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): February 18, 2010

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))

Item 2.02. Results of Operations and Financial Condition.

     On February 18, 2010, The Williams Companies, Inc. (“Williams” or the “Company”) issued a press release announcing its financial results for the quarter and year ended December 31, 2009. A copy of the press release and its accompanying financial highlights and operating statistics and 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 operating statistics 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 7.01. Regulation FD Disclosure.

     On February 18, 2010, Williams issued a press release announcing its domestic and international proved natural gas and oil reserves as of December 31, 2009. A copy of the press release announcing the same is furnished as Exhibit 99.2 to this Current Report on Form 8-K and is incorporated herein in its entirety by reference.

     The press release 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)	None
(d)	Exhibits

Exhibit 99.1	Copy of Williams’ press release dated February 18, 2010, and its accompanying schedules, publicly announcing the Company’s financial results for the quarter and year ended December 31, 2009.
Exhibit 99.2	Copy of Williams’ press release dated February 18, 2010, publicly announcing its domestic and international proved natural gas and oil reserves as of December 31, 2009.

2

     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: February 18, 2010	/s/ Donald R. Chappel
	Name:	Donald R. Chappel
	Title:	Senior Vice President and Chief Financial Officer

3

INDEX TO EXHIBITS

EXHIBIT
NUMBER	DESCRIPTION
Exhibit 99.1	Copy of Williams’ press release dated February 18, 2010, and its accompanying schedules, publicly announcing the Company’s financial results for the quarter and year ended December 31, 2009
Exhibit 99.2	Copy of Williams’ press release dated February 18, 2010, publicly announcing its domestic and international proved natural gas and oil reserves as of December 31, 2009.

4

EX-99.1

Exhibit 99.1

NYSE: WMB

Date: Feb. 18, 2010

Williams Reports Fourth-Quarter and Full-Year 2009 Financial Results

• Net Income is $285 Million, $0.49 Per Share for 2009

• Recurring Adjusted Income is $552 Million, $0.94 Per Share for 2009

• Recurring Adjusted Earnings Per Share Expected to Double by 2011

• Total Proved Reserves for 2009 were approximately 4.5 Tcfe

• Proved, Probable, Possible Reserves Up 14%

• Completion of Asset Contributions to Williams Partners Paves Way for Enhanced Growth Opportunities

• Long-term Gathering Agreement Leads to Marcellus Expansion via Williams Partners

Year-End Summary Financial Information	2009						2008
Per share amounts are reported on a diluted basis. All amounts are attributable to The Williams Companies, Inc.	millions			per share			millions			per share
Income from continuing operations	$	438		$	0.75		$	1,306		$	2.21
Income (loss) from discontinued operations		(153	)		(0.26	)		112			0.19
Net income	$	285		$	0.49		$	1,418		$	2.40
Recurring income from continuing operations*	$	531		$	0.90		$	1,290		$	2.18
After-tax mark-to-market adjustments		21			0.04			(47	)		(0.08	)
Recurring income from continuing operations — after mark-to-market adjustments*	$	552		$	0.94		$	1,243		$	2.10

Quarterly Summary Financial Information	4Q 2009						4Q 2008
Per share amounts are reported on a diluted basis. All amounts are attributable to The Williams Companies, Inc.	millions			per share			millions			per share
Income from continuing operations	$	172		$	0.29		$	123		$	0.21
Income (loss) from discontinued operations		—			—			(8	)		(0.01	)
Net income	$	172		$	0.29		$	115		$	0.20
Recurring income from continuing operations*	$	165		$	0.28		$	201		$	0.34
After-tax mark-to-market adjustments		(4	)		(0.01	)		(16	)		($0.02	)
Recurring income from continuing operations — after mark-to-market adjustments*	$	161		$	0.27		$	185		$	0.32

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

          TULSA, Okla. — Williams (NYSE: WMB) announced 2009 unaudited net income attributable to Williams of $285 million, or $0.49 per share on a diluted basis, compared with net income of $1,418 million, or $2.40 cents per share on a diluted basis for 2008.

          Lower energy commodity prices in 2009, particularly in the first half of the year, impacted results in Exploration & Production and Midstream, as both businesses’ results were lower than 2008.

          Higher natural gas production; Exploration & Production’s hedge positions, which cover a significant portion of its production; and fee-based revenues from certain of Midstream’s gathering and processing services helped mitigate the effect of the lower commodity prices in 2009. Both businesses’ results also improved throughout 2009. Gas Pipeline’s results, as expected, were relatively steady.

          The year-to-date loss from discontinued operations is primarily due to the charges that were recorded in first-quarter 2009 associated with the company’s operations in Venezuela. As a result of the Venezuelan government’s expropriation of the El Furrial and PIGAP II compression facilities in May, Williams is now reporting the results of those operations in discontinued operations.

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

          Recurring income from continuing operations, after adjustments to remove the effect of mark-to-market accounting for certain hedges and other derivatives in Gas Marketing Services, is $552 million, or $0.94 per share for 2009. On the same adjusted basis, recurring income from continuing operations was $1,243 million, or $2.10 per share, for 2008.

          The lower recurring adjusted results for the year is due to the large disparity between the relatively low 2009 commodity prices, particularly in the first half of the year, compared with the 2008 prices.

          As previously noted, the relatively steady results in Gas Pipeline, as well as higher natural gas production, Exploration & Production’s hedge positions and fee-based revenues in Midstream, partially offset some of the negative effect of lower commodity prices.

          A reconciliation of the company’s income from continuing operations to recurring income from continuing operations and mark-to-market adjustments is available at www.williams.com and as an attachment to this news release.

CEO Comment

          “With our transformational asset contributions to Williams Partners complete, we are poised to pursue a greater number of value-creating growth projects throughout our businesses,” said Steve Malcolm, chairman, president and chief executive officer. “We will pursue these opportunities with financial discipline using the strength of our investment-grade balance sheet.

          “One of the opportunities we are seizing is a midstream expansion in the Marcellus Shale. Williams Partners will fund the construction of a natural gas gathering pipeline to support a long-term agreement with Cabot Oil & Gas, one of the key producers in the area.

          “Growing our businesses will benefit our shareholders and also add to our domestic natural gas infrastructure,” Malcolm said. “We believe strongly that natural gas is a very important part of our energy future — it’s an abundant, job-creating, cleaner domestic energy source. It also will help make renewable energy sources, such as wind and solar, viable long-term options.”

Consolidated Earnings Guidance for 2010-11 Unchanged, Recurring Adjusted Earnings Expected to Double by 2011

          The chart below shows Williams’ 2010-11 commodity price assumptions and the related outlook for its consolidated financial results for 2010-11. The chart reflects the pro-forma post-restructuring reporting of Williams and Williams Partners.

          Beginning with reporting in first-quarter 2010, Williams’ business segments for financial reporting will be Exploration & Production, Williams Partners and Other. The company’s consolidated financial reporting will be unchanged. Exploration & Production will include the former Gas Marketing segment and the Other segment will include the Canadian and Olefins midstream businesses and the retained 25.5-percent interest in Gulfstream.

          For Williams Partners’ reporting beginning first-quarter 2010, its business segments will be Gas Pipeline and Midstream.

          The commodity price assumptions and consolidated earnings outlook for 2010-11 are unchanged from what the company previously provided on Jan. 19. Williams Partners’ 2010 capital expenditures have been increased in the consolidated outlook by $100 million to a range of $950 million to $1,200 million. This increase primarily reflects the previously noted Midstream expansion in the Marcellus Shale.

          Williams expects to double its recurring adjusted earnings in 2011 compared with 2009 at the midpoint of guidance. Primary drivers for the increase in profits include higher commodity prices, higher natural gas production and the contribution of growth projects.

          As previously announced, Williams expects to incur estimated nonrecurring charges totaling approximately $425 million, net of tax, in the first-quarter 2010 in conjunction with the asset contribution transactions with Williams Partners. These are comprised primarily of costs associated with Williams’ cash tender offer for debt, including the market-value premium. The company expects lower annual interest expenses associated with the new Williams Partners debt offering to substantially offset the economic effect of the market-value premium over book value.

Commodity Price Assumptions and Financial Outlook	2010									2011
As of Feb. 18, 2010
	Low			Midpoint			High			Low			Midpoint			High
Natural Gas ($/MMBtu):
NYMEX	$	4.50		$	5.75		$	7.00		$	5.00		$	6.50		$	8.00
Rockies	$	3.90		$	5.00		$	6.10		$	4.35		$	5.65		$	6.95
Avg. San Juan/Mid-Continent	$	4.05		$	5.20		$	6.35		$	4.55		$	5.93		$	7.30
Oil / NGL:
Crude Oil — WTI ($  per barrel)	$	60		$	75		$	90		$	65		$	80		$	95
Crude to Gas Ratio		12.9x			13.1x			13.3x			11.9x			12.5x			13.0x
NGL to Crude Oil Relationship		53	%		56	%		59	%		53	%		55	%		57	%
Average NGL Margins ($  per gallon)	$	0.35		$	0.51		$	0.67		$	0.38		$	0.51		$	0.64
Capital Expenditures (millions)
Exploration & Production	$	1,000		$	1,200		$	1,400		$	1,300		$	1,700		$	2,100
Williams Partners		950			1,075			1,200			675			775			875
Other		100			138			175			360			418			480
Total Capital Expenditures(1)	$	2,050		$	2,413		$	2,775		$	2,300		$	2,875		$	3,450
Recurring Adj. Segment Profit (millions)(2)
Exploration & Production	$	285		$	605		$	925		$	390		$	973		$	1,555
Williams Partners		1,185			1,435			1,685			1,325			1,545			1,765
Other		80			130			180			150			180			210
Total Recurring Adj. Segment Profit(3)	$	1,575		$	2,175		$	2,775		$	1,900		$	2,700		$	3,500
Recurring Adj. Earnings Per Share(2)	$	0.80		$	1.35		$	1.90		$	1.10		$	1.87		$	2.65

(1)	Recurring Segment Profit and Earnings Per Share are adjusted to remove the effect of mark-to-market accounting and EPS is diluted. The Recurring Adjusted earnings amounts are non-GAAP measures. Reconciliations to the most relevant GAAP measures are attached to this news release.
(2)	Sum of the ranges for each business line does not necessarily match total range.
(3)	Sum of the ranges for the business units does not match the consolidated total due to the offsetting effect of natural gas prices within the business units. Also, corporate is not presented separately but is included in the total.

Business Segment Results

          Williams’ business segment results for fourth-quarter and full-year 2009 are presented in the following table. As previously announced, Williams’ business segment reporting will change beginning with first-quarter 2010 to reflect the company’s new reporting segments as a result of the strategic restructuring. As this table reflects 2009 results, it is being presented in the pre-restructuring form.

Consolidated Segment Profit	Full Year						4Q
Amounts in millions	2009			2008			2009			2008
Exploration & Production	$	418		$	1,260		$	115			($27	)
Midstream Gas & Liquids		640			871			269			134
Gas Pipeline		667			689			169			157
	$	1,725		$	2,820		$	553		$	264
Gas Marketing Services		($18	)	$	3			($4	)	$	12
Other		(1	)		(3	)		(4	)		(1	)
Consolidated Segment Profit	$	1,706		$	2,820		$	545		$	275

Recurring Consolidated Segment Profit After
Mark-to-Market Adjustments*	Full Year						4Q
Amounts in millions	2009			2008			2009			2008
Exploration & Production	$	476		$	1,298		$	137		$	136
Midstream Gas & Liquids		665			834			230			105
Gas Pipeline		671			670			173			157
	$	1,812		$	2,802		$	540		$	398
Gas Marketing after MTM Adjustments	$	16			($72	)		($11	)		($14	)
Other		(1	)		(3	)		(4	)		(1	)
Recurring Consolidated Segment Profit After Mark-to-Market Adjustments	$	1,827		$	2,727		$	525		$	383

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

Exploration & Production

          Exploration & Production includes natural gas production and development in the U.S. Rocky Mountains, San Juan Basin, Barnett Shale, and oil and gas development in South America. The company also made its initial investment in the Marcellus Shale in 2009.

          The business reported segment profit of $418 million for 2009, compared with segment profit of $1,260 million in 2008.

          The decline in segment profit is due to lower net realized average prices for natural gas production in 2009 versus 2008. During 2009, Williams’ net realized average price for U.S. production was $4.22 per thousand cubic feet of natural gas equivalent (Mcfe), which was 35 percent lower than the $6.48 per Mcfe realized in 2008.

          Higher natural gas production for the year and lower operating taxes partially offset the decline in net realized average price. Also contributing to the segment profit decline was higher depletion expense for the year driven by higher capitalized costs.

Average Daily Production
Amounts in million cubic feet equivalent of natural	Full Year
gas (MMcfe)	2009		2008		Growth rate
Piceance Basin		697		650		7	%
Powder River Basin		244		228		7	%
Other Basins		241		216		12	%
U.S. Interests only		1,182		1,094		8	%
U.S. & International Interests		1,236		1,144		8	%

          Although full-year average daily natural gas production grew from 2008 to 2009, average daily production declined somewhat throughout 2009 because of the company’s reduced drilling activity. Average daily natural gas production on U.S. interests fell 4 percent from first-quarter to fourth-quarter 2009.

          For fourth-quarter 2009, Exploration & Production reported a segment profit of $115 million, compared with a segment loss of $27 million in fourth-quarter 2008.

          The primary driver of the year-over-year increase in fourth quarter segment profit was the absence of impairment charges of $129 million related to properties in the Arkoma Basin that were recorded in fourth-quarter 2008.

          In a separate announcement today, Williams announced that its total proved natural gas and oil reserves as of Dec. 31, 2009, were approximately 4.5 trillion cubic feet equivalent (Tcfe) — including international reserves of approximately 0.2 Tcfe. These numbers are based on the new Securities and Exchange Commission reporting rules.

          Before adjusting for the effects of unusually low 2009 prices, total proved reserves would have been up 7 percent to 4.8 Tcfe with a reserves replacement rate of 173 percent. Using the same adjustment method, domestic reserves would have also increased 7 percent to approximately 4.6 Tcfe. Approximately 97 percent of total proved reserves are natural gas, with approximately 57 percent proved developed and 43 percent proved undeveloped reflecting a continuation of the increase in the ratio of proved developed to undeveloped.

           Before adjusting for the effects of 2009 natural gas prices, the company’ three-year average proved U.S. finding and development (F&D) cost was $2.38 per thousand cubic feet equivalent (Mcfe) down from $2.57 per Mcfe in 2008. The three year average F&D cost for reserves adds from drilling activity was $2.06 per Mcfe. For year 2009 alone, Williams’ F&D cost was $1.69 per Mcfe. The 2009 cost from drilling activity was $1.53 per Mcfe.

          Please see today’s separate news release for the complete discussion of the company’s 2009 natural gas reserves.

Midstream Gas & Liquids

          Midstream provides natural gas gathering, treating, and processing, deepwater production handling and oil transportation, NGL fractionation and storage services and olefin production.

          The business reported segment profit of $640 million for 2009, compared with segment profit of $871 million for 2008. On a recurring basis, segment profit was $665 million for 2009, compared with recurring segment profit of $834 million for 2008.

          The decline in segment profit for the year is primarily because of lower average annual NGL and olefin prices, partially offset by decreased production costs reflecting lower natural gas prices. Higher fee-based revenues also helped mitigate the lower NGL prices. NGL prices, especially ethane prices, have generally been improving during 2009, following significant declines in the fourth quarter of 2008.

          The increase in fee-based revenue for the year was attributable to connecting new supplies in the deepwater Gulf of Mexico through the Blind Faith extension in late 2008, as well as new volumes from processing Williams’ natural gas production at Willow Creek.

          Also contributing to the decline were non-recurring items. These included a $68 million loss in first-quarter 2009 related to Midstream’s Venezuelan investment and the absence of $32 million of income related to a partial settlement of litigation in 2008. These items were partially offset by a $40 million pre-tax gain on the sale of the company’s Cameron Meadows processing plant in the fourth quarter of 2009.

          For fourth-quarter 2009, Midstream reported segment profit of $269 million, compared with $134 million in fourth-quarter 2008.

          The improvement in results for the fourth quarter is primarily due to improved NGL and olefin prices and production in the fourth quarter of 2009 over 2008. Equity earnings of the company’s Discovery investment were higher in the fourth quarter of 2009 due primarily to the absence of unfavorable hurricane impacts that occurred in the fourth quarter of 2008 and new volumes from Discovery’s Tahiti expansion in 2009. In addition, fee revenues were higher as a result of processing volumes at the new Willow Creek plant.

Gas Pipeline

          Gas Pipeline, which primarily delivers natural gas to markets along the Eastern Seaboard, in Florida and in the Pacific Northwest, reported 2009 segment profit of $667 million, compared with $689 million for 2008.

          The lower segment profit was due primarily to higher operating and maintenance, depreciation and pension expenses, partially offset by higher other service revenues and by lower project development costs.

          The 2008 results also included the benefit of a $9 million gain on sale of excess natural gas inventory in the second quarter and a $10 million gain on the sale of certain assets in the third quarter.

          For fourth-quarter 2009, Gas Pipeline reported segment profit of $169 million, compared with $157 million for fourth-quarter 2008.

          The higher segment profit was due primarily to higher transportation revenues, partially offset by higher SG&A and other expenses.

Gas Marketing

          Williams is not including a discussion of Gas Marketing’s results in this news release. The full Management Discussion and Analysis of 2009 results will be provided in the company’s Form 10-K that it plans to file with the Securities and Exchange Commission next week.

Today’s Analyst Call

          Management will discuss the year-end 2009 results and 2010-11 consolidated outlook during a live webcast beginning at 9:30 a.m. EST today. Participants are encouraged to access the webcast and slides for viewing, downloading and printing at www.williams.com.

          A limited number of phone lines also will be available at (888) 352-6793. International callers should dial (719) 457-2643. Replays of the year-end webcast, in both streaming and downloadable podcast formats, will be available for two weeks at www.williams.com following the event.

Form 10-K

     The company plans to file its Form 10-K with the SEC during the week of Feb. 22. The document will be available on both the SEC and Williams websites.

About Williams (NYSE: WMB)

Williams is an integrated natural gas company focused on exploration and production, midstream gathering and processing, and interstate natural gas transportation primarily in the Rocky Mountains, Gulf Coast, Pacific Northwest, Eastern Seaboard and the Marcellus Shale in Pennsylvania. Most of the company’s interstate gas pipeline and midstream assets are held through its 84-percent ownership interest (including the general-partner interest) in Williams Partners L.P (NYSE: WPZ), a leading diversified master limited partnership. More information is available at www.williams.com. Go to http://www.b2i.us/irpass.asp?BzID=630&to=ea&s=0 to join our e-mail list.

Contact:	Jeff Pounds
	Williams (media relations)
	(918) 573-3332
	Travis Campbell
	Williams (investor relations)
	(918) 573-2944
	Richard George
	Williams (investor relations)
	(918) 573-3679
	Sharna Reingold
	Williams (investor relations)
	(918) 573-2078

# # #

Our reports, filings, and other public announcements may 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 various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

• Financial condition and liquidity;

• Business strategy;

• Estimates of proved gas and oil reserves;

• Reserve potential;

• Development drilling potential;

• Cash flow from operations or results of operations;

• Seasonality of certain business segments; and

• Natural gas and natural gas liquids prices and demand.

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that could adversely affect our business, results of operations and financial condition are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

• Availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future natural gas reserves), market demand, volatility of prices, and the availability and cost of capital;

• Inflation, interest rates, fluctuation in foreign exchange, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);

• The strength and financial resources of our competitors;

• Development of alternative energy sources;

• The impact of operational and development hazards;

• Costs of, changes in, or the results of laws, government regulations (including proposed climate change legislation), environmental liabilities, litigation, and rate proceedings;

• Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;

• Changes in maintenance and construction costs;

• Changes in the current geopolitical situation;

• Our exposure to the credit risk of our customers;

• Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;

• Risks associated with future weather conditions;

• Acts of terrorism; and

• Additional risks described in our filings with the Securities and Exchange Commission (“SEC”).

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Investors are urged to closely consider the disclosures and risk factors in our annual report on Form 10-K filed with the SEC on Feb. 25, 2009, and our quarterly reports on Form 10-Q available from our offices or from our website at www.williams.com.

The SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, under existing economic condition, operating methods , and governmental regulations. Beginning with year-end reserves for 2009, the SEC permits the optional disclosure of probable and possible reserves. We have elected to use in this presentation, but not in our Annual Report on Form 10-K, “probable” reserves and “possible” reserves, excluding their valuation. The SEC defines “probable” reserves as “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC defines “possible” reserves as “those additional reserves that are less certain to be recovered than probable reserves.” Williams has applied these definitions in estimating probable and possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in Williams’ Annual Report on Form 10-K for the fiscal year ended December 31, 2008, available from Williams at One Williams Center, Tulsa, OK 74172 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov.

The SEC’s rules prohibit us from including in filings with the SEC estimates of resources. Our resource estimations include estimates of hydrocarbon quantities for (i) new areas for which we do not have sufficient information to date to classify as proved, probable or even possible reserves and (ii) other areas to take into account the low level of certainty of recovery of the resources. Resource estimates do not take into account the certainty of resource recovery and are therefore not indicative of the expected future recovery and should not be relied upon. Resource estimates might never be recovered and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors.

Financial Highlights and Operating Statistics
(UNAUDITED)

Final

December 30, 2009

Reconciliation of Income from Continuing Operations Attributable to The Williams Companies, Inc. to Recurring Earnings
(UNAUDITED)

	2008															2009
(Dollars in millions, except per-share amounts)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr		2nd Qtr			3rd Qtr			4th Qtr			Year
Income from continuing operations attributable to The Williams Companies, Inc. available to common stockholders	$	411		$	412		$	360		$	123		$	1,306		$	2	$	123		$	141		$	172		$	438
Income from continuing operations — diluted earnings per common share	$	0.69		$	0.69		$	0.61		$	0.21		$	2.21		$	—	$	0.21		$	0.24		$	0.29		$	0.75
Nonrecurring items:
Exploration & Production (E&P)
Gain on sale of Peru interests	$	(118	)	$	(30	)	$	—		$	—		$	(148	)	$	—	$	—		$	—		$	—		$	—
Reserve for/(recovery of) receivables from bankrupt counterparty		—			5			4			—			9			—		—			—			(4	)		(4	)
Impairments of certain natural gas properties		—			—			14			129			143			5		—			—			15			20
Accrual for Wyoming severance taxes		—			—			—			34			34			—		3			(4	)		(4	)		(5	)
Penalties from early release of drilling rigs		—			—			—			—			—			34		(2	)		—			—			32
Depletion expense adjustment related to new guidance		—			—			—			—			—			—		—			—			14			14
Unclaimed property assessment accrual		—			—			—			—			—			—		—			—			1			1
Total Exploration & Production nonrecurring items		(118	)		(25	)		18			163			38			39		1			(4	)		22			58
Gas Pipeline
Gain on sale of excess inventory gas — TGPL		—			(9	)		—			—			(9	)		—		—			—			—			—
Gain on sale of certain south Texas assets — TGPL		—			—			(10	)		—			(10	)		—		—			—			—			—
Unclaimed property assessment accrual — TGPL		—			—			—			—			—			—		—			—			3			3
Unclaimed property assessment accrual — NWP		—			—			—			—			—			—		—			—			1			1
Total Gas Pipeline nonrecurring items		—			(9	)		(10	)		—			(19	)		—		—			—			4			4
Midstream Gas & Liquids (MGL)
Impairment of Carbonate Trend pipeline		—			—			—			6			6			—		—			—			—			—
Involuntary conversion gain related to Ignacio gas processing plant		—			(3	)		(6	)		(3	)		(12	)		1		—			(5	)		—			(4	)
Reserve for/(recovery of) receivables from bankrupt counterparty		—			1			—			—			1			—		—			—			—			—
Final earnout payment from 2005 Gulf Liquids asset sale		—			—			(8	)		—			(8	)		—		—			—			—			—
Charges from Hurricanes Gustav & Ike		—			—			8			5			13			—		—			—			—			—
Involuntary conversion gain from hurricane damage at Cameron Meadows		—			—			—			(5	)		(5	)		—		—			—			—			—
Gulf Liquids litigation partial settlement		—			—			—			(32	)		(32	)		—		—			—			—			—
Loss from Venezuela investment		—			—			—			—			—			68		—			—			—			68
Gain on sale of Cameron Meadows		—			—			—			—			—			—		—			—			(40	)		(40	)
Restructuring transaction costs		—			—			—			—			—			—		—			—			1			1
Total Midstream Gas & Liquids nonrecurring items		—			(2	)		(6	)		(29	)		(37	)		69		—			(5	)		(39	)		25
Nonrecurring items included in segment profit (loss)		(118	)		(36	)		2			134			(18	)		108		1			(9	)		(13	)		87
Nonrecurring items below segment profit (loss)
Interest related to Gulf Liquids litigation partial settlement — MGL		—			—			—			(11	)		(11	)		—		—			—			—			—
Interest related to Wyoming severance taxes — E&P		—			—			—			4			4			—		—			—			—			—
Loss associated with Venezuela investment — E&P		—			—			—			—			—			11		—			—			—			11
Reversal of litigation contingency — Corporate		—			—			—			—			—			—		(5	)		—			—			(5	)
Impairment of cost-based investment — Corporate		—			—			—			—			—			—		—			7			—			7
Restructuring transaction costs — Corporate		—			—			—			—			—			—		—			—			1			1
		—			—			—			(7	)		(7	)		11		(5	)		7			1			14
Total nonrecurring items		(118	)		(36	)		2			127			(25	)		119		(4	)		(2	)		(12	)		101
Tax effect for above items		(45	)		(14	)		1			49			(9	)		15		(1	)		(1	)		(5	)		8
Recurring income from continuing operations available to common stockholders	$	338		$	390		$	361		$	201		$	1,290		$	106	$	120		$	140		$	165		$	531
Recurring diluted earnings per common share	$	0.57		$	0.66		$	0.61		$	0.34		$	2.18		$	0.18	$	0.20		$	0.24		$	0.28		$	0.90
Weighted-average shares — diluted (thousands)		598,627			596,187			589,138			587,057			592,719			582,361		588,780			590,059			591,439			589,385

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

1

Consolidated Statement of Operations
(UNAUDITED)

	2008															2009
(Dollars in millions, except per-share amounts)	1st Qtr *			2nd Qtr*			3rd Qtr*			4th Qtr*			Year *			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Revenues	$	3,095		$	3,574		$	3,137		$	2,084		$	11,890		$	1,922		$	1,909		$	2,098		$	2,326		$	8,255
Segment costs and expenses:
Costs and operating expenses		2,264			2,614			2,280			1,618			8,776			1,444			1,392			1,537			1,708			6,081
Selling, general and administrative expenses		111			131			133			129			504			125			129			126			132			512
Other (income) expense — net		(114	)		(32	)		1			73			(72	)		33			(1	)		1			(16	)		17
Total segment costs and expenses		2,261			2,713			2,414			1,820			9,208			1,602			1,520			1,664			1,824			6,610
Equity earnings		36			37			54			10			137			23			26			44			43			136
Income (loss) from investments		—			—			—			1			1			(75	)		—			—			—			(75	)
Total segment profit		870			898			777			275			2,820			268			415			478			545			1,706
Reclass equity earnings		(36	)		(37	)		(54	)		(10	)		(137	)		(23	)		(26	)		(44	)		(43	)		(136	)
Reclass (income) loss from investments		—			—			—			(1	)		(1	)		75			—			—			—			75
General corporate expenses		(42	)		(42	)		(34	)		(31	)		(149	)		(40	)		(38	)		(40	)		(46	)		(164	)
Operating income		792			819			689			233			2,533			280			351			394			456			1,481
Interest accrued		(160	)		(161	)		(162	)		(153	)		(636	)		(162	)		(167	)		(168	)		(164	)		(661	)
Interest capitalized		8			16			16			19			59			20			22			15			19			76
Investing income (loss)		55			54			65			15			189			(61	)		24			39			44			46
Early debt retirement costs		—			—			—			(1	)		(1	)		—			—			—			(1	)		(1	)
Other income (expense) — net		4			—			2			(6	)		—			(2	)		1			(1	)		4			2
Income from continuing operations before income taxes		699			728			610			107			2,144			75			231			279			358			943
Provision (benefit) for income taxes		251			257			199			(30	)		677			56			80			87			136			359
Income from continuing operations		448			471			411			137			1,467			19			151			192			222			584
Income (loss) from discontinued operations		91			29			10			(5	)		125			(243	)		18			2			—			(223	)
Net income (loss)	$	539		$	500		$	421		$	132		$	1,592		$	(224	)	$	169		$	194		$	222		$	361
Less: Net income (loss) attributable to noncontrolling interests		39			63			55			17			174			(52	)		27			51			50			76
Net income (loss) attributable to The Williams Companies, Inc.	$	500		$	437		$	366		$	115		$	1,418		$	(172	)	$	142		$	143		$	172		$	285
Amounts attributable to The Williams Companies, Inc.:
Income from continuing operations	$	411		$	412		$	360		$	123		$	1,306		$	2		$	123		$	141		$	172			438
Income (loss) from discontinued operations		89			25			6			(8	)		112			(174	)		19			2			—			(153	)
Net income (loss)	$	500		$	437		$	366		$	115		$	1,418		$	(172	)	$	142		$	143		$	172		$	285
Diluted earnings (loss) per common share:
Income from continuing operations	$	0.69		$	0.69		$	0.61		$	0.21		$	2.21		$	—		$	0.21		$	0.24		$	0.29		$	0.75
Income (loss) from discontinued operations		0.15			0.04			0.01			(0.01	)		0.19			(0.29	)		0.03			—			—			(0.26	)
Net income (loss)	$	0.84		$	0.73		$	0.62		$	0.20		$	2.40		$	(0.29	)	$	0.24		$	0.24		$	0.29		$	0.49
Weighted-average number of shares used in computation (thousands)		598,627			596,187			589,138			587,057			592,719			582,361			588,780			590,059			591,439			589,385
Common shares outstanding at end of period (thousands)		584,025			579,117			578,641			579,052			579,052			580,072			582,933			583,101			583,432			583,432
Market price per common share (end of period)	$	32.98		$	40.31		$	23.65		$	14.48		$	14.48		$	11.38		$	15.61		$	17.87		$	21.08		$	21.08
Common dividends per share	$	0.10		$	0.11		$	0.11		$	0.11		$	0.43		$	0.11		$	0.11		$	0.11		$	0.11		$	0.44

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.

* Amounts reported above for 2008 have been adjusted to reflect the presentation of certain revenues and costs on a net basis, with no impact to segment profit.

2

Reconciliation of Segment Profit (Loss) to Recurring Segment Profit (Loss)
(UNAUDITED)

	2008															2009
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Segment profit (loss):
Exploration & Production	$	430		$	496		$	361		$	(27	)	$	1,260		$	78		$	119		$	106		$	115		$	418
Gas Pipeline		180			179			173			157			689			179			162			157			169			667
Midstream Gas & Liquids		238			270			229			134			871			12			137			222			269			640
Gas Marketing Services		21			(46	)		16			12			3			(2	)		(6	)		(6	)		(4	)		(18	)
Other		1			(1	)		(2	)		(1	)		(3	)		1			3			(1	)		(4	)		(1	)
Total segment profit	$	870		$	898		$	777		$	275		$	2,820		$	268		$	415		$	478		$	545		$	1,706
Nonrecurring adjustments:
Exploration & Production	$	(118	)	$	(25	)	$	18		$	163		$	38		$	39		$	1		$	(4	)	$	22		$	58
Gas Pipeline		—			(9	)		(10	)		—			(19	)		—			—			—			4			4
Midstream Gas & Liquids		—			(2	)		(6	)		(29	)		(37	)		69			—			(5	)		(39	)		25
Gas Marketing Services		—			—			—			—			—			—			—			—			—			—
Other		—			—			—			—			—			—			—			—			—			—
Total segment nonrecurring adjustments	$	(118	)	$	(36	)	$	2		$	134		$	(18	)	$	108		$	1		$	(9	)	$	(13	)	$	87
Recurring segment profit (loss):
Exploration & Production	$	312		$	471		$	379		$	136		$	1,298		$	117		$	120		$	102		$	137		$	476
Gas Pipeline		180			170			163			157			670			179			162			157			173			671
Midstream Gas & Liquids		238			268			223			105			834			81			137			217			230			665
Gas Marketing Services		21			(46	)		16			12			3			(2	)		(6	)		(6	)		(4	)		(18	)
Other		1			(1	)		(2	)		(1	)		(3	)		1			3			(1	)		(4	)		(1	)
Total recurring segment profit	$	752		$	862		$	779		$	409		$	2,802		$	376		$	416		$	469		$	532		$	1,793

Note:  Segment profit (loss) includes equity earnings and income (loss) from investments reported in investing income (loss) in the Consolidated Statement of Operations. Equity earnings results from investments accounted for under the equity method. Income (loss) from investments results from the management of certain equity investments.

3

Exploration & Production
(UNAUDITED)

	2008													2009
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr		4th Qtr			Year		1st Qtr			2nd Qtr			3rd Qtr			4th Qtr		Year
Revenues:
Production	$	631		$	840		$	731	$	497		$	2,699	$	492		$	455		$	479		$	548	$	1,974
Gas management		72			92			79		57			300		35			33			22			41		131
Hedge ineffectiveness and forward mark-to-market gains (losses)		(2	)		(14	)		18		(1	)		1		(2	)		(1	)		(1	)		1		(3	)
International		17			19			18		18			72		17			18			19			21		75
Other		10			11			15		13			49		11			25			3			3		42
Total revenues		728			948			861		584			3,121		553			530			522			614		2,219
Segment costs and expenses:
Depreciation, depletion and amortization (including International)		166			182			187		202			737		219			217			217			236		889
Lease and other operating expenses		60			61			72		73			266		71			62			62			63		258
Operating taxes		49			69			65		56			239		28			3			19			26		76
Exploration expense		2			1			3		21			27		12			21			5			20		58
Third party & affiliate gathering & processing		23			27			28		26			104		28			31			38			55		152
Selling, general and administrative expenses (including International)		37			44			49		46			176		43			42			43			43		171
Gas management expenses		71			91			78		54			294		34			29			26			40		129
International (excluding DD&A and SG&A)		6			10			9		11			36		7			6			9			8		30
Other (income) expense — net		(113	)		(27	)		14		128			2		37			4			1			14		56
Total segment costs and expenses		301			458			505		617			1,881		479			415			420			505		1,819
Equity earnings		3			6			5		6			20		4			4			4			6		18
Reported segment profit (loss)		430			496			361		(27	)		1,260		78			119			106			115		418
Nonrecurring adjustments		(118	)		(25	)		18		163			38		39			1			(4	)		22		58
Recurring segment profit	$	312		$	471		$	379	$	136		$	1,298	$	117		$	120		$	102		$	137	$	476
Operating statistics
Domestic:
Total domestic net volumes (Bcfe)		92.2			101.0			100.8		106.4			400.4		110.3			107.3			105.6			108.3		431.5
Net domestic volumes per day (MMcfe/d)		1,013			1,110			1,096		1,156			1,094		1,225			1,180			1,148			1,177		1,182
Net domestic realized price ($/Mcfe) (1)	$	6.580		$	8.056		$	6.971	$	4.428		$	6.479	$	4.205		$	3.949		$	4.183		$	4.540	$	4.220
Production taxes per Mcfe	$	0.529		$	0.683		$	0.648	$	0.525		$	0.597	$	0.254		$	0.024		$	0.182		$	0.241	$	0.176
Lease and other operating expense per Mcfe	$	0.653		$	0.606		$	0.712	$	0.685		$	0.664	$	0.649		$	0.576		$	0.581		$	0.588	$	0.599
(1) Net realized price is calculated the following way: production revenues (including hedging activities and incremental margins related to gas management activities) less gathering & processing expense divided by net volumes.
International:
Total volumes including Equity Investee (Bcfe)		5.7			5.7			5.9		6.0			23.3		6.1			6.1			6.4			6.5		25.1
Volumes per day (MMcfe/d)		63			62			64		66			64		67			68			69			71		69
Volumes net to Williams (after minority interest) (Bcfe)		4.5			4.4			4.6		4.8			18.3		4.7			4.9			5.0			5.1		19.7
Volumes net to Williams per day (MMcfe/d)		49			49			50		52			50		53			53			54			56		54
Total Domestic and International:
Volumes net to Williams (after minority interest) (Bcfe)		96.7			105.4			105.4		111.2			418.7		115.0			112.2			110.6			113.4		451.2
Volumes net to Williams per day (MMcfe/d)		1,062			1,159			1,146		1,208			1,144		1,278			1,233			1,202			1,232		1,236

4

Gas Pipeline
(UNAUDITED)

	2008														2009
(Dollars in millions)	1st Qtr		2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr		3rd Qtr			4th Qtr		Year
Revenues:
Northwest Pipeline	$	107	$	107		$	108		$	113		$	435		$	112		$	107	$	107		$	108	$	434
Transcontinental Gas Pipe Line		305		299			299			296			1,199			290			312		273			281		1,156
Other		1		—			—			(1	)		—			(1	)		2		(1	)		1		1
Total revenues		413		406			407			408			1,634			401			421		379			390		1,591
Segment costs and expenses:
Costs and operating expenses		201		207			210			222			840			195			232		196			190		813
Selling, general and administrative expenses		36		40			42			39			157			42			39		41			41		163
Other (income) expense — net		6		(5	)		3			3			7			—			3		4			7		14
Total segment costs and expenses		243		242			255			264			1,004			237			274		241			238		990
Equity earnings		10		15			21			13			59			15			15		19			17		66
Reported segment profit:
Northwest Pipeline		53		52			56			57			218			58			51		55			56		220
Transcontinental Gas Pipe Line		122		119			109			93			443			107			98		88			96		389
Other		5		8			8			7			28			14			13		14			17		58
Total reported segment profit		180		179			173			157			689			179			162		157			169		667
Nonrecurring adjustments:
Northwest Pipeline		—		—			—			—			—			—			—		—			1		1
Transcontinental Gas Pipe Line		—		(9	)		(10	)		—			(19	)		—			—		—			3		3
Total nonrecurring adjustments		—		(9	)		(10	)		—			(19	)		—			—		—			4		4
Recurring segment profit:
Northwest Pipeline		53		52			56			57			218			58			51		55			57		221
Transcontinental Gas Pipe Line		122		110			99			93			424			107			98		88			99		392
Other		5		8			8			7			28			14			13		14			17		58
Total recurring segment profit	$	180	$	170		$	163		$	157		$	670		$	179		$	162	$	157		$	173	$	671
Operating statistics
Northwest Pipeline
Throughput (TBtu)		219.8		171.0			179.5			211.1			781.4			224.0			172.9		165.7			205.9		768.5
Average daily transportation volumes (TBtu)		2.4		1.9			2.0			2.3			2.1			2.5			1.9		1.8			2.2		2.1
Average daily firm reserved capacity (TBtu)		2.6		2.5			2.5			2.5			2.5			2.6			2.6		2.6			2.7		2.7
Transcontinental Gas Pipe Line
Throughput (TBtu)		536.5		443.0			448.5			482.4			1,910.4			549.7			420.8		443.4			487.5		1,901.4
Average daily transportation volumes (TBtu)		5.9		4.9			4.9			5.2			5.2			6.1			4.6		4.8			5.3		5.2
Average daily firm reserved capacity (TBtu)		7.0		6.7			6.6			6.8			6.8			7.0			6.6		6.7			6.9		6.8

5

Midstream Gas & Liquids
(UNAUDITED)

	2008															2009
(Dollars in millions)	1st Qtr **			2nd Qtr**			3rd Qtr**			4th Qtr**			Year**			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Revenues:
Gathering & processing	$	97		$	108		$	105		$	104		$	414		$	107		$	106		$	121		$	129		$	463
NGL sales from gas processing		383			473			397			270			1,523			150			172			217			268			807
Production handling and transportation		27			29			24			28			108			33			33			35			31			132
Olefins sales (including Gulf and Canada)		325			335			319			146			1,125			143			152			184			189			668
Marketing sales		1,146			1,345			1,078			474			4,043			466			579			771			875			2,691
Other revenues		51			57			49			58			215			38			42			36			43			159
		2,029			2,347			1,972			1,080			7,428			937			1,084			1,364			1,535			4,920
Intrasegment eliminations		(581	)		(720	)		(644	)		(303	)		(2,248	)		(244	)		(279	)		(373	)		(436	)		(1,332	)
Total revenues		1,448			1,627			1,328			777			5,180			693			805			991			1,099			3,588
Segment costs and expenses:
NGL cost of goods sold		187			286			196			101			770			92			69			75			99			335
Olefins cost of goods sold		280			279			288			132			979			119			120			141			154			534
Marketing cost of goods sold		1,148			1,330			1,102			556			4,136			461			564			763			858			2,646
Other cost of goods sold		16			15			13			9			53			7			5			5			9			26
Operating costs		154			141			152			163			610			147			155			144			164			610
Other
Selling, general and administrative expenses		34			39			36			35			144			35			40			37			41			153
Other (income) expense — net		(5	)		3			(16	)		(58	)		(76	)		(7	)		1			(2	)		(39	)		(47	)
Intrasegment eliminations		(581	)		(720	)		(644	)		(303	)		(2,248	)		(244	)		(279	)		(373	)		(436	)		(1,332	)
Total segment costs and expenses		1,233			1,373			1,127			635			4,368			610			675			790			850			2,925
Equity earnings		23			16			28			(9	)		58			4			7			21			20			52
Income (loss) from investments		—			—			—			1			1			(75	)		—			—			—			(75	)
Reported segment profit		238			270			229			134			871			12			137			222			269			640
Nonrecurring adjustments		—			(2	)		(6	)		(29	)		(37	)		69			—			(5	)		(39	)		25
Recurring segment profit	$	238		$	268		$	223		$	105		$	834		$	81		$	137		$	217		$	230		$	665
Operating statistics
Domestic Gathering and Processing
Gathering volumes (TBtu)		234			268			254			257			1,013			252			251			277			288			1,068
Plant inlet natural gas volumes (Tbtu)		325			337			328			321			1,311			318			308			352			364			1,342
NGL equity sales (million gallons) *		308			366			272			285			1,231			292			297			317			314			1,220
NGL margin ($/gallon)	$	0.64		$	0.51		$	0.74		$	0.59		$	0.61		$	0.20		$	0.35		$	0.45		$	0.54		$	0.39
NGL production (million gallons) *		634			645			555			538			2,372			579			590			657			683			2,509
Olefins
Canadian NGL equity sales (million gallons)		33			22			20			37			112			36			30			37			23			126
Olefins sales (Ethylene & Propylene) (million lbs)		457			428			407			313			1,605			462			445			437			384			1,728
Discovery Producer Services L.L.C. (equity investment) — 100%
NGL equity sales (million gallons)		37			23			21			4			85			12			25			30			27			94
NGL production (million gallons)		70			58			43			10			181			30			56			79			85			250
Laurel Mountain Midstream, LLC (equity invetment) - 100%
Gathering volumes (Tbtu)		—			—			—			—			—			—			3			9			10			22

*	Excludes volumes associated with partially owned assets that are not consolidated for financial reporting purposes.
**	Amounts reported above for 2008 have been adjusted to reflect the presentation of certain revenues and costs on a net basis, with no impact to segment profit.

6

Gas Marketing Services
(UNAUDITED)

	2008											2009
(Dollars in millions)	1st Qtr		2nd Qtr			3rd Qtr		4th Qtr		Year		1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Revenues	$	1,650	$	2,010		$	1,716	$	1,036	$	6,412	$	867		$	598		$	697		$	890		$	3,052
Segment costs and expenses:
Costs and operating expenses		1,625		2,049			1,695		1,019		6,388		864			599			700			891			3,054
Selling, general and administrative expenses		4		7			4		5		20		5			4			5			4			18
Other (income) expense — net		—		—			1		—		1		—			1			(2	)		(1	)		(2	)
Total segment costs and expenses		1,629		2,056			1,700		1,024		6,409		869			604			703			894			3,070
Reported segment profit (loss)		21		(46	)		16		12		3		(2	)		(6	)		(6	)		(4	)		(18	)
Nonrecurring adjustments		—		—			—		—		—		—			—			—			—			—
Recurring segment profit (loss)	$	21	$	(46	)	$	16	$	12	$	3	$	(2	)	$	(6	)	$	(6	)	$	(4	)	$	(18	)

7

Capital Expenditures and Investments
(UNAUDITED)

	2008															2009
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr		2nd Qtr			3rd Qtr			4th Qtr			Year
Capital expenditures:
Exploration & Production	$	363		$	705		$	844		$	554		$	2,466		$	444	$	229		$	487		$	274		$	1,434
Gas Pipeline:
Northwest Pipeline		17			20			28			24			89			9		36			58			50			153
Transcontinental Gas Pipe Line		33			49			55			68			205			22		45			94			142			303
Other		2			(2	)		(1	)		1			—			—		—			—			—			—
Total		52			67			82			93			294			31		81			152			192			456
Midstream Gas & Liquids		104			204			135			146			589			133		142			111			87			473
Gas Marketing Services		—			—			1			—			1			—		—			—			—			—
Other		16			8			8			9			41			4		13			2			5			24
Discontinued Operations		1			1			—			1			3			—		—			—						—
Total*	$	536		$	985		$	1,070		$	803		$	3,394		$	612	$	465		$	752		$	558		$	2,387
Purchase of investments:
Exploration & Production		—			3			3			(3	)		3			—		—			1			—			1
Gas Pipeline		20			28			36			8			92			10		5			2			4			21
Midstream Gas & Liquids		—			—			—			—			—			3		112			(1	)		6			120
Other		—			16			(1	)		1			16			—		(1	)		1			—			—
Total	$	20		$	47		$	38		$	6		$	111		$	13	$	116		$	3		$	10		$	142
Summary:
Exploration & Production	$	363		$	708		$	847		$	551		$	2,469		$	444	$	229		$	488		$	274		$	1,435
Gas Pipeline		72			95			118			101			386			41		86			154			196			477
Midstream Gas & Liquids		104			204			135			146			589			136		254			110			93			593
Gas Marketing Services		—			—			1			—			1			—		—			—			—			—
Other		16			24			7			10			57			4		12			3			5			24
Discontinued Operations		1			1			—			1			3			—		—			—						—
Total	$	556		$	1,032		$	1,108		$	809		$	3,505		$	625	$	581		$	755		$	568		$	2,529
Cumulative summary:
Exploration & Production	$	363		$	1,071		$	1,918		$	2,469		$	2,469		$	444	$	673		$	1,161		$	1,435		$	1,435
Gas Pipeline		72			167			285			386			386			41		127			281			477			477
Midstream Gas & Liquids		104			308			443			589			589			136		390			500			593			593
Gas Marketing Services		—			—			1			1			1			—		—			—			—			—
Other		16			40			47			57			57			4		16			19			24			24
Discontinued Operations		1			2			2			3			3			—		—			—						—
Total	$	556		$	1,588		$	2,696		$	3,505		$	3,505		$	625	$	1,206		$	1,961		$	2,529		$	2,529
Capital expenditures incurred and purchase of investments
Increases to property, plant and equipment	$	579		$	982		$	1,032		$	882		$	3,475		$	484	$	420		$	809		$	601		$	2,314
Purchase of investments		20			47			38			6			111			13		116			3			10			142
Total	$	599		$	1,029		$	1,070		$	888		$	3,586		$	497	$	536		$	812		$	611		$	2,456
* Increases to property, plant and equipment	$	579		$	982		$	1,032		$	882		$	3,475		$	484	$	420		$	809		$	601		$	2,314
Changes in related accounts payable and accrued liabilities		(43	)		3			38			(79	)		(81	)		128		45			(57	)		(43	)		73
Capital expenditures	$	536		$	985		$	1,070		$	803		$	3,394		$	612	$	465		$	752		$	558		$	2,387

8

Depreciation, Depletion and Amortization and Other Selected Financial Data
(UNAUDITED)

	2008															2009
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year
Depreciation, depletion and amortization:
Exploration & Production	$	165		$	180		$	190		$	202		$	737		$	219		$	217		$	217		$	236		$	889
Gas Pipeline:
Northwest Pipeline		22			21			21			22			86			22			21			22			21			86
Transcontinental Gas Pipe Line		55			59			59			62			235			61			61			62			64			248
Other		—			—			—			—			—			—			1			(1	)		—			—
Total		77			80			80			84			321			83			83			83			85			334
Midstream Gas & Liquids		48			47			51			57			203			53			53			55			56			217
Gas Marketing Services		1			—			—			—			1			—			—			1			—			1
Other		4			3			5			6			18			4			6			5			5			20
Discontinued Operations		7			8			7			8			30			8			—			—			—			8
Total	$	302		$	318		$	333		$	357		$	1,310		$	367		$	359		$	361		$	382		$	1,469
Other selected financial data:
Cash and cash equivalents	$	2,239		$	1,937		$	1,524		$	1,438		$	1,438		$	1,785		$	1,853		$	1,640		$	1,867		$	1,867
Total assets	$	27,172		$	31,216		$	26,893		$	26,006		$	26,006		$	25,368		$	25,026		$	24,952		$	25,280		$	25,280
Capital structure:
Debt
Current	$	49		$	46		$	46		$	18		$	18		$	3		$	13		$	19		$	17		$	17
Noncurrent	$	7,638		$	7,711		$	7,685		$	7,683		$	7,683		$	8,278		$	8,265		$	8,258		$	8,259		$	8,259
Stockholders’ equity	$	7,801		$	7,652		$	8,574		$	8,440		$	8,440		$	8,326		$	8,324		$	8,307		$	8,453		$	8,453
Debt to debt-plus-stockholders’ equity ratio		49.6	%		50.3	%		47.4	%		47.7	%		47.7	%		49.9	%		49.9	%		49.9	%		49.5	%		49.5	%

9

Adjustment to remove MTM effect

Dollars in millions except for per share amounts

	4th Quarter						YTD
	2009			2008*			2009			2008*
Recurring income from cont. ops available to common shareholders	$	165		$	201		$	531		$	1,290
Recurring diluted earnings per common share	$	0.28		$	0.34		$	0.90		$	2.18
Mark-to-Market (MTM) adjustments for Gas Marketing		(7	)		(26	)		34			(75	)
Tax effect of total MTM adjustments		3			10			(13	)		28
After tax MTM adjustments		(4	)		(16	)		21			(47	)
Recurring income from cont. ops available to common shareholders after MTM adjust.	$	161		$	185		$	552		$	1,243
Recurring diluted earnings per share after MTM adj.	$	0.27		$	0.32		$	0.94		$	2.10
weighted average shares — diluted (thousands)		591,439			587,057			589,385			592,719

Note: all amounts attributable to Williams

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.

Some annual figures may differ from sum of quarterly figures due to rounding.

* Amounts have been recast to reflect certain Venezuela operations as discontinued operations.

Non-GAAP Measures:

     This press release includes certain financial measures, recurring earnings and recurring segment profit, that are non-GAAP financial measures as defined under the rules of the Securities and Exchange Commission. Recurring earnings and recurring segment profit exclude items of income or loss that the company characterizes as unrepresentative of its ongoing operations. Both measures provide investors meaningful insight into the company’s results from ongoing operations. This press release 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 a company’s performance. In addition, management believes that these measures provide investors an enhanced perspective of the operating performance of the company. Neither recurring earnings nor recurring segment profit are intended to represent an alternative to net income or segment profit. 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 press release is also shown including Gas Marketing Services mark-to-market adjustments, such as recurring income from continuing operations after mark-to-market adjustments and the related per share measures. This press release is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses the mark-to-market adjustments to better reflect Gas Marketing’s results on a basis that is more consistent with Gas Marketing’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 Gas Marketing Services’ 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 derivative assets and liabilities 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 Gas Marketing segment but does not substitute for actual cash flows. We also apply the mark-to-market adjustment and the recurring adjustments to present a measure referred to as recurring income from continuing operations after mark-to-market adjustments.

EX-99.2

Exhibit 99.2

NYSE: WMB

Date: Feb. 18, 2010

Williams Reports 2009 Natural Gas Reserves

• Total Proved Reserves for 2009 were approximately 4.5 Tcfe

• Assuming Year- end ‘08 Prices, Total Proved Reserves Up 7%; Reserves Replacement 173%

• 2009 U.S. Drilling Activity F&D $1.53 per Mcfe

• Proved, Probable, Possible Reserves Up 14%

     TULSA, Okla. — Williams (NYSE: WMB) announced today that its total proved natural gas and oil reserves as of Dec. 31, 2009, were approximately 4.5 trillion cubic feet equivalent (Tcfe) — including international reserves of approximately 0.2 Tcfe.

     Before adjusting for the effects of unusually low 2009 prices, total proved reserves would have been up 7 percent to 4.8 Tcfe with a reserves replacement rate of 173 percent. Using the same adjustment method, U.S. reserves would have also increased 7 percent to approximately 4.6 Tcfe. Approximately 97 percent of total proved reserves are natural gas, with approximately 57 percent proved developed and 43 percent proved undeveloped reflecting a continuation of the increase in the ratio of proved developed to undeveloped.

     Proved, probable, and possible (3P) reserves increased by 14 percent to 14.8 Tcfe from 13.0 Tcfe in 2008.

     The new Securities and Exchange Commission reporting rules require that year-end proved reserve volumes are calculated using an average price for the full-year 2009, rather than the year-end price. This resulted in utilization of a basin price approximately 33 percent lower than the previous year. When applying this average price and other new rules from the SEC, U.S. proved reserves were 4.3 Tcfe.

     The new SEC disclosures rules allow for reserves sensitivity analysis using alternate price and cost criteria. The following table reflects alternate natural gas price scenarios, which are below current forward basin market prices.

2009 Year-End U.S. Proved Reserves

	New SEC Rules		Alternate Price Scenarios
Amounts in billions cubic feet equivalent (Bcfe)			2009 Avg.		Year-end
of natural gas, except where noted.	2009 Avg. price		price + $1.00		2008 Price
Price — Henry Hub/Rockies ($/Mcfe)	$	3.87 / $3.07	$	4.87 / $4.07	$	5.71 / $4.61
Proved Developed		2,387		2,484		2,513
Proved Undeveloped		1,868		2,097		2,119
Total Proved		4,255		4,581		4,632
3 year avg. F&D ($/Mcfe)	$	2.89	$	2.44	$	2.38

     Under the new rules, reserves generally cannot be classified as proved if they will take more than five years to develop according to planned drilling activity and taking into account anticipated proved undeveloped conversion rates for wells drilled. This rule change resulted in reclassification of 496 Bcfe of reserves from proved undeveloped to probable.

     Additionally, the new rules now allow adding undeveloped proved reserves locations that are more than one offset away from currently producing wells where there is reasonable certainty of production. This rule change resulted in the addition of 454 Bcfe of proved reserves.

     Williams added 570 Bcfe through 2009 drilling activity. Williams anticipates developing all year-end 2009 proved reserves within five years.

     In 2009, Williams invested almost $1.3 billion of capital in its exploration and production business. That figure includes $873 million for U.S. development drilling and $305 million in growth acquisitions.

     “The extent of what our team accomplished in 2009 is striking particularly in an environment where we were working with about half the capital of the prior year,” said Ralph Hill, president of Williams’ E&P business.

     “Even with this lower capital level, we added 570 Bcfe of drill bit additions essentially equal to prior years, established our position in the Marcellus Shale, and completed a major acquisition in the Piceance. We drove our costs down sharply and our drilling investments continued to deliver strong returns on capital even with lower prices. ”

     As predicted by the company, the Rockies basis differential has narrowed. The differential was less than 30 cents per million British thermal unit (MMBtu) by year end 2009. The company believes that more than sufficient capacity and optionality currently exists for Rockies gas to move to a variety of attractive markets. And with planned additional pipeline capacity under construction, the company believes the Rockies basis will continue to be in a similar narrow range for the majority of the decade. The current market exemplifies this with a basis range between 40-50 cents per MMBtu through 2016.

     In 2009, Williams participated in 882 gross wells in the United States, achieving a drilling success rate of 99 percent, and increased production by 8 percent.

     Before adjusting for the effects of 2009 natural gas prices, the company’s three-year average proved U.S. finding and development (F&D) cost was $2.38 per thousand cubic feet equivalent (Mcfe), down from $2.57 per Mcfe in 2008. The three year average F&D cost for reserves adds from drilling activity was $2.06 per Mcfe. For year 2009 alone, Williams’ F&D cost was $1.69 per Mcfe. The 2009 cost from drilling activity was $1.53 per Mcfe.

     International proved reserves for year-end 2009 increased 26 percent from the prior year of approximately 26 million barrels of oil equivalent to approximately 33 million barrels of oil equivalent, or approximately 0.2 Tcfe of natural gas.

     Williams’ exploration and production business primarily develops natural gas reserves in the Piceance, Powder River, San Juan, Fort Worth and Marcellus Shale/Appalachia basins in the U.S.

     Approximately 99 percent of Williams’ year-end 2009 U.S. proved reserves estimates were audited by Netherland, Sewell & Associates, Inc. Their judgment determined Williams’ estimates are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles.

     Approximately 93 percent of proved reserves estimates for international properties were reviewed and certified by Ralph E. Davis and Associates, with approximately 7 percent reviewed and certified by RPS Energy.

     Proved reserves are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under assumed economic conditions.

Proved Reserves Reconciliation

Amounts in billion cubic feet equivalent of natural gas

U.S. proved reserves Dec. 31, 2008	4,339
Acquisitions	159
Wellhead production	(435	)
Effect of new SEC rules:
Price revisions	(336	)
5-year limit	(496	)
PUDs more than 1 offset away	454
Other additions/revisions	570
U.S. proved reserves Dec. 31, 2009 (SEC)	4,255
U.S. proved reserves Dec. 31, 2009 using year-end 2008 prices	4,632
International reserves	197
Total Dec. 31, 2009 proved reserves	4,829

About Williams (NYSE: WMB)

Williams is an integrated natural gas company focused on exploration and production, midstream gathering and processing, and interstate natural gas transportation primarily in the Rocky Mountains, Gulf Coast, Pacific Northwest, Eastern Seaboard and the Marcellus Shale in Pennsylvania. Most of the company’s interstate gas pipeline and midstream assets are held through its 84-percent ownership interest (including the general-partner interest) in Williams Partners L.P. (NYSE: WPZ), a leading diversified master limited partnership. More information is available at www.williams.com. Go to http://www.b2i.us/irpass.asp?BzID=630&to=ea&s=0 to join our e-mail list.

Contact:	Jeff Pounds Williams (media relations) (918) 573-3332
	Richard George Williams (investor relations) (918) 573-3679

# # #

Our reports, filings, and other public announcements may 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 various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

• Financial condition and liquidity;

• Business strategy;

• Estimates of proved gas and oil reserves;

• Reserve potential;

• Development drilling potential;

• Cash flow from operations or results of operations;

• Seasonality of certain business segments; and

• Natural gas and natural gas liquids prices and demand.

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that could adversely affect our business, results of operations and financial condition are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

• Availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future natural gas reserves), market demand, volatility of prices, and the availability and cost of capital;

• Inflation, interest rates, fluctuation in foreign exchange, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);

• The strength and financial resources of our competitors;

• Development of alternative energy sources;

• The impact of operational and development hazards;

• Costs of, changes in, or the results of laws, government regulations (including proposed climate change legislation), environmental liabilities, litigation, and rate proceedings;

• Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;

• Changes in maintenance and construction costs;

• Changes in the current geopolitical situation;

• Our exposure to the credit risk of our customers;

• Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;

• Risks associated with future weather conditions;

• Acts of terrorism; and

• Additional risks described in our filings with the Securities and Exchange Commission (“SEC”).

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to

update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Investors are urged to closely consider the disclosures and risk factors in our annual report on Form 10-K filed with the SEC on Feb. 25, 2009, and our quarterly reports on Form 10-Q available from our offices or from our website at www.williams.com.

The SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, under existing economic condition, operating methods , and governmental regulations. Beginning with year-end reserves for 2009, the SEC permits the optional disclosure of probable and possible reserves. We have elected to use in this presentation, but not in our Annual Report on Form 10-K, “probable” reserves and “possible” reserves, excluding their valuation. The SEC defines “probable” reserves as “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC defines “possible” reserves as “those additional reserves that are less certain to be recovered than probable reserves.” Williams has applied these definitions in estimating probable and possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in Williams’ Annual Report on Form 10-K for the fiscal year ended December 31, 2008, available from Williams at One Williams Center, Tulsa, OK 74172 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov.

The SEC’s rules prohibit us from including in filings with the SEC estimates of resources. Our resource estimations include estimates of hydrocarbon quantities for (i) new areas for which we do not have sufficient information to date to classify as proved, probable or even possible reserves and (ii) other areas to take into account the low level of certainty of recovery of the resources. Resource estimates do not take into account the certainty of resource recovery and are therefore not indicative of the expected future recovery and should not be relied upon. Resource estimates might never be recovered and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors.