8-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): November 3, 2005

The Williams Companies, Inc.

(Exact name of registrant as specified in its charter)

Delaware	1-4174	73-0569878
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)

One Williams Center, Tulsa, Oklahoma	74172
(Address of principal executive offices)	(Zip Code)

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

Not Applicable
(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240-14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

TABLE OF CONTENTS

Copy of Press Release

Copy of Slide Presentation

Item 2.02. Results of Operations and Financial Condition.

     On November 3, 2005, The Williams Companies, Inc. (“Williams” or the “Company”) issued a press release announcing its financial results for the quarter ended September 30, 2005. A copy of the press release and its accompanying reconciliation schedules are furnished as a part of this current report on Form 8-K as Exhibit 99.1 and is incorporated herein in its entirety by reference.

     The press release and accompanying reconciliation schedules are being furnished pursuant to Item 2.02, Results of Operations and Financial Condition. The information furnished is not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, is not subject to the liabilities of that section and is not deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

Item 7.01. Regulation FD Disclosure.

     Williams wishes to disclose for Regulation FD purposes its slide presentation, furnished herewith as Exhibit 99.2, to be utilized during a public conference call and webcast on the morning of November 3, 2005.

     The slide presentation is being furnished pursuant to Item 7.01, Regulation FD Disclosure. The information furnished is not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, is not subject to the liabilities of that section and is not deemed incorporated by reference in any filing under the Securities Act of 1933, as amended.

Item 9.01. Financial Statements and Exhibits.

(a)	None
(b)	None
(c)	Exhibits

Exhibit 99.1	Copy of Williams’ press release dated November 3, 2005, publicly announcing its third quarter 2005 financial results.
Exhibit 99.2	Copy of Williams’ slide presentation to be utilized during the November 3, 2005, public conference call and webcast.

     Pursuant to the requirements of the Securities Exchange Act of 1934, Williams has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	THE WILLIAMS COMPANIES, INC.
Date: November 3, 2005		/s/ Donald R. Chappel
	Name:	Donald R. Chappel
	Title:	Senior Vice President and Chief Financial Officer

2

INDEX TO EXHIBITS

EXHIBIT
NUMBER	DESCRIPTION
Exhibit 99.1	Copy of Williams’ press release dated November 3, 2005, publicly announcing its third quarter 2005 financial results.
Exhibit 99.2	Copy of Williams’ slide presentation to be utilized during the November 3, 2005, public conference call and webcast.

3

EX-99.1

NYSE: WMB

Date: Nov. 3, 2005

Williams Reports Third-Quarter 2005 Financial Results

• Natural Gas Production Climbs 19% During First 9 Months

• Net Cash from Operations Exceeds $1 Billion Through First Three Quarters

• Third-Quarter Results Lowered by Effect of Mark-to-Market Losses

• Guidance Raised for 2005, 2006 and 2007 on Higher Natural Gas Prices

• Company Plans Sale of Certain Interests to Williams Partners L.P.

• 2006 Capital Spending Increased by $300 Million for E&P and Midstream

3Q Summary Financial Information

	3Q 2005						3Q 2004
	millions			per share			millions			per share
Income from continuing operations	$	5.7		$	0.01		$	16.2		$	0.03
Income (loss) from discontinued operations		($1.3	)	$	0.00		$	82.4		$	0.16
Net income	$	4.4		$	0.01		$	98.6		$	0.19
Recurring income (loss) from continuing operations*	($	4.6	)	$	(0.01	)	$	135.8		$	0.26
After-tax mark-to-market adjustments	$	129.9		$	0.23		($	86.8	)	($	0.17	)
Recurring income from continuing operations - after mark-to-market adjustment*	$	125.3		$	0.22		$	49.0		$	0.09

Year-to-Date Summary Financial Information

	YTD 2005					YTD 2004
	millions			per share		millions			per share
Income (loss) from continuing operations	$	248.6		$	0.42	($	2.3	)	($	0.01	)
Income (loss) from discontinued operations	($	1.8	)	$	0.00	$	92.6		$	0.18
Net income	$	246.8		$	0.42	$	90.3		$	0.17
Recurring income from continuing operations*	$	259.7		$	0.44	$	193.5		$	0.37
After-tax mark-to-market adjustments	$	97.6		$	0.16	($	54.2	)	($	0.10	)
Recurring income from continuing operations - - after mark-to-market adjustment*	$	357.3		$	0.60	$	139.3		$	0.27

* A schedule reconciling income (loss) from continuing operations to recurring income (loss) from continuing operations and mark-to-market adjustments (non-GAAP measures) is available on Williams’ Web site at www.williams.com and as an attachment to this press release.

     TULSA, Okla. – Williams (NYSE:WMB) today announced third-quarter 2005 unaudited net income of $4.4 million, or 1 cent per share on a diluted basis, compared with net income of $98.6 million, or 19 cents per share, for third-quarter 2004.

     Year-to-date through Sept. 30, Williams reported net income of $246.8 million, or 42 cents per share on a diluted basis, compared with net income of $90.3 million, or 17 cents per share, for the first three quarters of 2004.

     For third-quarter 2005, the company reported income from continuing operations of $5.7 million, or 1 cent per share on a diluted basis, compared with $16.2 million, or 3 cents per share, for third-quarter 2004 on a restated basis.

     Results for the 2005 quarter reflect the benefit of increased natural gas production and higher net realized average prices for production sold, along with reduced levels of interest expense. These benefits were offset by the impact of forward unrealized mark-to-market losses experienced in the Power segment. Results for the 2004 quarter reflect the benefit of forward unrealized mark-to-market gains experienced in Power, offset by approximately $155 million in pre-tax charges associated with the early retirement of debt.

     Rising natural gas prices during the third quarter of this year benefited Williams’ Exploration & Production business, but contributed to reduced results in the company’s Power business.

     For the first nine months of 2005, Williams reported income from continuing operations of $248.6 million, or 42 cents per share on a diluted basis, compared with a loss of $2.3 million, or a loss of 1 cent per share, for the same period in 2004 on a restated basis.

CEO Perspective

     “The benefit of having diversity in our businesses and our revenue streams was evident during the third quarter,” said Steve Malcolm, chairman, president and chief executive officer.

     “We were able to create value and produce positive results, despite dealing with the hurricanes and a variety of factors that strained results in our Power business.

     “At the same time, our cash flows remain strong, we’re raising our guidance and we’ve increased our capital spending estimate for 2006.

     “We’re making these investments to produce the natural gas that America needs, to provide reliable services to our customers, and to seize opportunities to help bring even more energy online by building new pipeline and processing systems,” Malcolm added.

Recurring Results Adjusted for Effect of Mark-to-Market Accounting

     To provide an added level of disclosure and transparency, Williams continues to provide an analysis of recurring earnings adjusted for all mark-to-market effects from its Power business unit. Recurring earnings exclude items of income or loss that the company characterizes as unrepresentative of its ongoing operations.

     Recurring income from continuing operations – after adjusting for the mark-to-market impact to reflect income as though mark-to-market accounting had never been applied to Power’s designated hedges and other

derivatives – was $125.3 million, or 22 cents per share, for the third quarter of 2005. In last year’s third quarter, the adjusted recurring income from continuing operations was $49.0 million, or 9 cents per share, on a restated basis.

     Results for the 2005 quarter reflect the benefit of increased natural gas production and higher net realized average prices for production sold, along with reduced levels of interest expense.

     For the first nine months of 2005, recurring income from continuing operations – after adjusting for the mark-to-market impact to reflect income as though mark-to-market accounting had never been applied to Power’s designated hedges and other derivatives – was $357.3 million, or 60 cents per share, compared with $139.3 million, or 27 cents per share, for the same period in 2004 on a restated basis.

     A reconciliation of the company’s income from continuing operations to recurring income from continuing operations and mark-to-market adjustments accompanies this news release.

Business Segment Performance

     Williams’ primary businesses – Exploration & Production, Midstream Gas & Liquids, Gas Pipeline and Power – reported combined segment profit of $214.6 million in the third quarter of 2005.

     In the third quarter a year ago, these businesses reported combined segment profit of $433.6 million on a restated basis.

     For the first nine months of 2005, the four major businesses reported combined segment profit of $1.05 billion compared with $1.03 billion for the same period last year on a restated basis.

     Results for 2005 have benefited primarily from increased natural gas production volumes and higher net realized average prices, and steady, expected performance in Gas Pipeline. Results for 2005 have been negatively affected by the level of forward unrealized mark-to-market losses during the third quarter.

Exploration & Production: Volumes Up 19 Percent for First Nine Months of 2005

     Exploration & Production, which includes natural gas production and development in the U.S. Rocky Mountains, San Juan Basin and Mid-continent, and oil and gas development in South America, reported third-quarter 2005 segment profit of $158.8 million.

     In the third quarter a year ago, the business reported segment profit of $70.1 million. The improvement for the 2005 quarter reflects the benefit of significant increases in both production volumes and net realized average prices for production sold, along with a $21.7 million gain on the sale of certain outside-operated properties. These benefits were partially offset by higher expenses and a $15.8 million loss due to hedge ineffectiveness for future periods associated with the company’s NYMEX collars.

     For the first nine months of 2005, Exploration & Production reported segment profit of $380.8 million, compared with $164.9 million for the same period last year. The increase is primarily a result of the same production and pricing factors listed above.

     Year-to-date through Sept. 30, average daily production from domestic and international interests was approximately 649 million cubic feet of gas equivalent (MMcfe), compared with 546 MMcfe for the same period in 2004 – an increase of approximately 19 percent.

     Average daily domestic production volumes for the third quarter of 2005 totaled 629 MMcfe. That was approximately 18 percent higher than domestic volumes of 535 MMcfe from the same quarter a year ago. Increased production continues to primarily reflect higher volumes in the Piceance Basin. Williams also is realizing favorable production growth from the Big George area in the Powder River Basin.

     Year-over-year, the business has benefited from higher domestic production prices, offset somewhat by higher expenses. In addition, average sales prices in 2005 reflect a lower share of volumes that are hedged and increased contracted prices on the volumes that are hedged. During the third quarter of 2005, Williams realized net domestic average prices of $4.80 per Mcfe compared with $3.34 per Mcfe in the third quarter a year ago – an increase of approximately 44 percent.

     Williams currently has 15 rigs operating in the Piceance Basin of western Colorado – its cornerstone property for production growth. Williams also is preparing to deploy a new rig from Helmerich & Payne in the Piceance later this month or in early December. The original delivery schedule has been impacted by approximately one month due to disruptions caused by Hurricane Rita at a fabrication facility. A total of 10 new rigs are scheduled for delivery in the Piceance during 2005 and 2006. Williams has each of the new rigs under contract for a term of three years.

     Williams now plans to spend between $675 million to $725 million in its Exploration & Production business in 2005, compared with previous guidance of $605 million to $680 million. The change is primarily due to increased activity for new opportunities in the Piceance Basin, accelerated drilling in the Powder River Basin and increased drilling costs.

     Williams also has increased its expectation for segment profit from Exploration & Production in 2005. The company now expects $575 million to $600 million in segment profit, which includes $29 million of non-recurring income and the negative impact of the $15.8 million loss due to hedge ineffectiveness. That expectation is up from previous guidance of $410 million to $485 million for that measure. The increase is primarily the result of higher realized prices during the third quarter and expected prices during the fourth quarter.

Midstream Gas & Liquids: Seizes Growth Opportunities in West, Deepwater Gulf

     Midstream, which provides natural gas gathering and processing services, along with natural gas liquids (NGL) fractionation and storage services and olefins production, reported third-quarter 2005 segment profit of $121.1 million.

     In the third quarter a year ago, the business reported segment profit of $105.4 million on a restated basis. The quarterly improvement primarily reflects increased gathering and processing fee income; higher natural gas liquids production margins realized in the West; and the absence of a $16.5 million unfavorable adjustment to revenues recorded in third-quarter 2004. These benefits were offset partially by lower revenues associated with natural gas gathering and processing facilities that were affected by production shut-ins caused by hurricanes Katrina and Rita. More information about these events is contained later in the news release.

     For the first nine months of 2005, Midstream reported segment profit of $358.8 million compared with a restated $314 million for the same period last year.

     Through Sept. 30, Midstream had sold 1.01 billion gallons of NGL equity volumes compared with equity sales of 1.03 billion gallons for the first three quarters of 2004. Third-quarter 2005 performance was negatively affected by hurricanes Katrina and Rita. These equity volumes are retained and subsequently marketed by Williams as payment-in-kind under the terms of certain processing contracts.

     Gathering and processing volumes increased modestly year-over-year despite the effects of hurricanes Katrina and Rita during the third quarter. Gathering volumes were 949.4 trillion British thermal units (TBtu) in the first three quarters of 2005, compared with 931.4 TBtu in the 2004 period. Fee processing volumes in the first three quarters of 2005 were 555.8 TBtu compared with 555.2 TBtu in the first nine months of 2004.

     Williams’ financial results for Midstream have benefited from favorable natural gas liquids (NGL) margins in both 2005 and 2004, particularly in its western U.S. natural gas processing operations in areas such as Opal and Wamsutter in Wyoming.

     Citing the increased demand for processing capacity, Williams today announced plans to expand its Opal, Wyo., facility by adding a fifth cryogenic processing train. The project is designed to boost the overall processing capacity of Williams’ Opal facility from more than 1.1 billion cubic feet per day to approximately 1.45 billion cubic feet per day, with the ability to recover approximately 68,000 barrels per day of NGL products. Work on the project is scheduled to be completed in second-quarter 2007.

     Subsequent to the close of the third quarter, Williams also announced a $177 million offshore expansion to gather oil and gas from the Blind Faith Field in the deepwater Gulf of Mexico. To accommodate this anticipated production, Williams has agreed to extend its Canyon Chief and Mountaineer pipelines by 37 miles each. The project is scheduled for completion in third-quarter 2007.

     During the third quarter, Williams Partners L.P. (NYSE:WPZ) completed its initial public offering. The Williams Companies, Inc. (NYSE:WMB) and certain of its affiliates own approximately 60 percent of the new master limited partnership that primarily gathers, transports and processes natural gas and fractionates and stores natural gas liquids.

     In addition to Williams Partners’ initial asset portfolio, Williams now proposes to sell an approximate 25 percent interest in its existing gathering and processing assets in the Four Corners area to the master limited partnership.

     On a 100 percent basis, the unaudited operating income plus depreciation from the Four Corners assets has been $154 million, $151 million and $165 million for 2002, 2003 and 2004 respectively. The same measure for the first nine months of 2005 is $136 million.

     The terms of this proposed transaction, including price, will be subject to approval by the boards of directors of both Williams and Williams Partners’ general partner. Assuming such approvals are obtained, it is expected that the transaction would be completed during the second quarter of 2006.

     Williams continues to plan to spend $120 million to $140 million on capital expenditures in its Midstream business in 2005.

     Williams has increased its expectation for segment profit from Midstream in 2005. The company now expects $440 million to $480 million in segment profit from Midstream. That expectation is changed from previous guidance of $400 million to $470 million for that measure. The increase is primarily the result of favorable liquids margins.

Gas Pipeline: Expansions Tied to Market Demand

     Gas Pipeline, which primarily delivers natural gas to markets along the Eastern Seaboard, in Florida and in the Northwest, reported third-quarter 2005 segment profit of $161.1 million. In the third quarter a year ago, the business reported segment profit of $148.8 million.

     The increase in third-quarter 2005 segment profit compared with a year ago is primarily attributable to the benefit of a $14.2 million favorable adjustment from the resolution of litigation associated with its fuel tracker filings and an increase in equity earnings from Gulfstream Natural Gas System, L.L.C., a joint venture in which Williams owns a 50 percent interest. These items were partially offset by the termination of a firm transportation agreement related to the Gray’s Harbor lateral on the Northwest system effective January 2005.

     For the first nine months of 2005, Gas Pipeline reported segment profit of $493 million compared with $429 million for the same period last year. The increase for the nine-month period in 2005 is primarily the result of the previously noted litigation adjustment; the benefit of a second-quarter pension expense correction of $17 million; approximately $13 million in liability reductions associated with prior periods; $16 million in higher equity earnings from its Gulfstream investment; and the absence of a $9 million write-off of capitalized costs in 2004. These were partially offset by the termination of the previously mentioned Gray’s Harbor agreement.

     Following the close of the third quarter, Transco completed construction of a $16 million project to add 105,000 dekatherms per day of new firm service in central New Jersey. This expansion was placed into service Nov. 1.

     Transco also completed a successful open season in the third quarter for new capacity into the greater Washington, D.C., area. Customers executed precedent agreements for a total of 165,000 Dth/d of firm transportation service from receipt points in Guilford and Rockingham counties in North Carolina to certain mainline delivery points in northern Virginia and Maryland. The project, which is subject to Federal Energy Regulatory Commission approval, is anticipated to be placed into service in November 2007.

     Within the past week, Transco and Northwest Pipeline also announced new open seasons to provide between 200,000 and 300,000 Dth/d of additional capacity in the Northeast and approximately 575,000 Dth/d of additional capacity in Colorado, respectively.

     In Washington state, Williams has received final approval from the FERC to construct and operate approximately 80 miles of 36-inch pipeline loop in the existing Northwest Pipeline right of way between Sumas and Washougal, Wash. The estimated $333 million project will replace most of the capacity served previously by 268 miles of an existing 26-inch pipeline. Most of the construction is scheduled to occur in 2006 with an in-service date of November 2006.

     In August, Gulfstream began providing transportation service to Tampa Electric under a new long-term firm service agreement. The new contract provides up to 48,000 Dth/d to serve the H.L. Culbreath Bayside power generation facility in Hillsborough County, Fla.

     In October, Gulfstream completed a debt offering, issuing $850 million of senior unsecured notes of various maturities to certain institutional investors via a 144A private placement. Gulfstream used the proceeds to repay an existing construction loan and to return capital to its equity owners, including approximately $310 million to Williams.

     Williams is raising the low end of its 2005 capital spending range for Gas Pipeline by $20 million to reflect higher activity through the third quarter. The company now plans to spend $390 million to $420 million in capital expenditures for Gas Pipeline this year.

     Williams also is increasing its expectation for 2005 segment profit from Gas Pipeline. The company now expects $630 million to $645 million in segment profit from this business, which includes $50 million of non-recurring items and adjustments related to prior periods. Williams previously expected $590 million to $615 million in segment profit for 2005. The increase is primarily the result of the $14 million non-recurring item recorded in the third quarter, as well as lower than anticipated expenses in the last half of the year.

Power: Continues Cash-Flow Positive Year-to-Date

     Power manages an approximately 7,000-megawatt power portfolio and provides services that support Williams’ natural gas businesses.

     3Q Power Recurring Segment Profit Adjusted for Mark-to-Market Impact

	3Q '05			3Q '04
	(millions)			(millions)
Recurring Segment profit (loss)	($	226.0	)	$	109.3
Mark-to-market adjustments — net		213.0			(142.2	)
Recurring segment loss after mark-to-market adjustments	($	13.0	)	($	32.9	)

     YTD Power Recurring Segment Profit Adjusted for Mark-to-Market Impact

	YTD '05			YTD '04
	(millions)			(millions)
Recurring Segment profit (loss)	($	162.4	)	$	121.1
Mark-to-market adjustments — net		160.1			(87.1	)
Recurring segment loss after mark-to-market adjustments	($	2.3	)	$	34.0

     Power reported a third-quarter 2005 segment loss of $226.4 million, significantly reduced from a segment profit for the same quarter a year ago of $109.3 million. The reduction is primarily the result of unfavorable year-over-year changes from forward unrealized mark-to-market results. The changes consist of $141.1 million in forward unrealized mark-to-market losses in third-quarter 2005 versus $187.9 million in forward unrealized mark-to-market gains in third-quarter 2004. The mark-

to-market gains in the third quarter of 2004 resulted primarily from gas price increases on net long gas contracts that did not qualify for hedge accounting. The mark-to-market losses in third-quarter 2005 resulted from gas price increases on net short gas contracts that do not qualify for hedge accounting.

     Due to the adoption of hedge accounting in fourth-quarter 2004 and the related designation of certain derivative contracts as hedges, there was a significant change in the pool of contracts that are subject to changes in fair value being recognized as mark-to-market income in the current period.

     In recognition of its stated business intent, Power seeks to reduce its economic risk by selling power forward and by buying needed gas forward to maintain a balanced position. During third-quarter 2005 as new power sales/hedges were being completed, and in the normal course of business to reduce risk, Power began reducing certain less effective hedges by entering into offsetting economic contracts. Some of these offsetting contracts did not qualify for hedge accounting and the related changes in fair value were recorded as mark-to-market losses in the current period. Net unrealized gains of $379 million related to the effective portion of Power’s hedges are reported in accumulated other comprehensive loss in third-quarter 2005.

     Power reported a recurring segment loss adjusted for the effect of mark-to-market accounting of $13.0 million in third-quarter 2005, compared with a loss of $32.9 million a year ago. The year-over-year improvement primarily reflects the absence of losses from the interest rate and crude and refined products portfolio, offset by the effects of milder weather in California, an unplanned outage at the Ironwood facility and the impact of Hurricane Katrina.

     For the first nine months of 2005, Power reported a segment loss of $187.3 million compared with segment profit of $121.1 million for the same period in 2004. That change is primarily the result of $179 million in lower forward unrealized mark-to-market gains this year, the impact of milder weather in California, lower spark spreads due to higher natural gas prices, the losses from Hurricane Katrina, the outage at the Ironwood facility and $12 million in higher expenses related to settlements and litigation contingencies.

     For the first nine months of 2005, Power reported a recurring segment loss of $2.3 million adjusted for the effect of mark-to-market accounting, compared with segment profit of $34.0 million for the same period in 2004.

     The year-over-year decline is primarily due to milder weather in California, losses from Hurricane Katrina, the outage at the Ironwood facility in the third quarter, and the absence of a legacy natural gas portfolio that liquidated in first-quarter 2004, offset by the absence of losses in the interest rate portfolio, which was liquidated in fourth-quarter 2004, and the absence of losses in the crude and refined products portfolio.

     During and subsequent to this year’s third quarter, Power completed four new power sales contracts, ranging in term and volume, through 2010. These new contracts effectively reduce risk, increase value and increase cash-flow certainty. Additionally, these power sales reduce the portfolio’s future exposures to fuel-price and weather volatility.

     In the third quarter of 2005, Power used approximately $41 million in cash flow from operations, largely the result of the above referenced portfolio losses and working capital changes. For the first nine months of 2005,

Power generated approximately $44 million in cash flow from operations, largely the result of changes in working capital.

     As a result of the unexpectedly mild weather in California and the other factors already listed, the company has changed its 2005 expectation for cash flow from operations in Power to $25 million to $75 million on a basis that excludes future changes in working capital used in commodity risk management activity on behalf of all of Williams’ commodity businesses. Williams previously expected to generate cash flow from operations of $50 million to $150 million in 2005.

     As a result of the large mark-to-market losses recorded in the third quarter, coupled with the effects of higher natural gas prices and milder summer weather in California, Williams now expects a revised segment loss of between $175 million to $225 million from Power on a basis that excludes future mark-to-market changes. Williams previously expected a segment profit range of a $50 million loss to a $50 million profit.

     On a basis adjusted for the effects of mark-to-market accounting, Williams also has revised its expectation for Power’s 2005 recurring earnings to range from a loss of $50 million to break even due to the mild weather and other factors previously mentioned. Williams previously expected Power to generate 2005 recurring earnings of $50 million to $150 million on a basis adjusted for the effects of mark-to-market accounting.

Cash, Liquidity and Debt: New Credit Facilities Provide Additional Liquidity

     For the year through Sept. 30, net cash provided by operating activities was $1.08 billion, compared with $1.09 billion for the same period in 2004. The company has increased its expectation for cash flow in 2005 to $1.325 billion to $1.525 billion. The company previously expected $1.15 billion to $1.45 billion for the year.

     At the end of the third quarter, Williams had total liquidity of more than $2 billion. This consists of unrestricted cash and cash equivalents of approximately $1.4 billion, other liquid investments of $86 million, and $768 million in unused and available revolving credit facilities.

     In September, the company obtained $700 million in two five-year unsecured credit facilities. Williams now has a total of $2.475 billion in credit facilities.

     For the first three quarters of 2005, Williams has realized a year-over-year decrease in interest expense of $167.6 million as a result of debt reductions. At Sept. 30, 2005, Williams’ total outstanding long-term debt was approximately $7.7 billion.

Gulf Coast Update: Hurricane Rita Hits Close to Home for Operations, Employees

     Williams shut-in the majority of its onshore and offshore gathering and processing assets in the Gulf as a precaution in advance of hurricanes Katrina and Rita.

     The Transco and Gulfstream natural gas pipeline systems remained operational throughout both hurricanes and continued to meet market demand, although volumes were reduced on both systems because of producers’ storm-related supply shut-ins.

     Williams’ operations were relatively unscathed by the first hurricane, but the eye of the second hurricane came through the vicinity of Cameron, La., and Johnsons Bayou where Williams operates the Cameron Meadows natural gas processing plant and a Transco compression and metering station. Both facilities were damaged by the storm and more than half of the company’s 34 employees in the area lost their homes.

     Repairs are essentially complete at the Transco compressor station. The facility returned to service at a limited capacity Nov. 1. The station is flowing and dehydrating natural gas.

     The Cameron Meadows processing plant sustained significant damage and is expected to remain out of service for an extended period. Williams is evaluating the extent, nature, projected cost and feasibility of repairs at the Cameron Meadows plant. The company also is considering other options for restoring processing services in 2006 for the customers that have been served by the facility. The plant is covered by standard property and business interruption insurance.

     Offshore, the Devils Tower deepwater spar at Mississippi Canyon block 773 is preparing to resume commercial operations. Startup is expected to occur today or within the next few days. The facility has been available for service since shortly after Hurricane Katrina, but production had been shut-in until a downstream third-party oil terminal near Venice, La., reopened for business.

Guidance: Company Raises Profit Targets and Capital Spending

     In 2005, Williams now expects consolidated segment profit of $1.375 billion to $1.525 billion, compared with previous expectations of $1.3 billion to $1.585 billion for this measure.

     On a recurring basis adjusted for the impact of mark-to-market accounting, Williams now expects $1.55 billion to $1.70 billion in consolidated segment profit and earnings per share of 84 cents to 94 cents for 2005. The company previously expected $1.375 billion to $1.660 billion in consolidated segment profit and earnings per share of 70 cents to 90 cents for 2005, on a recurring basis adjusted for the impact of mark-to-market accounting.

     In 2006, Williams now expects consolidated segment profit of $1.520 billion to $1.820 billion on a recurring basis adjusted for the impact of mark-to-market accounting, compared with previous expectations of $1.515 billion to $1.815 billion for this measure.

     In 2007, Williams now expects consolidated segment profit of $1.830 billion to $2.255 billion on a recurring basis adjusted for the impact of mark-to-market accounting, compared with previous expectations of $1.640 billion to $2.065 billion for this measure.

     In 2008, Williams expects consolidated segment profit of $2.05 billion to $2.6 billion on a recurring basis adjusted for the impact of mark-to-market accounting.

     Williams cited favorable prices for natural gas as the primary factor for increasing the company’s consolidated segment profit forecasts.

     The company’s overall capital budget has increased, as well. It now plans to spend $1.2 billion to $1.35 billion for 2005; $1.825 billion to $2.050 billion for 2006; and $1.425 billion to $1.625 billion for 2007.

     Previously, Williams forecasted capital spending of $1.1 billion to $1.3 billion for 2005; $1.525 billion to $1.750 billion for 2006; and $1.1 billion to $1.3 billion for 2007.

     The $300 million increase in capital spending guidance for 2006 is budgeted for increased drilling costs and additional drilling in Exploration & Production, along with new infrastructure projects in Midstream.

Today’s Analyst Call

     Williams’ management will discuss the company’s third-quarter 2005 financial results and outlook during an analyst presentation to be webcast live beginning at 10 a.m. Eastern today.

     Participants are encouraged to access the presentation and corresponding slides via www.williams.com. A limited number of phone lines also will be available at (877) 502-9276. International callers should dial (913) 981-5591. Callers should dial in at least 10 minutes prior to the start of the discussion. Replays will be available at www.williams.com.

Form 10-Q

     The company is filing its Form 10-Q today with the Securities and Exchange Commission. The document will be available on both the SEC and Williams websites.

About Williams (NYSE:WMB)

Williams, through its subsidiaries, primarily finds, produces, gathers, processes and transports natural gas. The company also manages a wholesale power business. Williams’ operations are concentrated in the Pacific Northwest, Rocky Mountains, Gulf Coast, Southern California and Eastern Seaboard. More information is available at www.williams.com.

Contact:	Kelly Swan
	Williams (media relations)
	(918) 573-6932
	Richard George
	Williams (investor relations)
	(918) 573-3679

# # #

Williams’ reports, filings, and other public announcements might contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Private Securities Litigation Reform Act of 1995. You typically can identify forward-looking statements by the use of forward-looking words, such as “anticipate,” believe,” “could,” “continue,” “estimate,” “expect,” “forecast,” “may,” “plan,” “potential,” “project,” “schedule,” “will,” and other similar words. These statements are based on our intentions, beliefs, and assumptions about future events and are subject to risks, uncertainties, and other factors. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, other factors could cause our actual results to differ materially from the results expressed or implied in any forward-looking statements. Those factors include, among others: changes in general economic conditions and changes in the industries in which Williams conducts business; changes in federal or state laws and regulations to which Williams is subject, including tax, environmental and employment laws and regulations; the cost and outcomes of legal and administrative claims proceedings, investigations, or inquiries; the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including our credit ratings and general economic conditions; the level of creditworthiness of counterparties to our transactions; the amount of collateral required to be posted from time to time in our transactions; the effect of changes in accounting policies; the ability to control costs; the ability of each business unit to successfully implement key systems, such as order entry systems and service delivery systems; the impact of future federal and state regulations of business activities, including allowed rates of return, the pace of deregulation in retail natural gas and electricity markets, and the resolution of other regulatory matters; changes in environmental and other laws and regulations to which Williams and its

subsidiaries are subject or other external factors over which we have no control; changes in foreign economies, currencies, laws and regulations, and political climates, especially in Canada, Argentina, Brazil, and Venezuela, where Williams has direct investments; the timing and extent of changes in commodity prices, interest rates, and foreign currency exchange rates; the weather and other natural phenomena; the ability of Williams to develop or access expanded markets and product offerings as well as their ability to maintain existing markets; the ability of Williams and its subsidiaries to obtain governmental and regulatory approval of various expansion projects; future utilization of pipeline capacity, which can depend on energy prices, competition from other pipelines and alternative fuels, the general level of natural gas and petroleum product demand, decisions by customers not to renew expiring natural gas transportation contracts; the accuracy of estimated hydrocarbon reserves and seismic data; and global and domestic economic repercussions from terrorist activities and the government’s response to such terrorist activities. In light of these risks, uncertainties, and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time that we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

In regard to the company’s reserves in Exploration & Production, the SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves. We have used certain terms in this news release, such as “probable” reserves and “possible” reserves and “new opportunities potential” reserves that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Probable and possible reserves are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Possible reserve estimates are less certain than those for probable reserves. New opportunities potential is an estimate of reserves for new areas for which we do not have sufficient information to date to raise the reserves to either the probable category or the possible category. New opportunities potential estimates are even less certain that those for possible reserves. Reference to “total resource portfolio” include proved, probable and possible reserves as well as new opportunities potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our website at www.williams.com.

Reconciliation of Income (Loss) from Continuing Operations to Recurring Earnings
(UNAUDITED)

	2004													2005
(Dollars in millions, except for per-share amounts)	1st Qtr		2nd Qtr			3rd Qtr		4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			Year
Income (loss) from continuing operations available to common stockholders	$	—	($	18.5	)	$	16.2	$	95.5		$	93.2		$	202.2		$	40.7		$	5.7		$	248.6
Income (loss) from continuing operations — diluted earnings (loss) per common share	$	—	($	0.03	)	$	0.03	$	0.17		$	0.17		$	0.34		$	0.07		$	0.01		$	0.42
Nonrecurring items:
Power
Accrual for a regulatory settlement (1)		—		—			—		—			—			4.6			—			—			4.6
Accrual for litigation contingencies (1)		—		—			—		—			—			—			13.1			0.4			13.5
Prior period correction		—		—			—		—			—			6.8			—			—			6.8
Total Power nonrecurring items		—		—			—		—			—			11.4			13.1			0.4			24.9
Gas Pipeline
Prior period liability corrections — TGPL		—		—			—		—			—			(13.1	)		(4.6	)		—			(17.7	)
Prior period pension adjustment — TGPL		—		—			—		—			—			—			(17.1	)		—			(17.1	)
Write-off of previously-capitalized costs — idled segment of Northwest’s pipeline		—		9.0			—		—			9.0			—			—			—			—
Income from favorable ruling on FERC appeal (1999 Fuel Tracker)		—		—			—		—			—			—			—			(14.2	)		(14.2	)
Total Gas Pipeline nonrecurring items		—		9.0			—		—			9.0			(13.1	)		(21.7	)		(14.2	)		(49.0	)
Exploration & Production
Gain on sale of E&P properties		—		—			—		—			—			(7.9	)		—			(21.7	)		(29.6	)
Loss provision related to an ownership dispute		—		11.3			—		4.1			15.4			0.3			—			—			0.3
Total Exploration & Production nonrecurring items		—		11.3			—		4.1			15.4			(7.6	)		—			(21.7	)		(29.3	)
Midstream Gas & Liquids
La Maquina depreciable life adjustment		—		—			6.4		1.2			7.6			—			—			—			—
Gain on sale of Louisiana Olefins assets		—		—			—		(9.5	)		(9.5	)		—			—			—			—
Gulf Liquids arbitration award (Winterthur)		—		—			—		(93.6	)		(93.6	)		—			—			—			—
Impairment of Discovery		—		—			—		16.9			16.9			—			—			—			—
Devils Tower revenue correction		—		(16.5	)		16.5					—			—			—			—			—
Total Midstream Gas & Liquids nonrecurring items		—		(16.5	)		22.9		(85.0	)		(78.6	)		—			—			—			—
Other
Impairment of Longhorn		—		10.8			—		—			10.8			—			49.1			—			49.1
Write-off of capitalized project development costs		—		—			—		—			—			—			4.0			—			4.0
Augusta environmental reserve		—		—			—		11.8			11.8			—			—			—			—
Longhorn recapitalization fee		6.5		—			—		—			6.5			—			—			—			—
Total Other nonrecurring items		6.5		10.8			—		11.8			29.1			—			53.1			—			53.1
Nonrecurring items included in segment profit (loss)		6.5		14.6			22.9		(69.1	)		(25.1	)		(9.3	)		44.5			(35.5	)		(0.3	)
Nonrecurring items below segment profit (loss)
Impairment of cost-based investments (Investing income (loss) -Various)		—		—			15.7		2.3			18.0			—			—			—			—
Write-off of capitalized debt expense (Interest accrued — Corporate)		—		3.8			—		—			3.8			—			—			—			—
Premiums, fees and expenses related to the debt repurchase and debt tender offer (Other income (expense) — net — Corporate and Exploration & Production)		—		96.7			155.1		29.7			281.5			—			—			—			—
Gulf Liquids arbitration award (Winterthur) — interest income — (Investing income / loss) — Midstream)		—		—			—		(9.6	)		(9.6	)		—			—			—			—
Gain on sale of remaining interests in Seminole Pipeline and MAPL (Investing income / loss — Midstream)		—		—			—		—			—			—			(8.6	)		—			(8.6	)
Loss provision related to an ownership dispute — interest component (Interest accrued — Exploration & Production)		—		1.9			—		2.1			4.0			2.7			—			—			2.7
Directors and officers insurance policy adjustment (General corporate expenses — Corporate)		—		—			—		—			—			—			—			13.8			13.8
Loss provision related to ERISA litigation settlement (Other income (expense) — net - Corporate)		—		—			—		—			—			—			—			5.0			5.0
		—		102.4			170.8		24.5			297.7			2.7			(8.6	)		18.8			12.9
Total nonrecurring items		6.5		117.0			193.7		(44.6	)		272.6			(6.6	)		35.9			(16.7	)		12.6
Tax effect for above items (1)		2.5		44.8			74.1		(17.1	)		104.3			(2.8	)		10.7			(6.4	)		1.5
Recurring income (loss) from continuing operations available to common stockholders	$	4.0	$	53.7		$	135.8	$	68.0		$	261.5		$	198.4		$	65.9		($	4.6	)	$	259.7
Recurring diluted earnings (loss) per common share	$	0.01	$	0.10		$	0.26	$	0.12		$	0.49		$	0.33		$	0.11		($	0.01	)	$	0.44
Weighted-average shares — diluted (thousands)		519,485		521,698			529,525		586,497			535,611			599,422			578,902			580,735			604,749

⁽¹⁾ No tax effect on $.6 million of the accrual for a regulatory settlement in 1st quarter 2005 and $8 million of the accrual for litigation contingencies in 2nd quarter 2005.

Note: The sum of earnings (loss) per share for the quarters may not equal the total earnings (loss) per share for the year due to changes in the weighted-average number of common shares outstanding.

Reconciliation of Mark-to-Market Adjustments

	2005
Dollars in millions except for per share amounts	1Q			2Q			3Q			4Q	Year
Recurring income from cont. ops available to common shareholders	$	198		$	66		$	(5	)		$	260
Recurring diluted earnings per common share	$	0.33		$	0.11		$	(0.01	)		$	0.44
Mark-to-Market (MTM) adjustments:
Reverse forward unrealized MTM gains/losses		(221	)		(22	)		153				(90	)
Add realized gains/losses from MTM previously recognized		113			77			60				250
Total MTM adjustments		(108	)		55			213				160
Tax effect of total MTM adjustments (at 39%)		(42	)		21			83				62
After tax MTM adjustments		(66	)		34			130				98
Recurring income from cont. ops available to common shareholders after MTM adjust.	$	132		$	100		$	125			$	357
Recurring diluted earnings per share after MTM adj.	$	0.22		$	0.17		$	0.22			$	0.60
weighted average shares — diluted (thousands)		599,422			578,902			580,735				604,749

	2004 *
	1Q			2Q			3Q			4Q			Year
Recurring income from cont. ops available to common shareholders	$	4		$	54		$	136		$	68		$	261
Recurring diluted earnings per common share	$	0.01		$	0.10		$	0.26		$	0.12		$	0.49
Mark-to-Market (MTM) adjustments:
Reverse forward unrealized MTM gains/losses		(24	)		(70	)		(187	)		(23	)		(304	)
Add realized gains/losses from MTM previously recognized		136			11			45			(6	)		186
Total MTM adjustments		112			(59	)		(142	)		(29	)		(118	)
Tax effect of total MTM adjustments (at 39%)		44			(23	)		(55	)		(11	)		(46	)
After tax MTM adjustments		68			(36	)		(87	)		(17	)		(72	)
Recurring income from cont. ops available to common shareholders after MTM adjust.	$	72		$	18		$	49		$	50		$	189
Recurring diluted earnings per share after MTM adj.	$	0.14		$	0.03		$	0.09		$	0.09		$	0.35
		519,485			521,698			529,525			586,497			535,611

EX-99.2

Exhibit 99.2

Williams 2005 3rd Quarter Earnings Release November 3, 2005

Our reports, filings, and other public announcements might contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You typically can identify forward-looking statements by the use of forward-looking words, such as "anticipate," believe," "could," "continue," "estimate," "expect," "forecast," "may," "plan," "potential," "project," "schedule," "will," and other similar words. These statements are based on our intentions, beliefs, and assumptions about future events and are subject to risks, uncertainties, and other factors. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, other factors could cause our actual results to differ materially from the results expressed or implied in any forward-looking statements. Those factors include, among others: Our businesses are subject to complex government regulations that are subject to changes in the regulations themselves or in their interpretation or implementation; Our ability to gain adequate, reliable and affordable access to transmission and distribution assets due to the FERC and regional regulation of wholesale market transactions for electricity and gas; Our gas sales, transmission and storage operations are subject to government regulations and rate proceedings that could have an adverse impact on our ability to recover the costs of operating our pipeline facilities; The different regional power markets in which we compete or will compete in the future have changing regulatory structures; Our risk measurement and hedging activities might not prevent losses; Electricity, natural gas liquids and gas prices are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain existing businesses; We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets; Our operating results might fluctuate on a seasonal and quarterly basis; Risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments; Legal proceedings and governmental investigations related to our business; Recent developments affecting the wholesale power and energy trading industry sector that have reduced market activity and liquidity; Because we no longer maintain investment grade credit ratings, our counterparties have required us to provide higher amounts of credit support; Despite our restructuring efforts, we may not attain investment grade ratings; Institutional knowledge represented by our former employees now employed by our outsourcing service provider might not be adequately preserved; Failure of the outsourcing relationship might negatively impact our ability to conduct our business; Our ability to receive services from outsourcing provider locations outside the United States might be impacted by cultural differences, political instability, or unanticipated regulatory requirements in jurisdictions outside the United States; We could be held liable for the environmental condition of any of our assets, which could include losses or costs of compliance that exceed our current expectations; Environmental regulation and liability relating to our business will be subject to environmental legislation in all jurisdictions in which it operates, and such legislation may be subject to change; Potential changes in accounting standards that might cause us to revise our financial disclosure in the future, which might change the way analysts measure our business or financial performance; The continued availability of natural gas reserves to our natural gas transmission and midstream businesses; Our drilling, production, gathering, processing and transporting activities involve numerous risks that might result in accidents and other operating risks and costs; Compliance with the Pipeline Improvement Act may result in unanticipated costs and consequences; Estimating reserves and future net revenues involves uncertainties and negative revisions to reserve estimates and oil and gas price declines may lead to impairment of oil and gas assets; The threat of terrorist activities and the potential for continued military and other actions; The historic drilling success rate of our exploration and production business is no guarantee of future performance; and Our assets and operations can be affected by weather and other phenomena. In light of these risks, uncertainties, and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time that we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Forward Looking Statements

Oil & Gas Reserves Disclaimer The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves. We use certain terms in this presentation, such as "probable" reserves and "possible" reserves and "new opportunities potential" reserves that the SEC's guidelines strictly prohibit us from including in filings with the SEC. The SEC defines proved reserves as estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under the assumed economic conditions. Probable and possible reserves are estimates of potential reserves that are made using accepted geological and engineering analytical techniques, but which are estimated with reduced levels of certainty than for proved reserves. Possible reserve estimates are less certain than those for probable reserves. New opportunities potential is an estimate of reserves for new areas for which we do not have sufficient information to date to raise the reserves to either the probable category or the possible category. New opportunities potential estimates are even less certain that those for possible reserves. Reference to "total resource portfolio" include proved, probable and possible reserves as well as new opportunities potential. Investors are urged to closely consider the disclosures and risk factors in our Forms 10-K and 10-Q, available from our offices or from our Web site at www.williams.com.

3Q05 Review Steve Malcolm Chairman, President & CEO

3rd Quarter Headlines Recurring earnings after mark-to-market effect climb nearly 150% over year-ago level Exploration & Production growth continues Continued strength in liquids margins drive Midstream results higher Gas Pipeline continues steady performance Mild weather, high gas prices, hurricanes combine to depress Power results Overview

Headlines E&P ready to ramp up pace of growth again with arrival of new rigs in Piceance Basin Midstream captures significant deepwater production commitment, prepares to expand capacity in West Gas Pipeline continues to expand system to meet demand of growth markets Power completes deal to resell 1,500 megawatts of tolling rights through 2010 Planning sale to Williams Partners L.P. of about 25% interest in gathering and processing assets in Four Corners area Raising capital expenditure and profit guidance Overview

Effect of Hurricanes Overall effect on Williams expected to be minimal Interstate pipelines provided continuous service For Midstream, Katrina and Rita reduced volumes in the Gulf of Mexico area, but boosted margins in its western business Moving incremental volumes - stranded gas - via new interconnects on Discovery Contributed to depressed Power results Pushed delivery of first of 10 new FlexRig4? rigs in Piceance Basin to end of this month Overview

Financial Results and 2005 Outlook Don Chappel CFO

Financial Results Dollars in millions (except per share amounts) 3rd Qtr YTD 2005 2004 2005 2004 Income (Loss) from Continuing Operations $5 $16 $249 ($2) Income (Loss) from Disc. Operations (1) 83 (2) 92 Net Income (Loss) $4 $99 $247 $90 Net Income (Loss)/Share $0.01 $0.19 $0.42 $0.17 Recurring Income (Loss) from Cont. Ops./Share ($0.01) $0.26 $0.44 $0.37 Recurring Inc. from Cont. Ops. After MTM Adjustments/Share $0.22 $0. 09 $0.60 $0.27 Consolidated A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation.

Recurring Income from Cont. Operations A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Consolidated Dollars in millions 3rd Qtr YTD 2005 2004 2005 2004 Income (Loss) from Continuing Operations $6 $16 $249 ($2) Nonrecurring Items Impairments/Losses/Write-offs 5 16 61 41 Expense related to Prior Periods - - 17 (28) 11 Gain on Sale of Assets (22) - - (38) - - Debt Retirement Expense - - 155 - - 252 Other - Net - - 6 18 13 Total nonrecurring (17) 194 13 317 Tax Effect of Adjustments (6) 74 2 121 Recurring Income (Loss) from Continuing Operations Available To Common ($5) $136 $260 $194 Recurring Income (Loss) from Continuing Operations/Share ($0.01) $0.26 $0.44 $0.37

3rd Qtr YTD 2005 2004 2005 2004 Recurring Income from Cont. Operations After Mark-to-Market Adjustments Note: Adjustments have been made to reverse estimated forward unrealized MTM gains (losses) and add estimated realized gains from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives. A more detailed schedule reconciling income from continuing operations to recurring income from continuing operations after MTM adjustments is available on Williams' Web site at www.williams.com. Dollars in millions, except for per-share amounts Recurring Inc. (Loss) from Cont. Ops. Avail. To Common ($5) $136 $260 $194 Recurring Diluted Earnings (Loss) per Common Share ($0.01) $0.26 $0.44 $0.37 Mark-to-Market (MTM) adjustments for Power: Reverse forward unrealized MTM (gains) losses 153 (187) (90) (280) Add realized gains from MTM previously recognized 60 45 250 193 Total MTM adjustments 213 (142) 160 (87) Tax Effect of Total MTM Adjustments (at 39%) 83 (55) 62 (34) After-tax MTM Adjustments 130 (87) 98 (53) Recurring income from Continuing Operations Avail. To Common Shareholders After MTM Adjustments $125 $49 $358 $141 Recurring Diluted Earnings Per Share After MTM adjustments $0.22 $0.09 $0.60 $0.27 Consolidated

Net Income Components A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Consolidated 3rd Qtr YTD 2005 2004 2005 2004 Segment Profit $205 $436 $971 $1,008 Net Interest Expense (164) (197) (491) (657) Debt Retirement expense - - (155) - - (252) Other Income (Expense) - Net (38) (19) (62) (58) Income from Cont. Ops. Before Tax 3 65 418 41 Provision for Income Tax (2) 49 169 43 Income (Loss) from Continuing Ops. 5 16 249 (2) Income (Loss) from Discontinued Ops. (1) 83 (2) 92 Net Income $4 $99 $247 $90

Third Quarter Segment Profit A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. Dollars in millions Exploration & Production $159 $70 $137 $70 Midstream Gas & Liquids 121 105 121 128 Gas Pipeline 161 149 147 149 Power (226) 109 (226) 109 Other (10) 3 (10) 3 Segment Profit $205 $436 $169 $459 MTM Adjustments - Power 213 (142) Segment Profit after MTM Adjustments $382 $317 Memo: Power after MTM adjustments $(13) $(33) Consolidated Reported Recurring 3Q05 3Q04 3Q05 3Q04

2005 YTD Segment Profit Reported Recurring 2005 2004 2005 2004 Exploration & Production $38 $165 $352 $176 Midstream Gas & Liquids 359 314 359 320 Gas Pipeline 493 429 444 438 Power (187) 121 (162) 121 Other (75) (21) (23) (3) Segment Profit $971 $1,008 $970 $1,052 MTM Adjustments 160 (87) Segment Profit after MTM Adjustments $1,130 $965 Memo: Power after MTM adjustments ($2) $341 Dollars in millions Consolidated A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com and at the end of this presentation. 1 Includes impact of legacy natural gas portfolio that liquidated in 1Q04.

Major Changes in Quarter Recurring Segment Profit After Mark-to-Market Adjustments Consolidated Recurring Segment Profit after MTM Adj. 3Q04 $317 Exploration & Production 67 - Higher production volumes +$14million - Higher net realized price +$82 million - Impact of hedge ineffectiveness -$16 million Midstream (7) - Decreased NGL margins -$11 million - Increased processing fees +$7 million Gas Pipeline (2) - Increased Gulfstream earnings +$5 million - Grays Harbor contract termination -$5 million Power 20 - Absence of interest rate losses +$15 million Other (13) Recurring Segment Profit after MTM Adj. 3Q05 $382 Dollars in millions

Cash Information Consolidated 1 $273 MM of proceeds related to settlement of purchase contract underlying FELINE PACS 2 Includes international cash ($197), cash to settle legacy matters including tax settlement ($200), AK Quality Bank judgment and other matters. 2

Debt Balance1 Scheduled Debt Retirements & Amortization (6) Debt Balance @ 6/30/05 7,744 7.5% Scheduled Debt Retirements & Amortization (23) Debt Balance @ 9/30/05 $7,721 7.5% Fixed Rate Debt @ 9/30/05 $7,073 7.7% Variable Rate Debt @ 9/30/05 $648 5.7% Avg. Cost 1 Debt is long-term debt due within 1 year plus long-term debt. Dollars in millions Consolidated Debt Balance @ 12/31/04 $7,962 7.4% Scheduled Debt Retirements & Amortization (216) Capitalized Lease 4 Debt Balance @ 3/31/05 7,750 7.4%

Business Unit Results

Exploration & Production Ralph Hill Senior Vice President

Segment Profit Dollars in millions 3rd Qtr YTD 2005 2004 2005 2004 Segment Profit $159 $70 $381 $165 Nonrecurring: Ownership Issue - - - 11 Gain on sale of assets (22) - (29) - Recurring Segment Profit $137 $70 $352 $176 3Q04 to 3Q05 financial highlights include: Volume increase of 17% Net realized price increase of 44% Hedge ineffectiveness expense of $15.8MM in 3Q05 Recurring profit increase of 96%, excluding hedge ineffectiveness 119% Base business sequential quarter improved Increased recurring segment profit 16%, excluding hedge ineffectiveness 30% Increased volumes 5% $94 million negative hedge impact in 3Q05 including $16 million hedge ineffectiveness, $186 million year to date Exploration & Production

Strong Domestic Production Growth Exploration & Production 2004 2005

Impressive volume growth continues Full year with no lost time accidents for E&P Big George gross production up to 135 MMcf/d 12 rigs operating in Piceance Valley, 3 rigs in Highlands First H&P rig to be delivered in November Highlands production reaches 13 MMcf/d Additional Piceance Highland opportunity obtained Ft. Worth progressing Stable San Juan production continues International volumes up 10% sequentially Exploration & Production 3rd Quarter and 2005 Accomplishments

Powder River - Big George Coal Area Up 67 MMcf/d or 98% over a year ago Up 25 MMcf/d or 23% sequentially Big George production increase continues to offset Wyodak decline Exploration & Production Williams' Big George Production 0 20 40 60 80 100 120 140 160 Jun '04 Sep '04 Dec '04 Mar '05 Jun '05 Sep '05 MMcfd

Piceance Production Growth Up 84 MMcf/d or 34% over a year ago Up 19 MMcf/d or 6% sequentially Exploration & Production

3P Reserves August '05 Announcement: 37.5% increase in probable and possible reserves since year end '04 Extensive study of Piceance Valley yielded additional 1,600 locations and approximately 1.5 Tcf probable and possible reserves Rock quality Land/topography Drilling reach H&P rig capabilities provide access to some of the additional locations Does not include areas such as Trail Ridge, Ryan Gulch, Red Point and Allen Point Exploration & Production '04 YE Proved Existing Proved, Prob. & Poss. 3 Tcf 8.5 Tcf 3P '04 YE 7.0 Tcf '04 YE Proved

Piceance Highlands - Operations Update Exploration & Production

Project Area Net Acres Estimated Gross Potential Locations Estimated Net Potential Reserves (BCF) (1) 2004 Wells 2005 Wells 2006 Wells Trail Ridge (40-acre density)(2) 20,638 500 500 3 12 20 Ryan Gulch (40-acre density) 15,780 770 700 3 8 15 Allen Point (40-acre density) 6,240 200 140 0 6 9 Red Point (10-acre density) 1,908 190 200 0 2 10 Total 44,566 1,660 1,540 6 28 54 (1) Not included in US Reserves summary of 3.0 Tcf proved and 8.5 Tcf proved, probable and possible (2) 10-acre increased density hearing on COGCC docket for December 5, 2005 Piceance Highlands Projects Summary Exploration & Production

Piceance Highlands - Year to Date Results Exploration & Production Project Area Wells Drilled / Completed Average 30 Day Rate / Completed Well (MMCF/D) Preliminary Reserves Range (BCF/well) Trail Ridge 12 / 9 1.1 1.2 - 1.4 Ryan Gulch(1) 2 / 1 1.4 1.2 - 2.0 Red Point (2) - - 1.2 1.2 - 1.4 Allen Point 3 / 1 1.1 1.2 - 1.4 (1) Combination of our wells and offset wells from this year (2) All Rates and reserve range estimates based on offset areas

Reflective of core basins * Includes LOE, G&A, taxes and gathering ** Includes acquisition and development expenditures / proved reserves ('02-'04 average) Cash Margin Analysis Exploration & Production Previous 3-Year Average (2005-07) Cash Margin Cash Costs* Previous $1.81 $0.78 $3.71 $5.52 $0.00 $1.25 $2.50 $3.75 $5.00 Realized Gas Price Assumption Margin/Cost Assumption F&D Costs** $4.56 $1.56 $3.00

Dollars in millions Exploration & Production 2005-2007 Guidance 295 - 335 365 - 415 410 - 485 520 - 595 595 - 720 605 - 680 760 - 860 735 - 885 625 - 700 740 - 840 850 - 950 645 - 750 815 - 930 960 - 1,135 Includes YTD nonrecurring adjustments which increase reported earnings by $29 million $8.70 is average for 2005 and includes a $13.31 estimate for the 4th quarter Note: If guidance has changed, previous guidance from 8/4/2005 is shown in italics directly below $6.34 $5.96 $5.75 2005 2006 2007 Segment profit $575 - 6001 $650 - 725 $775 - 900 Annual DD&A 235 - 265 335 - 375 425 - 475 Segment profit + DD&A $810 - 865 $985 - 1,100 $1,200 - 1,375 Capital spending $675 - 725 $950 - 1,050 $950 - 1,050 Production (MMcfe/d) 650 - 675 750 - 825 875 - 975 Unhedged Price Assumption (NYMEX, $/Mcf) $8.702 $8.50 $7.00 Hedge Volume (MMcfe/d) 383 414 287

Dollars in millions 2006-07 Guidance Reconciliation Exploration & Production

Strategy remains rapid development of our premier drilling inventory Delivering meaningful volume growth through expanded development drilling activity -- Piceance is primary growth driver Long history of high drilling success, low finding costs Short time cycle investments, fast cash returns Maintaining top quartile cost and efficiency position Long-term repeatable drilling inventory of significant proved undeveloped, probables, and possibles New opportunities contributing Trail Ridge, Ryan Gulch, Red Point, Allen Point, Ft. Worth Basin, and Caney Shale Experienced and talented workforce Key Points Exploration & Production

Midstream Alan Armstrong Senior Vice President

Segment Profit Dollars in millions 3rd Qtr YTD 2005 2004 2005 2004 Segment Profit $121 $105 $359 $314 Nonrecurring: Depreciable Life Adjustment - 6 6 Devils Tower Revenue Recognition1 - 17 - - Recurring Segment Profit $121 $128 $359 $320 Key Business Drivers: Higher Gathering and Processing Fee Revenue Outages in Gulf Coast Drove High Western Margins Total NGL Production Lowered by Outages Midstream 1 Recognition of revenue correction 2Q '04 to 3Q '04.

3rd Quarter and 2005 Highlights Rapidly responded to Katrina Providing industry solutions: Discovery open seasons Damaged by Rita Cameron Plant still down Max volume at Canada Won Tahiti Gulf of Mexico business Delivering promised expansions: Opal TXP 5 Blind Faith 3rd quarterly increase in west gathered volumes & revenues 3Q '02 4Q '02 1Q '03 1Q '04 2Q '03 2Q '04 3Q '03 4Q '03 1Q 2Q 3Q 4Q 143 118.8 151.1 150.7 92.9 143.5 109 105.7 Recurring Segment Profit 102.2 78 112.3 108.3 53.6 98.5 69.4 65.6 Depreciation 40.8 40.8 38.8 42.4 39.3 45 39.6 40.1 2004 150 127 172 197 2005 175 155 170 0 Recurring Segment Profit + Depreciation Midstream

2005 2006 2007 Segment Profit $440-480 $400-500 $410-530 Annual DD&A 180-190 185-195 195-205 Segment Profit + DDA $620-670 $585-695 $605-735 Capital Spending $120-140 $230-250 $180-220 Note: If guidance has changed, previous guidance from 8/4/2005 is shown in italics directly below Midstream 2005-07 Guidance Dollars in millions $400 - $470 $580 - $660 $400 - $520 $110 - $130 $100 - $130 $590 - $720 $190 - $200 Major Growth Projects Update: In Guidance Identified '06-'07 Proposal Stage '06-'08 Opal TXP V (2Q 2007) $200-300 MM $600 MM Blind Faith (3Q 2007)

Dollars in millions Note: - - Segment Profit is stated on a recurring basis. Segment Profit for 2003 & 2004 has been restated to reflect reclassifications - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges. - - Margin uplift represents actual realized margin in excess of forecasted margin. Midstream 0 100 200 300 400 500 600 700 800 Capital 2003 Seg Profit + DDA Seg Profit & DDA Discretionary Expansion Margin Uplift Base Capital Spending Historic Expansion Discretionary Expansion Maintenance Well Connects Capital Seg Profit + DDA 2004 Capital Seg Profit + DDA 2005 Capital Seg Profit + DDA 2006 Capital Seg Profit + DDA 2007 Strong Free Cash Flow

Midstream Delivering Promised Expansions $177 MM to extend Canyon Chief and Mountaineer 37 miles Expected to be ready for service by 3Q 2007 Opportunity for gas processing at Mobile Bay Opportunity for gas transport through Transco and Gulfstream Liquids could be fractionated at Baton Rouge or Paradis Blind Faith

Midstream Delivering Promised Expansions Opal TXP V Adding capacity: Gas processing ~ 350 MMcf/day Liquids production ~ 17,000 BBls/day Total post-expansion capacity: Gas processing ~ 1.5 Bcf/day Liquids production ~ 68,000 BBls/day In service by 2Q 2007 Serving the Pinedale Anticline Field

Key Points Strong earnings and cash flows despite hurricanes MLP supplements growth strategy Capturing growth opportunities Delivered on "First Tranche" of expansion opportunities Organic growth around our Western assets Footprint expansion in the deepwater Robust opportunities in the pipeline Midstream Tutorial on November 30 Midstream

Gas Pipeline Phil Wright Senior Vice President

Segment Profit $161 $149 $493 $429 Nonrecurring 1999 Fuel Tracker adjustment1 (14) - (14) - Pension expense reduction1 - - (17) - Adjustment to carrying value of certain liabilities1 - - (18) - Write-off hydrostatic testing - - - 9 Recurring Segment Profit $147 $149 $444 $438 3Q04 to 3Q05 financial highlights include: $5 million increased earnings at Gulfstream $(5) million Gray's Harbor contract termination Segment Profit Dollars in millions 3rd Qtr YTD 2005 2004 2005 2004 Gas Pipeline 1 Prior period items

Northwest's 26" Replacement receives final FERC approval Transco and Gulfstream remained operational and met market demands throughout hurricane season Successful Gulfstream financing Successful in accelerating growth across our pipelines: Gulfstream began new transportation service to Tampa Electric under new long-term firm service agreement for 48 Mdth/d Construction began in July and wrapping up for Central New Jersey expansion project Transco holds successful open season for the Potomac Expansion project in July NWP announced an open season on the Parachute Lateral Project (Oct.) Transco announced open season on the Sentinel Project (Nov.) 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2004 213 210 211.7 223.9 2005 220.7 208 214.1 0 Gas Pipeline 3rd Quarter and 2005 Accomplishments

2005 2006 2007 Segment Profit $630 - 6451 $485 - 5302,3 $585 - 655 Annual DD&A 270 - 280 290 - 300 300 - 310 Segment Profit + DDA $900 - 925 $760 - 815 $885 - 965 Capital Spending $390 - 420 $600 - 6803 $300 - 390 Dollars in millions 2005-2007 Guidance Note: If guidance has changed, previous guidance from 8/04/05 is shown in italics directly below Gas Pipeline Includes: YTD nonrecurring items which increase reported earnings by $49 million Includes: Pipeline Safety Costs of $31 million previously capitalized (see note 3) Higher interest expense of $20 million at Gulfstream as a result of the October $850 million financing No nonrecurring or one-time items Higher expenses than 2005 3 Impact of Pipeline Safety Improvement Act accounting rule reflected. Assumes $31 million of lower capital offset by $31 million of higher expenses. 590 - 615 860 - 895 600 - 700 500 - 565 790 - 865 250 - 325 370 - 420

2005-2007 Capital Spending Detail $300 - 390 $600 - 680 $390 - 420 Total 120 - 155 20 - 35 20 - 30 2 276 48 $180 - 235 $305 - 370 $325 - 335 Normal Maintenance/ Compliance 2007 2006 2005 Dollars in millions NWP 26" Replacement Expansion1 Note: Sum of ranges may not add due to rounding Gas Pipeline 10 - 20 600 - 700 70 - 90 250 - 325 310 - 400 305 - 335 370 - 420 1Major Growth Projects (in guidance): 2005 2006 2007 Central New Jersey (in-service 11/05) $10 - 15 Leidy to Long Island (in-service 11/07) $ 5 - 10 $10 - 20 $75 - 95 Potomac Expansion (in-service 11/07) $ 5 - 10 $45 - 65

Key Points Strong performance continues; operationally and financially Strong cash flow provider Continued progress Compliance and reliability projects Expansion developments Preparation for rate cases on schedule to be in effect 2007 Gas Pipeline

Power Bill Hobbs Senior Vice President

Segment Profit Power Note: MTM Adjustments (recurring) excludes $12mm paid in 3Q05 for buyout of gas supply contract Dollars in millions 2005 2004 2005 2004 Gross Margin (Includes MTM) ($203) $131 ($98) $202 SG&A (21) (20) (54) (56) Operating & Other Inc./(Expense) (2) (2) (35) (25) Segment Profit/(Loss) (Includes MTM) (226) 109 (187) 121 MTM Adjustments 201 (142) 149 (87) Segment Profit/(Loss) After MTM Adjustments ($25) ($33) ($38) $34 Segment Profit/(Loss) (Includes MTM) ($226) $109 ($187) $121 Nonrecurring: Expense related to Settlements and Litigation Contingencies 0 0 13 0 Expense related to prior period 0 0 12 0 Recurring Segment Profit/(Loss) (226) 109 (162) 121 MTM Adjustments (recurring) 213 (142) 160 (87) Recurring Segment Profit/(Loss) After MTM Adjustments ($13) ($33) ($2) $34 3rd Qtr YTD

Power 1 Includes YTD nonrecurring adjustments which decrease reported Segment Profit by $25 million and reported Segment Profit after MTM Adjustments and CFFO by $37million. Power Segment Profit after MTM Adjustments and Power Segment Standalone CFFO would be $36 million higher on a recurring basis. A more detailed schedule reconciling income (loss) from continuing operations to recurring income from continuing operations is available on Williams' Web site at www.williams.com. YTD - Segment Profit to Cash Flow Power and Dollars in Millions Natural Gas Other Total YTD Gross Margin ($98) ($98) SG&A & Other Inc/(Exp) (89) (89) Segment Profit/(Loss) 1 (187) 0 (187) MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (101) (101) Add Realized Gains from MTM previously recognized 250 250 Segment Profit/(Loss) after MTM Adjustments 1 (38) 0 (38) Total Working Capital Change 0 82 82 Power Segment CFFO 1 (38) 82 44 Est. Working Capital Used for Other BU's 0 (39) (39) Power Segment Standalone CFFO ($38) $43 $5

Dollars in millions Items Impacting 3Q Performance Segment Profit After MTM Adjustments: Q305 Forecast (as of 6/30/05) $54 Estimated impact of mild weather in the West: (30) Cooling Degree Days (CDDs) at Los Angeles (LAX) YTD are 17% below 5 yr avg and 43% below '04 Average September peak load in Cal-ISO system 13% below 2004 Estimated impact of higher NG prices, hurricanes & others (25) Estimated impact of plant outages (12) Buyout of gas supply contract (12) ______ Q305 Segment Profit After MTM Adjustments ($25) Power

Cash Flow Analysis Power Undiscounted dollars in millions (GAAP Measure) Note: 3Q05 forecast estimated as of 12/30/04. 3Q05 actual cash flows agree in total with Power's Cash Flow Statement; however, the allocation of actual cash flows to the various deal types is based on estimates. Note: Estimated Cash Flows includes YTD nonrecurring adjustments which decrease reported cash flows by $36 million. Estimated cash flows would be $36million higher on a recurring basis. Combined Power Portfolio Actual v. Forecast 3Q'05 Q3'05A Q3'05F YTD05A YTD05F Tolling Demand Payment Obligations ($126) ($126) ($310) ($310) Resale of Tolling 34 14 116 87 Full Requirements (6) 0 (1) 6 Long-term Physical Forward Power Sales 3 10 46 54 OTC Hedges 13 4 89 74 Est. Tolling Cash Flows Associated with Hedges 117 165 Estimated Merchant Cash Flows 60 64 Subtotal Cash Flows 7 79 64 142 NG & Other Commodity (8) (6) (13) (7) SG&A and Other (24) (18) (89) (54) Working Capital & Other (15) (7) 82 83 Power segment CFFO (40) 48 44 164 Est. Working Capital Used for Other BU's 16 0 (39) 0 Power Standalone Cash Flows ($24) $48 $5 $164 88 123

2005 2006 2007 Prior Segment Profit Guidance ($50) - 50 ($270) - (120) ($220) - (70) MTM Earnings (3Q05) (141) Est. Forward MTM Impact 50 50 40 Chg due to Mkt Conditions, New deals & Other (108) 0 - (50) Total Impact (199) 50 - 0 40 Change in Segment Profit Guidance (200) 50 - 0 40 Segment Profit Guidance (225) - (175) (225) - (125) (180) - (30) Estimated MTM Adjustments 175 270 230 75 320 270 Reported Segment Profit after MTM Adj (50) - 0 50 - 150 50 - 200 25 - 125 50 - 200 Non-Recurring 25 0 0 Recurring Segment Profit after MTM Adj (25) - 25 50 - 150 50 - 200 50 - 150 50 - 200 50 - 150 50 - 200 Capital Expenditures - - - Dollars in millions 2005-07 Guidance Power Note: If guidance has changed, previous guidance from 2nd quarter is shown in italics directly below Cash Flow from Operations 25 - 75 50 - 150 0 - 200

New Power Contracts - 2005 Highlights Deals Consummated Around Each Toll All Customer Classes Have Been Represented Utilities Co-ops & Munis Hedge funds & banks Favorable Credit Terms Zero margining provisions in two deals in excess of 4 years Margin Caps in place for approx. 2000 MW of toll resell Lower margining agreements and netting will result in lower margin working capital Power

2005 Successes West 1,500 MW resale of tolling from AES 4000: 854 MW starting in 2006 and growing to 1,500 MW in 2007-10 490-MW resale of toll from AES 4000 for 2006-08 100-MW heat rate call option for 2008 690-MW capacity sales: from AES 4000 for June-Sept 2005 1,500 MW resale of tolling from AES 4000: 854 MW starting in 2006 and growing to 1,500 MW in 2007-10 Resale of tolling as a percentage of expected output: '06-67%, '07-85%, '08-81%, '09-68%, '10-68% Mid-Continent 500 MW heat rate-priced energy and capacity sale to CLECO utility starting in 2006- 09 (approval pending) 100 MW heat-rate call option for 5 years - 2009 (Kinder toll) 244-MW (max) block heat rate-priced energy sale for June-Sept 2005 Northeast 100-MW capacity sale from Ironwood to municipality for June 2005-May 2006 1,000 MW of heat-rate call options sold through 2006 Power

Dollars in millions 2005 Forecast: Recurring Segment Profit After MTM Adjustments Recurring Segment Profit After MTM Adjustments: 2005 Full Year Forecast $(25) - 25 Estimated cash flows from new hedges 50 - 60 Estimated improvement in weather 15 - 55 Reduced plant outages 10 - 10 _______ 2006 Full Year Forecast $50 - 150 Power

Key Points Results for 3rd quarter impacted by Mild weather in west Unplanned outage in east Hurricanes and high natural gas prices CFFO YTD positive Full year recurring segment profit guidance is at break even despite higher NG prices and weak market conditions. Deal flow has increased as previously shown. Power Tutorial on November 30 Power

2005-07 Consolidated Outlook Don Chappel CFO

Segment profit before MTM adjustment $1,375 - $1,525 $1,300 - $1,585 Net Interest Expense (650) - (670) (650) - (670) Other (Primarily General Corp. Costs) (70) - (100) (70) - (100) Pretax Income 655 - 755 580 - 815 Provision for Income Tax (260) - (300) (220) - (335) Income from Continuing Ops 395 - 455 360 - 480 Income/(Loss) from Discontinued Ops (10) - 0 (10) - 0 Net Income $385 - 455 $350 - 480 Diluted EPS $0.64 - $0.75 $0.58 - $0.79 Recurring Income from Cont. Ops $402 - $462 $377 - $497 Diluted EPS - Recurring $0.66 - $0.76 $0.62 - $0.82 Diluted EPS - Recurring After MTM Adjustments 1 $0.84 - $0.94 $0.70 - $0.90 Dollars in millions, except per-share amounts Nov 3 Guidance Consolidated 2005 Forecast Guidance Aug 4 Guidance 1 Includes MTM adjustment of $75 million (pretax) in Aug 4 guidance and $175 million (pretax) in Nov 3 guidance Note: Fully diluted shares of 605 million used in Aug 4 guidance and Nov 3 guidance

Dollars in millions 2005-07 Segment Profit Exploration & Production Midstream Gas Pipeline Power Other / Corp. / Rounding Total MTM Adjustment Total After MTM Adj. 2005 2006 Consolidated $575 - 600 440 - 480 630 - 645 (225) - (175) (45) - (25) $1,375 - 1,525 175 $1,550 - 1,700 $650 - 725 400 - 500 485 - 530 (225) - (125) (60) - (80) $1,250 - 1,550 270 $1,520 - 1,820 Note: If guidance has changed, previous guidance from 8/4/05 is shown in italics directly below 2007 $775 - 900 410 - 530 585 - 655 (180) - (30) 10 - (30) $1,600 - 2,025 230 $1,830 - 2,255 410 - 485 520 - 595 595 - 720 400 - 470 590 - 615 (220) - (70) 1,300 - 1,585 75 320 270 1,375 - 1,660 1,515 - 1,815 1,640 - 2,065 1,195 - 1,495 1,370 - 1,795 (270) - (120) (50) - 50 500 - 565 400 - 520 45 - (45) (50) - (35)

2005 2006 2007 Exploration & Prod. $675 - 725 $950 - 1,050 $950 - 1,050 Midstream 120 - 140 230 - 250 180 - 220 Gas Pipeline 390 - 420 600 - 680 300 - 390 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $1,200 - 1,350 $1,825 - 2,050 $1,425 - 1,625 Dollars in millions Notes: - - Sum of ranges for each business line does not necessarily match total range If guidance has changed, previous guidance from 8/4/05 is shown in italics directly below Consolidated 2005-07 Capital Expenditures 605 - 680 760 - 860 735 - 885 700 1,100 - 1,300 1,525 - 1,750 250 - 325 110 - 130 100 - 130 1,100 - 1,300 370

1 Operating free cash flow is defined as cash flow from operations less capital expenditures, before dividend or principal payments Note: If guidance has changed, previous guidance from 8/4/05 is shown in italics directly below Dollars in millions 2005-07 Outlook Consolidated Segment Profit Reported Seg. Profit MTM Adjustment After MTM Adjust. DD&A Cash Flow from Ops. Capital Expenditures Operating Free Cash Flow 1 2005 $1,375 - 1,525 1 175 1,550 - 1,700 700 - 775 1,325 - 1,525 1,200 - 1,350 125 - 175 2006 $1,250 - 1,550 270 1,520 - 1,820 790 - 890 1,625 - 1,925 1,825 - 2,050 (200) - (125) 2007 $1,600 - 2,025 230 1,830 - 2,255 900 - 1,000 1,850 - 2,150 1,425 - 1,625 425 - 525 1,300 - 1,585 75 320 270 1,375 - 1,660 1,515 - 1,815 1,640 - 2,065 1,195 - 1,495 1,370 - 1,795 50 - 150 25 - 100 1,150 - 1,450 1,650 - 1,950 1,100 - 1,300 1,525 - 1,750 1,100 - 1,300 550 - 650 840 - 940 770 - 870 1,550 - 1,850

Strong Operating Cash Flow Growth & Increasing Investment Opportunities . . . 2003 2004 2005 2006 2007 Cap Ex-Low 790 1200 1825 1425 Cap Ex-High 790 1350 2050 1625 CFFO-Low 588 1482 1325 1625 1850 CFFO-High 588 1473 1525 1925 2150 Debt to Cap 0.75 0.623 0.58 0.56 0.54 0.75 0.623 0.59 0.58 0.56 Cash Flow 1 / Cap Ex Debt / Cap 2 $1,473 $ Millions 1 Cash Flow from Continuing Operations (CFFO) 2 Debt to Capitalization = Total Debt / (Total Debt + Equity) 62% 56% to 58% 54% to 56% Consolidated 75% $588 $1,200 to $1,350 $1,425 to $1,625 $790 Cap Ex $1,850 to $2,150 Opportunity Rich Increasing Cash Flow $1,625 to $1,925 $1,825 to $2,050 Declining Debt / Cap % 58% to 59% $1,325 to $1,525

Segment Profit Guidance Trend 2004 2005 2006 2007 2008 SPAM Low 1263 1550 1520 1830 2050 SPAM High 1263 1700 1820 2255 2600 SP Low 1381 1275 1175 1375 SP High 1381 1575 1475 1800 Cap Ex-Low 790 1175 1825 1450 Cap Ex-High 790 1350 2050 1650 $ Millions $1,550 to $1,700 $1,520 to $1,820 $1,830 to $2,255 $1,263 (recurring) 1 Includes MTM adjustments of ($118) in 2004, $175 in 2005, $270 in 2006, $230 in 2007, and $167 in 2008. Consolidated Segment Profit After MTM Adjustments 1 (1-Yr CAGR) 17.4% 15.0% 28.7% (2-Yr CAGR) (3-Yr CAGR) $2,050 to $2,600 16.5% (4-Yr CAGR)

Drive/enable sustainable growth in EVA(r)/shareholder value Maintain a cash/liquidity cushion of $1.0 billion plus Continue to steadily improve credit ratios/ratings; ultimately achieving investment grade ratios Reduce risk in Power segment Opportunity rich Increasing focus and disciplined EVA(r)-based investments in natural gas businesses Attractive EVA-adding opportunities may require new capital If new capital is needed, choose optimal sources of capital Combination of growth in operating cash flows and EVA drives value creation Financial Strategy/Key Points Consolidated

Summary Steve Malcolm Chairman, President & CEO

Key Points Current growth activity continues to move key performance measures up Investing in future growth First planned sale to Williams Partners to deliver growth capital while retaining asset control Scope, scale of growth opportunities continues to expand Raising earnings, cash guidance; expect upward trend to make sharper incline in 2008 Summary

Q&A

Non-GAAP Reconciliations

Non-GAAP Disclaimer This presentation includes certain financial measures, EBITDA, recurring earnings, free cash flow and recurring segment profit, that are non-GAAP financial measures as defined under the rules of the Securities and Exchange Commission. EBITDA represents the sum of net income (loss), net interest expense, income taxes, depreciation and amortization of intangible assets, less income (loss) from discontinued operations. Recurring earnings and recurring segment profit provide investors meaningful insight into the Company's results from ongoing operations. This presentation is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are widely accepted financial indicators used by investors to compare company performance. In addition, management believes that these measures provide investors an enhanced perspective of the operating performance of the Company's assets and the cash that the business is generating. Neither EBITDA nor recurring earnings and recurring segment profit are intended to represent cash flows for the period, nor are they presented as an alternative to net income or cash flow from operations. They should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles. Certain financial information in this presentation is also shown including Power mark-to-market adjustments. This presentation is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Previously the Company did not qualify for hedge accounting with respect to its Power segment as a result of the Company's stated intent to exit the Power business. The Company ceased efforts to market the sale of Power during the third quarter 2004, and now qualifies for hedge accounting. Hedge accounting reduces earnings volatility associated with Power's portfolio of certain derivative hedging instruments. Prior to the adoption of hedge accounting, these derivative hedging instruments were accounted for on a mark-to-market basis with the change in fair value recognized in earnings each period. Management uses the mark-to-market adjustments to better reflect Power's results on a basis that is more consistent with Power's portfolio cash flows and to aid investor understanding. The adjustments reverse forward unrealized mark-to- market gains or losses from derivatives and add realized gains or losses from derivatives for which mark-to-market income has been previously recognized, with the effect that the resulting adjusted segment profit is presented as if mark-to-market accounting had never been applied to designated hedges or other derivatives. The measure is limited by the fact that it does not reflect potential unrealized future losses or gains on derivative contracts. However, management compensates for this limitation since reported earnings do reflect unrealized gains and losses of derivative contracts. Overall, management believes the mark-to-market adjustments provide an alternative measure that more closely matches realized cash flows for the Power segment.

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

Non-GAAP Reconciliation Schedule Non-GAAP Reconciliation

EBITDA Reconciliation 190 DD&A (3) Provision (benefit) for Income Taxes 164 Net Interest Expense $4 Net Income $356 EBITDA 1 Loss from Disc. Operations Non-GAAP Reconciliation 3Q05 Dollars in millions YTD $247 2 491 546 169 $1,455

* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions 3Q 2005 Segment Contribution Non-GAAP Reconciliation

Net Income $385 - 455 $350 - 480 Income from Disc. Ops. 10 - 0 10 - 0 Net Interest 650 - 670 650 - 670 DD&A 700 - 775 700 - 775 Provision for Income Taxes 260 - 300 220 - 335 Other/Rounding (5) - 0 (5) EBITDA $2,000 - 2,200 $1,930 - 2,260 MTM Adjustments 175 75 EBITDA - after MTM Adj. $2,175 - 2,375 $2,005 - 2,335 Dollars in millions 2005 Forecast EBITDA Reconciliation Consolidated Nov 3 Guidance Aug 4 Guidance

Power 1 (225) - (175) 10 - 20 (215) - (155) Gas Pipeline 630 - 645 270 - 280 900 - 925 Segment Profit (Loss) DD&A Segment Profit before DDA Other (Primarily General Corporate Expense & Investing Income) Rounding TOTAL E&P 575 - 600 235 - 265 810 - 865 Midstream 440 - 480 180 - 190 620 - 670 Total * 1,375 - 1,525 700 - 775 2,075 - 2,300 (70) - (100) (5) - 0 2,000 - 2,200 Corp/ Other (45) - (25) 5 - 20 (40) - (5) 2005 Forecast Segment Contribution Non-GAAP Reconciliation Dollars in millions 1 Segment Profit is prior to MTM adjustments

Dollars in millions Exploration & Production Midstream Gas Pipeline Power Other/Corp. Total MTM Adjustment Total After MTM Adj. Reported Consolidated $575 - 600 440 - 480 630 - 645 (225) - (175) (45) - (25) $1,375 - 1,525 175 $1,550 - 1,700 YTD Non-Recurring ($29) - - (49) 25 53 $0 - - $0 Recurring $546 - 571 440 - 480 581 - 596 (200) - (150) 8 - 28 $1,375 - 1,525 175 $1,550 - 1,700 Power After MTM Adj. ($50) - 0 1 $25 ($25) - 25 2005 Segment Profit - Recurring 1 Includes reported results and mark-to-market as indicated above

Net Income $385 - 455 $350 - 480 Less: Discontinued Operations 10 - 0 10 - 0 Income from Continuing Ops $395 - 455 $360 - 480 Non-Recurring Items (Pretax) 7 23 Less / (Plus) Taxes @ Approx. 39% 0 (6) Non-Recurring After Tax 7 17 Recurring Income from Cont. Ops $402 - 462 $377 - 497 Recurring EPS $0.66 - $0.76 $0.62 - $0.82 Mark-to-Market Adjustment (Pretax) Less Taxes @ 39% Mark-to-Market Adjust. After Tax Inc. from Cont. Ops after MTM Adj. Inc. from Cont. Ops after MTM Adj. EPS 175 (68) 107 $509 - 569 $0.84 - $0.94 75 (29) 46 $423 - 543 $0.70 - $0.90 2005 Forecast Guidance Reconciliation Non-GAAP Reconciliation Dollars in millions, except per-share amounts Nov 3 Guidance Aug 4 Guidance

Dollars in millions 2005-07 Guidance Reconciliation Consolidated CAP EX: Aug. 4 Guidance E&P: Incremental Drilling & costs Midstream: Expansion (Opal & Blind Faith) Gas Pipes: Expansions Other Misc / Rounding Nov. 3 Guidance 2005 $1,100 - 1,300 60 - - - - 40 - (10) $1,200 - 1,350 2006 $1,525 - 1,750 190 120 10 (20) $1,825 - 2,050 2007 $1,100 - 1,300 190 85 60 (10) $1,425 - 1,625 SEGMENT PROFIT 1 Aug. 4 Guidance - Reported E&P: Price, cost & volume Increases Midstream: Margin Increases " Expansions Gas Pipes: Lower Expenses 25, NonRecurring/Other 10 " Accounting Change (30), Lower Expenses 15 Power: High Gas Prices / Weather in West Other Misc / Rounding Nov. 3 Guidance - Reported $1,375 - 1,660 140 25 - - 35 - - (100) 75 - (60) $1,550 - 1,700 $1,515 - 1,815 130 - - - - - - (15) - - (110) $1,520 - 1,820 $1,640 - 2,065 180 - - 10 - - - - - - - - $1,830 - 2,255 1 Segment Profit After MTM Adjustment

Dollars in millions 2005- 07 Guidance Reconciliation Consolidated CASH FLOW FROM OPERATIONS (CFFO): Aug. 4 Guidance E&P Seg Profit / DD&A Increases Midstream Segment Profit Increase Gas Pipes Segment Profit Changes Power Change in CFFO Guidance Other Increases / (Decreases) Nov. 3 Guidance 2005 $1,150 - 1,450 140 25 35 (25) - (75) 0 - (50) $1,325 - 1,525 2006 $1,550 - 1,850 140 - - (15) (25) (25) $1,625 - 1,925 2007 $1,650 - 1,950 220 10 - - - - (30) $1,850 - 2,150

Appendix

Consolidated EPS $0.34 $0.07 $0.01 - $0.42 Recurring EPS 0.33 0.11 ($0.01) - 0.44 Rec. EPS after MTM Adj. 0.22 0.16 0.22 - 0.60 Average Shares (MM) 599 579 581 - 605 2005 1Q 2Q 3Q 4Q Total EPS $0.02 ($0.03) $0.19 $0.13 $0.31 Recurring EPS 0.01 0.10 0.26 0.12 0.49 Rec. EPS after MTM Adj. 0.14 0.03 0.09 0.09 0.35 Average Shares (MM) 519 522 530 586 536 2004 1Q 2Q 3Q 4Q Total EPS Metrics

Interest on Long-Term Debt $575 - 583 Amortization Discount/Premium and other Debt Expense 25 - 27 Credit Facilities: (incl. Commitment Fees plus LC Usage) 32 - 40 Interest on other Liabilities 23 - 30 Interest Expense $655 - 680 Less: Capitalized Interest (5) - (10) Net Interest Expense Guidance $650 - 670 Dollars in millions 2005 Consolidated 2005 Interest Expense Guidance

2005 Effective Tax Rates Consolidated

Dollars in millions Exploration & Production 2005-2007 Hedge Update 1 Please note basin locations not NYMEX 2005 2006 2007 Fixed Price: 4th Qtr NYMEX Volume (MMcfe/d) 283 299 172 Price ($/Mcfe) $4.49 $4.39 $4.18 Collars : NYMEX Volume (MMcfe/d) 50 65 15 Price ($/Mcfe) $6.75 - $8.50 $6.62 - $8.42 $6.50 - $8.25 Regional NWPL Rockies1 Volume (MMcfe/d) 50 50 50 Price ($/Mcfe) $6.10 - $7.70 $6.05 - $7.90 $5.65 - $7.45 EPNG San Juan1 Volume (MMcfe/d) 50 Price ($/Mcfe) $5.65 - $7.45

3Q 2005 Net Realized Price Calculation Exploration & Production

2005 4th Quarter Price Modeling Unhedged Price (NYMEX) $8.70 $8.50 $7.00 2005 2006 2007 Note: Economic impact of hedges may be different from the volume hedged due primarily to fuel and shrink and direct taxes Exploration & Production 2005 Unhedged Hedge Market Price: NYMEX $13.00 - $13.60 $4.49 Basis Differential (3.00 - 3.60) (0.47) Net basin market price $9.40 - $10.60 $4.02 Fuel & Shrinkage/Gathering/ (0.80 - 1.00) (0.80 - 1.00) Transportation Net Price $8.40 - $9.80 $3.02 - $3.22 Year Volume Totals (Bcfe) (total daily vols (daily hedge - - daily hedge vols) volumes) x x (92/1000) (92/1000) Net Gas Revenue =(unhedged =(hedged volumes x net volumes x net price) hedge price)

Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual equity liquids percentages, etc. Average Realized Margin shown for 2000-2004. Midstream Margins Above Average Domestic NGL Average Realized Net Margin and Volumes by Quarter Margin (Cents / Gallon) Total Production & Equity Volumes by Quarter (MM Gallons) Margin Total NGL Prod (MM Gals) Equity NGL Sales (MM Gals) Avg. Realized Margin

Fee-Based Bedrock of Earnings 2004 2005 2006 2007 Fee 694 733 763 846 Commodity 301 255 215 212 Note: Total revenues less cost of goods sold. Reflects forecasted margins in 2006-2007 at mid- point of range. Midstream 30% 70% 26% 22% 20% 74% 78% 80%

Dollars in millions Note: - - Segment Profit is stated on a recurring basis. Segment Profit for 2003 & 2004 has been restated to reflect reclassifications - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges. - - Margin uplift represents actual realized margin in excess of forecasted average margin. Midstream 0 100 200 300 400 500 600 700 800 Capital 2003 Seg Profit + DDA Seg Profit & DDA Discretionary Expansion Margin Uplift Base Capital Spending Historic Expansion Discretionary Expansion Maintenance Well Connects Capital Seg Profit + DDA 2004 Capital Seg Profit + DDA 2005 Capital Seg Profit + DDA 2006 Capital Seg Profit + DDA 2007 Strong Free Cash Flow Still Updating This Slide

Gas Pipeline Dollars in millions Strong Free Cash Flow 2003 2004 2005 2006 2007 Seg Profit + DDA Seg Profit + DDA Capital Spending Expansion Maintenance Mandatory Note: - - Segment Profit is stated on a recurring basis. - - Segment Profit + DDA and Capital Spending reflect midpoint of ranges for 2005 - 2007.

Corp./ E&P Midstream Power Other Total Dollars in millions As of 9/30/05 *Note: The allocation of LC's between business units as of 3/31 has been adjusted from that previously reported. Total 3/31/05 LC's reported is unchanged. 1Reflects net amount of margins out less margins in. WMB Collateral Outstanding $2 $0 $51 $0 $53 $0 $1 $24 $0 $25 $2 $1 $75 $0 $78 $1,145 $224 $247 $91 $1,707 $1,147 $225 $322 $91 $1,785 $475 $184 $357 $92 $1,108 $581 $116 ($49) $1 $649 Margins & Ad. Assurances1 Prepayments Subtotal Letters of Credit Total as of 9/30/05 Total as of 06/30/05 Change

Dollars in millions WMB Collateral Sensitivity Margin volatility (1% chance of exceeding) - - Potential incremental collateral requirement 9/30/05 6/30/05 3/31/05 30 days ($469) ($178) ($124) 180 days ($868) ($458) ($328) 360 days ($926) ($351) ($341) Increased margin volatility results from high natural gas prices and volatility Assumption: The margin numbers above consist of only the forward marginable position values, starting from November 2005.

Enterprise Risk Management Sensitivities Analysis 1 Assumes a correlated movement in prices across all commodities, including spreads, for all Williams business units combined. 2 Assumes a non-correlated change in West power prices only, no change in power volatility, full extrinsic value not included. Heat rate and position change associated with Spark Spread increase is consistent across all months. Cash flow ranges are not linear. 3 Assumes a non-correlated change in NGL processing spread (i.e. change in NGL price only). Price Increase 2005 2006 2007 WMB Natural Gas (Per MMBtu) $0.10 $0-$2 $4-$6 $12-15 1 Power West Spark Spread Power Price (Per MWh) $5.00 $0-5 $5-15 $5-15 2 Midstream Processing Margin NGL Price (Per Gallon) $0.01 $5-10 $10-15 $10-15 3 Estimated dollars in millions

Types of Sales Around Tolling Deals - -Generally, from the most to least effective hedges Type of Sale Resale of tolling Heat-rate Sales Full requirements Capacity sales Forward fixed price sales How It Works Williams buys tolling rights for a certain dollar amount per kilowatt-year and: Sells the same or similar tolling rights to another party. Example: CDWR Product D. Sells call rights on energy, or fixed amounts of energy, at a price determined by a heat rate and fuel price. Serves the load (demand) of an entity often at a fixed price, utilizing production from other Williams assets and/or the entity's resources. Examples: EMC and Allegheny Co-op contracts. Sells the right to claim the generation as capacity. Some energy rights are usually associated. Sells fixed blocks of power at a specified price, usually w/o specifying a source. Example: CDWR ABC.