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 September 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
--- ---

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 October 31, 2003
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Common Stock, $1 par value 518,183,708 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 cause actual
results to differ materially from forward-looking statements 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 $2.9
million, $85.6 million, $60.6 million and $60.7 million at September 30,
2003, December 31, 2002, September 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 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 and developing a balance sheet capable of supporting retained
businesses with favorable returns and opportunities for growth. As part of this
plan, Williams expects to generate proceeds, net of related debt, of
approximately $4 billion during 2003 and 2004, primarily from asset sales as
well as the contribution of proceeds from the sale and/or termination of certain
contracts within its marketing and trading portfolio. Through September 30,
2003, Williams received approximately $3.1 billion in net proceeds from the sale
of assets and businesses and the sale and/or termination of certain marketing
and trading contracts. Of this amount, $2.8 billion was realized from the sale
of assets and businesses, including the following:

o the retail travel centers;

o the Midsouth refinery;

o Texas Gas Transmission Corporation;

o Williams' general partnership interest and limited partner investment in
Williams Energy Partners;

o certain gas processing, natural gas liquids fractionation, storage and
distribution operations in western Canada and at a plant in Redwater,
Alberta;

o Williams' interest in Williams Bio-Energy L.L.C.;

o certain natural gas exploration and production properties in Kansas,
Colorado, Utah and New Mexico; and

o Williams' investment in soda ash operations in Colorado.

As previously announced, the Company intends to reduce its commitment to the
activities of Williams Power Company (Power) (formerly named Williams Energy
Marketing & Trading Company). This reduction may be realized by entering into a
joint venture with a third party or through the sale of a portion of or all of
the marketing and trading portfolio. Through the nine month period ended
September 30, 2003, Power has sold or entered into agreements to terminate
certain contracts for cash proceeds totaling approximately $315 million, which
is included in the $3.1 billion total noted above.

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 Williams Production RMT Company (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 September 30, 2003, the Company has notes payable and long-term debt
maturing through first-quarter 2004 totaling approximately $1.6 billion,
consisting largely of $1.4 billion of Williams' senior unsecured 9.25 percent
notes. In the third quarter of 2003, Williams' Board of Directors authorized the
Company to retire or otherwise prepay up to $1.8 billion of debt, including $1.4
billion designated for the Company's 9.25 percent notes due March 15, 2004. On
October 8, 2003, the Company announced a cash tender offer for any and all of
these $1.4 billion notes as well as cash tender offers and consent solicitations
for approximately $241 million of additional outstanding notes and debentures.
The Company will use available cash to fund the purchase of any notes accepted
under the tender offers. As of October 31, 2003, approximately $720 million of
the 9.25 percent notes had been accepted for purchase. Additionally, Williams
received tenders of notes and deliveries of related consents from holders of
approximately $230 million of the other notes. The tender offers are scheduled
to expire on November 6, 2003. 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.

5

Notes (Continued)

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 September 30, 2003, its results of operations for the
three and nine months ended September 30, 2003 and 2002 and cash flows for the
nine months ended September 30, 2003 and 2002.

During the second quarter of 2003, Power corrected the accounting treatment
previously applied to certain third party derivative contracts during 2002 and
2001. As a result, Power recognized $80.7 million of revenue in the
second-quarter of 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 that the Company now believes should not have been 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.

2. Basis of presentation
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During third-quarter 2003, Williams announced the name change of Williams
Energy Marketing and Trading to Power. Williams' management believes the new
name more accurately reflects the emphasis of the segment's current business
activity.

In accordance with the provisions related to discontinued operations within
Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," the 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; and

o certain gas processing, natural gas liquids fractionation, storage and
distribution operations in western Canada and at a plant in Redwater,
Alberta, previously part of the Midstream Gas & Liquids 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.

6

Notes (Continued)

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" (EITF 02-3). The Issue rescinded
EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities." EITF 02-3 precludes fair value accounting for
commodity trading inventories, and for energy trading contracts that are not
derivatives pursuant to SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities." 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). Approximately $755 million of the reduction
in net income relates to Power, 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 each 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. 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. Physical commodity inventories previously reflected at fair value are
now stated at average cost, not in excess of market. Inventory acquisition
costs, and the related costs and operating expenses in the Consolidated
Statement of Operations for storable commodities physically settled under
derivative contracts, reflect market prices on the date of physical settlement.
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 $469 million net asset representing the
remaining fair value of certain derivative contracts for which Power elected the
normal purchases and sales exclusion during second-quarter 2003 in accordance
with SFAS No. 133. Through September 30, 2003, $10 million of the initial fair
value of these contracts has been recognized in earnings. The remaining balance
will be recognized in earnings over the remaining periods of the contracts'
terms based on the estimated cash flows of the contracts at the time of
election. As of September 30 2003, the remaining terms of contracts for which
the normal purchases and sales exclusion has been elected range from
approximately four to seven years.

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

7

Notes (Continued)

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. If the Statement had 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.

4. Asset sales, impairments and other items
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Williams evaluates its 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.

8

Notes (Continued)

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.

9

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 months ended September 30, 2003,
is greater than the federal statutory rate due primarily to foreign operations
and state income taxes. For the nine months ended September 30, 2003, the
effective income tax rate is greater than the federal statutory rate due
primarily to nondeductible expenses, state income taxes, foreign operations, the
financial impairment of certain investments, and capital losses generated for
which valuation allowances were established.

The effective income tax rate for the three months ended September 30, 2002,
is less than the federal statutory rate due primarily to foreign operations
which reduce the tax benefit of the pretax loss. For the nine months ended
September 30, 2002, the effective income tax rate is less than the federal
statutory rate due primarily to the impairment of goodwill which is not
deductible for income tax purposes and foreign operations both of which reduce
the tax 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 September 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 nine months
ended September 30, 2003 and 2002 are as follows:

10

Notes (Continued)

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

HELD FOR SALE AT SEPTEMBER 30, 2003

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 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 (loss) on sales in the preceding
table of summarized results of discontinued operations. 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 of that approval. These operations were part of the
previously reported Petroleum Services segment.

Gulf Liquids New River Project LLC

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 of summarized
results of discontinued operations. Fair value was estimated based on a
discounted cash flow analysis. The sale of these operations is expected to be
completed within one year of the board's approval. These operations were part of
the Midstream Gas & Liquids segment.

11

Notes (Continued)

2003 COMPLETED TRANSACTIONS

Canadian liquids operations

During the third quarter of 2003, Williams completed the sale of certain
gas processing, natural gas liquids fractionation, storage and distribution
operations in western Canada and at its Redwater, Alberta plant for total
proceeds of approximately $228 million in cash and a $17.7 million short-term
note receivable. Williams recognized pre-tax gains totaling $86.6 million on the
sales which are included in (impairments) and gain (loss) on sales in the
preceding table of summarized results of discontinued operations. These
operations were part of the Midstream Gas & Liquids segment.

Soda ash operations

On September 9, 2003, Williams completed the sale of its soda ash mining
facility located in Colorado. The December 31, 2002 carrying value reflected the
then estimated fair value less cost to sell. During 2003, ongoing sale
negotiations continued to provide new information regarding estimated fair
value, and, as a result, additional impairment charges of $17.4 million were
recognized in 2003. Williams recognized a loss on the sale of $4.2 million.
These impairments, the loss on the sale and $92.3 million of 2002 impairments
(including $48.2 million during third-quarter 2002), are included in
(impairments) and gain (loss) on sales in the preceding table of summarized
results of discontinued operations. The soda ash operations were part of the
previously reported International segment.

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 pre-tax gain of $275.6
million on the sale, which is included in (impairments) and gain (loss) on sales
in the preceding table of summarized results of discontinued operations. The
Company deferred an additional $113 million associated with Williams'
indemnifications of the purchasers for a variety of matters, including
obligations that may arise associated with existing 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
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 pre-tax loss on the sale of $6.4
million. Third-quarter 2002 included an impairment charge of $144.3 million.
Both the additional loss and impairment charge are included in (impairments) and
gain (loss) on sales in the preceding table of summarized results of
discontinued operations. These operations were part of the previously reported
Petroleum Services segment.

Texas Gas

On May 16, 2003, Williams completed the sale of Texas Gas Transmission
Corporation for $795 million in cash and the assumption by the purchaser of $250
million in existing Texas Gas debt. This business was evaluated for
recoverability at March 31, 2003 on a held-for-use basis pursuant to SFAS No.
144, "Accounting for the Impairment or Disposal of Long-Lived Assets." As a
result, 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 based on management's assessment of the
expected sales price pursuant to the purchase and sale agreement. The impairment
charge is included in (impairments) and gain (loss) on sales in the preceding
table of summarized results of discontinued operations. No significant gain or
loss was recognized on the sale. Texas Gas was a segment within Gas Pipeline.

12

Notes (Continued)

Natural gas properties

On May 30, 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 during second-quarter 2003 and is included in (impairments) and gain
(loss) on sale in the preceding table of summarized results of discontinued
operations. These properties were part of the Exploration & Production segment.

Midsouth refinery and related assets

On March 4, 2003, Williams completed the sale of its refinery and other
related operations located in Memphis, Tennessee for approximately $455 million
in cash. These assets were previously written down by $240.8 million (including
$176.2 million during third-quarter 2002) to their estimated fair value less
cost to sell at December 31, 2002. A pre-tax 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 pre-tax gain on the sale of an earn-out
agreement retained by Williams in the sale of the refinery. The second-quarter
2002 impairment charge together with the gains are included in (impairments) and
gain (loss) on sale in the preceding table of summarized results of discontinued
operations. 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 for
approximately $189 million in cash. The December 31, 2002 carrying value
reflected the estimated fair value less cost to sell. Included in (impairments)
and gain (loss) on sale in the preceding table of summarized results of
discontinued operations are impairment charges of $112.1 million and $139.1
million for the three and nine months ended September 30, 2002, respectively. No
significant gain or loss was recognized on the sale. These operations were part
of the previously reported Petroleum Services segment.

2002 COMPLETED TRANSACTIONS

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. A third-quarter 2002 impairment charge of $86.9 million is
reflected in (impairments) and gain (loss) on sales in the preceding table of
summarized results of discontinued operations. Central 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. In the preceding table of summarized results of discontinued
operations, (impairments) and gain (loss) on sales includes a pre-tax gain of
$304.6 million in third-quarter 2002 and a $9 million reduction of the gain in
third-quarter 2003. These assets were part of the Midstream Gas & Liquids
segment.

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 of summarized results of
discontinued operations is a pre-tax gain of $31.7 million and a pre-tax loss of
$6.4 million for the three and nine months ended September 30, 2002,
respectively. Kern River was a segment within Gas Pipeline.

13

Notes (Continued)

7. Earnings (loss) per share
- --------------------------------------------------------------------------------

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

For the nine months ended September 30, 2003, approximately 8.6 million
weighted average shares 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 three and nine months ended September 30, 2003, approximately 10.2
and 6.9 million weighted-average shares, respectively, 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 nine months ended September 30, 2002, diluted earnings
(loss) per share is the same as the basic calculation. The inclusion of any
stock options, convertible preferred stock and unvested deferred stock would be
antidilutive as Williams reported a loss from continuing operations for these
periods. As a result, approximately 7,600 and 880,000 weighted-average stock
options for the three and nine months ended September 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
10.1 million weighted-average shares for the three and nine months ended
September 30, 2002, respectively, related to the assumed conversion of 9 7/8
percent cumulative convertible preferred stock and approximately 4.1 million and
3.5 million weighted-average unvested deferred shares for the three and nine
months ended September 30, 2002, respectively, have been excluded from the
computation of diluted earnings per common share.

14

Notes (Continued)

8. Stock-based compensation
- --------------------------------------------------------------------------------

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 (loss) and earnings (loss) 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 Williams awards made in 2002 and 2001 and from certain Williams
awards made in 1999.

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.

15

Notes (Continued)

9. Inventories
- --------------------------------------------------------------------------------

Inventories at September 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 $37.0 million, refined products by $2.9 million and
natural gas liquids by $1.0 million.

16

Notes (Continued)

10. Debt and banking arrangements
- --------------------------------------------------------------------------------

NOTES PAYABLE AND LONG-TERM DEBT

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

(1) At September 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), 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").

In the third quarter of 2003, Williams' Board of Directors authorized the
Company to retire or otherwise prepay up to $1.8 billion of debt, including $1.4
billion designated for the Company's 9.25 percent notes due March 15, 2004. On
October 8, 2003, Williams announced a cash tender offer for any and all of
Williams' $1.4 billion senior unsecured 9.25 percent notes as well as cash
tender offers and consent solicitations for approximately $241 million of
additional outstanding notes and debentures. As of October 31, 2003,
approximately $720 million of the 9.25 percent notes had been accepted for
purchase. Additionally, Williams received tenders of notes and deliveries of
related consents from holders of approximately $230 million of the other notes
and debentures. As a result of the tendered notes and related consents at
October 31, 2003, a premium of approximately $56 million will be reflected in
fourth-quarter 2003 as a charge to earnings.

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, generally continue indefinitely unless limited
by the underlying tax regulations, and have no carrying value. Williams has
never been called upon to perform under these indemnifications.

17

Notes (Continued)

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
under the facility. 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 ultimate termination date of the underlying
debt or letters of credit. The new credit facility replaced a $1.1 billion
credit line entered into in July 2002 that was comprised of a $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 released these
assets as collateral. The interest rate on the new agreement is variable at the
London InterBank Offered Rate (LIBOR) plus .75 percent. As of September 30,
2003, letters of credit totaling $422 million have been issued by the
participating financial institutions under this facility and remain outstanding.
No revolving credit loans were outstanding. At September 30, 2003, the amount of
restricted investments securing this facility was $443.7 million, which
collateralized the facility at 105.14 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, a subsidiary of Williams entered into a $500 million
secured note due May 30, 2007, at a floating interest rate of six-month LIBOR
plus 3.75 percent (totaling 4.9 percent at September 30, 2003). This loan
refinances a portion of the RMT note discussed above. Certain of Williams'
Exploration & Production interests in the U.S. Rocky Mountains had secured the
RMT note payable and 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 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 Investors Service and Standard and 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 nine months ended
September 30, 2003, are as follows:

18

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 $12
million for potential refund as of September 30, 2003.

Power subsidiaries are engaged in power marketing in various geographic
areas, including California. Prices charged for power by Williams and other
traders and generators in California and other western states have been
challenged in various proceedings including those before the FERC. In December
2000, the FERC issued an order which provided that, for the period between
October 2, 2000 and December 31, 2002, 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 $17 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, Power recorded a first-quarter 2003
charge for refund obligations of $37 million. Net interest income related to
amounts due from the counterparties is approximately $9 million through
September 30, 2003. On October 16, 2003, FERC issued an order granting rehearing
in part and denying rehearing in part. This order is not expected to have a
material effect on the refund calculation for Williams. 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.

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.

19

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, and (c) the
ten 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 in accordance with
ISO instruction (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. On March 13, 2003, FERC
issued an order agreeing with Williams and other generators covering minimum
load costs. Further guidance on the proposed market redesign was issued by the
FERC on October 28, 2003.

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 Power. 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 Power. 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. Final
approval by the court is needed to make the settlement effective as to
plaintiffs and to terminate the class actions as to Williams. On October 24,
2003, the court granted a motion for preliminary approval of the settlement. The
final approval hearing is currently scheduled for February 20, 2004. As of
September 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 Power seeking relief
from rates contained in three separate confirmation agreements between
PacifiCorp and Power (known as the Summer 2002 90-Day Contracts). PacifiCorp
filed similar complaints against three other suppliers. PacifiCorp alleges that
the rates contained in the contracts are unjust and unreasonable. Power 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

20

Notes (Continued)

for hearing, but held the hearing in abeyance pending the 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 Power 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, Power. The FERC staff asserted that Power
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 Power disagreed with some of the FERC
staff's allegations and furthermore believe that Power did not profit from the
alleged activities. Nevertheless, in order to avoid protracted litigation, on
March 13, 2003, Williams, Transco and Power 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, Power 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 Power.

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
replaces the earlier NOPR on cash management described above. The Interim Rule
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 became effective
on August 7, 2003. The Interim Rule also sought 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. On October 23, 2003, the
FERC issued

21

Notes (Continued)

its Final Rule (Order No. 634-A), which adopted the filing and reporting
requirements proposed in the Interim Rule, with certain modifications. Under the
Final Rule, a FERC-regulated entity must file its cash management program with
the FERC for informational purposes, and must compute its proprietary capital
ratio quarterly and notify the FERC within 45 days after the end of each
calendar quarter if its proprietary capital ratio drops below or subsequently
exceeds 30 percent.

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. Civil suits based on these facts have also been brought
against Williams and others in state court in California and in Federal court
in New York.

On March 26, 2003, FERC issued a Staff Report addressing Enron trading
practices, the allegation of cornering the gas market, and the gas price index
issue. The March 26, 2003 report 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. On June 25, 2003, FERC
issued a series of orders in response to the California parties' March 3, 2003
report on its 100 days of discovery discussed above and the Staff Report. These
orders resulted in further investigations regarding potential allegations of
physical withholding, economic withholding, and a show cause order to Williams
and others regarding specific practices alleged by an ISO report that various
companies engaged in Enron trading practices. On August 29, 2003, Williams and
FERC trial staff entered into a settlement of all Enron trading practices for
approximately $45,000. Certification and approval of the settlement is pending.
The investigations of physical and economic withholding are also continuing.

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

22

Notes (Continued)

the FERC. Power 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, Power could be subject
to surcharges of approximately $37 million, excluding interest, through
September 30, 2003, in addition to increased costs going forward.

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
September 30, 2003, Transco had accrued liabilities totaling approximately $29
million for these costs.

Transco has identified polychlorinated biphenyl (PCB) contamination 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 $29 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 September 30, 2003, Williams and its
subsidiaries had accrued liabilities totaling approximately $9 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.

23

Notes (Continued)

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 and other liabilities existing at the time the sale was
consummated. These assets and businesses include former fertilizer operations,
propane marketing operations, retail petroleum and refining operations,
petroleum products pipelines and related facilities, natural gas liquids
fractionation 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 September 30, 2003, Williams had accrued
approximately $9 million for such excess costs.

At September 30, 2003, Williams had accrued environmental liabilities
totaling approximately $17 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, natural gas liquids fractionation, 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 Refinery'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. At September 30, 2003,
Williams had accrued liabilities totaling approximately $8 million for these
costs. In addition, Williams deferred a portion of the gain associated with
Williams' indemnifications, including environmental indemnifications, of the
purchaser under the sales agreement. At September 30, 2003, Williams has a
remaining deferred gain relating to this sale of approximately $100 million.

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

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, Power, continues to
purchase gas under contracts which extend, in some cases, through the life of
the associated gas reserves. Certain of these contracts contain royalty
indemnification provisions 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.

24

Notes (Continued)

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 September 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 and subsequently entered a formal judgment reflecting his bench
ruling. The plaintiff is seeking an appeal. This case accounts for approximately
$10 million of the $18 million claimed in the two cases. In the other case
Transco and the producer have agreed in principle to settle the case, subject to
the negotiation of a formal settlement agreement.

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 plaintiffs' motion. The amended petition deletes all of the
Williams defendants except two Midstream subsidiaries.

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. The claim sought an unspecified amount of royalties allegedly not
paid to the federal government, treble damages, a civil penalty, attorneys'
fees, and costs. In connection with 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. 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 Williams and Williams Production RMT Company with a complaint in the
District Court in and for the City of Denver, State of Colorado. The complaint
alleges that the defendants have used mismeasurement techniques that distort the
BTU heating content of natural gas, resulting in the alleged underpayment of
royalties to Grynberg and other independent natural gas producers. The complaint
also alleges that defendants inappropriately took deductions from the gross
value of their natural gas and made other royalty valuation errors. Theories for
relief include breach of contract, breach of implied covenant of good faith and
fair dealing, anticipatory repudiation, declaratory relief, equitable
accounting, civil theft, deceptive trade practices, negligent misrepresentation,
deceit based on fraud, conversion, breach of fiduciary duty, and violations of
the state racketeering statute. Plaintiff is seeking actual damages of between
$2 million and $20 million based on interest rate variations, and punitive
damages in the amount of approximately $1.4 million dollars. On October 7, 2002,
the Williams 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. The motion to stay the proceedings was granted on January
15, 2003.

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 and Power, 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

25

Notes (Continued)

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. Preliminary approval
was granted on October 24, 2003 and a hearing on final approval is scheduled for
February 20, 2004.

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 Power 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 Power, 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 as discussed
above.

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 Power. 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 complaint of the WilTel securities holders was filed on September 27,
2002, and the amended complaint of the Williams securities holders was filed on
October 7, 2002. This amendment added numerous claims related to Power. 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 to whom Williams might have an
indemnity obligation. The Department of Labor is also independently
investigating Williams' employee benefit plans. 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.

26

Notes (Continued)

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 which was granted by the Court. These appeals were consolidated on
August 25, 2003.

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. On October 24, 2003, Williams and Western announced the
settlement of these claims. The main elements of the settlement allowed Williams
to receive improved terms in a long-term gathering agreement with Western in
exchange for a subsidiary of Western gaining rights to operate approximately
one-half of the properties jointly owned with Williams.

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 $50 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.

Power 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 Power
that was initially calculated to be in excess of $100 million payable to Power.
Arbitration was initiated to resolve this dispute. On June 5, 2003, Power and
AEP executed a settlement agreement resolving the dispute, pursuant to which AEP
paid Power $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 September 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.

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.

27

Notes (Continued)

COMMITMENTS

Power has entered into certain contracts giving it the right to receive fuel
conversion services as well as certain other services associated with electric
generation facilities that are currently in operation throughout the continental
United States. At September 30, 2003, Power's estimated committed payments under
these contracts are $80 million for the remainder of 2003, range from
approximately $391 million to $422 million annually through 2017 and decline
over the remaining five years to $57 million in 2022. Total committed payments
under these contracts over the next 19 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 September 30, 2003, was $48.7 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 on 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 the purchase of 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. 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 September 30, 2003, is $30.8 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 September 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 September 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 September 30, 2003. If ongoing efforts to refinance these
obligations are unsuccessful, Williams could be required to perform under its
guarantee.

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 September 30, 2003, Williams has an accrued liability
of $46.5 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 September 30, 2003.

28

Notes (Continued)

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).

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

Comprehensive income (loss) from both continuing and discontinued operations
is as follows:

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.

Power has entered into intercompany interest rate swaps with the corporate
parent, the effect of which is included in Power'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 income (loss) in the Consolidated Statement of Operations
below operating income.

29

Notes (Continued)

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

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

30

Notes (Continued)

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

- ----------

* Prior to January 1, 2003, Power intercompany cost of sales, which were netted
in revenues consistent with fair-value accounting, exceeded intercompany
revenue. Beginning January 1, 2003, Power intercompany cost of sales are no
longer netted in revenues due to the adoption of EITF Issue No. 02-3 (see
Note 3). Segment revenues and profit for Power include net realized and
unrealized mark-to-market gains of $95.4 million from derivative contracts
accounted for on a fair value basis for the three months ended September 30,
2003.

31

Notes (Continued)

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

- ----------

* Prior to January 1, 2003, Power intercompany cost of sales, which were
netted in revenues consistent with fair-value accounting, exceeded
intercompany revenue. Beginning January 1, 2003, Power intercompany
cost of sales are no longer netted in revenues due to the adoption of
EITF Issue No. 02-3 (see Note 3). Segment revenues and profit for Power
include net realized and unrealized mark-to-market gains of $304.3
million from derivative contracts accounted for on a fair value basis
for the nine months ended September 30, 2003.

32

Notes (Continued)

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

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

In January, 2003, the Financial Accounting Standards Board (FASB) issued
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 were initially to be effective for the first interim or
annual period beginning after June 15, 2003. However, in October 2003, the FASB
delayed the effective date of the Interpretation on those entities to the first
period ending after December 15, 2003. The effect of the adoption of the
Interpretation is not expected to be material to the consolidated financial
statements.

EITF Issue No. 01-8, "Determining Whether An Arrangement Contains a Lease",
became effective on July 1, 2003, and provides guidance for determining whether
certain contracts such as transportation, storage, load serving, and tolling
agreements are executory service arrangements or leases pursuant to SFAS No. 13.
A prospective transition is provided for whereby the consensus is to be applied
to arrangements consummated or modified after July 1, 2003. Williams' initial
review indicates that certain of Power's tolling agreements could be considered
leases under the consensus if the tolling agreements are modified after July 1,
2003. If such tolling agreements are deemed to be capital leases, the net
present value of the demand payments would be reported on the balance sheet
consistent with debt as an obligation under capital lease, and as an asset in
property, plant and equipment.

33

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 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 and developing a balance sheet capable of supporting retained businesses
with favorable returns and opportunities for growth in the future.

During second-quarter 2003, Williams repaid the RMT note payable of
approximately $1.15 billion (including 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 equal to the six-month London Interbank Offered Rate (LIBOR)
plus 3.75 percent (totaling 4.9 percent at September 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 of the Company's senior
unsecured 9.25 percent notes due March 2004.

Also in second-quarter 2003, 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 that,
on an annual basis, result in approximately $17 million in lower after-tax
carrying costs compared with the convertible preferred 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.

At September 30, 2003, Williams has notes payable and long-term debt maturing
through the first quarter of 2004 totaling approximately $1.6 billion. 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.

In the third quarter of 2003, Williams' Board of Directors authorized the
Company to retire or otherwise prepay up to $1.8 billion of debt, including $1.4
billion designated for the Company's 9.25% notes due on March 15, 2004. On
October 8, 2003, the Company announced a cash tender offer for any and all of
Williams' $1.4 billion senior unsecured 9.25 percent notes due March 2004 as
well as cash tender offers and consent solicitations for $241 million of
additional outstanding notes and debentures. As of October 31, 2003,
approximately $720 million of the 9.25 percent notes had been accepted for
purchase. Additionally, Williams received tenders of notes and deliveries of
related consents from holders of approximately $230 million of the other notes
and debentures. The tender offers are scheduled to expire on November 6, 2003.
The Company will use available cash to fund the purchase of any notes accepted
under the tender offers.

Long-term debt, excluding the current portion, at September 30, 2003 was
approximately $11 billion. See the Liquidity section for a maturity schedule of
the Company's long-term debt.

As part of its planned business strategy, Williams expects to generate
proceeds, net of related debt, of approximately $4 billion during 2003 and 2004
primarily from asset sales, as well as the contribution of proceeds from the
sale and/or termination of certain contracts within its marketing and trading
portfolio. Through September 30, 2003, Williams received approximately $3.1
billion in net proceeds from the sale of assets, businesses and the sale and/or
termination of certain marketing and trading contracts. Of this amount, $2.8
billion was realized from the sale of assets and businesses, including the
following:

o retail travel centers;

o Midsouth refinery;

o bio-energy operations;

o Texas Gas Transmission Corporation;

o general partnership interest and limited partner investment in Williams
Energy Partners;

o certain natural gas exploration and production properties in Kansas,
Colorado, New Mexico and Utah;

o Colorado soda ash mining operations; and

o certain gas processing, natural gas liquids fractionation, gathering and
storage operations in western Canada and at a plant in Redwater, Alberta.

34

Management's Discussion & Analysis (Continued)

The additional assets and/or businesses expected to be sold in 2003 and 2004
include the Alaska refinery and related assets, and certain assets within
Midstream Gas & Liquids (Midstream). The specific assets and the timing of such
sales are dependent on various factors, including negotiations with prospective
buyers, regulatory approvals, industry conditions, and Williams' short- and
long-term liquidity requirements. While management believes it has considered
all relevant information in assessing 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.

During third-quarter 2003, Williams announced the name change of Williams
Energy Marketing & Trading to Williams Power Company, Inc. (Power). Williams'
management believes the new name more accurately reflects the segment's current
business activity. Williams continues its efforts to reduce its commitment to
Power activities and exit this business. As part of these efforts, Power has
focused on managing its existing contractual commitments, while pursuing
potential dispositions and restructuring of certain of its long-term contracts.
Through September 30, 2003, Power has sold contracts resulting in cash proceeds
of approximately $315 million, which is included in the $3.1 billion of total
proceeds discussed above. Although management currently believes that the
Company has the financial resources and liquidity to meet the expected cash
requirements of Power, the Company continues to pursue several specific
transactions with interested parties involving the sales of portions of Power'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 assets. Because of
completed 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 segment;

o Gulf Liquids New River Project LLC, previously part of the Midstream 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;

o certain gas processing, natural gas liquids fractionation, storage and
distribution operations in western Canada and at a plant in Redwater,
Alberta, previously part of the Midstream segment.

35

Management's Discussion & Analysis (Continued)

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' 2002 Annual Report on Form 10-K.

CRITICAL ACCOUNTING POLICIES AND 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," (EITF
02-3) 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 on Williams' financial statements as a result of
applying this consensus.

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.

36

Management's Discussion & Analysis (Continued)

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

Williams' revenue increased $4.1 billion due primarily to increased revenues
at Power and Midstream as a result of the adoption of EITF 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 02-3, prior year amounts have not been restated. Prior to the
adoption of EITF 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. Power's revenues increased $4.2
billion and Midstream revenues increased $436 million. Offsetting these revenue
increases at the operating units was $485 million higher intercompany
eliminations primarily resulting from intercompany costs that were previously
netted in revenues prior to the adoption of EITF 02-3.

Costs and operating expenses increased $3.9 billion due primarily to the
impact of reporting certain costs gross at Power and Midstream, as discussed
above. Costs and operating expenses increased $3.8 billion at Power and $478
million at Midstream. Contributing to the increase at Midstream is a $94 million
increase attributable to higher market prices for natural gas. Offsetting these
cost increases at the operating units was $485 million higher intercompany
eliminations primarily as a result of intercompany costs that were previously
netted in revenues prior to the adoption of EITF 02-3.

Selling, general and administrative expenses decreased $60.8 million due
primarily to employee reductions at Power and, to a lesser extent, Gas Pipeline,
which resulted in lower salaries, benefits and other related costs.

Other (income) expense - net in 2002 reflects a $143.9 million gain from the
sale of Exploration & Production's interests in natural gas properties.

General corporate expenses decreased $26.3 million, or 60 percent, due
primarily to the absence of $20 million of costs related to consulting services
and legal fees associated with the liquidity and business issues addressed
during third-quarter 2002.

Operating income (loss) improved by $170.8 million due primarily to a $338.3
million favorable change in operating income (loss) at Power and a $26.3 million
decrease in general corporate expenses. The increase in operating income (loss)
is partially offset by a $170.4 million decrease in operating income at
Exploration & Production and a $34.3 million decrease at Midstream. The decrease
at Exploration & Production is due primarily to the absence in 2003 of $143.9
million in gains on sales of natural gas production properties in Wyoming and
the Anadarko basin during third-quarter 2002.

Interest accrued - net decreased $69.4 million, or 21 percent, due primarily
to the absence in 2003 of $59.9 million of interest expense and fees on the RMT
note payable, which was repaid in May 2003 (see Note 10), and $8 million lower
amortization expense related to deferred debt issuance costs, partially offset
by $10 million higher interest expense related to a petroleum pricing dispute.
An additional $7 million decrease in interest expense is attributable to a $2
million decrease reflecting lower average borrowing levels of long-term debt in
2003 and a $5 million decrease reflecting lower average interest rates on
long-term debt in 2003.

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 change in market value of these swaps was $54.7 million more favorable
in 2003 than 2002. The total notional amount of these swaps is approximately
$300 million at September 30, 2003 as compared to approximately $450 million at
September 30, 2002.

37

Management's Discussion & Analysis (Continued)

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

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

The decline in equity earnings for the three months ended September 30, 2003
as compared to 2002 is partially attributable to $6 million lower equity
earnings following the October 2002 sale of Gas Pipeline's 14.6 percent
ownership in Alliance Pipeline. The $22.9 million loss provision in 2002 is
related to the estimated recoverability of receivables from WilTel
Communications Group, Inc. (formerly Williams Communications Group, Inc.)
(WilTel). In 2002, the $58.5 million gain on sale relates to the investment in
a Lithuanian oil refinery, pipeline and terminal complex and the $11.6 million
net write-down relates to Williams' equity interest in a Canadian and U.S. gas
pipeline. In 2003, the $13.5 million gain relates to the sale of stock in
eSpeed Inc., and the $11 million gain reflects the sale of a 20 percent
aggregate ownership interest in the 3,000-mile West Texas LPG Pipeline Limited
Partnership. Interest income and other increased $6.4 million due primarily to
approximately $7 million of interest income on the WilTel promissory notes
relating to the 2002 sale of the Technology Center.

Minority interest in income and preferred returns of consolidated
subsidiaries in 2003 is lower than 2002 due primarily to the absence in 2003 of
preferred returns totaling $9 million on the preferred interests in Castle
Associates L.P., Piceance Production Holdings L.L.C., and Williams' Risk
Holdings L.L.C., which were reclassified as debt in the third quarter of 2002,
and Arctic Fox, L.L.C., which was reclassified as debt in April 2002.

The change in provision (benefit) for income taxes was unfavorable by $96.0
million due primarily to pre-tax income in 2003 as compared to a pre-tax loss
for 2002. The effective income tax rate for the three months ended September 30,
2003, is greater than the federal statutory rate due primarily to foreign
operations and state income taxes. The effective income tax rate for the three
months ended September 30, 2002 is less than the federal statutory rate due
primarily to foreign operations which reduce the tax benefit of the pretax loss.

The decrease in preferred stock dividends reflects the June 10, 2003
redemption of all the outstanding 9 7/8 percent cumulative-convertible preferred
shares (see Note 12).

Nine Months Ended September 30, 2003 vs. Nine Months Ended September 30, 2002

Williams' revenue increased $10.7 billion due primarily to increased revenues
at Power and Midstream as a result of the adoption of EITF 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 02-3, prior year amounts have not been restated. Prior to the
adoption of EITF 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. Power's revenues increased $10.8
billion and Midstream's revenues increased $1.4 billion. The increase in
revenues includes $327 million higher revenues at Midstream primarily resulting
from higher natural gas liquids (NGL) revenues at gas processing plants caused
by higher NGL prices in both domestic and Canadian markets and significantly
higher volumes produced at the Canadian facilities. Partially offsetting these
revenue

38

Management's Discussion & Analysis (Continued)

increases at the operating units was $1.4 billion higher intercompany
eliminations primarily resulting from intercompany costs that were previously
netted in revenues prior to the adoption of EITF 02-3. During the second quarter
of 2003, Power corrected the accounting treatment previously applied to certain
third party derivative contracts during 2002 and 2001, resulting in the
recognition of $80.7 million in revenues in the second quarter of 2003
attributable to prior periods (see Note 1). 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 $10.4 billion due primarily to the
impact of reporting certain costs gross at Power and Midstream, as discussed
above. Costs and operating expenses increased $10.4 billion at Power and $1.3
billion at Midstream. Contributing to the increase at Midstream is a $227
million increase due to higher market prices for natural gas used to replace the
heating value of NGL's extracted at Midstream's gas processing facilities.
Offsetting these cost increases at the operating units was $1.4 billion higher
intercompany eliminations primarily as a result of intercompany costs that were
previously netted in revenues prior to the adoption of EITF 02-3.

Selling, general and administrative expenses decreased $131.1 million due
primarily to reduced employee levels at Power and, to a lesser extent, Gas
Pipeline, 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 $188 million gain from the
sale of a Power contract and $96.4 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 that system and a $20 million charge
related to a settlement by Power with the Commodity Futures Trading Commission
(see Note 11). Other (income) expense - net in 2002 includes $152.7 million of
impairment charges, loss accruals, and write-offs within Power, including a
partial impairment of goodwill, and $143.9 million in net gains from the sale of
Exploration & Production's interests in natural gas properties.

General corporate expenses decreased $53.9 million, or 46 percent, due
primarily to the absence of $24 million of costs related to consulting services
and legal fees associated with the liquidity and business issues addressed
during third-quarter 2002 and $16.5 million lower advertising and branding
costs.

Operating income increased $783.1 million due primarily to a $714.0 million
improvement at Power, a $47.8 million increase at Midstream primarily from
domestic gathering and processing operations and $53.9 million lower general
corporate expenses. The increase in operating income (loss) is partially offset
by $48 million lower net gains in 2003 on the sale of Exploration & Production's
interests in natural gas properties.

Interest accrued - net increased $219.6 million, or 28 percent, due primarily
to $149.5 million of interest expense and fees on the RMT note payable, which
was repaid in May 2003 (see Note 10), $26.1 million higher amortization expense
related to deferred debt issuance costs, $12 million of interest expense within
Power related to a FERC ruling and $10 million of interest expense related to a
pending petroleum pricing dispute. Interest accrued - net increased by an
additional $32 million due to a $43 million increase reflecting higher average
interest rates on long-term debt in 2003, offset slightly by an $11 million
decrease reflecting lower average borrowing levels. The $26.1 million higher
amortization expense related to deferred debt issuance costs primarily 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).
These increases were slightly offset by an $18.5 million increase in capitalized
interest at Midstream due primarily to projects in the Gulf Coast region.

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 market value of these swaps was $118.8 million more favorable in 2003
than 2002. The total notional amount of these swaps is approximately $300
million at September 30, 2003 as compared to approximately $450 million at
September 30, 2002.

39

Management's Discussion & Analysis (Continued)

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

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

Equity earnings decreased $67.8 million due primarily to $27 million lower
equity earnings from Gulfstream Natural Gas System, LLC (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 contractor on the Gulfstream project and the absence of $17 million of
equity earnings following the October 2002 sale of Gas Pipeline's 14.6 percent
ownership interest in Alliance Pipeline. The $269.9 million loss provision in
2002 was related to the estimated recoverability of receivables from WilTel. In
2002, the $58.5 million gain on sale relates to the investment in a Lithuanian
oil refinery, pipeline and terminal complex and the $11.6 million net write-down
relates to Williams' equity interest in a Canadian and U.S. gas pipeline. The
$42.4 million impairment in 2003 relates to the investment in equity and debt
securities of Longhorn Partners Pipeline LP (Longhorn). Also in 2003, the $13.5
million gain relates to the sale of stock in eSpeed Inc., and the $11 million
gain reflects the sale of a 20 percent aggregate ownership interest in the
3,000-mile West Texas LPG Pipeline Limited Partnership. Impairment of cost based
investments in 2003 includes a $13.2 million impairment of Algar Telecom S.A.
(Algar), a $13.5 million impairment of ReserveCo and a $7.9 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
$58.1 million due primarily to a $36.2 million increase at Power comprised
primarily of interest income as a result of certain 2003 FERC proceedings. Also
contributing to the increase in interest income is $15 million of interest
income on the WilTel promissory notes relating to the 2002 sale of the
Technology Center, $4 million higher interest income due primarily to higher
cash and cash equivalents balances, a $4 million increase in interest income
from advances to equity affiliates and a $4 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 $23.5 million on the preferred interests in Castle
Associates L.P., Piceance Production Holdings L.L.C., and Williams' Risk
Holdings L.L.C., which were reclassified as debt in third-quarter 2002, and
Arctic Fox, L.L.C., which was reclassified as debt in April 2002.

Other income - net in 2003 includes $69.2 million of foreign currency
transaction gains on a Canadian dollar denominated note receivable partially
offset by $55.3 million of derivative losses 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.

40

Management's Discussion & Analysis (Continued)

The change in provision (benefit) for income taxes was unfavorable by $330.1
million due primarily to pre-tax income in 2003 as compared to a pre-tax loss
for 2002. The effective income tax rate for the nine months ended September 30,
2003, is greater than the federal statutory rate due primarily to nondeductible
expenses, state income taxes, foreign operations, the financial impairment of
certain investments and capital losses generated for which valuation allowances
were established. The effective income tax rate for the nine months ended
September 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
foreign operations which reduce the tax benefit of the pre-tax loss.

The cumulative effect of change in accounting principles reduced net income
for 2003 by $761.3 million due to a $762.5 million charge related to the
adoption of EITF 02-3 (see Note 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 first-quarter 2002 impact of
recording a $69.4 million noncash dividend associated with the accounting for a
preferred security that contained a conversion option that was beneficial to the
purchaser at the time the security was issued.

RESULTS OF OPERATIONS - SEGMENTS

Williams is currently organized into the following segments: Power, Gas
Pipeline, Exploration & Production, and Midstream. Due to recent asset sales and
the approval of additional 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.

POWER

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

POWER'S revenues and cost of sales increased by $4.2 billion and $3.8
billion, respectively, which equates to an increase in gross margin of $358
million. This significant increase in revenues and cost of sales is primarily a
result of the adoption of EITF 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
02-3 on January 1, 2003, revenues related to non-derivative energy contracts
were reported on a net basis in trading revenues. EITF 02-3 does not require
prior year amounts to be 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, 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, "Accounting for
Derivative Instruments and Hedging Activities" 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, Power recorded an adjustment as a
cumulative effect of change in accounting principle to remove the previously
reported fair value of

41

Management's Discussion & Analysis (Continued)

non-derivative energy contracts from the balance sheet. Power'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.

Power's gross margin increased $358 million principally due to a $351.5
million higher power and natural gas gross margin, $26.1 million higher
petroleum products gross margin, and $7 million higher European gross margin,
slightly offset by $26.7 million lower emerging products gross margin.

The power and natural gas gross margin increased $351.5 million from a margin
loss of $320.1 million in 2002 to a $31.4 million gross margin in 2003. The
$31.4 million gross margin in 2003 is primarily comprised of a $33.6 million
accrual loss and a $65 million mark-to-market gain. The accrual loss of $33.6
million is primarily related to narrower margins between power sales prices less
the cost of gas and power conversion services, or "spark spreads," on the
tolling portfolio that do not exceed contractually-obligated capacity payments.
The $65 million mark-to-market gain includes a $126.8 million valuation increase
to a derivative contract based on the terms of an agreement to terminate the
contract, partially offset by mark-to-market losses primarily resulting from
decreased 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 02-3 as discussed
above, these non-derivative energy-related trading contracts were accounted for
on an accrual basis. Therefore, 2002 earnings reflect the unfavorable impact of
narrower spark spreads in future periods on certain power tolling portfolios and
a valuation adjustment of $74.8 million as a result of market information
obtained through sales efforts on certain full requirements contracts. In
contrast, 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.

The petroleum products portfolio gross margin improved from a gross margin
loss of $42.4 million in 2002 to a gross margin loss of $16.3 million in 2003.
The $16.3 million gross margin loss in 2003 is primarily comprised of a $9.9
million accrual loss and a $6.4 million mark-to-market loss. This $26.1 million
improvement in gross margin was impacted by the implementation of EITF 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
third-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 European gross margin improved from $1.5 million in 2002 to $8.5 million
in 2003. This $7 million increase in European gross margin is primarily
attributable to lower losses in 2003 as European operations have been
substantially eliminated. The emerging products gross margin decreased from
$63.6 million in 2002 to a $36.9 million mark-to-market gain in 2003. The $26.7
million decrease in emerging products gross margin is primarily attributable to
lower interest rates on forward interest rate positions that are marked to
market.

Selling, general, and administrative expenses decreased by $39 million, or 60
percent. This cost reduction is primarily due to the impact of employee
reductions in the Power business segment. Power employed approximately 251
employees at September 30, 2003, compared with approximately 582 employees at
September 30, 2002.

Other (income) expense - net increased $35.3 million. This increase is due
primarily to a $13.5 million gain from the sale of Power's investment in eSpeed
common stock, receipt of $13 million in contingent sales proceeds in connection
with an energy trading contract sold in the second quarter of 2003 and the
effect in 2002 of a $11.5 million write-off associated with a terminated power
plant project.

Segment profit increased $431.5 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.

Power's future results will continue to be affected by the willingness of
counterparties to enter into transactions with Power, the liquidity of markets
in which Power operates, 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 Power 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 Power'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

42

Management's Discussion & Analysis (Continued)

outcome of these items could result in future operating losses for Power or
limit Power's ability to achieve profitable operations.

Nine Months Ended September 30, 2003 vs. Nine Months Ended September 30, 2002

POWER'S revenues and cost of sales increased by $10.8 billion and $10.4
billion, respectively, which equates to an increase in gross margin of $432.9
million. This significant increase in revenues and cost of sales is primarily a
result of the adoption of EITF 02-3, as discussed previously.

Power's gross margin increased $432.9 million principally due to $579.4
million higher power and natural gas gross margin partially offset by $108.8
million lower emerging products gross margin and $38.2 million lower petroleum
products gross margin.

The power and natural gas gross margin increased $579.4 million from a margin
loss of $332.4 million in 2002 to a $247 million gross margin in 2003. The $247
million gross margin in 2003 is primarily comprised of a $171.7 million accrual
loss offset by a $338.1 million mark-to-market gain and $80.7 million in
revenues in the second quarter 2003 attributable to prior periods. In the
second-quarter of 2003, Power 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. These contracts were previously marked
to market with changes in fair value reported within earnings. The prior period
corrections relate to the fair value of these derivative contracts and do not
represent actual current period cash flows. Refer to Note 1 of Notes to the
Consolidated Financial Statements for further information. The accrual loss of
$171.7 million is primarily related to narrower spark spreads. Of the $338.1
million mark-to-market gain, $126.8 million is a positive valuation adjustment
to a derivative contract based on the terms of an agreement to terminate the
contract. The other mark-to-market gains are primarily a result of increased gas
prices in 2003 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 02-3 as discussed
previously, these non-derivative energy-related trading contracts were accounted
for on an accrual basis. Therefore, 2002 earnings reflected the unfavorable
impact of narrower spark spreads in future periods on certain power tolling
portfolios and a valuation adjustment of $74.8 million as a result of market
information obtained through sales efforts on certain full requirements
contracts. In contrast, 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. The 2003 mark-to-market gains are partially
offset by an $85.1 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.

The petroleum products portfolio gross margin decreased from $4.3 million in
2002 to a margin loss of $33.9 million in 2003. The $33.9 million gross margin
loss in 2003 is primarily comprised of a $23.7 million accrual loss and a $10.2
million mark-to-market loss. The decrease in gross margin of $38.2 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 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 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 emerging products portfolio gross margin decreased from $85.2 million in
2002 to a mark-to-market margin loss of $23.6 million in 2003. The $108.8
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 $72.9 million, or
41 percent. This cost reduction is due primarily to the impact of employee
reductions in the Power business segment.

Other (income) expense - net increased $348 million. This increase is
primarily due to a $188 million gain from the sale of an energy trading contract
in 2003, a $13.5 million gain from the sale of Power's investment in eSpeed
common stock and the effect in 2002 of $95.2 million of impairments and loss
accruals associated with certain terminated power projects and a $57.5 million
partial goodwill impairment. The 2003 increase was partially offset by a $20
million charge for the settlement reached with the Commodity Futures Trading
Commission (see Note 11).

43

Management's Discussion & Analysis (Continued)

Segment profit increased $857.5 million due primarily to increased power and
natural gas gross margins, decreased selling, general and administrative
expenses and improved other (income) expense- net, partially offset by decreased
petroleum products 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 $799 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 third-quarter 2003 reporting, Gas Pipeline's continuing
operations include Northwest Pipeline Corporation (Northwest Pipeline),
Transcontinental Gas Pipe Line Corporation (Transco), a 50 percent interest in
Gulfstream 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 $1.7 million and $7.4 million of revenues for the three months and
nine months ended September 30, 2002, respectively, and $1.4 million and $14.0
million of segment profit for the three and nine months ended September 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 September 30, 2003 vs. Three Months Ended September 30, 2002

GAS PIPELINE'S revenues decreased $7.4 million, or two percent, due primarily
to $26 million in reductions in the rate refund liabilities and other
adjustments associated with a rate case settlement on Transco in 2002 and $4
million lower storage demand revenues due to lower storage rates in connection
with Transco's rate proceedings that became effective in late 2002. Partially
offsetting these decreases were $16 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, $6 million of additional revenue on the
Northwest Pipeline system primarily from new projects (Gray's Harbor, Centralia,
and Chehalis) and $6 million higher cash-out sales related to gas imbalance
settlements (offset in costs and operating expenses).

Cost and operating expenses increased $16 million, or 11 percent, due
primarily to $6 million higher depreciation expense and $4 million higher ad
valorem taxes resulting from increased property, plant and equipment placed into
service and $6 million higher cash-out sales related to gas imbalance
settlements (offset in revenues).

General and administrative costs decreased $10 million, or 22 percent, due
primarily to lower salaries, benefits, and other related costs resulting from
employee reductions.

Other (income) expense - net in 2003 includes $7.2 million of income at
Transco resulting from a partial reduction of accrued liabilities for claims
associated with certain producers as a result of recent settlements and court
rulings (see Note 11).

Segment profit, which includes equity earnings and income (loss) from
investments (included in investing income), decreased $5.8 million reflecting
$7.4 million lower revenues, $16 million higher costs, $10 million lower general
and administrative expenses, and other income discussed above. The decrease also
reflects the absence of an $8.7 million gain on sale of the general partnership
interest in Northern Border Partners, L.P., in 2002. Partially offsetting the
decreases above is the net effect of the absence of a $11.6 million net
impairment charge on Gas Pipeline's 14.6 percent ownership in Alliance Pipeline,
which was sold in October 2002, and $6 million of related equity earnings.

44

Management's Discussion & Analysis (Continued)

Nine Months Ended September 30, 2003 vs. Nine Months Ended September 30, 2002

GAS PIPELINE'S revenues increased $32.4 million, or four percent, due
primarily to $48 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,
$15 million on the Northwest Pipeline system resulting from new projects (Gray's
Harbor, Centralia, and Chehalis) and $5 million higher transportation revenues
on the Northwest Pipeline system. Partially offsetting these increases were $26
million in reductions in the rate refund liabilities and other adjustments
associated with a rate case settlement on Transco in 2002, $12 million lower
storage demand revenues due to lower storage rates in connection with Transco's
rate proceedings that became effective in late 2002, and $5 million lower
cash-out sales related to gas imbalance settlements (offset in costs and
operating expenses).

Cost and operating expenses increased $3 million, or one percent, due
primarily to $14 million higher depreciation expense due to increased property,
plant and equipment placed into service and $6 million higher tracked costs
which are passed through to customers (offset in revenues). These increases were
partially offset by $15 million lower fuel expense on Transco, resulting
primarily from pricing differentials on the volumes of gas used in operation,
and $5 million lower cash-out sales related to gas imbalance settlements (offset
in revenues).

General and administrative costs decreased $29 million, or 24 percent, due
primarily to the absence of $16 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. Subsequent to the implementation of the same system at
Transco in the second quarter of 2003 and a determination of the unique and
additional programming requirements that would be needed to complete the system
at Northwest Pipeline, management determined that the system would not be
implemented at Northwest Pipeline. Other (income) expense - net in 2003 also
includes $7.2 million of income at Transco due to a partial reduction of accrued
liabilities for claims associated with certain producers as a result of recent
settlements and court rulings.

Segment profit, which includes equity earnings and income (loss) from
investments (included in investing income), decreased $16.5 million, or 4
percent, due to $73 million lower equity earnings, the $25.5 million charge at
Northwest Pipeline discussed previously, and $3 million higher operating costs.
These decreases to segment profit were partially offset by $32.4 million higher
revenues, $29 million lower general and administrative costs discussed above,
and 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 $73 million
decrease to equity earnings reflects $27 million lower equity earnings from
Gulfstream, the absence of a $27.4 million benefit in 2002 related to the
contractual construction completion fee received by an equity affiliate and the
absence of $17 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 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 that included sales of
properties located primarily in Kansas, Colorado and New Mexico. During the
third quarter of 2003, Williams sold additional properties in Utah and Colorado,
thus completing the targeted sales. The completed sales represented
approximately 16 percent of Williams' proved domestic reserves at December 31,
2002. Exploration & Production has received net proceeds of approximately $464
million resulting in net pre-tax gains of approximately $134.9 million,
including $39.7 million of pre-tax gains reported in discontinued operations
related to the interests in the Raton and Hugoton basins. The

45

================================================================================
Management's Discussion & Analysis (Continued)

following discussion relates to the continuing operations of Exploration &
Production and those operations that were sold but do not qualify for
discontinued operations reporting.

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

EXPLORATION & PRODUCTION'S revenues decreased $40.7 million, or 19 percent,
due primarily to $28 million lower domestic production revenues resulting
largely from a 13 percent decrease in net domestic production volumes in
addition to lower realized sales prices (including the impact of hedge
positions). The decrease in production volumes primarily results from the impact
of reduced drilling activity in January through August of this year due to
capital constraints and the absence of volumes from properties sold in 2002 and
2003. During the third quarter, the drilling activities on our retained
properties returned to levels more consistent with 2002 drilling activities. The
drilling activities are expected to increase production volumes in the future.
Approximately 90 percent of all domestic production during third-quarter 2003
was hedged. Exploration & Production has contracts that hedge approximately 82
percent of estimated production for the remainder of 2003 at prices that average
$3.78 per million cubic feet equivalent (mcfe) at the basin level. In addition,
Exploration & Production has contracts that hedge approximately 80 percent of
estimated production in 2004 at prices that average $3.63 per mcfe at the basin
level. Exploration & Production also has contracts that hedge approximately 50
percent of estimated 2005 production at prices that average above $4.00 per mcfe
at the basin level. Most all of the derivative contracts are entered into with
Power which in turn enters into offsetting derivative contracts with unrelated
third parties. Generally, Power bears the counterparty performance risks
associated with unrelated third parties. Exploration & Production also has
derivative contracts with Power 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 $1 million gain as compared to a $7 million gain in 2002.

Costs and expenses, including selling, general and administrative expenses,
decreased $6 million, including $4 million decrease in selling, general and
administrative expense, $3 million lower depreciation, depletion and
amortization expense and $3 million lower lease operating expense. The decrease
in selling general and administrative costs reflects reduced consulting fees and
lower compensation expense. The decreased depreciation, depletion and
amortization expense is due to the previously discussed asset sales and lower
production volumes. These decreases were partially offset by $5 million higher
operating taxes due primarily to higher market prices in 2003.

Other (income) expense - net in 2002 includes approximately $143.9 million
in gains from the sales of certain interests in natural gas properties during
third-quarter 2002.

Segment profit decreased $169.4 million due primarily to the gains on the
sales of assets in 2002 that were discussed above and the lower production
revenues.

Nine Months Ended September 30, 2003 vs. Nine Months Ended September 30, 2002

EXPLORATION & PRODUCTION'S revenues decreased $39.4 million, or six percent
due primarily to $42 million lower production revenues. The lower domestic
production revenues reflect $51 million lower revenues due to a ten percent
decrease in net domestic production volumes, partially offset by $9 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 87
percent of all domestic production during the first nine months of 2003 was
hedged.

Costs and expenses, including selling, general and administrative expenses,
decreased $2 million including $8 million lower exploration expenses, $3 million
lower depreciation, depletion and amortization expense, and $3 million lower
selling general and administrative expense offset by $16 million higher
operating taxes due primarily to higher market prices. The lower exploration
expenses reflect the current focus of the company on developing proved
properties while reducing exploratory activities.

Other (income) expense - net in 2003 includes approximately $95.3 million in
net gains on sales of assets during 2003, which were discussed previously. Other
(income) expense - net in 2002 includes approximately $147 million in net gains
on sales of natural gas properties during 2002.

Segment profit decreased $75.8 million due primarily to $52 million lower
net gains in 2003 on sales of assets as compared to 2002, which are discussed
above. Additionally, lower production revenues due primarily to lower production
volumes also contributed to the decrease.

46

Management's Discussion & Analysis (Continued)

MIDSTREAM GAS & LIQUIDS

Midstream has announced its intention to sell certain assets, including
certain operations in Canada. During the third quarter of 2003, Midstream
completed the sales of its West Stoddart gas processing facility and the
fractionation, storage, and distribution system at its Redwater, Alberta plant
in western Canada. Midstream also completed the sale of its 45 percent interest
in the Rio Grande pipeline in second-quarter and its 20 percent interest in the
West Texas Pipeline Limited Partnership in third-quarter 2003. In October,
Midstream closed the sale of its 37.5 percent interest in Wilprise Pipeline Co.
and its 16.67 percent interest in Tri-states NGL Pipeline LLC. Midstream
continues to evaluate and pursue various asset sale transactions, including the
assets of its wholly owned subsidiary Gulf Liquids New River LLC (Gulf Liquids).
In June 2003, Williams' Board of Directors authorized management to sell Gulf
Liquids.

Midstream expects that the completion of asset sales will have the effect of
lowering revenues and/or segment profit in the periods following the sales.
However, continued growth in the deepwater areas of the Gulf of Mexico are
expected to contribute to future segment revenues and segment profit
mitigating the decline from asset sales.

Pursuant to current accounting guidance, Midstream has classified the
operations of Gulf Liquids, certain natural gas processing operations in western
Canada and Redwater extraction as discontinued operations. All prior periods
reflect this reclassification.

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

Midstream revenues increased $436 million due primarily to the effect of a
change in the reporting of NGL trading activities for which costs are no longer
netted in revenues as a result of the application of EITF 02-3. In addition to
this effect, Midstream's revenues increased $61 million due primarily to higher
NGL revenues resulting from higher market prices partially offset by lower
volumes at the Canadian gas processing plants. While domestic NGL revenues were
lower as a result of less favorable processing economics, additional fee-based
revenues generated by new deepwater assets offset this decline. Additionally,
Olefins revenues increased due to higher sales volumes and prices at both
domestic and Canadian facilities.

Cost and operating expenses increased $478 million due primarily to the
adoption of EITF 02-3 as discussed above. In addition to this effect, costs and
expenses increased $103 million, of which, $94 million is attributable to higher
market prices for natural gas used to replace the heating value of NGL's
extracted at Midstream's gas processing facilities. The remaining increase is
due primarily to higher market costs for NGL's used as feedstock to produce
olefins, increased maintenance spending, and higher depreciation, partially
offset by lower selling, general and administrative expenses.

Segment profit declined by $37.3 million primarily as a result of reduced
gas processing margins reflecting a lower processing spread between the price
earned for producing NGL's compared to the price of natural gas used to replace
the heating value of the NGL's. In particular, the price of natural gas in
third-quarter 2003 increased significantly compared to third-quarter 2002. While
higher long-term natural gas prices tend to increase demand for Midstream's
gathering and processing services, the short-term price increase compared to
third-quarter 2002 adversely impacted gas processing margins. Lower net trading
margins and a decline in equity earnings have also contributed to the segment
profit reduction. However, gains on sales of investments, additional fee
revenues from new infrastructure in the deepwater fields in the Gulf of Mexico,
and the benefit of more favorable contractual

47

Management's Discussion & Analysis (Continued)

arrangements concerning existing Gulf Coast processing facilities partially
offset the decline. A more detailed analysis of segment profit of Midstream's
operations is presented below:

Domestic Gathering & Processing: Midstream's domestic gathering and
processing segment profit declined $15.9 million, with the West Region recording
a $31.2 million decline, partially offset by a $15.3 million increase in the
Gulf Coast Region. The decline in the West Region is attributable to a $24.5
million decline in gas processing margins due to natural gas prices that
increased to a greater degree than NGL prices during this period. In
third-quarter 2002, the West Region experienced very favorable processing
margins due to depressed natural gas prices created by transportation
constraints for gas production in the Wyoming area. Consequently, natural gas
prices in Wyoming were approximately 38 percent lower than those in the Gulf
Coast markets during the third quarter of 2002. The completion of the Kern River
Pipeline system expansion in 2003 relieved the transportation constraints in
Wyoming. As a result, the favorable Wyoming gas price differential fell from $2
per MMBtu in third-quarter 2002 to $.48 per MMBtu in third-quarter 2003. In the
Gulf Coast Region, segment profit increased $15.9 million attributable to $10.6
million in incremental net profits associated with recently completed
infrastructure located in the deepwater area in the Gulf of Mexico. This region
also benefited from higher revenues derived from temporary gas treating
agreements which provided incentives to Gulf Coast processors to remove
hydrocarbon liquids from producers' gas as required to meet quality standards of
interstate gas pipelines. Most gas processing in the Gulf Coast had been shut
down due to uneconomic processing conditions. As a result, pipelines began
enforcing their gas quality tariffs and required gas producers to have a
contract with a processing plant before they would allow the gas to enter the
interstate pipeline grid. Midstream would expect these temporary arrangements to
remain in place as long as the processing environment remains unfavorable.

Venezuela: Segment profit increased $5.7 million, primarily attributable to
higher processing revenue at the PIGAP facility due to processing fees being
calculated using a variety of indices, including the Venezuelan rate of
inflation, which was somewhat higher during the quarter. The Venezuelan economic
and political environment remains fluid and volatile, but has not significantly
impacted the operations and cash flows of Midstream's facilities. Midstream's
Venezuelan operations were constructed and are currently operated for the
exclusive benefit of Petroleos de Venezuela (PDVSA), the state-owned petroleum
company of Venezuela. Contracts with PDVSA stipulate a majority of the payment
to be in U.S. dollars and provide protection against the devaluation and lack of
liquidity of the Venezuelan Bolivar. These contracts also provide for
adjustments for inflation and minimum volume guarantees provided plants are
operational.

Canada: Midstream's Canadian segment profit declined $14.3 million due
primarily to lower gas processing margins and lower olefins margins. Gas
processing margins from extraction facilities fell $8.6 million due to gas
purchase prices increasing at a greater rate than NGL sales prices. Olefins
sales margins declined $5 million primarily due to a $2.8 million inventory
adjustment and higher feedstock costs.

Other: Segment profit for Midstream's other operations declined $12.8
million due to lower trading revenues, lower domestic olefins margins and lower
earnings from investments.

Segment profit for Midstream's domestic olefins activities
declined $7.1 million as a result of reduced olefins margins as the price of
feedstock (ethane and propane) increased more than the price of olefins
products. The decline in Olefins margins continues to reflect the decline in
olefins product prices that are largely driven by the consumer product markets
softening against the rising energy commodity markets.

Segment profit for NGL trading, fractionation, and storage operations
declined by $4.4 million, primarily as a result of a $9.4 million decline in NGL
trading earnings, partially offset by $3.4 million in lower selling, general and
administrative costs reflecting the decline in liquids trading operations.
Third-quarter 2003 trading results reflect an overall margin of $1.5 million,
compared to a margin of $10.9 million realized in the same period of 2002
resulting from long NGL positions in a rising market. Lower operations and
maintenance spending on the NGL fractionation and storage facilities also
reduce segment profit.

Midstream's earnings from partially-owned investments accounted for on the
equity method declined $1.3 million due largely to $4 million in lower earnings
at Discovery Pipeline (Discovery) and the absence of earnings from the Rio
Grande and West Texas Pipeline investments, which were sold in 2003. Partially
offsetting the decline in segment profit is the current period net difference
between an $11 million net gain on the sale of Midstream's interest in the West
Texas Pipeline partnership and a $5.6 million impairment of the partnership
investment in Aux Sable Liquid Products, L.P. (Aux Sable). The impairment
resulted from management's assessment that there had been an other than
temporary decline in the fair value of this investment.

48

Management's Discussion & Analysis (Continued)

Nine Months Ended September 30, 2003 vs. Nine Months Ended September 30, 2002

Midstream revenues increased $1.4 billion due primarily to the 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
02-3. In addition to this effect, Midstream's revenues increased $327 million
primarily resulting from increased NGL sales at gas processing plants caused by
higher NGL prices partially offset by lower volumes in both domestic and
Canadian markets. Although Gulf Coast NGL revenues were lower as a result of
less favorable processing economics, additional fee-based revenues generated by
new deepwater assets more than offset this decline. Additionally, olefins sales
increased due to increased sales and higher prices at both domestic and Canadian
facilities.

Cost and operating expenses also increased $1.3 billion due primarily to the
adoption of EITF 02-3 as discussed above. In addition to this effect, costs and
expenses increased $285 million, of which $227 million is attributable to
modestly higher market prices for natural gas used to replace the heating value
of NGL's extracted at Midstream's gas processing facilities. Feedstock purchases
for the olefins facilities increased $81.4 million due to both higher NGL prices
and sales volumes. In addition, lower selling, general and administrative
expenses, and lower other operating costs were partially offset by higher
depreciation expense resulting from the new deepwater operations.

Segment profit increased $30 million due primarily to the additional net
profit contribution of the deepwater assets, the majority of which were placed
in service during the fourth quarter of 2002. Despite monthly fluctuations,
average gas processing margins for the nine months of 2003 were somewhat
comparable with the first nine months of 2002. These margins increased steadily
each quarter in 2002 as NGL prices rose at a greater rate than natural gas
prices. After peaking in the first quarter of 2003, processing margins
deteriorated in the second quarter as NGL prices fell while gas prices continued
to increase, particularly in the Wyoming area. In addition, lower partnership
earnings and asset impairment charges were offset by reduced selling, general
and administrative expenses and a net gain on the sale of an investment. A more
detailed analysis of segment profit of Midstream's various operations is
presented below:

Domestic Gathering & Processing: Midstream's domestic gathering and
processing segment profit improved $86.6 million with the Gulf and West Regions
recording $70 million and $16.2 million increases, respectively.

The Gulf Region's $70.4 million increase is largely attributable to $38.4
million of incremental operating profit associated with new infrastructure in
the deepwater area of the Gulf of Mexico. The Canyon Station production
platform, Seahawk gas gathering pipeline, and Banjo oil transportation system
were placed into service during the latter half of 2002 and each contributed to
Midstream's segment profit. The Gulf Coast gas processing plants provided
approximately $25 million in additional revenues from $7 million in higher
processing margins and $19 million in higher fee-based revenues. A portion of
this increase relates to the temporary processing agreements created to allow
producers' gas to be processed to achieve pipeline quality standards. Also,
higher gathering volumes originating from new deepwater production, combined
with lower operating expenses, resulted in $12 million of additional segment
profit recorded on the regulated gas gathering system.

The West Region's $16.2 million increase in segment profit includes a $7
million decline resulting from the August 2002 sale of the Kansas Hugoton
gathering system. Bolstered by depressed natural gas prices in Wyoming,
processing margins in the West Region grew steadily throughout 2002 as NGL
prices increased. After peaking in the first quarter of 2003, processing margins
fell considerably in the following two quarters as natural gas prices climbed in
response to additional gas pipeline capacity relieving the downward price
pressure. Gas processing margins for the first nine months of 2003 were slightly
less than those of the same period in 2002. Segment profits were higher largely
due to more efficient operations with favorable variances realized from lower
maintenance expense and lower fuel purchases.

Venezuela: Segment profit increased $1.1 million, primarily as a result of a
$13 million increase in operating profit at the PIGAP gas compression facility
offset largely by a $10 million decrease in the El Furrial operating margins due
primarily to plant downtime resulting from a fire at the plant during the first
quarter of 2003. Also offsetting the increase in PIGAP operating profit is a $2
million decline resulting from the termination by PDVSA of the Jose Terminal
operations contract in December 2002. The year-to-date decline in operating
profit resulting from the termination of this contract is indicative of the
decline expected to occur over future periods. However, the outcome of
arbitration with PDVSA regarding the termination of this contract could impact
the operating profit of Midstream's Venezuelan operations in future periods.

49

Management's Discussion & Analysis (Continued)

Canada: Midstream's Canadian segment profit declined $25.1 million, due
primarily to $6 million in lower gas processing margins caused by gas prices
increasing at a greater rate than NGL prices. Operating expenses were $11
million higher, most of which are attributed to the olefins facility that became
operational in April 2002. In addition, currency transaction losses were higher
due to the decline of the U.S. dollar.

Other: Segment profit for Midstream's other operations fell $32.7 million
due to lower trading revenues, lower domestic olefins margins, and lower
earnings from investments.

Segment profit for Midstream's domestic olefins activities declined
$14.9 million as a result of reduced olefins fractionation margins as the price
of feedstock (ethane and propane) increased more than the price of olefins
products. Higher maintenance expenses also contributed to the decline in segment
profit.

Segment profit for Midstream's NGL trading, fractionation, and storage
operations increased $1 million, primarily as a result of $12 million in lower
selling, general and administrative costs related to NGL trading activities.
This increase is offset by an $8 million decline in liquids trading operations
and lower NGL handling fees caused by the sale of several NGL terminals in 2002.

Midstream's earnings from partially-owned investments accounted for on the
equity method declined $18.8 million due largely to a $13.4 million charge
against Midstream's investment in Discovery reflecting adjustments to expense
certain amounts capitalized in periods prior to Williams becoming the operator,
and the sale of other investments which generated positive earnings in 2002.
Also included in 2003 segment profit were net gains totaling approximately $15.8
million on the sale of Midstream's interests in the West Texas and Rio Grande
liquids pipeline partnerships and $14.1 million of impairment charges associated
with the Aux Sable partnership investment.

OTHER

Other segment loss for the nine months ended September 30, 2003 includes a
$42.4 million impairment related to the investment in Longhorn. Other segment
profit for the three and nine months ended September 30, 2002 includes a $58.5
million gain on the sale of Williams' 27 percent ownership interest in the
Lithuanian operations. The impairment resulted from management's assessment that
there had been an other than temporary decline in the fair value of this
investment.

FAIR VALUE OF ENERGY RISK MANAGEMENT AND TRADING ACTIVITIES

The chart below reflects the fair value of energy trading derivatives for
Power and Midstream 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, Power 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 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 are accounted for using the mark to market
accounting method. The table of trading contracts presented below includes the
fair value as of September 30, 2003 of only those contracts that are held to
provide price risk management services to third party customers or that do not
hedge or that could not reasonably be considered an economic hedge to mitigate
Power's or Midstream's own long-term structured contract positions. 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.

(MILLIONS)

Power 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 September 30, 2003 the fair value of these non-trading derivative contracts
was a net asset of $728 million. Power 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 September 30, 2003 the
fair value of these hedges was a net liability of approximately $156 million.
Various other business units within Williams also possess certain SFAS No. 133
hedge liabilities of approximately $25 million.

50

Management's Discussion & Analysis (Continued)

ESTIMATES AND ASSUMPTIONS REGARDING COUNTERPARTY PERFORMANCE AND CREDIT RISK
CONSIDERATIONS

Power and Midstream 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 Investors
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. Power
and Midstream 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, Power and Midstream enter into netting agreements to mitigate
counterparty performance and credit risk.

The gross forward credit exposure from Power's and Midstream's derivative
contracts as of September 30, 2003 is summarized as below.

In addition to the gross Power and Midstream derivative exposure discussed
above, other business units within Williams possess an additional $29 million in
gross derivative asset exposure.

Power and Midstream assess their credit exposure on a net basis when
appropriate and contractually allowed. The net forward credit exposure from
Power's and Midstream derivative contracts as of September 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.

(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 Investors Service do not currently

51

Management's Discussion & Analysis (Continued)

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 $734.2 million
at September 30, 2003, represents an overall decrease in derivative credit
exposure of approximately 40 percent on a comparable basis from December 31,
2002. In 2002 and 2003, Power closed out various trading positions and as a
result has not suffered significant losses due to recent bankruptcy filings.
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 Power'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. Power 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 Power are discussed in more
detail in Note 11 of Notes to the Consolidated Financial Statements. The outcome
of these matters could affect the creditworthiness and ability to perform
contractual obligations of Power 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 $2.9 billion at
September 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 $532 million at September 30, 2003 as compared to
$352 million at December 31, 2002

o Cash generated from sales of assets

o Cash generated from operations

o $378 million available under Williams' current revolving credit facility
at September 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 Transco. As of November 5, 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.

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 approximately
$4 billion during 2003 and 2004. Through September 30, 2003, Williams has
received $2.8 billion in net proceeds from the sale of assets and $315 million
from the sale and/or termination of certain marketing and trading contracts.

52

Management's Discussion & Analysis (Continued)

Also, the Company's board of directors has approved resolutions that authorize
management to negotiate and facilitate the sales of the assets of Gulf Liquids
New River Project LLC and Williams' Alaska operations. In October 2003, Williams
completed the sale of its interest in two natural gas liquids pipelines for
$26.5 million. These assets were previously identified for divestiture.

Included in the $315 million is $100 million received in September 2003
associated with the expected termination of Williams long-term power contract
with Allegheny Energy Supply Company, LLC, a subsidiary of Allegheny Energy,
Inc. Williams anticipates it will terminate the supply contract upon its receipt
of the final $28 million of the termination payment, which is due in
installments of $14 million to be paid in the first and third quarters of 2004.

Based on its 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 through first-quarter 2004, the
Company has scheduled debt retirements of approximately $1.6 billion. In the
third quarter of 2003, Williams' Board of Directors authorized the Company to
retire or otherwise prepay up to $1.8 billion of debt, including $1.4 billion
designated for the Company's 9.25% notes due March 15, 2004. On October 8, 2003,
the Company announced a cash tender offer for any and all of Williams' $1.4
billion senior unsecured 9.25 percent notes due in March 2004, as well as cash
tender offers and consent solicitations for approximately $241 million of
additional notes and debentures. As of October 31, 2003, approximately $720
million of the 9.25 percent notes had been accepted for purchase. Additionally,
Williams received tenders of notes and deliveries of related consents from
holders of approximately $230 million of the other notes and debentures. The
tender offers are scheduled to expire on November 6, 2003.

OPERATING ACTIVITIES

For the nine months ended September 30, 2003, Williams recorded
approximately $133.5 million in provisions for losses on property and other
assets consisting primarily of a $42.4 million impairment of Williams'
investment in Longhorn, a $25.5 million charge related to the write-off of
software development costs at Northwest Pipeline, a $14.1 million impairment of
Williams investment in Aux Sable, a $13.5 million impairment of an investment in
a company holding phosphate reserves and a $13.2 million impairment of Algar.

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 payable until maturity. The RMT
note payable was repaid in May 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 $15.5 million for the nine months ended September 30,
2003. Additionally, one of the covenants under the indenture 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 (see Note 10).
Williams also paid $32.6 million in accrued dividends on the 9 7/8 percent
cumulative-convertible preferred shares that were redeemed in June 2003.

On October 23, 2003, Williams announced that its PIGAP high-pressure gas
compression project in Venezuela had obtained $230 million in non-recourse
financing. Williams owns a 70 percent interest in the project. Proceeds from the
loan will be used to repay notes due to Williams and the other owner for a
portion of the initial funding of construction-related costs. Upon the execution
of the loan, the project also made additional cash distributions to the owners
based on their respective ownership interests. Williams expects to receive
approximately $185 million, less applicable taxes, in total cash proceeds.

53

Management's Discussion & Analysis (Continued)

INVESTING ACTIVITIES

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

o $799 million related to the sale of Texas Gas Transmission Corporation

o $464 million related to certain natural gas exploration and production
properties in Kansas, Colorado, New Mexico and Utah

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

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 $192 million related to the sale of certain natural gas liquids assets in
Redwater, Alberta

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

o $59 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

o $36 million related to the sale of a natural gas processing plant in western
Canada

o $29 million related to the sale of Williams investment in the Rio Grand
Pipeline

o $29 million related to the sale of Williams investment in West Texas LPG
Pipeline Limited Partnership

o $27 million related to the sale of Williams investment in American Soda, LLP

COMMITMENTS

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

(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) Power 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.

54

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 in the first three quarters of 2003 and debt payments
in each of the first three quarters. During 2003, Williams has repaid the RMT
note payable (see Note 10), $224 million on the variable rate debt of Snow Goose
LLC, $531.2 million of variable rate debt due in 2003 and 2004, $139.8 million
of capitalized lease obligations, and $78.5 million of variable rate debt due in
2006. In the third quarter of 2003, Williams' Board of Directors authorized the
Company to retire or otherwise prepay up to $1.8 billion of debt, including $1.4
billion designated for the Company's 9.25% notes due March 15, 2004. On October
8, 2003, the Company initiated a cash tender offer for any and all of Williams
$1.4 billion senior unsecured 9.25 percent notes and cash tender offers and
consent solicitations for approximately $241 million of additional outstanding
notes and debentures. As of October 31, 2003, approximately $720 million of the
9.25 percent notes had been accepted for purchase. Additionally, Williams
received tenders of notes and deliveries of related consents from holders of
approximately $230 million of the other notes and debentures. The tender offers
are scheduled to expire on November 6, 2003. 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 in 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

Power and Midstream 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. Power and Midstream 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 is 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 September 30, 2003 and December 31, 2002, the value at
risk for the derivative contracts considered to be held for trading purposes was
$13.3 million and $50.2 million, respectively. The adoption of EITF 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
September 30, 2003 trading value at risk. For the disclosure in the Form 10-Q
for March 31, 2003, Power and Midstream considered all derivatives other than
those

55

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

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, beginning 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 that hedge or that could reasonably be considered a possible hedge of
the market risk of Power and Midstream's own long-term structured portfolios.

Non-trading

The non-trading portfolio consists of derivative contracts that hedge or
that could reasonably be considered a possible hedge of changes in energy
commodity prices within Exploration & Production, the non-trading operations of
Midstream and the non-trading operations of Power. Exploration & Production is
exposed to commodity price risk associated with the sales price of the natural
gas and crude oil it produces. Midstream is exposed to commodity price risk
related to natural gas purchases, natural gas liquids purchases and sales, and
electricity costs. Power is exposed to commodity price risk related to
electricity purchased and sold and natural gas purchased for the production of
electricity. At September 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 September
30, 2003 and December 31, 2002, the value at risk for the non-trading derivative
commodity instruments was $19.3 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.

56

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 limit 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 Investors Service and Standard and Poor's, are met.

Item 6. Exhibits and Reports on Form 8-K

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

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 third-quarter 2003, Williams filed a Form 8-K on the
following dates reporting events under the specified items: July 1,
2003 Items 5 and 7; July 18, 2003 Item 9; July 24, 2003 Items 5 and
7; August 5, 2003 Items 5, 7 and 9; August 12, 2003 Item 7, 9 and
12; September 12, 2003 Items 5, 7 and 9.

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)

November 6, 2003