UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2008

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

THE WILLIAMS COMPANIES, INC.

(Exact name of registrant as specified in its charter)

DELAWARE		73-0569878
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

ONE WILLIAMS CENTER, TULSA, OKLAHOMA		74172
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number: (918) 573-2000

NO CHANGE

Former name, former address and former fiscal year, if changed since last report.

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes o No þ

     Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.

Class		Outstanding at October 31, 2008
Common Stock, $1 par value		578,674,347    Shares

 

 

		Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statement of Income — Three and Nine Months Ended September 30, 2008 and 2007			3
Consolidated Balance Sheet — September 30, 2008 and December 31, 2007			4
Consolidated Statement of Cash Flows — Nine Months Ended September 30, 2008 and 2007			5
Notes to Consolidated Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
Item 3. Quantitative and Qualitative Disclosures about Market Risk			53
Item 4. Controls and Procedures			55
Part II. Other Information			56
Item 1. Legal Proceedings			56
Item 1A. Risk Factors			56
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			58
Item 5. Other Information			58
Item 6. Exhibits			58
EX-10.2
EX-12
EX-31.1
EX-31.2
EX-32

     Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

     All statements, other than statements of historical facts, included in this report which address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements 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;
	•		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 document. Many of the factors that will determine these results are beyond our ability to control or project. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

	•		Availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and increased costs of capital;
	•		Inflation, interest rates, fluctuation in foreign exchange, and general economic conditions;
	•		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;
	•		Changes in the current geopolitical situation;
	•		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;
	•		Our ability to successfully manage the risks associated with selling and marketing products in the wholesale energy markets;
	•		Acts of terrorism;
	•		Additional risks described in our filings with the Securities and Exchange Commission.

     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 and referred to below 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.

     Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2007, and Part II, Item 1A. Risk Factors of this Form 10-Q.

The Williams Companies, Inc.

		Three months								Nine months
		ended September 30,								ended September 30,
(Dollars in millions, except per-share amounts)		2008				2007				2008				2007
Revenues:
Exploration & Production		$	883			$	499			$	2,607			$	1,521
Gas Pipeline			407				392				1,226				1,178
Midstream Gas & Liquids			1,436				1,360				4,747				3,605
Gas Marketing Services			1,716				1,247				5,376				3,929
Other			6				7				18				20
Intercompany eliminations			(1,181	)			(645	)			(3,754	)			(2,201	)
Total revenues			3,267				2,860				10,220				8,052
Segment costs and expenses:
Costs and operating expenses			2,386				2,222				7,506				6,245
Selling, general and administrative expenses			133				107				375				317
Other income — net			—				(2	)			(152	)			(38	)
Total segment costs and expenses			2,519				2,327				7,729				6,524
General corporate expenses			34				40				118				116
Operating income (loss):
Exploration & Production			356				159				1,273				546
Gas Pipeline			152				162				486				473
Midstream Gas & Liquids			226				279				743				669
Gas Marketing Services			16				(67	)			(9	)			(160	)
Other			(2	)			—				(2	)			—
General corporate expenses			(34	)			(40	)			(118	)			(116	)
Total operating income			714				493				2,373				1,412
Interest accrued			(166	)			(171	)			(496	)			(515	)
Interest capitalized			16				9				40				21
Investing income			65				78				175				196
Minority interest in income of consolidated subsidiaries			(55	)			(29	)			(157	)			(68	)
Other income — net			2				8				7				12
Income from continuing operations before income taxes			576				388				1,942				1,058
Provision for income taxes			207				160				738				417
Income from continuing operations			369				228				1,204				641
Income (loss) from discontinued operations			(3	)			(30	)			99				124
Net income		$	366			$	198			$	1,303			$	765
Basic earnings per common share:
Income from continuing operations		$	.63			$	.38			$	2.07			$	1.07
Income (loss) from discontinued operations			—				(.05	)			.17				.21
Net income		$	.63			$	.33			$	2.24			$	1.28
Weighted-average shares (thousands)			577,448				596,836				582,105				598,124
Diluted earnings per common share:
Income from continuing operations		$	.62			$	.38			$	2.02			$	1.05
Income (loss) from discontinued operations			—				(.05	)			.17				.20
Net income		$	.62			$	.33			$	2.19			$	1.25
Weighted-average shares (thousands)			589,138				610,651				594,630				611,761
Cash dividends declared per common share		$	.11			$	.10			$	.32			$	.29

See accompanying notes.

The Williams Companies, Inc.

		September 30,				December 31,
(Dollars in millions, except per-share amounts)		2008				2007
ASSETS
Current assets:
Cash and cash equivalents		$	1,524			$	1,699
Accounts and notes receivable (net of allowance of $38 at September 30, 2008 and $27 at December 31, 2007)			1,089				1,192
Inventories			324				209
Derivative assets			2,091				1,736
Assets of discontinued operations			16				185
Deferred income taxes			72				199
Other current assets and deferred charges			365				318
Total current assets			5,481				5,538
Investments			990				901
Property, plant and equipment, at cost			25,335				22,787
Less accumulated depreciation, depletion, and amortization			(7,686	)			(6,806	)
Property, plant and equipment — net			17,649				15,981
Derivative assets			1,008				859
Goodwill			1,011				1,011
Other assets and deferred charges			754				771
Total assets		$	26,893			$	25,061
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	1,072			$	1,131
Accrued liabilities			1,144				1,158
Derivative liabilities			1,968				1,824
Liabilities of discontinued operations			13				175
Long-term debt due within one year			84				143
Total current liabilities			4,281				4,431
Long-term debt			7,827				7,757
Deferred income taxes			3,525				2,996
Derivative liabilities			1,002				1,139
Other liabilities and deferred income			1,045				933
Contingent liabilities and commitments (Note 12)
Minority interests in consolidated subsidiaries			639				1,430
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 613 million shares issued at September 30, 2008 and 608 million shares issued at December 31, 2007)			613				608
Capital in excess of par value			8,077				6,748
Retained earnings (deficit)			823				(293	)
Accumulated other comprehensive income (loss)			102				(121	)
			9,615				6,942
Less treasury stock, at cost (35 million shares of common stock at September 30, 2008 and 22 million shares at December 31, 2007)			(1,041	)			(567	)
Total stockholders’ equity			8,574				6,375
Total liabilities and stockholders’ equity		$	26,893			$	25,061

See accompanying notes.

The Williams Companies, Inc.

		Nine months ended
		September 30,
(Dollars in millions)		2008				2007
OPERATING ACTIVITIES:
Net income		$	1,303			$	765
Adjustments to reconcile to net cash provided by operations:
Reclassification of deferred net hedge gains related to sale of power business			—				(429	)
Depreciation, depletion and amortization			953				792
Provision for deferred income taxes			497				445
Provision for loss on investments, property and other assets			19				136
Net gain on disposition of assets			(37	)			(20	)
Gain on sale of contractual production rights			(148	)			—
Minority interest in income of consolidated subsidiaries			157				68
Amortization of stock-based awards			33				58
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable			278				(72	)
Inventories			(111	)			23
Margin deposits and customer margin deposits payable			72				31
Other current assets and deferred charges			(78	)			(11	)
Accounts payable			(252	)			(2	)
Accrued liabilities			17				(250	)
Changes in current and noncurrent derivative assets and liabilities			(103	)			200
Other, including changes in noncurrent assets and liabilities			6				(57	)
Net cash provided by operating activities			2,606				1,677
FINANCING ACTIVITIES:
Proceeds from long-term debt			674				184
Payments of long-term debt			(634	)			(318	)
Proceeds from issuance of common stock			32				37
Proceeds from sale of limited partner units of consolidated partnerships			362				—
Tax benefit of stock-based awards			21				21
Dividends paid			(186	)			(174	)
Purchase of treasury stock			(474	)			(234	)
Dividends and distributions paid to minority interests			(90	)			(57	)
Changes in restricted cash			(20	)			(4	)
Changes in cash overdrafts			4				43
Other — net			(5	)			(6	)
Net cash used by financing activities			(316	)			(508	)
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures			(2,593	)			(2,100	)
Net proceeds from dispositions			37				1
Changes in accounts payable and accrued liabilities			2				34
Proceeds from sale of discontinued operations			22				—
Purchases of investments/advances to affiliates			(105	)			(37	)
Purchases of auction rate securities			—				(304	)
Proceeds from sales of auction rate securities			—				353
Proceeds from sale of contractual production rights			148				—
Proceeds from dispositions of investments and other assets			25				65
Other — net			(1	)			5
Net cash used by investing activities			(2,465	)			(1,983	)
Decrease in cash and cash equivalents			(175	)			(814	)
Cash and cash equivalents at beginning of period			1,699				2,269
Cash and cash equivalents at end of period		$	1,524			$	1,455

See accompanying notes.

The Williams Companies, Inc.

Note 1. General

     Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto in our Annual Report on Form 10-K. The accompanying unaudited financial statements include all normal recurring adjustments that, in the opinion of our management, are necessary to present fairly our financial position at September 30, 2008, and results of operations for the three and nine months ended September 30, 2008 and 2007 and cash flows for the nine months ended September 30, 2008 and 2007.

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Recent Market Events

     The recent instability in financial markets has created global concerns about the liquidity of financial institutions and is having overarching impacts on the economy as a whole. In this volatile economic environment, many financial markets, institutions and other businesses remain under considerable stress. In addition, oil and gas prices have recently experienced significant declines. These events are impacting our business. However, we note the following:

	•		We are reducing our levels of expected capital expenditures.
	•		As of September 30, 2008, we have approximately $1.5 billion of cash and cash equivalents and nearly $2.6 billion of available capacity under our credit facilities.
	•		We have no significant debt maturities until 2011.
	•		Our risk from our net credit exposure to derivative counterparties, considering master netting agreements and collateral support, is not significant. Our net credit exposure as of September 30, 2008, related to derivative assets is $384 million, net of $54 million of collateral support. This exposure is concentrated with investment grade financial institution counterparties.

     To the extent that these recent events drive sustained lower energy commodity prices, it will negatively impact our future results of operations and cash flow from operations and could result in a further reduction in capital expenditures. These impacts could also include the future nonperformance of counterparties or impairments of goodwill and long-lived assets.

Note 2. Basis of Presentation

Discontinued Operations

     In accordance with the provisions related to discontinued operations within Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the accompanying consolidated financial statements and notes reflect the results of operations and financial position of our former power business as discontinued operations. (See Note 3.) These operations included a 7,500-megawatt portfolio of power-related contracts that was sold in 2007 and our natural-gas fired electric generating plant located in Hazleton, Pennsylvania (Hazleton) that was sold in March 2008, in addition to other power-related assets.

     Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.

Notes (Continued)

Master Limited Partnerships

     We currently own approximately 23.6 percent of Williams Partners L.P., including the interests of the general partner, which is wholly owned by us, and incentive distribution rights. Considering the presumption of control of the general partner in accordance with Emerging Issues Task Force (EITF) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” we consolidate Williams Partners L.P. within our Midstream Gas & Liquids (Midstream) segment.

     In January 2008, Williams Pipeline Partners L.P. completed its initial public offering of 16.25 million common units at a price of $20 per unit. In February 2008, the underwriters exercised their right to purchase an additional 1.65 million common units at the same price. The initial asset of the partnership is a 35 percent interest in Northwest Pipeline GP (Northwest Pipeline). Upon completion of these transactions, we now own approximately 47.7 percent of the interests in Williams Pipeline Partners L.P., including the interests of the general partner, which is wholly owned by us, and incentive distribution rights. In accordance with EITF Issue No. 04-5, we consolidate Williams Pipeline Partners L.P. within our Gas Pipeline segment due to our control through the general partner.

Note 3. Discontinued Operations

     The summarized results of discontinued operations and summarized assets and liabilities of discontinued operations primarily reflect our former power business except where noted otherwise.

Summarized Results of Discontinued Operations

     The following table presents the summarized results of discontinued operations for the three and nine months ended September 30, 2008 and 2007.

		Three months ended								Nine months ended
		September 30,								September 30,
		2008				2007				2008				2007
		(Millions)								(Millions)
Revenues		$	—			$	703			$	5			$	2,210
Income (loss) from discontinued operations before income taxes			(4	)			(52	)			159				324
(Impairments) and gain (loss) on sales			8				2				8				(124	)
(Provision) benefit for income taxes			(7	)			20				(68	)			(76	)
Income (loss) from discontinued operations		$	(3	)		$	(30	)		$	99			$	124

     Income (loss) from discontinued operations before income taxes for the nine months ended September 30, 2008, includes $128 million of gains from the favorable resolution of matters involving pipeline transportation rates associated with our former Alaska operations and $54 million of income from a reduction of remaining amounts accrued in excess of our obligation associated with the Trans-Alaska Pipeline System Quality Bank (see Note 12). These gains are partially offset by a $10 million charge from a settlement primarily related to the sale of natural gas liquids pipeline systems in 2002 (see Note 12) and a charge of $10 million associated with an oil purchase contract related to our former Alaska refinery.

     Income (loss) from discontinued operations before income taxes for the nine months ended September 30, 2007, includes a gain of $429 million (reported in revenues of discontinued operations) associated with the reclassification of deferred net hedge gains from accumulated other comprehensive income to earnings in second-quarter 2007. This reclassification was based on the determination that the forecasted transactions related to the derivative cash flow hedges being sold were probable of not occurring. The three and nine months ended September 30, 2007, includes unrealized mark-to-market losses of $49 million and $72 million, respectively.

     (Impairments) and gain (loss) on sales for the three and nine months ended September 30, 2008, primarily represents $9 million of final proceeds from the sale of our former power business.

     (Impairments) and gain (loss) on sales for the nine months ended September 30, 2007, includes impairments of $111 million related to the carrying value of certain derivative contracts for which we had previously elected the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and, accordingly, were no longer recording at fair value, and $13 million related to our natural gas-fired electric generating plant near Hazleton, Pennsylvania. These impairments were based on our comparison of the carrying value to the estimate of fair value less cost to sell.

Notes (Continued)

Summarized Assets and Liabilities of Discontinued Operations

     The following table presents the summarized assets and liabilities of discontinued operations as of September 30, 2008 and December 31, 2007. The September 30, 2008, and December 31, 2007, balances for derivative assets and derivative liabilities represent contracts remaining to be assigned to the purchaser of our former power business, entirely offset by reciprocal positions with that same party. We continue to pursue assignment of the remaining contracts. The December 31, 2007, balance of property, plant and equipment — net includes Hazleton. These assets were sold in a March 2008 transaction for $8 million.

		September 30,				December 31,
		2008				2007
		(Millions)
Derivative assets		$	11			$	114
Accounts receivable — net			5				55
Other current assets			—				3
Total current assets			16				172
Property, plant and equipment — net			—				8
Other noncurrent assets			—				5
Total noncurrent assets			—				13
Total assets		$	16			$	185
Derivative liabilities		$	11			$	114
Other current liabilities			2				61
Total current liabilities			13				175
Total liabilities		$	13			$	175

Note 4. Asset Sales, Impairments and Other Accruals

     The following table presents significant gains or losses from asset sales, impairments and other accruals or adjustments reflected in other income — net within segment costs and expenses.

		Three months ended								Nine months ended
		September 30,								September 30,
		2008				2007				2008				2007
		(Millions)								(Millions)
Exploration & Production
Gain on sale of contractual right to an international production payment		$	—			$	—			$	(148	)		$	—
Impairment of certain natural gas producing properties			14				—				14				—
Gas Pipeline
Income from change in estimate related to a regulatory liability			—				—				—				(17	)
Income from payments received for a terminated firm transportation agreement on Grays Harbor lateral. Associated with this gain is interest income of $2 million, which is included in investing income			—				(12	)			—				(18	)
Gain on sale of certain south Texas assets			(10	)			—				(10	)			—

     In January 2008, we sold a contractual right to a production payment on certain future international hydrocarbon production for $148 million. In the first quarter of 2008, we received $118 million in cash, with the remainder placed in escrow subject to certain post-closing conditions and adjustments. We recognized a pre-tax gain of $118 million in the first quarter of 2008 related to the initial cash received. In the second quarter of 2008, the remaining cash was received from escrow and recognized as income.

     Investing income within our Other segment includes gains from the sales of cost-based investments of $10 million and $15 million for the nine months ended September 30, 2008 and 2007, respectively.

Notes (Continued)

     The provision for income taxes includes:

		Three months ended								Nine months ended
		September 30,								September 30,
		2008				2007				2008				2007
		(Millions)								(Millions)
Current:
Federal		$	33			$	8			$	299			$	5
State			(11	)			6				34				7
Foreign			10				12				39				37
			32				26				372				49
Deferred:
Federal			149				118				312				319
State			22				11				41				33
Foreign			4				5				13				16
			175				134				366				368
Total provision		$	207			$	160			$	738			$	417

     The effective income tax rates for the three and nine months ended September 30, 2008, are greater than the federal statutory rate due primarily to the effect of state income taxes.

     The effective income tax rates for the three and nine months ended September 30, 2007, are greater than the federal statutory rate due primarily to the effect of state income taxes and taxes on foreign operations. The higher effective tax rate for the nine months ended September 30, 2007, was partially offset by a benefit recognized based on a favorable private letter ruling received from the Internal Revenue Service concerning our securities litigation settlement and fees, a portion of which were previously treated as nondeductible.

     During the next twelve months, we do not expect settlement of any unrecognized tax benefit associated with domestic or international matters under audit to have a material impact on our financial position.

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

		Three months ended								Nine months ended
		September 30,								September 30,
		2008				2007				2008				2007
		(Dollars in millions, except per-share amounts;
		shares in thousands)
Income from continuing operations available to common stockholders for basic and diluted earnings per common share (1)		$	369			$	228			$	1,204			$	641
Basic weighted-average shares (2)			577,448				596,836				582,105				598,124
Effect of dilutive securities:
Nonvested restricted stock units			1,304				1,769				1,337				1,553
Stock options			3,468				4,726				4,003				4,762
Convertible debentures (3)			6,918				7,320				7,185				7,322
Diluted weighted-average shares			589,138				610,651				594,630				611,761
Earnings per common share from continuing operations:
Basic		$	.63			$	.38			$	2.07			$	1.07
Diluted		$	.62			$	.38			$	2.02			$	1.05

Notes (Continued)

     The table below includes information related to stock options that were outstanding at September 30 of each respective year but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the third quarter weighted-average market price of our common shares.

		September 30,				September 30,
		2008				2007
Options excluded (millions)			1.9				1.9
Weighted-average exercise prices of options excluded		$	37.04			$	37.56
Exercise price ranges of options excluded		$	32.05 - $42.29			$	33.51 - $42.29
Third quarter weighted-average market price		$	30.22			$	32.56

Note 7. Employee Benefit Plans

     Net periodic benefit expense for the three and nine months ended September 30, 2008 and 2007 are as follows:

		Pension Benefits
		Three months								Nine months
		ended September 30,								ended September 30,
		2008				2007				2008				2007
		(Millions)								(Millions)
Components of net periodic pension expense:
Service cost		$	6			$	5			$	17			$	17
Interest cost			15				13				45				40
Expected return on plan assets			(20	)			(18	)			(59	)			(54	)
Amortization of net actuarial loss			3				5				10				14
Net periodic pension expense		$	4			$	5			$	13			$	17

		Other Postretirement Benefits
		Three months								Nine months
		ended September 30,								ended September 30,
		2008				2007				2008				2007
		(Millions)								(Millions)
Components of net periodic other postretirement benefit expense:
Service cost		$	1			$	1			$	2			$	2
Interest cost			5				5				14				13
Expected return on plan assets			(4	)			(3	)			(10	)			(9	)
Regulatory asset amortization			1				1				3				4
Net periodic other postretirement benefit expense		$	3			$	4			$	9			$	10

     During the nine months ended September 30, 2008, we contributed $37 million to our pension plans and $11 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $25 million to our pension plans in the remainder of 2008 for a total of approximately $62 million. We presently anticipate making additional contributions of approximately $4 million to our other postretirement benefit plans in 2008 for a total of approximately $15 million.

     The assets and liabilities recorded on the Consolidated Balance Sheet at September 30, 2008, representing the funded status of the pension and other postretirement benefit plans, use various assumptions including expected long-term rates of return on plan assets and discount rates. Considering the decline in the overall equity markets during 2008, the expected return on plan assets may not be achieved during 2008. Additionally, the 2008 increase in interest rates on high-quality corporate bonds could result in higher discount rates, resulting in lower plan obligations. As a result, the pension and other postretirement benefit plan assets and liabilities recorded as of September 30, 2008, may not represent the actual funded status of the plans as of that date. The annual measurement of the funded status of the plans will occur as of December 31, 2008. The impact of the differences between actual and assumed outcomes and changes in assumptions will likely cause a significant net actuarial loss and will be recognized in other comprehensive income, net of taxes, and amortized in net periodic benefit expense beginning in 2009.

Notes (Continued)

Note 8. Inventories

     Inventories at September 30, 2008 and December 31, 2007 are as follows:

		September 30,				December 31,
		2008				2007
		(Millions)
Natural gas liquids (NGLs)		$	146			$	66
Natural gas in underground storage			74				45
Materials, supplies and other			104				98
		$	324			$	209

Note 9. Debt and Banking Arrangements

Long-Term Debt

   Revolving credit and letter of credit facilities (credit facilities)

     At September 30, 2008, no loans are outstanding under our credit facilities. Letters of credit issued under our facilities are:

		Letters of Credit at
		September 30, 2008
		(Millions)
$500 million unsecured credit facilities		$	—
$700 million unsecured credit facilities		$	237
$1.5 billion unsecured credit facility		$	28

     Lehman Commercial Paper Inc., which is committed to fund up to $70 million of our $1.5 billion revolving credit facility, has filed for bankruptcy. Lehman Brothers Commercial Bank, which has not filed for bankruptcy, is committed to fund up to $12 million of Williams Partners L.P.’s $200 million revolving credit facility. We expect that our ability to borrow under these facilities is reduced by these committed amounts. The committed amounts of other participating banks under these agreements remain in effect and are not impacted by the above.

   Exploration & Production’s credit agreement

     In February 2007, Exploration & Production entered into a five-year unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. In June 2008, the agreement was extended through December 2013.

   Issuances and retirements

     On January 15, 2008, Transcontinental Gas Pipe Line Corporation (Transco) retired $100 million of 6.25 percent senior unsecured notes due January 15, 2008, with proceeds borrowed under our $1.5 billion unsecured credit facility.

     On April 15, 2008, Transco retired a $75 million adjustable rate unsecured note due April 15, 2008, with proceeds borrowed under our $1.5 billion unsecured credit facility.

     On May 22, 2008, Transco issued $250 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018 to certain institutional investors in a Rule 144A private debt placement. A portion of these proceeds was used to repay Transco’s $100 million and $75 million loans from January 2008 and April 2008, respectively, under our $1.5 billion unsecured credit facility. In September 2008, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

     On May 22, 2008, Northwest Pipeline issued $250 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018 to certain institutional investors in a Rule 144A private debt placement. These proceeds were used to repay Northwest Pipeline’s $250 million loan from December 2007 under our $1.5 billion unsecured credit facility. In September 2008, Northwest Pipeline completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

Notes (Continued)

Note 10. Fair Value Measurements

Adoption of SFAS No. 157

     SFAS No. 157, “Fair Value Measurements” (SFAS 157), establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. On January 1, 2008, we applied SFAS 157 for our assets and liabilities that are measured at fair value on a recurring basis, primarily our energy derivatives. Upon applying SFAS 157, we changed our valuation methodology to consider our nonperformance risk in estimating the fair value of our liabilities. The initial adoption of SFAS 157 had no material impact on our Consolidated Financial Statements. In February 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) FAS 157-2, permitting entities to delay application of SFAS 157 to fiscal years beginning after November 15, 2008, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Beginning January 1, 2009, we will apply SFAS 157 fair value requirements to nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed at fair value on a recurring basis. SFAS 157 requires two distinct transition approaches: (1) cumulative-effect adjustment to beginning retained earnings for certain financial instrument transactions and (2) prospectively as of the date of adoption through earnings or other comprehensive income, as applicable, for all other instruments. Upon adopting SFAS 157, we applied a prospective transition as we did not have financial instrument transactions that required a cumulative-effect adjustment to beginning retained earnings.

     Fair value is the price that would be received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market based measurement considered from the perspective of a market participant. We use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

     SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

	•		Level 1 — Quoted prices in active markets for identical assets or liabilities that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 primarily consists of financial instruments that are exchange-traded, including certain instruments that were part of sales transactions in 2007 and remain to be assigned to the purchaser. These unassigned instruments are entirely offset by reciprocal positions entered into directly with the purchaser. These reciprocal positions have also been included in Level 1.
	•		Level 2 — Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 primarily consists of over-the-counter (OTC) instruments such as forwards and swaps.
	•		Level 3 — Includes inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 consists of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value. Instruments in this category primarily include OTC options.

     In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.

Notes (Continued)

     The following table sets forth by level within the fair value hierarchy our assets and liabilities that are measured at fair value on a recurring basis.

Fair Value Measurements at September 30, 2008 Using:

		Quoted Prices
		in Active
		Markets for				Significant
		Identical				Other				Significant
		Assets or				Observable				Unobservable
		Liabilities				Inputs				Inputs
		(Level 1)				(Level 2)				(Level 3)				Total
		(Millions)
Assets:
Energy derivatives		$	1,008			$	1,705			$	386			$	3,099
Other assets			12				—				10				22
Total assets		$	1,020			$	1,705			$	396			$	3,121
Liabilities:
Energy derivatives		$	950			$	1,916			$	104			$	2,970
Total liabilities		$	950			$	1,916			$	104			$	2,970

     Energy derivatives include commodity based exchange-traded contracts and OTC contracts. Exchange-traded contracts include futures and options. OTC contracts include forwards, swaps and options.

     Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.

     The determination of fair value also incorporates the time value of money and credit risk factors including the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash deposits and letters of credit) and our nonperformance risk on our liabilities.

     Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.

     Contracts for which fair value can be estimated from executed transactions or broker quotes corroborated by other market data are generally classified within Level 2. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

     Certain instruments trade in less active markets with lower availability of pricing information requiring valuation models using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The fair value of options is estimated using an industry standard Black-Scholes option pricing model. Certain inputs into the model are generally observable, such as commodity prices and interest rates, whereas other model inputs, such as implied volatility by location, is unobservable and requires judgment in estimating. The instruments included in Level 3 at September 30, 2008, predominantly consist of options that primarily hedge future sales of production from our Exploration & Production segment, are structured as costless collars and are financially settled.

     The following tables set forth a reconciliation of changes in the fair value of net derivatives and other assets classified as Level 3 in the fair value hierarchy.

Notes (Continued)

Level 3 Fair Value Measurements Using Significant Unobservable Inputs
Three Months Ended September 30, 2008

		Net Derivatives				Other Assets
		(Millions)
Balance as of July 1, 2008		$	(641	)		$	10
Realized and unrealized gains (losses):
Included in income from continuing operations			22				—
Included in other comprehensive income (See Note 13)			870				—
Purchases, issuances, and settlements			27				—
Transfers in/out of Level 3			4				—
Balance as of September 30, 2008		$	282			$	10
Unrealized gains included in income from continuing operations relating to instruments still held at September 30, 2008		$	23			$	—

Level 3 Fair Value Measurements Using Significant Unobservable Inputs
Nine Months Ended September 30, 2008

		Net Derivatives				Other Assets
		(Millions)
Balance as of January 1, 2008		$	(14	)		$	10
Realized and unrealized gains (losses):
Included in income from continuing operations			(7	)			—
Included in other comprehensive income (See Note 13)			210				—
Purchases, issuances, and settlements			91				—
Transfers in/out of Level 3			2				—
Balance as of September 30, 2008		$	282			$	10
Unrealized losses included in income from continuing operations relating to instruments still held at September 30, 2008		$	(21	)		$	—

     Realized and unrealized gains (losses) included in income from continuing operations for the above period are reported in revenues in our Consolidated Statement of Income.

Note 11. Stockholders’ Equity

     During 2008, we purchased 13 million shares of our common stock for $474 million at an average cost of $36.76 per share completing our $1 billion common stock repurchase program. This stock repurchase is recorded in treasury stock on our Consolidated Balance Sheet. From the program’s inception in third-quarter 2007 to its completion in July 2008, we purchased 29 million shares of our common stock reaching the $1 billion limit (including transaction costs) authorized by our Board of Directors. Our overall average cost per share was $34.74.

     At December 31, 2007, we held all of Williams Partners L.P.’s seven million subordinated units outstanding. In February 2008, these subordinated units were converted into common units of Williams Partners L.P. due to the achievement of certain financial targets that resulted in the early termination of the subordination period. While these subordinated units were outstanding, other issuances of partnership units by Williams Partners L.P. had preferential rights and the proceeds from these issuances in excess of the book basis of assets acquired by Williams Partners L.P. were therefore reflected as minority interest on our Consolidated Balance Sheet rather than as equity. Due to the conversion of the subordinated units, these original issuances of partnership units no longer have preferential rights and now represent the lowest level of equity securities issued by Williams Partners L.P. In accordance with our policy regarding the issuance of equity of a consolidated subsidiary, such issuances of nonpreferential equity are accounted for as capital transactions and no gain or loss is recognized. Therefore, as a result of the first-quarter conversion, we recognized a decrease to minority interest and a corresponding increase to stockholders’ equity of approximately $1.2 billion.

Notes (Continued)

Note 12. Contingent Liabilities

Rate and Regulatory Matters and Related Litigation

     Our interstate pipeline subsidiaries have various regulatory proceedings pending. As a result, a portion of the revenues of these subsidiaries has been collected subject to refund. We have accrued a liability for these potential refunds as of September 30, 2008, which we believe is adequate for any refunds that may be required.

Issues Resulting from California Energy Crisis

     Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the U.S. Federal Energy Regulatory Commission (FERC). These challenges included refund proceedings, summer 2002 90-day contracts, investigations of alleged market manipulation including withholding, gas indices and other gaming of the market, new long-term power sales to the State of California that were subsequently challenged and civil litigation relating to certain of these issues. We have entered into settlements with the State of California (State Settlement), major California utilities (Utilities Settlement), and others that substantially resolved each of these issues with these parties.

     As a result of a June 2008 U.S. Supreme Court decision, certain contracts that we entered into during 2000 and 2001 may be subject to partial refunds depending on the results of further proceedings at the FERC. These contracts, under which we sold electricity, totaled approximately $89 million in revenue. While we are not a party to the cases involved in the U.S. Supreme Court decision, the buyer of electricity from us is a party to the cases and claims that we must refund to the buyer any loss it suffers due to the FERC’s reconsideration of the contract terms at issue in the decision.

     Certain other issues also remain open at the FERC and for other nonsettling parties.

  Refund proceedings

     Although we entered into the State Settlement and Utilities Settlement, which resolved the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, such as the counterparty to the contracts described above and various California end users that did not participate in the Utilities Settlement. As a part of the Utilities Settlement, we funded escrow accounts that we anticipate will satisfy any ultimate refund determinations in favor of the nonsettling parties including interest on refund amounts that we might owe to settling and nonsettling parties. We are also owed interest from counterparties in the California market during the refund period for which we have recorded a receivable totaling approximately $24 million at September 30, 2008. Collection of the interest and the payment of interest on refund amounts from the escrow accounts is subject to the conclusion of this proceeding. Therefore, we continue to participate in the FERC refund case and related proceedings.

     Challenges to virtually every aspect of the refund proceedings, including the refund period, continue to be made. Because of our settlements, we do not expect that the final resolution of refund obligations will have a material impact on us. Due to the ongoing proceedings and challenges, the final refund calculation has not been made and aspects of the refund calculation process remain unsettled.

Reporting of Natural Gas-Related Information to Trade Publications

     Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, in each case seeking an unspecified amount of damages. We are currently a defendant in:

	•		State court litigation in California brought on behalf of certain business and governmental entities that purchased gas for their use.
	•		Class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri, Tennessee and Wisconsin brought on behalf of direct and indirect purchasers of gas in those states. On October 29, 2008, the Tennessee appellate court reversed the state court’s dismissal of the plaintiffs’ claims on federal preemption grounds and sent the case back to the lower court for further proceedings. The Missouri case has been remanded to Missouri state court. The cases in the other jurisdictions have been removed and transferred to the federal court in Nevada. On February 19, 2008, the federal court granted summary judgment in the Colorado case in favor of us and most of the other defendants. We expect that the Colorado plaintiffs will appeal.

Notes (Continued)

Mobile Bay Expansion

     In 2002, an administrative law judge at the FERC issued an initial decision in Transco’s 2001 general rate case which, among other things, rejected the recovery of the costs of Transco’s Mobile Bay expansion project from its shippers on a “rolled-in” basis and found that incremental pricing for the Mobile Bay expansion project is just and reasonable. In 2004, the FERC issued an Order on Initial Decision in which it reversed certain parts of the administrative law judge’s decision and accepted Transco’s proposal for rolled-in rates. Gas Marketing Services holds long-term transportation capacity on the Mobile Bay expansion project. Certain parties filed appeals in federal court seeking to overturn the FERC’s ruling on the rolled-in rates. On April 2, 2008, Gas Marketing Services executed an agreement that settled this matter for $10 million, which was accrued in 2007.

Environmental Matters

  Continuing operations

     Since 1989, our Transco subsidiary has had studies underway to test certain of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. Transco has responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of its sites. Transco has identified polychlorinated biphenyl (PCB) contamination in compressor systems, soils and related properties at certain compressor station sites. Transco has also been involved in negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs. In addition, Transco commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. The costs of any such remediation will depend upon the scope of the remediation. At September 30, 2008, we had accrued liabilities of $5 million related to PCB contamination, potential mercury contamination, and other toxic and hazardous substances. Transco has been identified as a potentially responsible party at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, we have estimated our aggregate exposure for remediation of these sites to be less than $500,000, which is included in the environmental accrual discussed above. We expect that these costs will be recoverable through Transco’s rates.

     Beginning in the mid-1980s, our Northwest Pipeline subsidiary evaluated many of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. Consistent with other natural gas transmission companies, Northwest Pipeline identified PCB contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, Northwest Pipeline identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the EPA in the late 1980s and Northwest Pipeline conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required Northwest Pipeline to reevaluate its previous mercury clean-ups in Washington. Consequently, Northwest Pipeline is conducting additional remediation activities at certain sites to comply with Washington’s current environmental standards. At September 30, 2008, we have accrued liabilities of $7 million for these costs. We expect that these costs will be recoverable through Northwest Pipeline’s rates.

     In March 2008, the EPA issued a new air quality standard for ground level ozone. We currently do not know if our interstate gas pipelines will be impacted by the new standard. If they are, we will likely incur additional capital expenditures to comply. At this time we are unable to estimate the cost of these additions that may be required to meet the new regulations. We expect that costs associated with these compliance efforts will be recoverable through rates.

     We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At September 30, 2008, we have accrued liabilities totaling $6 million for these costs.

     Williams Production RMT Company performed voluntary audits of its 2006 and 2007 compliance with state and federal air regulations. In June 2007, pursuant to Colorado’s audit immunity privilege law, we disclosed to the Colorado Department of Public Health and Environment (CDPHE) that certain aspects of our facilities were not in compliance. We also described corrective actions that had or would be taken to remedy the issues. The CDPHE denied our request for penalty immunity and proposed a penalty. In a separate matter, the CDPHE issued a Notice of Violation (NOV) to Williams Production RMT Company in 2006 related to operating permits for our Roan Cliffs and Hayburn gas plants in Garfield County, Colorado. We settled both of these matters with the CDPHE in June 2008 and paid a $93,300 civil penalty and made a $373,200 contribution to a state environmental program.

Notes (Continued)

     In April 2007, the CDPHE issued an NOV to Williams Production RMT Company related to alleged air permit violations at the Rifle Station natural gas dehydration facility located in Garfield County, Colorado. The Rifle Station facility had been shut down prior to our receipt of the NOV and, except for some minor operations, remains closed. We settled the matter with the CDPHE in June 2008 and paid an $11,200 civil penalty and made a $44,800 contribution to a state environmental program.

     In April 2007, the New Mexico Environment Department’s Air Quality Bureau (NMED) issued an NOV to Williams Four Corners, LLC (Four Corners) that alleged various emission and reporting violations in connection with our Lybrook gas processing plant’s flare and leak detection and repair program. In December 2007, the NMED proposed a penalty of approximately $3 million. In July 2008, the NMED issued an NOV to Four Corners that alleged air emissions permit exceedances for three glycol dehydrators at one of our compressor facilities and proposed a penalty of approximately $103,000. We are discussing the proposed penalties with the NMED.

     In March 2008, the EPA proposed a penalty of $370,000 for alleged violations relating to leak detection and repair program delays at our Ignacio gas plant in Colorado and for alleged permit violations at a compressor station. We met with the EPA and are exchanging information in order to resolve the issues.

     In September 2007, the EPA requested, and our Transco subsidiary later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Clean Air Act. On March 28, 2008, the EPA issued NOVs alleging violations of Clean Air Act requirements at these compressor stations. We met with the EPA in May 2008 and submitted our response denying the allegations in June 2008.

   Former operations, including operations classified as discontinued

     In connection with the sale of certain assets and businesses, we have retained responsibility, through indemnification of the purchasers, for environmental and other liabilities existing at the time the sale was consummated, as described below.

     Agrico

     In connection with the 1987 sale of the assets of Agrico Chemical Company, we agreed to indemnify the purchaser for environmental cleanup costs resulting from certain conditions at specified locations to the extent such costs exceed a specified amount. At September 30, 2008, we have accrued liabilities of $9 million for such excess costs.

     Other

     At September 30, 2008, we have accrued environmental liabilities of $15 million related primarily to our:

	•		Potential indemnification obligations to purchasers of our former retail petroleum and refining operations;
	•		Former propane marketing operations, bio-energy facilities, petroleum products and natural gas pipelines;
	•		Discontinued petroleum refining facilities; and
	•		Former exploration and production and mining operations.

     Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws.

Notes (Continued)

   Summary of environmental matters

     Actual costs incurred for these matters could be substantially greater than amounts accrued depending on the actual number of contaminated sites identified, the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA and other governmental authorities and other factors, but the amount cannot be reasonably estimated at this time.

Other Legal Matters

  Will Price (formerly Quinque)

     In 2001, fourteen of our entities were named as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The fourth amended petition, which was filed in 2003, deleted all of our defendant entities except two Midstream subsidiaries. All remaining defendants have opposed class certification and a hearing on plaintiffs’ second motion to certify the class was held in April 2005. We are awaiting a decision from the court. The amount of any possible liability cannot be reasonably estimated at this time.

  Grynberg

     In 1998, the U.S. Department of Justice (DOJ) informed us that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against us and certain of our wholly owned subsidiaries. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In connection with our sales of Kern River Gas Transmission in 2002 and Texas Gas Transmission Corporation in 2003, we agreed to indemnify the purchasers for any liability relating to this claim, including legal fees. The maximum amount of future payments that we could potentially be required to pay under these indemnifications depends upon the ultimate resolution of the claim and cannot currently be determined. Grynberg had also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. In 1999, the DOJ announced that it would not intervene in any of the Grynberg cases. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. Grynberg’s measurement claims remained pending against us and the other defendants; the court previously dismissed Grynberg’s royalty valuation claims. In 2005, the court-appointed special master entered a report which recommended that the claims against our Gas Pipeline and Midstream subsidiaries be dismissed but upheld the claims against our Exploration & Production subsidiaries against our jurisdictional challenge. In October 2006, the District Court dismissed all claims against us and our wholly owned subsidiaries. In November 2006, Grynberg filed his notice of appeal with the Tenth Circuit Court of Appeals and the court held oral argument on September 25, 2008.

     In August 2002, Jack J. Grynberg, and Celeste C. Grynberg, Trustee on Behalf of the Rachel Susan Grynberg Trust, and the Stephen Mark Grynberg Trust, served us and one of our Exploration & Production subsidiaries with a complaint in state court in Denver, Colorado. The complaint alleges that we have used mismeasurement techniques that distort the British Thermal Unit heating content of natural gas, resulting in the alleged underpayment of royalties to Grynberg and other independent natural gas producers. The complaint also alleges that we inappropriately took deductions from the gross value of their natural gas and made other royalty valuation errors. Under various theories of relief, the plaintiff was seeking actual damages between $2 million and $20 million based on interest rate variations and punitive damages in the amount of approximately $1 million. In 2004, Grynberg filed an amended complaint against one of our Exploration & Production subsidiaries. In 2005, the parties agreed to dismiss mismeasurement claims. In September 2008, the court ruled in our favor on motions for summary judgment dismissing various claims. Trial on the remaining breach of contract and accounting claims has been set for November 2008. The amount of any possible liability cannot be reasonably estimated at this time.

Notes (Continued)

   Securities class actions

     Numerous shareholder class action suits were filed against us in 2002 in the United States District Court for the Northern District of Oklahoma. The majority of the suits alleged that we and co-defendants, WilTel, previously an owned subsidiary known as Williams Communications, and certain corporate officers, acted jointly and separately to inflate the stock price of both companies. WilTel was dismissed as a defendant as a result of its bankruptcy. These cases were consolidated and an order was issued requiring separate amended consolidated complaints by our equity holders and WilTel equity holders. The underwriter defendants have requested indemnification and defense from these cases. If we grant the requested indemnifications to the underwriters, any related settlement costs will not be covered by our insurance policies. We covered the cost of defending the underwriters. In 2002, the amended complaints of the WilTel securities holders and of our securities holders added numerous claims. On February 9, 2007, the court gave its final approval to our settlement with our securities holders. We entered into indemnity agreements with certain of our insurers to ensure their timely payment related to this settlement. The carrying value of our estimated liability related to these agreements is immaterial because we believe the likelihood of any future performance is remote.

     On July 6, 2007, the court granted various defendants’ motions for summary judgment and entered judgment for us and the other defendants in the WilTel matter. The plaintiffs appealed the court’s judgment. Any obligation of ours to the WilTel equity holders as a result of a settlement, or as a result of trial in the event of a successful appeal of the court’s judgment, will not likely be covered by insurance because our insurance coverage has been fully utilized by the settlement described above. The extent of any such obligation is presently unknown and cannot be estimated, but it is reasonably possible that our exposure could materially exceed amounts accrued for this matter.

   TAPS Quality Bank

     One of our subsidiaries, Williams Alaska Petroleum, Inc. (WAPI), has been engaged in administrative litigation being conducted jointly by the FERC and the Regulatory Commission of Alaska (RCA) concerning the Trans-Alaska Pipeline System (TAPS) Quality Bank. In 2004, the FERC and RCA presiding administrative law judges rendered their joint and individual initial decisions, and we accrued approximately $134 million based on our computation and assessment of ultimate ruling terms that were considered probable. Our additional potential refund liability terminated on March 31, 2004, when WAPI sold the Alaska refinery and ceased shipping on the TAPS pipeline. We subsequently accrued additional amounts for interest.

     In 2006, the FERC entered its final order, which the RCA adopted. On February 15, 2008, the Alaska Supreme Court upheld the RCA’s order and on March 16, 2008, the D.C. Circuit Court of Appeals upheld the FERC’s order. We have paid substantially all amounts invoiced by the Quality Bank Administrator and third parties, except certain disputed amounts which remain accrued.

     We believe that the likelihood of successful appeal by the counterparties is remote, considering the relevant facts and circumstances related to this matter, including the favorable 2008 D.C. Circuit Court of Appeals rulings, and our assessment of the counterparties’ limited remaining options. As a result, during the first quarter of 2008 we reduced remaining amounts accrued in excess of our estimated remaining obligation by $54 million.

     On August 18, 2008, a counterparty requested a writ of certiorari from the U.S. Supreme Court to appeal the ruling of the D.C. Circuit Court of Appeals.

   Redondo Beach taxes

     In 2005, we and AES Redondo Beach, L.L.C. received a tax assessment letter from the city of Redondo Beach, California, in which the city asserted that taxes, interest and penalties were owed related to natural gas used at the generating facility operated by AES Redondo Beach. In connection with the sale of our power business (see Note 2), we and AES Redondo Beach agreed to equally share, for periods prior to the closing of the sale, any ultimate tax liability as well as the funding of amounts previously paid to the city under protest. In July, 2008, we settled all disputes with the city and they subsequently refunded all tax payments made under protest plus half of the earned interest on those amounts. We shared this refund with AES Redondo Beach.

   Gulf Liquids litigation

     Gulf Liquids contracted with Gulsby Engineering Inc. (Gulsby) and Gulsby-Bay for the construction of certain gas processing plants in Louisiana. National American Insurance Company (NAICO) and American Home Assurance Company provided payment and performance bonds for the projects. In 2001, the contractors and sureties filed multiple cases in Louisiana and Texas against Gulf Liquids and us.

Notes (Continued)

     In 2006, at the conclusion of the consolidated trial of the asserted contract and tort claims, the jury returned its actual and punitive damages verdict against us and Gulf Liquids. Based on our interpretation of the jury verdicts, we estimated exposure for actual damages of approximately $68 million plus potential interest of approximately $25 million, all of which have been accrued as of September 30, 2008. In addition, we concluded that it was reasonably possible that any ultimate judgment might have included additional amounts of approximately $199 million in excess of our accrual, which primarily represented our estimate of potential punitive damage exposure under Texas law.

     From May through October 2007, the court entered seven post-trial orders in the case (interlocutory orders) which, among other things, overruled the verdict award of tort and punitive damages as well as any damages against us. The court also denied the plaintiffs’ claims for attorneys’ fees. On January 28, 2008, the court issued its judgment awarding damages against Gulf Liquids of approximately $11 million in favor of Gulsby and approximately $4 million in favor of Gulsby-Bay. Gulf Liquids, Gulsby, Gulsby-Bay, and NAICO are appealing the judgment. If the judgment is upheld on appeal, our liability will be substantially less than the amount of our accrual for these matters.

   Wyoming severance taxes

     In August 2006, the Wyoming Department of Audit (DOA) assessed our subsidiary, Williams Production RMT Company, for additional severance tax and interest for the production years 2000 through 2002. In addition, the DOA notified us of an increase in the taxable value of our interests for ad valorem tax purposes. We disputed the DOA’s interpretation of the statutory obligation and appealed this assessment to the Wyoming State Board of Equalization (SBOE). The SBOE upheld the assessment and remanded it to the DOA to address the disallowance of a credit. The SBOE did not award interest on the assessment. We estimate that the amount of the additional severance and ad valorem taxes to be approximately $4 million. We appealed the SBOE decision to the Wyoming Supreme Court, which heard oral argument on August 12, 2008. If the DOA prevails in its interpretation of our obligation and applies the same basis of assessment to subsequent periods, it is reasonably possible that we could owe a total of approximately $23 million to $25 million in additional taxes and interest from January 1, 2003 through September  30, 2008.

   Royalty litigation

     In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in Colorado state court alleging that we improperly calculated oil and gas royalty payments, failed to account for the proceeds that we received from the sale of gas and extracted products, improperly charged certain expenses, and failed to refund amounts withheld in excess of ad valorem tax obligations. The plaintiffs claim that the class might be in excess of 500 individuals and seek an accounting and damages. The parties have reached a partial settlement agreement for an amount that was previously accrued. The partial settlement has received preliminary approval by the court, and we anticipate trial in late 2009 on remaining issues related to royalty payment calculation and obligations under specific lease provisions. We are not able to estimate the amount of any additional exposure at this time.

     Certain other royalty matters are currently being litigated by other producers with a federal regulatory agency in Colorado and with a state agency in New Mexico. Although we are not a party to these matters, the final outcome of those cases might lead to a future unfavorable impact on our results of operations.

Other Divestiture Indemnifications

     Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.

     We sold a natural gas liquids pipeline system in 2002, and in 2006, the purchaser of that system filed its complaint against us and our subsidiaries in state court in Houston, Texas. The purchaser alleged that we breached certain warranties under the purchase and sale agreement and sought approximately $18 million in damages and our specific performance under certain guarantees. The dispute was settled in June 2008 and all court cases have been dismissed.

Notes (Continued)

     At September 30, 2008, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.

     In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.

Summary

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

Guarantees

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

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

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

     We have provided guarantees in the event of nonpayment by our previously owned communications subsidiary, WilTel, on certain lease performance obligations that extend through 2042. The maximum potential exposure is $42 million at September 30, 2008. Our exposure declines systematically throughout the remaining term of WilTel’s obligations. The carrying value of these guarantees is $38 million at September 30, 2008.

     Former managing directors of Gulf Liquids are involved in litigation related to the construction of gas processing plants. Gulf Liquids has indemnity obligations to the former managing directors for legal fees and potential losses that may result from this litigation. Claims against these former managing directors have been settled and dismissed after payments on their behalf by directors and officers insurers. Some unresolved issues remain between us and these insurers, but no amounts have been accrued for any potential liability.

Notes (Continued)

     We have guaranteed the performance of a former subsidiary of our wholly owned subsidiary MAPCO Inc., under a coal supply contract. This guarantee was granted by MAPCO Inc. upon the sale of its former subsidiary to a third party in 1996. The guaranteed contract provides for an annual supply of a minimum of 2.25 million tons of coal. Our potential exposure is dependent on the difference between current market prices of coal and the pricing terms of the contract, both of which are variable, and the remaining term of the contract. Given the variability of the terms, the maximum future potential payments cannot be determined. We believe that our likelihood of performance under this guarantee is remote. In the event we are required to perform, we are fully indemnified by the purchaser of MAPCO Inc.’s former subsidiary. This guarantee expires in December 2010 and has no carrying value.

     We have guaranteed commercial letters of credit totaling $20 million on behalf of ACCROVEN, an equity method investee. These expire in January 2009 and have no carrying value.

     We have provided guarantees on behalf of certain entities in which we have an equity ownership interest. These generally guarantee operating performance measures and the maximum potential future exposure cannot be determined. There are no expiration dates associated with these guarantees. No amounts have been accrued at September 30, 2008.

Note 13. Comprehensive Income

     Comprehensive income is as follows:

		Three months ended								Nine months ended
		September 30,								September 30,
		2008				2007				2008				2007
		(Millions)								(Millions)
Net income		$	366			$	198			$	1,303			$	765
Other comprehensive income (loss):
Net unrealized gains on derivative instruments			1,083				131				256				252
Net reclassification into earnings of derivative instrument (gains) losses			62				(32	)			142				(476	)
Foreign currency translation adjustments			(10	)			25				(27	)			56
Amortization of pension benefits net actuarial loss			3				5				10				14
Amortization of other postretirement benefits prior service cost			—				—				1				1
Other comprehensive income (loss) before taxes			1,138				129				382				(153	)
Income tax benefit (provision) on other comprehensive income (loss)			(434	)			(40	)			(154	)			80
Other comprehensive income (loss) before minority interest			704				89				228				(73	)
Allocation of other comprehensive income (loss) to minority interest			(12	)			—				(5	)			—
Other comprehensive income (loss)			692				89				223				(73	)
Comprehensive income		$	1,058			$	287			$	1,526			$	692

     Net unrealized gains on derivative instruments represents changes in the fair value of certain derivative contracts that have been designated as cash flow hedges. The net unrealized gains on derivative instruments are as follows:

		Three months ended								Nine months ended
		September 30,								September 30,
		2008				2007				2008				2007
		(Millions)								(Millions)
Net unrealized gains (losses) on:
Forward natural gas purchases and sales		$	1,034			$	132			$	274			$	284
Forward natural gas liquids sales			50				(1	)			(18	)			(1	)
Forward power purchases and sales			—				—				—				(31	)
Other derivative instruments			(1	)			—				—				—
		$	1,083			$	131			$	256			$	252

     Net reclassification into earnings of derivative instrument (gains) losses for the nine months ended September 30, 2007, includes a gain of $429 million. This reclassification was based on the determination that the forecasted transactions related to the derivative cash flow hedges being sold as part of the sale of our power business were probable of not occurring.

Notes (Continued)

Note 14. Segment Disclosures

     Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different technology, marketing strategies and industry knowledge. Our master limited partnerships, Williams Partners L.P. and Williams Pipeline Partners L.P., are consolidated within our Midstream and Gas Pipeline segments, respectively. (See Note 2.) Other primarily consists of corporate operations.

Performance Measurement

     We currently evaluate performance based upon segment profit (loss) from operations, which includes segment revenues from external and internal customers, segment costs and expenses, equity earnings (losses) and income (loss) from investments, including impairments related to investments accounted for under the equity method. Intersegment sales are generally accounted for at current market prices as if the sales were to unaffiliated third parties.

     External revenues of our Exploration & Production segment include third-party oil and gas sales, which are more than offset by transportation expenses and royalties due third parties on intersegment sales.

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

		Exploration								Midstream				Gas
		&				Gas				Gas &				Marketing
		Production				Pipeline				Liquids				Services				Other				Eliminations				Total
		(Millions)
Three months ended September 30, 2008
Segment revenues:
External		$	(79	)		$	403			$	1,442			$	1,499			$	2			$	—			$	3,267
Internal			962				4				(6	)			217				4				(1,181	)			—
Total revenues		$	883			$	407			$	1,436			$	1,716			$	6			$	(1,181	)		$	3,267
Segment profit (loss)		$	361			$	173			$	254			$	16			$	(2	)		$	—			$	802
Less equity earnings			5				21				28				—				—				—				54
Segment operating income (loss)		$	356			$	152			$	226			$	16			$	(2	)		$	—				748
General corporate expenses																											(34	)
Total operating income																										$	714
Three months ended September 30, 2007
Segment revenues:
External		$	(21	)		$	385			$	1,350			$	1,141			$	5			$	—			$	2,860
Internal			520				7				10				106				2				(645	)			—
Total revenues		$	499			$	392			$	1,360			$	1,247			$	7			$	(645	)		$	2,860
Segment profit (loss)		$	169			$	183			$	300			$	(67	)		$	—			$	—			$	585
Less equity earnings			10				21				21				—				—				—				52
Segment operating income (loss)		$	159			$	162			$	279			$	(67	)		$	—			$	—				533
General corporate expenses																											(40	)
Total operating income																										$	493