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): May 5, 2005

The Williams Companies, Inc.

(Exact name of registrant as specified in its charter)

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

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))

Item 2.02. Results of Operations and Financial Condition.

      On May 5, 2005, The Williams Companies, Inc. (“Williams” or the “Company”) issued a press release announcing its financial results for the quarter ended March 31, 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 financial highlights and 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 8.01. Other Events.

      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 May 5, 2005.

      The slide presentation is being furnished pursuant to Item 8.01, Other Events. 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 May 5, 2005, publicly announcing its first quarter 2005 financial results.
	Exhibit 99.2	Copy of Williams’ slide presentation to be utilized during the May 5, 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: May 5, 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 May 5, 2005, publicly announcing its first quarter 2005 financial results.
Exhibit 99.2	Copy of Williams’ slide presentation to be utilized during the May 5, 2005, public conference call and webcast.

3

EX-99.1

EXHIBIT 99.1

NYSE: WMB

Date:       May 5, 2005

Williams Reports First-Quarter 2005 Financial Results

•   Natural Gas Production, NGL Sales Volumes Both Up 22%

•   31% Increase in Average Net Realized Sales Price for Natural Gas

•   NGL Sales Margins 30% Higher Than 5-Year Average

•   Interest Expense Drops 32%; Period Benefits From Lower Debt Levels

•   Year-Over-Year Cash Flow From Operations Nearly Triples

•   Company Raises Guidance for Mark-to-Market-Adjusted EPS

Summary Financial Information

	1Q 2005						1Q 2004
	millions			per share			millions		per share
Income from continuing operations	$	202.2		$	0.34		$	—	$	—
Income (loss) from discontinued operations		(1.1	)		—			9.9		0.02
Net income		201.1			0.34			9.9		0.02
Recurring income from continuing operations*		198.4			0.33			4.0		0.01
After-tax mark-to-market adjustments		(66.0	)		(0.11	)		69.0		0.13
Recurring income from continuing operations - - after mark-to-market adjustment*	$	132.4		$	0.22		$	73.0	$	0.14

* A schedule reconciling income (loss) from continuing operations to recurring income from continuing operations and mark-to-market adjustments 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 first-quarter 2005 unaudited net income of $201.1 million, or 34 cents per share on a diluted basis, compared with net income of $9.9 million, or 2 cents per share, for first-quarter 2004.

      For first-quarter 2005, the company reported income from continuing operations of $202.2 million, or 34 cents per share on a diluted basis, compared with break even, or 0 cents per share, for the same period in 2004 on a restated basis.

      The improvement in continuing operations over last year’s quarter reflects the benefit of increased levels of natural gas production and higher net realized average prices in Exploration & Production, increased sales volumes

and favorable margins for Midstream’s equity natural gas liquids, higher mark-to-market gains in Power, and lower levels of interest expense following significant reductions of debt in 2004.

CEO Perspective

      “Williams is focused on delivering superior, sustainable growth in economic and shareholder value,” said Steve Malcolm, chairman, president and chief executive officer. “The success we’re realizing is marked by our ability to execute our strategic plan, sustain our financial discipline and capitalize on the competitive advantages of our businesses.

      “The future for Williams is now. That’s why we have seized an opportunity in the Piceance Basin to increase the pace of development beginning later this year.Our strategy for creating value is simple: make disciplined investments in natural-gas-focused businesses that are located in key growth areas where we enjoy the competitive advantages of scale, a low-cost position or market leadership.”

Recurring Results

      Recurring income from continuing operations – which excludes items of income or loss that the company characterizes as unrepresentative of its ongoing operations – was $198.4 million, or 33 cents per share, for the first quarter of 2005.

      In last year’s first quarter, Williams reported recurring income of $4.0 million, or 1 cent per share, on a restated basis.

      The improvement in recurring income is attributable to the same factors that drove improvement in income from continuing operations over last year’s quarter, as previously described in this news release.

      A reconciliation of the company’s income from continuing operations – a generally accepted accounting principles measure – to its recurring results accompanies this news release.

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

      To provide an added level of disclosure and transparency, Williams is providing an analysis of recurring earnings adjusted for all of Power’s mark-to-market effects. Williams introduced this measure last year when it reported third-quarter results.

      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 $132.4 million, or 22 cents per share, for the first quarter of 2005.

      In last year’s first quarter, recurring income from continuing operations was $73 million, or 14 cents per share, after adjusting for the impact of mark-to-market accounting.

      The improvement results primarily from the increases noted previously with respect to the company’s Midstream and Exploration & Production segments and lower levels of interest expense. The effect of those increases was offset partially by the absence of significant gains realized in first-quarter 2004 from legacy natural gas trading positions in Power.

      A reconciliation of the company’s income from continuing operations on a recurring basis to its recurring results that have been adjusted for the impact of mark-to-market accounting accompanies this news release.

Business Segment Performance

      Williams’ primary businesses – Exploration & Production, Midstream Gas & Liquids, Gas Pipeline and Power – reported combined segment profit of $513.8 million in the first quarter of 2005.

      In the first quarter a year ago, these businesses reported combined segment profit of $277 million on a restated basis.

      The improvement in year-over-year segment profit is primarily attributable to increased production levels and higher net realized average prices for production sold in Exploration & Production, along with favorable natural gas liquids margins and increased sales volumes in Midstream. Power results also include an increase in mark-to-market earnings.

Exploration & Production: Piceance Basin Production Increases 59%

      Exploration & Production, which includes natural gas production and development in the U.S. Rocky Mountains, San Juan Basin and Midcontinent, and oil and gas development in South America, reported first-quarter 2005 segment profit of $103.7 million.

      In the first quarter a year ago, the business reported segment profit of $51.5 million. The year-over-year improvement reflects significant increases in both production volumes and net realized average prices for production sold, partially offset by higher lease operating expenses and depreciation, depletion and amortization.

      The business benefited from its ability to realize production prices averaging 31 percent higher than last year when sales prices were unfavorably affected by lower contracted hedged prices on a greater share of production volumes. The increased production primarily reflects higher drilling levels in the Piceance Basin. Also contributing to the increased segment profit is a first-quarter 2005 gain of approximately $8 million on the sale of certain non-core undeveloped leasehold properties in Colorado.

      In the first quarter of 2005, average daily production from domestic and international interests was approximately 614 million cubic feet of gas equivalent (MMcfe), compared with 502 MMcfe in the first quarter of 2004. Average daily production for the first quarter of 2005 was up only marginally from the 612 MMcfe reported in fourth-quarter 2004, after inclement weather impeded drilling progress in January. Increased development and production resumed in February and March.

      First-quarter 2005 average daily production solely from domestic volumes has increased 24 percent from the same period a year ago, growing from 457 MMcfe to 568 MMcfe.

      Williams currently has 13 rigs operating in the Piceance Basin of western Colorado – its cornerstone property for production growth. First-quarter 2005 average daily production from the Piceance Basin was 282 MMcfe, a 59 percent increase over year-ago levels.

      Williams now expects to have an average of approximately 20 rigs operating in the Piceance Basin in 2006 and an average of approximately 22 rigs there in 2007, following the company’s first-quarter agreement to contract 10 new rigs, each for a term of three years. Williams expects to begin deploying the new rigs on pace with the contracted delivery schedule – one per month, beginning in November this year.

      As a result of the agreement for the new rigs that was announced March 23, Williams has increased its planned capital spending in Exploration & Production in 2005 to a range of $530 million to $605 million, an increase of $30 million from the previous guidance range of $500 million to $575 million.

      Williams continues to expect 2005 segment profit of $400 million to $475 million from Exploration & Production.

Midstream Gas & Liquids: Strong Margins Continue, Sales Volumes Grow

      Midstream, which provides gathering, processing, natural gas liquids fractionation and storage services, reported first-quarter 2005 segment profit of $128.6 million.

      In the first quarter a year ago, the business reported segment profit of $110.1 million on a restated basis. The year-over-year improvement primarily reflects higher natural gas liquids production margins and sales volumes, and higher olefins production margins, partially offset by higher operating expenses.

      Midstream continues to benefit from favorable natural gas liquids margins, particularly in its western U.S. natural gas processing operations in areas such as Opal and Wamsutter in Wyoming. The olefins business also benefited from favorable commodity prices associated with rising crude oil prices and additional demand for ethylene and propylene products.

      In the first quarter of 2005, Midstream sold 398.7 million gallons of NGL equity volumes, an increase of approximately 22 percent vs. equity sales of 327.6 million gallons in the prior-year period.

      Gathering and processing volumes increased slightly year over year. Gathering volumes were 315.5 trillion British thermal units (TBtu) in the 2005 first quarter vs. 307.1 TBtu in the 2004 period. Processing volumes were 181.0 TBtu in the 2005 first quarter vs. 176.2 TBtu in the 2004 period.

      Williams has moved upward by $20 million the range of segment profit it expects in 2005 from Midstream. The company now expects $370 million to $450 million in segment profit from Midstream. For purposes of forecasting the range of expected segment profit from Midstream, the company assumed NGL margins at a five-year average for the year.

Gas Pipeline: Solid Results; Record 3-Day Transportation Volume on Transco

      Gas Pipeline, which primarily delivers natural gas to markets in the Northwest, along the Eastern Seaboard and to Florida, reported first-quarter 2005 segment profit of $167.4 million.

      In the first quarter a year ago, the business reported segment profit of $147.4 million on a restated basis. The increase in first-quarter 2005 segment profit compared to a year ago is primarily attributable to approximately

$13 million in expense reductions related to prior periods and $7.7 million in higher equity earnings from Gulfstream, a joint venture in which Williams owns a 50 percent interest.

      The increase at Gulfstream reflects the benefit of a $4.6 million construction fee realized with the completion of the Phase II expansion project and the additional revenues under an associated new contract. The expansion involved a new 110-mile segment that was placed into service in February, expanding Gulfstream’s reach across Florida and facilitating an increase of long-term firm service by 350 million cubic feet per day. Approximately two-thirds of Gulfstream’s 1.1 billion cubic feet of total capacity is contracted on a firm basis beginning in mid 2005.

      In the first quarter, Transco established a three-day record for transportation volumes, delivering an average of 8.36 million dekatherms per day Jan. 17-19.

      Associated with Transco’s recently announced Leidy-to-Long Island expansion project, Transco executed a customer agreement in March to transport 100,000 dekatherms of natural gas per day from Leidy, Pa., to growing markets in the northeastern United States, including New York, beginning in November 2007.

      Williams has moved upward by $10 million the lower end of the range for segment profit it expects in 2005 from Gas Pipeline. The company now expects $555 million to $585 million in segment profit from Gas Pipeline.

Power: Positive Cash Flow Continues

      Power, which manages an approximate 7,000-megawatt power portfolio, reported first-quarter 2005 segment profit of $114.1 million. In the first quarter a year ago, the business reported a segment loss of $32.0 million on a restated basis.

      The increase in first-quarter 2005 segment profit compared to a year ago is primarily attributable to a $197.4 million increase in forward unrealized mark-to-market gains largely associated with power and natural gas contracts. Increases in forward natural gas prices in the first quarter of 2005 were greater than in the first quarter of 2004. Partially offsetting these mark-to-market gains was the absence of income associated with realized gains from previously recognized mark-to-market earnings.

      Power’s first-quarter recurring segment profit on a basis adjusted for the impact of mark-to-market accounting was $17.4 million in 2005, compared with $80.3 million a year ago. The year-over-year decline is primarily because of the absence of significant gains realized in first-quarter 2004 from legacy natural-gas-trading positions; those gains had been recognized in prior periods as mark-to-market income. The first-quarter 2004 gains were partially offset by losses realized from Power’s interest-rate portfolio. The net impact of the two preceding factors was approximately $60 million. The base business performed as expected in both periods. The company liquidated both the legacy natural gas and interest rate portfolios last year in order to reduce risk.

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

	1Q '05			1Q '04
	(millions)			(millions)
Segment profit (loss)	$	114.1		$	(32.0	)
Non-recurring adjustments	$	11.4		$	—
Recurring segment profit (loss)	$	125.5		$	(32.0	)
Mark-to-market adjustments:
Reverse forward unrealized mark-to-market gains	$	(221.1	)	$	(23.7	)
Add realized gains from mark-to-market previously recognized	$	113.0		$	136.0
Recurring segment profit after mark-to-market adjustments	$	17.4		$	80.3

      Power generated cash flow from operations of approximately $48 million in the first quarter. That figure includes $13 million of working capital used in commodity risk management activity on behalf of other Williams commodity businesses.

      Power is focused on delivering positive cash flows, reducing risk and providing functions that support Williams’ natural gas businesses.

      For 2005, Williams has moved upward by $200 million the range of segment profit it expects from Power as a result of unrealized mark-to-market gains recorded in the first quarter. The company now expects reported results ranging from a $50 million loss to a $50 million profit from Power.

      On a basis adjusted for the impact of mark-to-market accounting, Williams continues to expect $50 million to $150 million in segment profit from Power. Also unchanged is the company’s expectation that Power will generate $50 million to $150 million in 2005 cash flow from operations on a basis that excludes future changes in working capital used in commodity risk management activity on behalf of all Williams commodity businesses.

Cash and Debt: $304 Million Net Cash From Operations in First Quarter

      Net cash provided by operating activities for the first quarter of 2005 was approximately $304.4 million, compared with $102.8 million in the first quarter of 2004.

      At the end of the first quarter, Williams had total liquidity of approximately $2 billion. This consists of unrestricted cash and cash equivalents of approximately $1.2 billion, along with $828 million in unused and available revolving credit facilities.

      Williams has reduced its debt by approximately $212 million in 2005 through scheduled maturities. At March 31, 2005, Williams’ total outstanding debt was approximately $7.75 billion.

      The lower level of debt in the first quarter of 2005 compared to the level in the first quarter of 2004 contributed to a year-over-year decrease in interest expense of approximately $79 million.

Guidance: Company Raises Expectation for Mark-to-Market Adjusted EPS

      For 2005, Williams has moved upward by $225 million the range of consolidated segment profit it expects. The company now expects $1.3 billion to $1.6 billion in consolidated segment profit.

      On a basis adjusted for the impact of mark-to-market accounting, the company expects $1.4 billion to $1.7 billion in segment profit, which is up slightly from the range announced on Feb. 23.

      Williams continues to expect cash flow provided from operating activities of $1.3 billion to $1.6 billion for the year.

      The company has increased the range of recurring income from continuing operations it expects to 53 cents to 77 cents per share, primarily as a result of unrealized mark-to-market gains recorded in the first quarter. The company’s previous guidance was 31 cents to 56 cents per share.

      On a basis adjusted for the impact of mark-to-market accounting, Williams moved upward the range of recurring income from continuing operations it expects in 2005. The company now expects 65 cents to 90 cents per share; the previous range was 63 cents to 87 cents.

Master Limited Partnership

      Subsequent to the close of the first quarter, Williams Partners L.P. filed a registration statement on Form S-1 with the Securities and Exchange Commission relating to a proposed underwritten initial public offering for limited partnership interests in this wholly owned Williams entity.

      Williams Partners L.P. will own a 40 percent interest in the Discovery natural gas gathering, transportation, processing and NGL fractionation system that runs from the deepwater Gulf of Mexico to a location near Paradis, La; the Carbonate Trend sour-gas gathering pipeline off the coast of Alabama; three integrated NGL storage facilities near Conway, Kan.; and a 50 percent interest in an NGL fractionator near Conway.

      The registration statement for Williams Partners L.P. has not yet become effective. These securities may not be sold nor may offers to buy be accepted prior to the time the registration statement becomes effective.

      This news release shall not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of these securities in any state in which such offer, sale or solicitation would be unlawful prior to registration or qualification under the securities law in any such state.

Today’s Analyst Call

      Williams’ management will discuss the company’s first-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 (800) 810-0924 International callers should dial (913) 981-4900. Callers should dial in at least 10 minutes prior to the start of the discussion.

      Replays of the webcast will be available at www.williams.com only.

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
	Karl Meyer
	Williams (investor relations)
	(918) 573-4395

# # #

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.

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
Income (loss) from continuing operations available to common stockholders	$	0.0		($18.5	)	$	16.2	$	95.5		$	93.2		$	202.2
Income (loss) from continuing operations - diluted earnings per share	$	—		($0.03	)	$	0.03	$	0.17		$	0.17		$	0.34
Nonrecurring items:
Power
Accrual for a regulatory settlement (1)		—		—			—		—			—			4.6
Prior period correction															6.8
Total Power nonrecurring items		—		—			—		—			—			11.4
Gas Pipeline
Prior period liability corrections		—		—			—		—			—			(13.1	)
Write-off of previously-capitalized costs - idled segment of Northwest’s pipeline		—		9.0			—		—			9.0			—
Total Gas Pipeline nonrecurring items		—		9.0			—		—			9.0			(13.1	)
Exploration & Production
Gain on sale of E&P properties		—		—			—		—			—			(7.9	)
Loss provision related to an ownership dispute		—		11.3			—		4.1			15.4			0.3
Total Exploration & Production nonrecurring items		—		11.3			—		4.1			15.4			(7.6	)
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			—
Devil’s 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 and Aspen project		—		10.8			—		—			10.8			—
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			—
Nonrecurring items included in segment profit (loss)		6.5		14.6			22.9		(69.1	)		(25.1	)		(9.3	)
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	)		—
Loss provision related to an ownership dispute - interest component (Interest accrued - Exploration & Production)		—		1.9			—		2.1			4.0			2.7
		—		102.4			170.8		24.5			297.7			2.7
Total nonrecurring items		6.5		117.0			193.7		(44.6	)		272.6			(6.6	)
Tax effect for above items (1)		2.5		44.8			74.1		(17.1	)		104.3			(2.8	)
Recurring income (loss) from continuing operations available to common stockholders	$	4.0	$	53.7		$	135.8	$	68.0		$	261.5		$	198.4
Recurring diluted earnings per common share	$	0.01	$	0.10		$	0.26	$	0.12		$	0.49		$	0.33
Weighted-average shares — diluted (thousands)		519,485		521,698			529,525		586,497			535,611			599,422

⁽¹⁾No tax effect on $.6 million of the accrual for a regulatory settlement in 1st 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.

Adjustment to remove MTM impact

Dollars in millions except for per share amounts

	2005									2004
	1Q			2Q	3Q	4Q	Year			1Q			2Q			3Q			4Q			Year
Recurring income from cont. ops available to common shareholders	$	198					$	198		$	4		$	54		$	136		$	68		$	261
Recurring diluted earnings per common share	$	0.33					$	0.33		$	0.01		$	0.10		$	0.26		$	0.12		$	0.49
Mark-to-Market (MTM) adjustments:
Reverse forward unrealized MTM gains/losses		(221	)					(221	)		(24	)		(70	)		(188	)		(23	)		(304	)
Add realized gains/losses from MTM previously recognized		113						113			136			11			45			(6	)		186
Total MTM adjustments		(108	)					(108	)		112			(59	)		(143	)		(29	)		(118	)
Tax effect of total MTM adjustments (at 39%)		(42	)					(42	)		44			(23	)		(56	)		(11	)		(46	)
After tax MTM adjustments		(66	)					(66	)		69			(36	)		(87	)		(17	)		(72	)
Recurring income from cont. ops available to common shareholders after MTM adjust.	$	132					$	132		$	73		$	18		$	49		$	51		$	189
Recurring diluted earnings per share after MTM adj.	$	0.22					$	0.22		$	0.14		$	0.03		$	0.09		$	0.09		$	0.35
weighted average shares - diluted (thousands)		599,422						599,422			519,485			521,698			529,525			586,497			535,611

Adjustments have been made to reverse estimated forward unrealized MTM gains/losses and add estimated realized gains/losses from MTM previously recognized, i.e. assumes MTM accounting had never been applied to designated hedges and other derivatives.

EX-99.2

Exhibit 99.2

Williams 2005 1st Quarter Earnings Release May 5, 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 and possible" 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 a reduced level of certainty than for proved reserves. Possible reserve estimates are less certain than those for probable reserves. 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.

Overview Steve Malcolm, Chairman, President & CEO

Headlines Williams delivers strong 1Q performance Midstream benefits again from above average margins, strong volumes Exploration & Production boosts year-over- year production Gas Pipeline posts another solid quarter Power continues to deliver positive cash flow Strength in consolidated cash flows continues Overview

Headlines Williams seizes rich opportunities for growth Picking up the pace to grow Piceance production Expanding pipelines to meet market demand Pursuing deep-water infrastructure opportunities Contracting existing power capacity Business overview set for May 12 Power Gas Pipeline E&P Overview

Headlines Williams Partners L.P. files registration statement $270 million expected initial enterprise value 100% equity capitalization at IPO 3Q expected completion Williams ownership 2% General Partner Interest 61% Limited Partner Interest $85 million cash to Williams expected at closing Williams would receive minimum quarterly distribution of $3.1 million per quarter Williams to account for partnership on consolidated basis Note: All dollar amounts on this page are approximate. Overview

MLP Foundation Assets Discovery 40% interest Integrated wellhead-to-market midstream services for Gulf of Mexico producers Offshore gathering and transportation system with 600 MMcf/d capacity Onshore gas processing and fractionation facilities Carbonate Trend Pipeline Sour-gas gathering pipeline offshore Alabama 120 MMcf/d capacity Conway Storage Largest storage facility at main trading hub in Midcontinent Approximately 20 million bbls storage for multiple NGL products Direct connectivity into Mid-America Pipeline Conway Fractionator 50% interest in fractionator adjacent to storage facility Share of capacity is 53,500 bbl/d Williams Partners L.P.

MLP Benefits to Williams Gain access to new, lower cost source of equity capital Receive premium valuation for assets Retain control of monetized assets Redeploy IPO proceeds Create Economic Value Added(r) Deliver WMB shareholders increased equity value Williams Partners L.P.

2005 Financial Results Don Chappel, CFO

1st Quarter 2005 2004 Income from Continuing Operations $202 $0 Income (Loss) from Disc. Operations (1) 10 Net Income $201 $10 Net Income/Share $0.34 $0.02 Recurring Inc. from Cont. Ops. /Share $0.33 $0.01 Recurring Inc. from Continuing Ops. After MTM Adjustments/Share $0.22 $0.14 Financial Results Dollars in millions (except per share amounts) 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.

2005 2004 Income from Continuing Operations $202 $0 Gains on Sale of Assets (8) - Income Related to Prior Periods (6) - Other - Net 7 7 Tax effect of adjustments 3 (3) Recurring Inc. from Cont. Ops. Avail. to Com. $198 $4 Recurring Income from Cont. Ops./Share $0.33 $0.01 Recurring Income from Cont. Operations Dollars in millions 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. 1st Quarter Consolidated

Recurring Income from Cont. Ops. After Mark-to-Market Adjustments Consolidated Note: Adjustments have been made to reverse estimated forward unrealized MTM gains 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 income from Cont. Ops. avail. to Common Recurring Diluted Earnings per Common Share Mark-to-Market (MTM) adjustments for Power: Reverse forward unrealized MTM gains Total MTM adjustments Tax effect of total MTM adjustments (at 39%) Recurring income from Continuing Operations avail. to Common Shareholders after MTM adjustments Recurring Diluted Earnings per share after MTM adjustments After-tax MTM adjustments Add realized gains from MTM previously recognized 1st Quarter 2005 198 $ 0.33 $ (221) (108) 42 132 $ 0.22 $ (66) 113 2004 4 $ 0.01 $ (24) 112 (44) 73 $ 0.14 $ 69 136

2005 2004 Segment Profit $510 $268 Net Interest Expense (164) (239) Other Income/(Expense) - Net (14) (17) Income from Cont. Ops. Before Tax 332 12 Provision for Income Tax 130 12 Income/(Loss) from Continuing Ops. $202 $0 Income/(Loss) from Discontinued Ops. (1) 10 Net Income $201 $10 Net Income Components Dollars in millions (except per share amounts) 1st Quarter Consolidated

First Quarter Segment Profit Reported Recurring 1Q05 1Q04 1Q05 1Q04 Exploration & Production $104 $52 $96 $52 Midstream Gas & Liquids 129 110 129 110 Gas Pipeline 167 147 154 147 Power 114 (32) 125 (32) Other (4) (9) (4) (2) Segment Profit $510 $268 $500 $275 MTM Adjustments - Power (108) 112 Segment Profit after MTM Adjustments $392 $387 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.

Major Changes in Quarter Recurring Segment Profit After Mark-to-Market Adjustments Consolidated Recurring Segment Profit after MTM Adj. 1Q04 $387 Exploration & Production 44 - Higher production volumes +$16 million - Higher net realized price +$36 million Midstream 19 - Increased NGL margins +$19 million - Increased NGL volume +$7 million - Improved olefins results +$6 million - Increased O&M -6 million Gas Pipeline 7 - Increased Gulfstream earnings +$3 million - Gulfstream completion fee +$5 million Power (63) - Lower realized gains in natural gas portfolio - $91 million - Absence of realized losses on interest rate portfolio +$31 million Other (2) Recurring Segment Profit after MTM Adj. 1Q05 $392 Dollars in millions

1Q05 Beginning Unrestricted $930 Cash flow from Continuing Operations 304 Proceeds from Issuing Common* 288 Sale of WilTel Note 54 Contract Termination Payment 88 Debt Retirements (216) Capital Expenditures/Investments (223) Dividends (29) Other-Net 14 Ending Unrestricted Cash at 3/31/05 $1,210 Restricted Cash at 3/31/05 (not included above) $83 Cash Information Dollars in millions Consolidated * $273 MM of proceeds related to settlement of purchase contract underlying FELINE PACS

Debt Balance 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% Fixed Rate Debt @ 3/31/05 $7,094 7.7% Variable Rate Debt @ 3/31/05 $656 5.0% Avg. Cost * Debt is long-term debt due within 1 year plus long-term debt plus notes payable. Dollars in millions Consolidated

Business Unit Results

Exploration & Production Ralph Hill, Senior Vice President

1st Quarter 2005 2004 Segment Profit Dollars in millions Segment Profit $104 $52 Nonrecurring: Gain on sale of assets (8) - Recurring Segment Profit $96 $52 Exploration & Production 1Q04 to 1Q05 financial highlights include: Volume increase of 22% Net realized price increase of 31% Recurring profit increase of 88% Base business sequential quarter improved Recurring profit increased 28% Volumes increased by 1.5%, despite unprecedented winter weather $36 million negative hedge impact in 1Q05

Strong Domestic Production Growth Exploration & Production 2004 2005 400 500 600 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Net MMcfed

2005 Accomplishments 1Q05 production up 22%, 113 MMcfed since 1Q04 Piceance production up 59% since 1Q04 Piceance higher activity, 10 new H&P rigs contracted Additional Piceance 10-acre spacing approved Trail Ridge/Ryan Gulch additional drilling this year Big George volumes continue to increase San Juan production up 13% since 1Q04 Arkoma Caney shale position expanded Exploration & Production

2005 2006 2007 Segment profit $400 - 475 $480 - 555 $550 - 675 Annual DD&A 235 - 265 280 - 320 350 - 400 Segment Profit + DD&A $635 - 740 $760 - 875 $900 - 1,075 Capital spending $530 - 605 $725 - 825 $725 - 875 Production (MMcfe/d) 600 - 700 720 - 820 825 - 925 Hedges (NYMEX Equivalent) Fixed Price: Volume (MMcfe/d) 283 298 172 Price ($/Mcfe) $4.44 $4.39 $4.20 Collar: Volume (MMcfe/d) 50 65 15 Price ($/Mcfe) $6.75 - $8.50 2Q-YE $6.62 - $8.42 $6.50 - $8.25 Dollars in millions Exploration & Production 2005-2007 Guidance Note: Guidance (except DD&A) was updated in the 3/23/05 press release regarding accelerated drilling program. Changes in DD&A are shown in italics directly below 220 - 250 250 - 290 300 - 350

Key Points Exploration & Production Achieving strong volume growth Continuing to expand 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 Strategy remains rapid development of our premier drilling inventory

Midstream Alan Armstrong, Senior Vice President

1st Quarter 2005 2004 Segment Profit $129 $110 Nonrecurring: - - Recurring Segment Profit $129 $110 Dollars in millions 1Q04 to 1Q05 financial highlights include: $19 million increase in NGL margins $7 million increase in NGL volume $6 million due to better performance in Olefins $(6) million increased O&M expense $(4) million Canyon Station outage Midstream Segment Profit

1st Quarter and 2005 Accomplishments Three key operating statistics up: Gathering volumes up 3% Processing volumes up 3% NGL sales volumes up 22% Two new Letters of Intent executed for Deepwater Acquired ENI's interest in Discovery Gulf Liquids sale, 2Q05 S-1 for Williams Partners L.P. * Excludes gains/losses/impairments 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 150 128 172 197 2005 178 0 0 0 Recurring Segment Profit + Depreciation* Midstream

2005 2006 2007 Segment Profit $370-450 $400-500 $400-520 Annual DD&A 180-190 185-195 190-200 Segment Profit + DDA $550-640 $585-695 $590-720 Capital Spending $120-140 $110-130 $100-130 Note: - - Guidance does not include any new major deepwater capital projects - - If guidance has changed, previous guidance from 2/23/05 is shown in italics directly below Midstream 2005-2007 Guidance Dollars in millions $350 - $430

Key Points Raising 2005 guidance, again Strong demand for services is yielding Higher key operating statistics High return organic growth opportunities Continued strong free cash flows Deepwater expansion continues One-two punch Premier assets in growth basins Attracting volumes through reliability Midstream

Gas Pipeline Phil Wright, Senior Vice President

Segment Profit $167 $147 Nonrecurring: Expense reduction related to prior period* (13) - Recurring Segment Profit $154 $147 1Q04 to 1Q05 financial highlights include: $5 million - Gulfstream completion fee $3 million - Increased earnings at Gulfstream Segment Profit 1st Quarter 2005 2004 Dollars in millions Gas Pipeline * Reflects reversal of transportation and exchange liabilities and certain other liabilities recorded in prior periods

Transco sets three-day delivery record in January Gulfstream Phase II placed into service FERC approves the Central New Jersey project Leidy to Long Island project - agreement executed with KeySpan Transco and Northwest receive top ranking by the Mastio & Co. customer survey in their respective regions 1Q 2Q 3Q 4Q 2002 193.6 214.1 200.3 2004 208 208 211.7 223.9 2005 220.7 0 0 0 Gas Pipeline 1st Quarter and 2005 Accomplishments

2005 2006 2007 Segment Profit (1) $555 - 585 $500 - 565 $565 - 635 Annual DD&A 280 - 290 290 - 300 300 - 310 Segment Profit + DDA $835 - 875 $790 - 865 $865 - 945 Capital Spending $370 - 420 $475 - 550 $250 - 325 Dollars in millions 2005-2007 Guidance Note: If guidance has changed, previous guidance from 2/23/05 is shown in italics directly below Gas Pipeline 1 Reflects termination of Gray's Harbor contract in 1Q05 2 Assumes 1/1/06 refinancing of $250 million of debt and additional financing of $350 million for Gulfstream. 545 - 585 825 - 875 515 - 565 575 - 635 875 - 945 805 - 865 (2) (2)

2005-2007 Capital Spending Detail Total Normal Maintenance/ Compliance Dollars in millions NWP 26" Replacement Expansion $370 - 420 20 - 30 48 $305 - 335 2005 $475 - 550 10 - 20 276 $190 - 245 2006 $250 - 325 70 - 90 2 $180 - 235 2007 Note: Amounts include AFUDC Sum of ranges may not add due to rounding Gas Pipeline

Key Points Another strong quarter, operationally and financially Strong free cash flow generator Achieving substantial progress in operational compliance and reliability projects Continued success in... Customer satisfaction Expansion development System operations Gas Pipeline

Power Bill Hobbs, Senior Vice President

Gross Margin $140 ($2) SG&A (16) (16) Op. & Other Inc / (Expense) (10) (14) Segment Profit $114 $(32) Nonrecurring: Expense related to prior period and other 11 - Recurring Segment Profit 125 (32) MTM Adjustments (108) 112 Recurring Segment Profit after MTM Adjustments $17 $80 1st Quarter 2005 2004 Segment Profit Dollars in millions Power

Segment Profit to Cash Flow Power Dollars in millions Power & Natural Gas Other Total Gross Margin $140 $140 SG&A & Other Inc/(Exp) (26) (26) Segment Profit $114 $0 $114 MTM Adjustments: Reverse Forward Unrealized MTM (Gains) (221) (221) Add Realized Gains from MTM previously recognized 113 113 Segment Profit after MTM Adjustments $6 $0 $6 Total Working Capital Change 42 42 Power Segment CFFO $6 $42 $48 Est. Working Capital Used for Other BU's 13 13 Power Segment Standalone CFFO $6 $55 $61

2005 2006 2007 2/23/05 Segment Profit Guidance ($250) - (150) ($200) - (50) ($100) - 50 1st Quarter 2005 Impact: MTM Earnings 221 Est. Forward Impact of MTM (32) (54) (92) Total 1st Quarter 2005 Impact 189 (54) (92) Change in Segment Profit Guidance 200 (50) (100) Revised Segment Profit Guidance ($50) - 50 ($250) - (100) ($200) - (50) MTM Adjustments* 100 300 250 300 250 150 Segment Profit after MTM Adjustments* 50 - 150 50 - 200 50 - 200 Unchanged Cash Flow from Operations* 50 - 150 50 - 200 50 - 200 Unchanged Capital Expenditures - - - Dollars in millions - 2005-2007 Guidance Power * If guidance has changed, previous guidance from 2/23/05 is shown in italics directly below -

Key Points Positive CFFO in a shoulder quarter CFFO expected to remain positive Risk reducing contracts term sales are occurring Expect to see improvements Market liquidity Spark spreads Williams credit Active E&P drilling program will increase natural gas sales Factors impacting guidance Spark spread movement up or down Capacity market timing and value New long-term contracts Power

2005-2007 Consolidated Outlook Don Chappel, CFO

Segment profit before MTM adjustment $1,275 - 1,575 $1,050 - 1,350 Net Interest Expense (630) - (665) (625) - (660) Other (Primarily General Corp. Costs) (80) - (110) (90) - (125) Pretax Income 565 - 800 335 - 565 Provision for Income Tax (235) - (320) (155) - (245) Income from Continuing Ops 330 - 480 180 - 320 Income/(Loss) from Discontinued Ops (10) - 0 (5) - 5 Net Income $320 - 480 $175 - 325 Diluted EPS $0.53 - $0.80 $0.31 - $0.57 Recurring Income from Cont. Ops $326 - 476 $180 - 320 Diluted EPS - Recurring $0.54 - $0.80 $0.31 - $0.56 Diluted EPS - Recurring After MTM Adjustments(1) $0.65 - $0.90 $0.63 - $0.88 (1) Includes MTM adjustments of $100 million (pretax) in May 5 Guidance and $300 million (pretax) in Feb. 23 Guidance Dollars in millions, except per-share amounts May 5 Guidance Consolidated 2005 Forecast Guidance Feb 23 Guidance

Dollars in millions 2005-2007 Segment Profit Exploration & Production Midstream Gas Pipeline Power Other/Corp. Total MTM Adjustment Total After MTM Adj. 2005 2006 Consolidated $400 - 475 370 - 450 555 - 585 (50) - 50 0 - 15 $1,275 - 1,575 100 $1,375 - 1,675 $480 - 555 400 - 500 500 - 565 (250) - (100) 45 - (45) $1,175 - 1,475 300 $1,475 - 1,775 350 - 430 515 (250) - (150) 5 - 10 35 - (40) Note: If guidance has changed, previous guidance from 2/23/05 is shown in italics directly below 1,050 - 1,350 $1,450 - 1,750 300 (200) - (50) 250 545 $1,350 - 1,650 1,200 - 1,500 450 - 525 2007 $550 - 675 400 - 520 565 - 635 (200) - (50) 10 - (30) $1,325 - 1,750 250 $1,575 - 2,000 (100) - 50 0 150 $1,525 - 1,950 575 500 - 625 1,375 - 1,800

(1) Free cash flow is defined as cash flow from operations less capital expenditures, before dividend or principal payments (2) An additional $25 million income tax expense is forecast in 2005 - 2007 Note: If guidance has changed, previous guidance from 2/23/05 is shown in italics directly below Dollars in millions 2005 - 2007 Outlook Consolidated Segment Profit Reported Seg. Profit MTM Adjustment After MTM Adjust. DD&A Cash Flow from Ops. Capital Expenditures Free Cash Flow (1) Effective Tax Rate (2) Cash Tax Rate 2005 $1,275 - 1,575 100 1,375 - 1,675 700 - 775 1,300 - 1,600 1,025 - 1,225 275 - 375 39% 3 - 5% 300 1,050 - 1,350 1,000 - 1,200 300 - 400 1,350 - 1,650 2006 $1,175 - 1,475 300 1,475 - 1,775 750 - 850 1,450 - 1,750 1,350 - 1,550 100 - 200 39% 4 - 8% 1,150 - 1,350 300 - 400 250 1,450 - 1,750 1,200 - 1,500 2007 $1,325 - 1,750 250 1,575 - 2,000 800 - 900 1,600 - 1,900 1,100 - 1,300 500 - 600 39% 5 - 10% 900 - 1,100 700 - 800 150 1,525 - 1,950 1,375 - 1,800

2005 2006 2007 Exploration & Prod. $530 - 605 $725 - 825 $725 - 875 Midstream 120 - 140 110 - 130 100 - 130 Gas Pipeline 370 - 420 475 - 550 250 - 325 Power - - - Other/Corporate 10 - 30 10 - 30 10 - 30 Total $1,025 - 1,225 $1,350 - 1,550 $1,100 - 1,300 Dollars in millions Notes: - - Sum of ranges for each business line does not necessarily match total range If guidance has changed, previous guidance from 2/23/05 is shown in italics directly below Consolidated 2005 - 2007 Capital Expenditures $1,150 - 1,350 $900 - 1,100 $1, 000 - 1,200 525 - 625 525 - 675 500 - 575

Dollars in millions 2005-2007 Maintenance vs. Growth Capital Note: Sum of ranges for each business line does not necessarily match total range Explor. & Prod. Growth Maintenance Total Midstream Growth Maintenance Total Gas Pipeline Growth Maintenance Total Power Other/Corp - Maint. Total: Growth Maintenance Total $340 - 395 190 - 210 530 - 605 60 - 75 60 - 65 120 - 140 20 - 30 350 - 390 370 - 420 - 10 - 30 420 - 500 610 - 695 $1,025 - 1,225 $515 - 595 210 - 230 725 - 825 60 - 75 50 - 55 110 - 130 10 - 20 465 - 530 475 - 550 - 10 - 30 585 - 690 735 - 845 $1,350 - 1,550 $495 - 625 230 - 250 725 - 875 50 - 70 50 - 60 100 - 130 70 - 90 180 - 235 250 - 325 - 10 - 30 615 - 785 470 - 575 $1,100 - 1,300 2005 2006 2007 Consolidated

Steady Improvement . . . 2004 2005 2006 2007 CFFO-Low 1482 1300 1450 1600 CFFO-High 1473 1600 1750 1900 Debt to Cap 0.623 0.58 0.57 0.54 0.623 0.59 0.58 0.56 Cash Flow 1 Debt / Cap 2 Increasing Cash Flow $1,473 $1,300 to $1,600 $1,450 to $1,750 $ Millions 1 Cash Flow from Continuing Operations (CFFO) 2 Debt to Capitalization = Total Debt / (Total Debt + Equity) 62% 58% to 59% 57% to 58% Decreasing Debt / Cap % 54% to 56% $1,600 to $1,900 Consolidated

Guidance Trends 2004 2005 2006 2007 SPAM Low 1263 1375 1475 1575 SPAM High 1263 1675 1775 2000 SP Low 1381 1275 1175 1375 SP High 1381 1575 1475 1800 Cap Ex-Low 790 1025 1350 1100 Cap Ex-High 790 1225 1550 1300 $1,025 to $1,225 $1,350 to $1,550 $1,100 to $1,300 $ Millions $790 $1,375 to $1,675 $1,475 to $1,775 $1,575 to $2,000 $1,263 (recurring) * Includes MTM adjustments of ($118) in 2004, $100 in 2005, $300 in 2006, and $250 in 2007 Consolidated Segment Profit After MTM Adjustments * Cap Ex

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 Increase focus and disciplined EVA(r) -based investments in natural gas businesses Optimize use of free cash flow Combination of growth in operating cash flows and reduction in interest costs drives value creation Financial Strategy/Key Points Consolidated

Summary Steve Malcolm

Hitting on all cylinders Another strong quarter Raising earnings guidance Seizing rich opportunities to grow shareholder value Williams Partners L.P. files registration statement Business overview on May 12 Key Points 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 178 DD&A 130 Provision for Income Taxes 164 Net Interest Expense $201 Net Income $674 EBITDA 1 Loss from Disc. Operations Non-GAAP Reconciliation 1Q05 Dollars in millions

* Excluding equity earnings and income (loss) from investments contained in segment profit Dollars in millions Total Segment Profit (Loss) $510 DD&A 179 Segment Profit before DDA $689 General Corporate Expense (28) Investing Income* 13 Other Income - - TOTAL $674 Gas Pipeline $129 46 $175 Corp/Other ($1) ($4) 3 $234 $163 E&P Midstream $167 $104 67 59 $118 Power $114 4 1Q 2005 Segment Contribution Non-GAAP Reconciliation

Net Income $320 - 480 $175 - 325 Income (Loss) from Disc. Ops. 10 - 0 5 - (5) Net Interest 630 - 665 625 - 660 DD&A 700 - 775 700 - 775 Provision for Income Taxes 235 - 320 155 - 245 Other/Rounding (20) - (15) (10) - 0 EBITDA - Reported & Recurring $1,875 - 2,225 $1,650 - 2,000 MTM Adjustments 100 300 EBITDA after MTM Adj. $1,975 - 2,325 $1,950 - 2,300 Dollars in millions 2005 Forecast EBITDA Reconciliation Consolidated May 5 Guidance Feb 23 Guidance

Power * (50) - 50 10 - 20 (40) - 70 Gas Pipeline 555 - 585 280 - 290 835 - 875 Segment Profit (Loss) DD&A Segment Profit before DDA Other (Primarily General Corporate Expense & Investing Income) TOTAL RECURRING E&P 400 - 475 235 - 265 635 - 740 Midstream 370 - 450 180 - 190 550 - 640 Total * 1,275 - 1,575 700 - 775 1,975 - 2,350 (100) - (125) 1,875 - 2,225 Corp/ Other 0 - 15 (5) - 10 (5) - 25 2005 Forecast Segment Contribution Non-GAAP Reconciliation 350 - 430 (250) - (150) 5 - 10 1,050 - 1,350 220 - 250 10 - 25 620 - 725 530 - 620 (240) - (130) 15 - 35 1,750 - 2,125 1,650 - 2,000 545 825 Dollars in millions * Segment Profit is on a reported basis and prior to MTM adjustments

Net Income $320 - 480 $175 - 325 Less: Discontinued Operations 10 - 0 5 - (5) Income from Continuing Ops $330 - 480 $180 - 320 Non-Recurring Items (Pretax) (7) - Less Taxes @ 39% 3 - Non-Recurring After Tax (4) - Recurring Income from Cont. Ops $326 - 476 $180 - 320 Recurring EPS $0.54 - $0.80 $0.31 - $0.56 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 100 (39) 61 $387 - 537 $0.65 - $0.90 300 (117) 183 $363 - 503 $0.63 - $0.88 2005 Forecast Guidance Reconciliation Non-GAAP Reconciliation Dollars in millions, except per-share amounts May 5 Guidance Feb 23 Guidance

Appendix

EPS Metrics Consolidated EPS $0.34 - - - Recurring EPS 0.33 - - - Rec. EPS after MTM Adj. 0.22 - - - Average Shares (MM) 599 - - - 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

Interest on Long-Term Debt $560 - 580 Amortization Discount/Premium and other Debt Expense 25 Credit Facilities: (incl. Commitment Fees plus LC Usage) 30 - 40 Interest on other Liabilities 20 - 30 Interest Expense $635 - 675 Less: Capitalized Interest (5) - (10) Net Interest Expense Guidance $630 - 665 2005 Interest Expense Guidance Dollars in millions 2005 Consolidated

Drivers Consolidated Dollars in millions

2005 Effective Tax Rate Combined Continuing Ops. Disc. Ops. First Quarter 2005 Federal $115 35% $116 35% $(1) 35% State 14 4% 14 4% * 3% Foreign (5) (2%) (5) (2%) - 0% Other 5 5% 5 2% - 0% Tax Provision $129 39% $130 39% ($1) 38% Dollars in millions Consolidated * Rounding - less than .1 million benefit

1Q 2005 Net Realized Price Calculation Exploration & Production 1Q05 Unhedged Hedge Market Price: NYMEX including collars $6.20 - $6.30 $4.59 Basis Differential (0.50 - 1.00) (0.49) Net basin market price $5.30 - $5.70 $4.10 Fuel & Shrinkage/Gathering/ (0.80 - 1.00) (0.80 - 1.00) Transportation Net Price $4.50 - $4.70 $3.10 - $3.30 Quarter Volume Totals (qtr daily volumes (qtr daily qtr daily hedged volumes) hedge volumes) x (90/1000) x (90/1000) Net Gas Revenue =(unhedged =(hedged volumes x net volumes x net price) hedge price)

2005 Price Modeling Unhedged Price (NYMEX) $6.34 $5.96 $5.75 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

Q1'02 Q2'02 Q3'02 Q4'02 Q1'03 Q2'03 Q3'03 Q4'03 Q1'04 Q2'04 Q3'04 Q4'04 Q1'05 Margin 5.21 7.7 11.75 12.75 17.16 7.99 6.18 11.01 10.08 8.84 17.64 22.6 15.03 Volume (MM Gallons) 292 296 333 271 300 199 228 298 327 328 373 400.5 399 Note: Based on actual realized prices, contractual obligations, shrink, fuel, actual equity liquids percentages, etc. Average Actual Margin shown for 2000 - 2004. Midstream Margins Above Average Domestic NGL Actual Average Net Margin and Volume by Quarter Margin (Cents / Gallon) Equity Volume by Quarter (MM Gallons) Avg Margin

Fee-Based Bedrock of Earnings 2004 2005 2006 2007 Fee 694 755.6 799 823 Commodity 301 227 207.7 210 Note: Total revenues less cost of goods sold. Reflects 5 year average (Jan '00 - Dec '04) margins in 2006-2007 at mid-point of range. Midstream 30% 70% 23% 21% 20% 77% 79% 80%

Strong Free Cash Flow 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. - - 2004 margin uplift represents actual realized margin in excess of forecasted average margins. Midstream 0 100 200 300 400 500 600 700 800 Capital 2003 Seg Profit + DDA Seg Profit & DDA Discretionary Expansion 2004 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

Cash Flow Variance Analysis Undiscounted dollars in millions Note: 1Q05 forecast estimated as of 12/30/04. 1Q05 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. Power

Enterprise Risk Management Margins & Ad. Assur. $70 $1 $87 - $158 $134 Prepayments - 4 27 - 31 40 Subtotal $70 $5 $114 $ - $189 $174 Letters of Credit 496 104 257 90 947 855 Total as of 3/31/05 $566 $109 $371 $90 $1,136 $1,029 Total as of 12/31/04 $449 $135 $350 $95 $1,029 Change $117 ($26) $21 ($5) $107 Corp./ 12/31/04 E&P Midstream Power Other Total Total Dollars in millions As of 3/31/05

Enterprise Risk Management Margin volatility (99% confidence interval) - - Incremental liquidity requirement 3/31/05 12/30/04 30 days ($124) ($106) 180 days ($328) ($268) 360 days ($341) ($353) Assumption: The margin numbers above consist of only the forward marginable position values, starting from May 2005. Dollars in millions