreed to terminate a long-term power contract with
Allegheny Energy Supply Company, LLC, a subsidiary of Allegheny Energy, Inc.,
for cash consideration of $128 million payable to Williams. The agreement is
subject to certain conditions, including a provision that Allegheny successfully
complete the sale of its energy supply agreement with the California Department
of Water Resources.

Based on the Company's forecast of cash flows and liquidity, Williams
believes that it has, or has access to, the financial resources and liquidity to
meet future cash requirements. For the remainder of 2003 and including periods
through first-quarter 2004, the Company has scheduled debt retirements of
approximately $1.8 billion.

OPERATING ACTIVITIES

For the six months ended June 30, 2003, Williams recorded approximately
$121 million in provisions for losses on property and other assets consisting
primarily of the $42.4 million impairment of Williams' investment in Longhorn
Partners Pipeline L.P., $25.5 million charge related to write-off of software
development costs at Northwest Pipeline, $13.5 million impairment of an
investment in a company holding phosphate reserves and the $12 million
impairment of Algar Telecom S.A.

The net gain on disposition of assets primarily consists of the gains on
the sales of natural gas properties during second-quarter 2003.

The accrual for fixed rate interest included in the RMT note payable on the
Consolidated Statement of Cash Flows represents the quarterly noncash
reclassification of the deferred fixed rate interest from an accrued liability
to the RMT note payable. The amortization of deferred set-up fee and fixed rate
interest on the RMT note payable relates to amounts recognized in the income
statement as interest expense, which were not paid until maturity. The RMT note
payable was repaid in June 2003 (see Note 10).

FINANCING ACTIVITIES

For a discussion of borrowings and repayments in 2003, see Note 10 of Notes
to Consolidated Financial Statements.

Dividends paid on common stock are currently $.01 per common share on a
quarterly basis and total $10.3 million for the six months ended June 30, 2003.
Additionally, one of the covenants under the indenture

51

Management's Discussion & Analysis (Continued)

for the new $800 million senior unsecured notes due 2010 currently limits the
quarterly common stock dividends paid by Williams to not more than $.02 per
common share. This restriction may be removed in the future as Williams'
financial condition improves and certain requirements in the covenants are met.
Williams also paid $32.6 million in dividends on the 9 7/8 percent cumulative-
convertible preferred shares that were redeemed in June 2003.

INVESTING ACTIVITIES

For 2003, net cash proceeds from asset dispositions, sales of businesses
and disposition of investments include the following:

o $793 million related to the sale of Texas Gas Transmission
Corporation

o $431 million (net of cash held by Williams Energy Partners)
related to the sale of Williams' general partnership interest and
limited partner investment in Williams Energy Partners

o $417 million related to certain natural gas exploration and
production properties in Kansas, Colorado and New Mexico

o $452 million related to the sale of the Midsouth refinery

o $188 million related to the sale of the Williams travel centers

o $60 million related to the sale of Williams' equity interest in
Williams Bio-Energy L.L.C.

o $40 million related to the sale of the Worthington facility

COMMITMENTS

The table below summarizes the more significant contractual obligations and
commitments by period. These amounts do not reflect debt reductions contingent
upon asset sales (see Note 10).

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

(2) Energy Marketing & Trading has entered into certain contracts giving
Williams the right to receive fuel conversion services as well as
certain other services associated with electric generation facilities
that are either currently in operation or are to be constructed at
various locations throughout the continental United States.

52

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 debt issuances and debt payments in both the first and second
quarters of 2003. During 2003, Williams has repaid or retired the RMT note
payable (see Note 10), $224 million on the variable rate debt of Snow Goose LLC,
$448.2 million of variable rate debt due in 2003, $139.8 million of capitalized
lease obligations and $78.5 million of variable rate debt due in 2006. During
2003, Williams, or its subsidiaries, issued the following debt:

o March 2003-Northwest Pipeline Corporation, a subsidiary of Williams,
through a private debt placement, issued $175 million of 8.125 percent
notes payable in 2010

o May 2003-Williams issued $300 million of 5.5 percent junior
subordinated convertible debentures, due 2033.

o May 2003-Williams RMT Production Company issued a $500 million
secured, subsidiary-level loan, due in 2007, at a floating interest
rate of 3.75 percent over the six-month London InterBank Offered Rate

o June 2003-Williams issued $800 million of 8.625 percent senior
unsecured notes due in 2010 under the company's $3 billion shelf
registration statement

COMMODITY PRICE RISK

Energy Marketing & Trading and Midstream Gas & Liquids are exposed to the
impact of market fluctuations in the price of natural gas, electricity, crude
oil, refined products, and natural gas liquids as a result of managing risk
associated with the Company's owned energy related assets and long-term
energy-related contracts as well as its proprietary trading activities. Energy
Marketing & Trading and Midstream Gas & Liquids manage the risks associated with
these market fluctuations using various derivatives for both trading and
non-trading purposes. Certain of these derivative contracts are designated as
cash flow hedges under SFAS No. 133 and others are accounted for under the
mark-to-market method of accounting. Derivative contracts are subject to changes
in energy commodity market prices, volatility and correlation of those commodity
prices, the portfolio position of the contracts, the liquidity of the market in
which the contract is transacted and changes in interest rates. The risk in the
trading and non-trading portfolios are measured utilizing a value-at-risk
methodology to estimate the potential one-day loss from adverse changes in the
fair value of the portfolios. Value at risk requires a number of key assumptions
and is not necessarily representative of actual losses in fair value that could
be incurred from the portfolios. The value-at-risk model assumes that, as a
result of changes in commodity prices, there is a 95 percent probability that
the one-day loss in fair value of the portfolios will not exceed the value at
risk. 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 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 has historically been
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. Commodity
contracts designated as a normal purchase or sale pursuant to SFAS No. 133 and
non-derivative energy contracts have been excluded from the estimation of value
at risk.

TRADING

The trading portfolio consists of derivative contracts held to provide
price risk management services to third-party customers based on a contract by
contract assessment. These contracts are accounted for using the mark-to-market
accounting method. At June 30, 2003 and December 31, 2002, the value at risk for
the derivative contracts considered to be held for trading purposes was $6.5
million and $50.2 million, respectively. The adoption of EITF Issue No. 02-3
resulted in non-derivative energy contracts no longer being accounted for and
reported at fair value, therefore such contracts have not been included in the
June 30, 2003 trading value at risk. For the disclosure in the Form 10-Q for
March 31, 2003, Energy Marketing & Trading and Midstream Gas & Liquids
considered all derivatives other than those designated as cash flow hedges under
SFAS No. 133 to be trading. As previously noted, consistent with Williams'
continued evaluation of its future involvement in the merchant power and
generation business, in the second quarter of 2003 trading contracts were
reevaluated to include only those entered into to provide risk management
services to third party customers and not those contracts hedging or mitigating
the market risk of Energy Marketing & Trading and Midstream Gas & Liquid's own
long-term structured portfolios.

53

Item 3. Quantitative and Qualitative Disclosures About Market Risk (concluded)

NON-TRADING

The non-trading portfolio consists of derivative contracts held to hedge
changes in energy commodity prices within Exploration & Production, the
non-trading operations of Midstream Gas & Liquids and the non-trading operations
of Energy Marketing & Trading. Exploration & Production is exposed to commodity
price risk associated with the sales price of the natural gas and crude oil it
produces. Midstream Gas & Liquids is exposed to commodity price risk related to
natural gas purchases, natural gas liquids purchases and sales, and electricity
costs. Energy Marketing & Trading is exposed to commodity price risk related to
electricity purchased and sold and natural gas purchased for the production of
electricity. At June 30, 2003, the non-trading portfolio consists of derivative
contracts designated as cash flow hedges under SFAS No. 133 and non-trading
derivative contracts accounted for under the mark-to-market method of
accounting. The value-at-risk model did not consider the underlying commodity
positions to which the cash flow hedges relate. Therefore, it is not
representative of economic losses that could occur on a total non-trading
portfolio basis that includes the underlying commodity positions. At June 30,
2003 and December 31, 2002, the value at risk for the non-trading derivative
commodity instruments was approximately $23.6 million and $45 million,
respectively.

ITEM 4. CONTROLS AND PROCEDURES

An evaluation of the effectiveness of the design and operation of Williams'
disclosure controls and procedures (as defined in Rule 13a-15(e) and 15(d)-(e)
of the Securities Exchange Act)(Disclosure Controls) was performed as of the end
of the period covered by this report. This evaluation was performed under the
supervision and with the participation of Williams' management, including
Williams' Chief Executive Officer and Chief Financial Officer. Based upon that
evaluation, Williams' Chief Executive Officer and Chief Financial Officer
concluded that, subject to the limitations noted below, these Disclosure
Controls are effective.

Williams' management, including its Chief Executive Officer and Chief
Financial Officer, does not expect that Williams' Disclosure Controls or its
internal controls over financial reporting (Internal Controls) will prevent all
error and all fraud. A control system, no matter how well conceived and
operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met. Further, the design of a control
system must reflect the fact that there are resource constraints, and the
benefits of controls must be considered relative to their costs. Because of the
inherent limitations in all control systems, no evaluation of controls can
provide absolute assurance that all control issues and instances of fraud, if
any, within the company have been detected. These inherent limitations include
the realities that judgments in decision-making can be faulty, and that
breakdowns can occur because of simple error or mistake. Additionally, controls
can be circumvented by the individual acts of some persons, by collusion of two
or more people, or by management override of the control. The design of any
system of controls also is based in part upon certain assumptions about the
likelihood of future events, and there can be no assurance that any design will
succeed in achieving its stated goals under all potential future conditions.
Over time, controls may become inadequate because of changes in conditions, or
the degree of compliance with the policies or procedures may deteriorate.
Because of the inherent limitations in a cost-effective control system,
misstatements due to error or fraud may occur and not be detected. Williams
monitors its Disclosure Controls and Internal Controls and makes modifications
as necessary; Williams' intent in this regard is that the Disclosure Controls
and the Internal Controls will be maintained as systems change and conditions
warrant.

There has been no change in Williams' Internal Controls that occurred
during the period covered by this report that has materially affected, or is
reasonably likely to materially affect, Williams' Internal Controls.

54

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The information called for by this item is provided in Note 11 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

The terms of the $800 million 8.625 percent senior unsecured notes due 2010
issued on June 10, 2003 currently limits the payment of quarterly dividends to
no greater than $.02 per common share. This restriction may be lifted if certain
conditions, including Williams attaining an investment grade rating from both
Moody's Investor's Services and Standard & Poor's, are met.

On May 28, 2003, Williams issued $300 million of 5.5 percent junior subordinated
convertible debentures due 2033 in a private placement. These notes, which are
not callable by the company for seven years, are convertible at the option of
the holder into Williams common stock at a conversion price of $10.89 per share.
The proceeds were used to redeem all of the outstanding 9 7/8 percent
cumulative-convertible preferred shares.

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

The Annual Meeting of Stockholders of the Company was held on May 15, 2003. At
the Annual Meeting, three individuals were elected as directors of the Company
and seven individuals continue to serve as directors pursuant to their prior
elections. The appointment of Ernst & Young LLP as the independent auditor of
the Company for 2003 was ratified and an amendment to The Williams Companies,
Inc. 2002 Incentive Plan was approved. A shareholder proposal regarding an audit
services policy was not approved.

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

Election of Directors

Ratification of Appointment of Independent Auditors

Approval of an Amendment to The Williams Companies, Inc. 2002 Incentive Plan

Approval of a Policy on Audit Services

55

Item 6. Exhibits and Reports on Form 8-K

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

Exhibit 4.1 - Ninth Supplemental Indenture dated June 10, 2003 between
The Williams Companies, Inc. as Issuer and JPMorgan Chase Bank as
Trustee.

Exhibit 4.2-- Indenture dated as of May 28, 2003, by and between The
Williams Companies, Inc. and JPMorgan Chase Bank, as Trustee for the
issuance of the 5.5% Junior Subordinated Convertible Debentures due
2033.

Exhibit 4.3 - Registration Rights Agreement between The Williams
Companies, Inc., as Issuer, and Lehman Brothers Inc., as Initial
Purchaser dated May 28, 2003.

Exhibit 10.1 - U.S. $500,000,000 Term Loan Agreement among Williams
Production Holdings LLC, Williams Production RMT Company, as Borrower,
the Several Lenders from time to time parties thereto, Lehman Brothers
Inc. and Banc of America Securities LLC as Joint Lead Arrangers,
Citigroup USA, Inc. and JPMorgan Chase Bank, as Co-Syndication Agents,
Bank of America, N.A., as Documentation Agent, and Lehman Commercial
Paper Inc., as Administrative Agent dated as of May 30, 2003.

Exhibit 10.2-- Guarantee and Collateral Agreement made by Williams
Production Holdings LLC, Williams Production RMT Company and certain
of its Subsidiaries in favor of Lehman Commercial Paper Inc. as
Administrative Agent dated as of May 30, 2003.

Exhibit 10.3 - U.S. $800,000,000 Credit Agreement dated as of June 6,
2003, among The Williams Companies, Inc., Northwest Pipeline
Corporation, Transcontinental Gas Pipe Line Corporation, as Borrowers,
Citibank, N.A., as Administrative Agent and Collateral Agent, Bank of
America, N.A., as Syndication Agent, JPMorgan Chase Bank, as
Documentation Agreement, Citibank, N.A. and Bank of America, N.A as
Issuing Banks, the banks named therein as Banks and Citigroup Global
Markets Inc. and Banc of America Securities LLC as Joint Lead
Arrangers and Joint Book Runners.

Exhibit 10.4-- Security Agreement dated as of June 6, 2003, among The
Williams Companies, Inc., as Grantor, Citibank, N.A., as Collateral
Agent and Citibank, N.A. as Securities Intermediary.

Exhibit 10.5-- Stock Purchase Agreement dated as of May 19, 2003,
between MEHC Investment, Inc., MidAmerican Energy Holdings Company,
and The Williams Companies, Inc.

Exhibit 10.6 - Purchase Agreement by and among Williams Energy
Services, LLC, Williams Natural Gas Liquids, Inc. and Williams GP LLC
collectively, as Selling Parties, and WEG Acquisitions, L.P. as Buyer
for the purchase and sale of all the membership interests of WEG GP
LLC, all the Common Units and Subordinated Units of Williams Energy
Partners, L.P. owned by Williams Energy Services, LLC and Williams
Natural Gas Liquids, Inc. and all of the Class B Common Units of
Williams Energy Partners, L.P. dated as of April 18, 2003.

Exhibit 10.7 - Amendment No. 1 to the Purchase Agreement dated as of
April 18, 2003 by and among Williams Energy Services, LLC, Williams
Natural Gas Liquids, Inc. and Williams GP LLC collectively, as Selling
Parties, and WEG Acquisitions, L.P. as Buyer for the purchase and sale
of all the membership interests of WEG GP LLC, all the Common Units
and Subordinated Units of Williams Energy Partners, L.P. owned by
Williams Energy Services, LLC and Williams Natural Gas Liquids, Inc.
and all of the Class B Common Units of Williams Energy Partners, L.P.
dated as of May 5, 2003.

Exhibit 10.8 -Transition Services Agreement by and between The
Williams Companies, Inc. and WEG Acquisitions, L.P. dated June 17,
2003.

Exhibit 10.9 - New Omnibus Agreement among WEG Acquisitions, L.P.,
Williams Energy Services, LLC, Williams Natural Gas Liquids, Inc. and
The Williams Companies, Inc. dated as of June 17, 2003.

56

Exhibit 10.10 - Assumption Agreement dated June 17, 2003 by and
between The Williams Companies, Inc. and WEG Acquisitions, L.P.

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

Exhibit 31.1 - Certification of Chief Executive Officer pursuant to
Rules 13a-14(a) and 15d-14(a) promulgated under the Securities
Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation
S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.

Exhibit 31.2 - Certification of Chief Financial Officer pursuant to
Rules 13a-14(a) and 15d-14(a) promulgated under the Securities
Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation
S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.

Exhibit 32--Certification of Chief Executive Officer and Chief
Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) During second-quarter 2003, Williams filed a Form 8-K on the
following dates reporting events under the specified items: April 10,
2003 Item 9; April 15, 2003 Item 9; April 16, 2003 Item 9; April 21,
2003 Item 5 and Item 9; April 22, 2003 Item 5 and Item 7; April 25,
2003 Item 9; May 13, 2003 Item 9 and Item 12; May 19, 2003 Item 9; May
21, 2003 Item 9; May 23, 2003 Item 5 and Item 7; May 29, 2003 Item 9;
May 30, 2003 Item 9; June 2, 2003 Item 9; June 5, 2003 Item 7; June 9,
2003 Item 5 and Item 7; June 10, 2003 Item 5 and Item 7; June 13, 2003
Item 7; June 19, 2003 Item 9; and June 27, 2003 Item 5 and Item 7.

57

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 12, 2003

INDEX TO EXHIBITS
-----------------

Exhibit 10.10-- Assumption Agreement dated June 17, 2003 by and between The
Williams Companies, Inc. and WEG Acquisitions, L.P.

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

Exhibit 31.1-- Certification of Chief Executive Officer pursuant to Rules
13a-14(a) and 15d-14(a) promulgated under the Securities
Exchange Act of 1934, as amended, and Item 601(b)(31) of
Regulation S-K, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.

Exhibit 31.2-- Certification of Chief Financial Officer pursuant to Rules
13a-14(a) and 15d-14(a) promulgated under the Securities
Exchange Act of 1934, as amended, and Item 601(b)(31) of
Regulation S-K, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.

Exhibit 32-- Certification of Chief Executive Officer and Chief Financial
Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.