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

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 8.01. Other Events

On May 21, 2007, we announced a definitive agreement to sell substantially all of our power business to Bear Energy, LP, a unit of the Bear Stearns Company, Inc. for $512 million. We have revised certain historical financial information previously included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006, and our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2007, to reflect the results of operations and financial position of our power business as discontinued operations in accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”

The following items of the Form 10-K have been revised for the discontinued operations described above and are filed as exhibits to this Current Report on Form 8-K:

	•		Item 6. Selected Financial Data
	•		Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	•		Item 7A. Quantitative and Qualitative Disclosures About Market Risk
	•		Item 8. Financial Statements and Supplementary Data
	•		Exhibit 12. Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2006, 2005, 2004, 2003, and 2002
	•		Exhibit 23.1. Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP

The following items of the Form 10-Q have been revised for the discontinued operations described above and are filed as exhibits to this Current Report on Form 8-K:

	•		Item 1. Financial Statements
	•		Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	•		Item 3. Quantitative and Qualitative Disclosures About Market Risk
	•		Exhibit 12. Computation of Ratio of Earnings to Fixed Charges for the three months ended March 31, 2007

The revised items of the Form 10-K and Form 10-Q described above have been updated for only the power business discontinued operations. We have not otherwise updated for activities or events occurring after the dates these items were originally presented in the Form 10-K and Form 10-Q. This Current Report on Form 8-K should be read in conjunction with our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007, and other Current Reports on Form 8-K.

Item 9.01. Financial Statements and Exhibits

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

Exhibit No.		Description
12		Revised Computations of Ratio of Earnings to Fixed Charges for the years ended December 31, 2006, 2005, 2004, 2003, and 2002 and for the three months ended March 31, 2007.
23.1		Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
99.1		Revised Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Financial Statements and Supplementary Data (Part II, Items 6, 7, 7A and 8 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).
99.2		Schedule II — Valuation and Qualifying Accounts for each of the three years ended December 31, 2006
99.3		Revised Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Quantitative and Qualitative Disclosures About Market Risk (Part I, Items 1, 2, and 3 of our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2007).

SIGNATURE

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

October 12, 2007

INDEX TO EXHIBITS

Exhibit No.		Description
12		Revised Computations of Ratio of Earnings to Fixed Charges for the years ended December 31, 2006, 2005, 2004, 2003, and 2002 and for the three months ended March 31, 2007.
23.1		Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
99.1		Revised Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Financial Statements and Supplementary Data (Part II, Items 6, 7, 7A and 8 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2006).
99.2		Schedule II — Valuation and Qualifying Accounts for each of the three years ended December 31, 2006
99.3		Revised Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Quantitative and Qualitative Disclosures About Market Risk (Part I, Items 1, 2, and 3 of our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2007).

Exhibit 12

The Williams Companies, Inc.
Computation of Ratio of Earnings to Fixed Charges

		Years Ended December 31,
		2006				2005				2004				2003				2002
		(Dollars in millions)
Earnings:
Income (loss) from continuing operations before income taxes and cumulative effect of change in accounting principles		$	557.9			$	774.0			$	298.5			$	(374.9	)		$	(629.5	)
Minority interest in income and preferred returns of consolidated subsidiaries			40.0				25.7				21.4				19.4				41.8
Less: Equity earnings			(98.9	)			(65.6	)			(49.9	)			(20.3	)			(82.7	)
Income (loss) from continuing operations before income taxes and cumulative effect of change in accounting principles, minority interest in income and preferred returns of consolidated subsidiaries and equity earnings			499.0				734.1				270.0				(375.8	)			(670.4	)
Add:
Fixed charges:
Interest accrued, including proportionate share from 50% owned investees			694.2				680.1				821.8				1,274.0				1,172.2
Rental expense representative of interest factor			15.5				19.2				18.3				25.3				22.0
Preferred distributions			—				—				—				47.8				58.1
Total fixed charges			709.7				699.3				840.1				1,347.1				1,252.3
Distributed income of equity-method investees			113.0				107.7				60.5				21.5				81.3
Less:
Capitalized interest			(17.2	)			(7.2	)			(6.7	)			(45.5	)			(27.3	)
Preferred distributions			—				—				—				(47.8	)			(58.1	)
Total earnings as adjusted		$	1,304.5			$	1,533.9			$	1,163.9			$	899.5			$	577.8
Fixed charges		$	709.7			$	699.3			$	840.1			$	1,347.1			$	1,252.3
Ratio of earnings to fixed charges			1.84				2.19				1.39				(a	)			(a	)

The Williams Companies, Inc.
Computation of Ratio of Earnings to Fixed Charges
(Dollars in millions)

		Three months ended
		March 31, 2007
Earnings:
Income from continuing operations before income taxes		$	274.3
Minority interest in income of consolidated subsidiaries			14.0
Less: Equity earnings			(21.4	)
Income from continuing operations before income taxes, minority interest in income of consolidated subsidiaries and equity earnings			266.9
Add:
Fixed charges:
Interest accrued, including proportionate share from 50% owned investees			178.0
Rental expense representative of interest factor			4.4
Total fixed charges			182.4
Distributed income of equity-method investees			19.3
Less:
Capitalized interest			(4.9	)
Total earnings as adjusted		$	463.7
Fixed charges		$	182.4
Ratio of earnings to fixed charges			2.54

Exhibit 23.1

Consent Of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following registration statements on Form S-3 and Form S-4, and related prospectuses of The Williams Companies, Inc. and in the following registration statements on Form S-8 of our report dated February 22, 2007, except for the matters related to the sale of power business described in Note 2, as to which the date is October 8, 2007, with respect to the consolidated financial statements and schedule of The Williams Companies, Inc. included in this Current Report (Form 8-K).

     Form S-3:

Registration Statement Nos. 333-20927, 333-20929, 333-29185, 333-35097, 333-70394, 333-85540, 333-106504, and 333-134293

     Form S-4:

Registration Statement Nos. 333-57416, 333-63202, 333-85568, and 333-129779

     Form S-8:

		Registration No. 33-58671 —		The Williams Companies, Inc. Stock Plan for Nonofficer Employees
		Registration No. 33-58971 —		Transco Energy Company Thrift Plan
		Registration No. 333-03957 —		The Williams Companies, Inc. 1996 Stock Plan for Non-Employee Directors
		Registration No. 333-11151 —		The Williams Companies, Inc. 1996 Stock Plan
		Registration No. 333-40721 —		The Williams Companies, Inc. 1996 Stock Plan for Nonofficer Employees
		Registration No. 333-51994 —		The Williams Companies, Inc. 1996 Stock Plan for Nonofficer Employees
		Registration No. 333-66474 —		The Williams Companies, Inc. 2001 Stock Plan
		Registration No. 333-76929 —		The Williams International Stock Plan
		Registration No. 333-85542 —		The Williams Investment Plus Plan
		Registration No. 333-85546 —		The Williams Companies, Inc. 2002 Incentive Plan
		Registration No. 333-142985 —		The Williams Companies, Inc. Employee Stock Purchase Plan

/s/ Ernst & Young LLP

Tulsa, Oklahoma
October 8, 2007

Exhibit 99.1

Item 6. Selected Financial Data

     The following financial data as of December 31, 2006 and 2005, and for the three years ended December 31, 2006, are an integral part of, and should be read in conjunction with, the consolidated financial statements and related notes. All other amounts have been prepared from our financial records. Certain amounts below have been recast or reclassified. See Note 1 of Notes to Consolidated Financial Statements in Part II Item 8 for discussion of changes in 2006, 2005 and 2004. Information concerning significant trends in the financial condition and results of operations is contained in Management’s Discussion & Analysis of Financial Condition and Results of Operations of this report.

		2006				2005				2004				2003				2002
		(Millions, except per-share amounts)
Revenues(1)		$	9,376.4			$	9,781.4			$	8,407.5			$	8,615.0			$	3,295.5
Income (loss) from continuing operations(2)			347.0				472.1				148.6				(248.0	)			(433.1	)
Income (loss) from discontinued operations(3)			(38.5	)			(156.8	)			15.1				517.1				(321.6	)
Cumulative effect of change in accounting principles(4)			—				(1.7	)			—				(761.3	)			—
Diluted earnings (loss) per common share:
Income (loss) from continuing operations			.57				.79				.28				(.54	)			(1.01	)
Income (loss) from discontinued operations			(.06	)			(.26	)			.03				1.00				(.62	)
Cumulative effect of change in accounting principles			—				—				—				(1.47	)			—
Total assets at December 31			25,402.4				29,442.6				23,993.0				27,021.8				34,988.5
Short-term notes payable and long-term debt due within one year at December 31			392.1				122.6				250.1				938.5				2,077.1
Long-term debt at December 31			7,622.0				7,590.5				7,711.9				11,039.8				11,075.7
Stockholders’ equity at December 31			6,073.2				5,427.5				4,955.9				4,102.1				5,049.0
Cash dividends per common share			.345				.25				.08				.04				.42

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Sale of Power Business

     On May 21, 2007, we announced our intent to sell substantially all of our power business to Bear Energy, LP, a unit of the Bear Stearns Company, Inc. for $512 million. This pending sale reduces the risk and complexity of our overall business model and allows our ongoing efforts to focus our investment capital and growth efforts on our core natural gas businesses. The sale is expected to close in 2007.

     The pending sale of our power business to Bear Energy, LP, includes tolling contracts, full requirements contracts, tolling resales, heat rate options, related hedges and other related assets including certain property and software. Our natural gas-fired electric generating plant located in Hazleton, Pennsylvania (Hazleton), is currently being marketed for sale. These operations are part of our previously reported Power segment and are now reflected in our results of operations as discontinued operations. (See Notes 1 and 2 of Notes to Consolidated Financial Statements.)

     Other continuing components of our former Power segment are now being reported as follows:

	•		Marketing and risk management operations that support our natural gas businesses are reflected in the new Gas Marketing Services segment.
	•		Our equity investment in Aux Sable Liquid Products, LP (Aux Sable) is now reported within the Midstream segment.
	•		Our natural gas-fired electric generating plant near Bloomfield, New Mexico (Milagro facility), is now reported within the Other segment.

General

     We are primarily a natural gas company, engaged in finding, producing, gathering, processing, and transporting natural gas. Our operations are located principally in the United States and are organized into the following reporting segments: Exploration & Production, Gas Pipeline, Midstream Gas & Liquids (Midstream), and Gas Marketing Services. (See Note 1 of Notes to Consolidated Financial Statements for further discussion of reporting segments.)

     Unless indicated otherwise, the following discussion of critical accounting estimates, discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Item 8 of this document [Exhibit 99.1].

Overview of 2006

     Our plan for 2006 was focused on continued disciplined growth. Objectives and highlights of this plan included:

Objectives		Highlights
Continuing to improve both EVA® and segment profit.		2006 segment profit of $1,486.3 million contributed to improving our EVA®.
Investing in our natural gas businesses in a way that improves EVA®, meets customer needs, and enhances our competitive position.		Total capital expenditures were approximately $2.5 billion, of which approximately $1.4 billion was invested in Exploration & Production.
Continuing to increase natural gas production in a responsible and efficient manner.		Exploration & Production increased its average daily production by approximately 21% over last year and also added 597 billion cubic feet equivalent in net reserves during 2006. Additionally, we received 2006 industry awards including Hydrocarbon Producer of the Year and North America’s Best Field Rejuvenation.

Objectives		Highlights
Accelerating additional asset transactions between us and Williams Partners L.P., our master limited partnership.		Williams Partners L.P. acquired 100 percent of Williams Four Corners LLC for a total of $1.583 billion.
Increasing the scale of our gathering and processing business in key growth basins.		We invested approximately $257 million in capital expenditures in Midstream including Deepwater Gulf expansion projects and completing the expansion of our Opal gas processing facility.
Filing new rates to enable our Gas Pipeline segment to create additional value.		Northwest Pipeline and Transco each filed a general rate case with the Federal Energy Regulatory Commission (FERC). In January 2007, Northwest Pipeline reached a settlement in its pending rate case. The settlement is subject to FERC approval, which is expected by mid-2007.

     Our 2006 income from continuing operations decreased to $347.0 million, as compared to $472.1 million in 2005. Our net cash provided by operating activities was $1,889.6 million in 2006 compared to $1,449.9 million in 2005. These comparative results reflect the resolution of certain legacy litigation issues partially offset by the benefit of strong natural gas liquid margins. In addition to achieving these results, the following represent significant actions or events that occurred during the year:

Recent Events

     In June 2006, Williams Partners L.P. acquired 25.1 percent of our interest in Williams Four Corners LLC for $360 million. The acquisition was completed after Williams Partners L.P. successfully closed a $150 million private debt offering of senior unsecured notes due 2011 and an equity offering of approximately $225 million in net proceeds. In December 2006, Williams Partners L.P. acquired the remaining 74.9 percent interest in Williams Four Corners LLC for $1.223 billion. The acquisition was completed after Williams Partners L.P. successfully closed a $600 million private debt offering of senior unsecured notes due 2017, a private equity offering of approximately $350 million of common and Class B units, and a public equity offering of approximately $294 million in net proceeds. The debt and equity issued by Williams Partners L.P. is reported as a component of our consolidated debt balance and minority interest balance, respectively. Williams Four Corners LLC owns certain gathering, processing and treating assets in the San Juan Basin in Colorado and New Mexico.

     In December 2006, Northwest Pipeline completed and placed into service its capacity replacement project in the state of Washington. The project involved abandoning 268 miles of 26-inch pipeline and replacing it with approximately 80 miles of 36-inch pipeline constructed in four sections along the same pipeline corridor. Additionally, Northwest Pipeline modified five existing compressor stations and created additional net horsepower.

     Northwest Pipeline and Transco have each filed a general rate case with the FERC. Northwest Pipeline reached a settlement in its pending rate case. The settlement is subject to FERC approval, which is expected by mid-2007. The new rates for Northwest Pipeline are effective in January 2007, subject to refund. The new rates for Transco are expected to be effective in March 2007, subject to refund.

     In April 2006, Transco issued $200 million aggregate principal amount of 6.4 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement. In October 2006, Transco completed an offer to exchange all of these notes for substantially identical notes registered under the Securities Act of 1933, as amended.

     In April 2006, we retired a secured floating-rate term loan for $488.9 million, including outstanding principal and accrued interest. The loan was due in 2008 and secured by substantially all of the assets of Williams Production RMT Company. The loan was retired using a combination of cash and revolving credit borrowings.

     In May 2006, we replaced our $1.275 billion secured revolving credit facility with a $1.5 billion unsecured revolving credit facility. The new facility contains similar terms and financial covenants as the secured facility, but contains certain additional restrictions. (See Note 11 of Notes to Consolidated Financial Statements.)

     In May 2006, our Board of Directors approved a regular quarterly dividend of 9 cents per share of common stock, which reflects an increase of 20 percent compared with the 7.5 cents per share paid in each of the three prior quarters.

     In June 2006, Northwest Pipeline issued $175 million aggregate principal amount of 7 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement. In October 2006, Northwest Pipeline completed an offer to exchange all of these notes for substantially identical notes registered under the Securities Act of 1933, as amended.

     In June 2006, we reached an agreement-in-principle to settle class-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000, and July 22, 2002, for a total payment of $290 million to plaintiffs. We funded our $145 million portion of the settlement with cash-on-hand in November 2006, with the balance funded directly by our insurers. We recorded a pre-tax charge for approximately $161 million in second quarter 2006. This settlement did not have a material effect on our liquidity position. (See Note 15 of Notes to Consolidated Financial Statements.)

     On July 31, 2006, and August 1, 2006, we received a verdict in civil litigation related to a contractual dispute surrounding certain natural gas processing facilities known as Gulf Liquids. We recorded a pre-tax charge for approximately $88 million in second quarter 2006 related to this loss contingency. (See Note 15 of Notes to Consolidated Financial Statements.)

     Our property insurance coverage levels and premiums were revised during the second quarter of 2006. In general, our coverage levels have decreased while our premiums have increased. These changes reflect general trends in our industry due to hurricane-related damages in recent years.

     In November 2005, we initiated an offer to convert our 5.5 percent junior subordinated convertible debentures into our common stock. In January 2006, we converted approximately $220.2 million of the debentures in exchange for 20.2 million shares of common stock, a $25.8 million cash premium, and $1.5 million of accrued interest.

Outlook for 2007

     Our plan for 2007 is focused on continued disciplined growth. Objectives of this plan include:

	•		Continue to improve both EVA® and segment profit.
	•		Invest in our natural gas businesses in a way that improves EVA®, meets customer needs, and enhances our competitive position.
	•		Continue to increase natural gas production and reserves.
	•		Increase the scale of our gathering and processing business in key growth basins.
	•		Successfully resolving the rate cases for both Northwest Pipeline and Transco.

     Potential risks and/or obstacles that could prevent us from achieving these objectives include:

	•		Volatility of commodity prices;
	•		Lower than expected levels of cash flow from operations;
	•		Decreased drilling success at Exploration & Production;
	•		Exposure associated with our efforts to resolve regulatory and litigation issues (see Note 15 of Notes to Consolidated Financial Statements);
	•		General economic and industry downturn.

     We continue to address these risks through utilization of commodity hedging strategies, focused efforts to resolve regulatory issues and litigation claims, disciplined investment strategies, and maintaining our desired level of at least $1 billion in liquidity from cash and revolving credit facilities.

     New Accounting Standards and Emerging Issues

     Accounting standards that have been issued and are not yet effective may have a material effect on our Consolidated Financial Statements in the future. These include:

	•		SFAS No. 157 “Fair Value Measurements” (SFAS 157). The effective date for this Statement is for fiscal years beginning after November 15, 2007. We will assess the impact on our Consolidated Financial Statements.
	•		FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (FIN 48).

     FIN 48 prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. A tax position that meets the more likely than not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit, determined on a cumulative probability basis, that is greater than 50 percent likely of being realized upon ultimate settlement.

     We adopted FIN 48 as of January 1, 2007. The cumulative effect of applying the Interpretation will be reported as an adjustment to the opening balance of retained earnings. The net impact of the cumulative effect of adopting FIN 48 is expected to be in the range of a $10 million to $20 million decrease in retained earnings.

     See Recent Accounting Standards in Note 1 of Notes to Consolidated Financial Statements for further information on these and other recently issued accounting standards.

Critical Accounting Estimates

     The preparation of financial statements, in conformity with generally accepted accounting principles, requires management to make estimates and assumptions that affect the reported amounts therein. We have discussed the following accounting estimates and assumptions as well as related disclosures with our Audit Committee. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.

     Revenue Recognition — Derivative Instruments and Hedging Activities

     We hold a substantial portfolio of energy trading and nontrading contracts for a variety of purposes. We review these contracts to determine whether they are nonderivatives or derivatives. If they are derivatives, we further assess whether the contracts qualify for either cash flow hedge accounting or the normal purchases and normal sales exception.

     The determination of whether a derivative contract qualifies as a cash flow hedge includes an analysis of historical market price information to assess whether the derivative is expected to be highly effective in achieving offsetting cash flows attributed to the hedged risk. We also assess whether the hedged forecasted transaction is probable of occurring. This assessment requires us to exercise judgment and consider a wide variety of factors in addition to our intent, including internal and external forecasts, historical experience, changing market and business conditions, our financial and operational ability to carry out the forecasted transaction, the length of time until the forecasted transaction is projected to occur, and the quantity of the forecasted transaction. In addition, we compare actual cash flows to those that were expected from the underlying risk. If a hedged forecasted transaction is not

probable of occurring, or if the derivative contract is not expected to be highly effective, the derivative does not qualify for hedge accounting.

     For derivatives that are designated as cash flow hedges, we do not reflect changes in their fair value in earnings until the associated hedged item affects earnings. For those that have not been designated as hedges or do not qualify for hedge accounting, we recognize the net change in their fair value in income currently (marked to market).

     For derivatives that are designated as cash flow hedges, we prospectively discontinue hedge accounting and recognize future changes in fair value directly in earnings if we no longer expect the hedge to be highly effective, or if we believe that the hedged forecasted transaction is no longer probable of occurring. If the forecasted transaction becomes probable of not occurring, we must also reclass amounts previously recorded in other comprehensive income into earnings in addition to prospectively discontinuing hedge accounting. If the effectiveness of the derivative improves and is again expected to be highly effective in offsetting cash flows attributed to the hedged risk, or if the forecasted transaction again becomes probable, we may prospectively re-designate the derivative as a hedge of the underlying risk.

     Derivatives for which the normal purchases and normal sales exception has been elected are accounted for on an accrual basis. In determining whether a derivative is eligible for this exception, we assess whether the contract provides for the purchase or sale of a commodity that will be physically delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In making this assessment, we consider numerous factors, including the quantities provided under the contract in relation to our business needs, delivery locations per the contract in relation to our operating locations, duration of time between entering the contract and delivery, past trends and expected future demand, and our past practices and customs with regard to such contracts. Additionally, we assess whether it is probable that the contract will result in physical delivery of the commodity and not net financial settlement.

     The fair value of derivative contracts is determined based on the nature of the transaction and the market in which transactions are executed. We also incorporate assumptions and judgments about counterparty performance and credit considerations in our determination of their fair value. Contracts are executed in the following environments:

	•		Organized commodity exchange or over-the-counter markets with quoted prices;
	•		Organized commodity exchange or over-the-counter markets with quoted market prices but limited price transparency, requiring increased judgment to determine fair value;
	•		Markets without quoted market prices.

     The number of transactions executed without quoted market prices is limited. We estimate the fair value of these contracts by using readily available price quotes in similar markets and other market analyses. The fair value of all derivative contracts is continually subject to change as the underlying commodity market changes and our assumptions and judgments change.

     Additional discussion of the accounting for energy contracts at fair value is included in Energy Trading Activities within Item 7 and Note 1 of Notes to Consolidated Financial Statements.

     Oil- and Gas-Producing Activities

     We use the successful efforts method of accounting for our oil- and gas-producing activities. Estimated natural gas and oil reserves and forward market prices for oil and gas are a significant part of our financial calculations. Following are examples of how these estimates affect financial results:

•

An increase (decrease) in estimated proved oil and gas reserves can reduce (increase) our unit-of-production depreciation, depletion and amortization rates.

•

Changes in oil and gas reserves and forward market prices both impact projected future cash flows from our oil and gas properties. This, in turn, can impact our periodic impairment analyses, including that for goodwill.

     The process of estimating natural gas and oil reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering, and economic data. After being estimated internally, 99.9 percent of our reserve estimates are either audited or prepared by independent experts. The data may change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates could occur from time to time. A revision of our reserve estimates within reasonably likely parameters is not expected to result in an impairment of our oil and gas properties or goodwill. However, reserve estimate revisions would impact our depreciation and depletion expense prospectively. For example, a change of approximately 10 percent in oil and gas reserves for each basin would change our annual depreciation, depletion and amortization expense between approximately $25 million and $31 million. The actual impact would depend on the specific basins impacted and whether the change resulted from proved developed, proved undeveloped or a combination of these reserve categories.

     Forward market prices, which are utilized in our impairment analyses, include estimates of prices for periods that extend beyond those with quoted market prices. This forward market price information is consistent with that generally used in evaluating our drilling decisions and acquisition plans. These market prices for future periods impact the production economics underlying oil and gas reserve estimates. The prices of natural gas and oil are volatile and change from period to period, thus impacting our estimates. An unfavorable change in the forward price curve within reasonably likely parameters is not expected to result in an impairment of our oil and gas properties or goodwill.

     Contingent Liabilities

     We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. See Note 15 of Notes to Consolidated Financial Statements.

     Valuation of Deferred Tax Assets and Tax Contingencies

     We have deferred tax assets resulting from certain investments and businesses that have a tax basis in excess of the book basis and from tax carry-forwards generated in the current and prior years. We must evaluate whether we will ultimately realize these tax benefits and establish a valuation allowance for those that may not be realizable. This evaluation considers tax planning strategies, including assumptions about the availability and character of future taxable income. At December 31, 2006, we have approximately $926 million of deferred tax assets for which a $36 million valuation allowance has been established. When assessing the need for a valuation allowance, we considered forecasts of future company performance, the estimated impact of potential asset dispositions and our ability and intent to execute tax planning strategies to utilize tax carryovers. Based on our projections, we believe that it is probable that we can utilize our year-end 2006 federal tax net operating losses carryovers and charitable contribution carryovers prior to their expiration. We do not expect to be able to utilize $36 million of foreign deferred tax assets related to carryovers. See Note 5 of Notes to Consolidated Financial Statements for additional information regarding the tax carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by potential changes in jurisdictional income tax laws and the circumstances surrounding the actual realization of related tax assets.

     We regularly face challenges from domestic and foreign tax authorities regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various filing positions, we record a liability

for probable tax contingencies. The ultimate disposition of these contingencies could have a significant impact on net cash flows. To the extent we were to prevail in matters for which accruals have been established or were required to pay amounts in excess of our accrued liability, our effective tax rate in a given financial statement period may be materially impacted.

     Pension and Postretirement Obligations

     We have employee benefit plans that include pension and other postretirement benefits. Pension and other postretirement benefit plan expense and obligations are calculated by a third-party actuary and are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute expense and the benefit obligations are shown in Note 7 of Notes to Consolidated Financial Statements. The following table presents the estimated increase (decrease) in pension and other postretirement benefit expense and obligations resulting from a one-percentage-point change in the specified assumption.

		Benefit Expense								Benefit Obligation
		One-Percentage-				One-Percentage-				One-Percentage-				One-Percentage-
		Point Increase				Point Decrease				Point Increase				Point Decrease
		(Millions)
Pension benefits:
Discount rate		$	(12	)		$	14			$	(129	)		$	151
Expected long-term rate of return on plan assets			(10	)			10				—				—
Rate of compensation increase			2				(2	)			14				(13	)
Other postretirement benefits:
Discount rate			(1	)			1				(41	)			47
Expected long-term rate of return on plan assets			(2	)			2				—				—
Assumed health care cost trend rate			6				(5	)			61				(48	)

     The expected long-term rates of return on plan assets are determined by combining a review of historical returns realized within the portfolio, the investment strategy included in the plans’ Investment Policy Statement, and the capital market projections provided by our independent investment consultant for the asset classifications in which the portfolio is invested as well as the target weightings of each asset classification. These rates are impacted by changes in general market conditions, but because they are long-term in nature, short-term market swings do not significantly impact the rates. Changes to our target asset allocation would also impact these rates. Our expected long-term rate of return on plan assets used for our pension plans is 7.75 percent for 2006 and was 8.5 percent from 2002-2005. Over the past ten years, our actual average return on plan assets for our pension plans has been approximately 7.9 percent.

     The discount rates are used to discount future benefit cash flows to today’s dollars. Decreases in these rates increase the obligation and, generally, increase the related expense. The discount rates for our pension and other postretirement benefit plans were determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 7 of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term high-quality corporate bonds.

     The expected rate of compensation increase represents average long-term salary increases. An increase in this rate causes pension obligation and expense to increase.

     The assumed health care cost trend rates are based on our actual historical cost rates that are adjusted for expected changes in the health care industry.

Results of Operations

     Consolidated Overview

     The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2006. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

		Years ended December 31,
						$ Change				% Change								$ Change				% Change
						from				from								from				from
		2006				2005(1)				2005(1)				2005				2004(1)				2004(1)				2004
		(Millions)												(Millions)												(Millions)
Revenues		$	9,376.4			$	-405.0				-4	%		$	9,781.4			$	+1,373.9				+16	%		$	8,407.5
Costs and expenses:
Costs and operating expenses			7,566.4				+318.3				+4	%			7,884.7				-1,173.9				-17	%			6,710.8
Selling, general and administrative expenses			389.3				-112.0				-40	%			277.3				+12.7				+4	%			290.0
Other (income) expense — net			33.3				+23.1				+41	%			56.4				-109.8			NM					(53.4	)
General corporate expenses			132.1				+13.4				+9	%			145.5				-25.7				-21	%			119.8
Securities litigation settlement and related costs			167.3				-157.9			NM					9.4				-9.4			NM					—
Total costs and expenses			8,288.4												8,373.3												7,067.2
Operating income			1,088.0												1,408.1												1,340.3
Interest accrued — net			(652.6	)			+7.3				+1	%			(659.9	)			+151.1				+19	%			(811.0	)
Investing income			167.6				+142.8			NM					24.8				-26.1				-51	%			50.9
Early debt retirement costs			(31.4	)			-31.0			NM					(.4	)			+281.7				+100	%			(282.1	)
Minority interest in income of consolidated subsidiaries			(40.0	)			-14.3				-56	%			(25.7	)			-4.3				-20	%			(21.4	)
Other income — net			26.3				-0.8				-3	%			27.1				+5.3				+24	%			21.8
Income from continuing operations before income taxes and cumulative effect of change in accounting principle			557.9												774.0												298.5
Provision for income taxes			210.9				+91.0				+30	%			301.9				-152.0				-101	%			149.9
Income from continuing operations			347.0												472.1												148.6
Income (loss) from discontinued operations			(38.5	)			+118.3				+75	%			(156.8	)			-171.9			NM					15.1
Income before cumulative effect of change in accounting principle			308.5												315.3												163.7
Cumulative effect of change in accounting principle			—				+1.7				+100	%			(1.7	)			-1.7			NM					—
Net income		$	308.5											$	313.6											$	163.7

      2006 vs. 2005

     The decrease in revenues is primarily due to lower natural gas realized revenues at Gas Marketing Services associated with lower natural gas sales prices. Additionally, the effect of a change in forward prices on legacy natural gas derivative contracts not designated as cash flow hedges had an unfavorable impact on revenues. Partially offsetting these decreases are increased crude, olefin and natural gas liquid (NGL) marketing revenues, higher NGL production revenue at Midstream and increased production revenue at Exploration & Production.

     The decrease in costs and operating expenses is largely due to reduced natural gas purchase prices at Gas Marketing Services. Partially offsetting these decreases are increased crude, olefin and NGL marketing purchases and operating expenses at Midstream and increased depreciation, depletion and amortization and lease operating expense at Exploration & Production.

     The increase in selling, general and administrative (SG&A) expenses is primarily due to increased personnel costs, insurance expense, higher information systems support costs and the absence of a $17.1 million reduction of pension expense at Gas Pipeline in 2005. Additionally, Exploration & Production experienced higher costs due to increased staffing in support of increased drilling and operational activity.

     Other (income) expense — net within operating income in 2006 includes:

	•		A $72.7 million accrual for a Gulf Liquids litigation contingency;
	•		Income of $9 million due to a settlement of an international contract dispute at Midstream.

     Other (income) expense — net within operating income in 2005 includes:

	•		An $82.2 million accrual for litigation contingencies at Gas Marketing Services, associated primarily with agreements reached to substantially resolve exposure related to certain natural gas price and volume reporting issues;
	•		Gains totaling $29.6 million on the sale of certain natural gas properties at Exploration & Production;
	•		A gain of $9 million on a sale of land in our Other segment.

     General corporate expenses decreased primarily due to the absence of $13.8 million of insurance settlement charges in 2005 associated with certain insurance coverage allocation issues.

     The securities litigation settlement and related costs is the result of settling class-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000 and July 22, 2002.

     Interest accrued — net in 2006 includes $22 million in interest expense associated with our Gulf Liquids litigation contingency.

     The increase in investing income is due to:

	•		The absence of an $87.2 million impairment in 2005 on our investment in Longhorn Partners Pipeline, L.P. (Longhorn);
	•		The absence of a $23 million impairment in 2005 of our Aux Sable Liquid Products, L.P. (Aux Sable) equity investment;
	•		An approximate $30 million increase in interest income primarily associated with increased earnings on cash and cash equivalent balances associated with higher rates of return;
	•		Increased equity earnings of $33.3 million due largely to the absence of equity losses in 2006 on Longhorn and increased earnings of our Discovery Producer Services LLC (Discovery) and Aux Sable investments.

These increases are partially offset by:

	•		A $16.4 million impairment of a Venezuelan cost-based investment at Exploration & Production;
	•		The absence of an $8.6 million gain on sale of our remaining Mid-America Pipeline (MAPL) and Seminole Pipeline (Seminole) investments at Midstream in 2005.

     Early debt retirement costs in 2006 includes $25.8 million in premiums and $1.2 million in fees related to the January 2006 debt conversion and $4.4 million of accelerated amortization of debt expenses related to the retirement of the debt secured by assets of Williams Production RMT Company.

     The increase in minority interest in income of consolidated subsidiaries is primarily due to the growth of Williams Partners L.P., our consolidated master limited partnership.

     Provision for income taxes changed favorably primarily due to decreased pre-tax income. The effective income tax rate for 2006 is slightly higher than the federal statutory rate primarily due to state income taxes, the effect of taxes on foreign operations, nondeductible convertible debenture expenses and an accrual for income tax

contingencies, partially offset by the favorable resolution of federal income tax litigation and the utilization of charitable contribution carryovers not previously benefited. The 2006 effective income tax rate has been increased by an adjustment to increase overall deferred income tax liabilities. The effective income tax rate for 2005 is higher than the federal statutory rate due primarily to state income taxes, nondeductible expenses, and the inability to utilize charitable contribution carryovers. The 2005 effective income tax rate was reduced by an adjustment to reduce overall deferred income tax liabilities and favorable settlements on federal and state income tax matters. (See Note 5 of Notes to Consolidated Financial Statements.)

     Income (loss) from discontinued operations in 2006 includes:

	•		A $14.2 million net-of-tax loss related to our discontinued power business (see Note 2 of Notes to Consolidated Financial Statements);
	•		An $11.9 million net-of-tax litigation settlement related to our former chemical fertilizer business;
	•		A $3.7 million net-of-tax charge associated with the settlement of a loss contingency related to a former exploration business;
	•		A $9.1 million net-of-tax charge associated with an oil purchase contract related to our former Alaska refinery.

     Income (loss) from discontinued operations in 2005 includes a $154.8 million net-of-tax loss related to our discontinued power business. (See Note 2 of Notes to Consolidated Financial Statements.)

     Cumulative effect of change in accounting principle in 2005 is due to the implementation of FIN 47. (See Note 9 of Notes to Consolidated Financial Statements.)

     2005 vs. 2004

     The increase in revenues is due primarily to higher natural gas prices and production volumes sold and gas management income at Exploration & Production, higher natural gas prices realized at Gas Marketing Services, and increased NGL prices and crude marketing revenue at Midstream.

     The increase in costs and operating expenses is due primarily to increased natural gas purchase prices at Gas Marketing Services. Also contributing to the increase were higher crude marketing costs and NGL production costs at Midstream in addition to increased depreciation, depletion and amortization and gas management expense at Exploration & Production.

     The decrease in SG&A expenses is primarily due to the $17.1 million reduction in expenses at Gas Pipeline to record the cumulative impact of a correction to pension expense attributable to the periods 2003 and 2004 and a $9.7 reduction of bad debt expense at Gas Marketing Services resulting from the sale of certain receivables to a third party. Partially offsetting these items is increased staffing costs at Exploration & Production in support of increased operational drilling activity.

     Other (income) expense — net, within operating income, in 2004 includes:

	•		Income of $93.6 million from an insurance arbitration award associated with Gulf Liquids at Midstream;
	•		Gains of $16.2 million from the sale of Exploration & Production’s securities, invested in a coal seam royalty trust, that were purchased for resale;
	•		A $9.5 million gain on the sale of Louisiana olefins assets at Midstream;
	•		A $15.4 million loss provision related to an ownership dispute on prior period production included at Exploration & Production;

	•		An $11.8 million environmental expense accrual related to the Augusta refinery facility included in our Other segment;
	•		A $9 million write-off of previously capitalized costs on an idled segment of Northwest Pipeline’s system included at Gas Pipeline.

     The increase in general corporate expenses is due primarily to the $13.8 million of expense related to the settlement of certain insurance coverage issues and a $16 million increase in outside legal costs associated primarily with securities class action matters.

     The decrease in interest accrued — net is due primarily to lower average borrowing levels in 2005 as compared to 2004.

     The decrease in investing income is due primarily to a $76.4 million increase in impairment charges on our investment in Longhorn, a $13.9 million increase in Longhorn equity losses, and the $23 million impairment of our Aux Sable equity investment. Partially offsetting these decreases are the following increases:

	•		A $30.4 million increase in domestic and international equity earnings, excluding Longhorn and Aux Sable;
	•		The absence in 2005 of a $20.8 million impairment of an international cost-based investment;
	•		The absence in 2005 of a $16.9 million impairment of our Discovery equity investment;
	•		The $8.6 million gain on the sale of our remaining interests in the MAPL and Seminole assets;
	•		The absence in 2005 of a $6.5 million Longhorn recapitalization fee.

     Early debt retirement costs include premiums, fees and expenses related to the retirement of debt.

     Provision for income taxes changed unfavorably primarily due to increased pre-tax income in 2005 as compared to 2004. The effective income tax rate for 2005 is higher than the federal statutory rate due primarily to state income taxes, nondeductible expenses and the inability to utilize charitable contribution carryovers. The 2005 effective income tax rate has been reduced by an adjustment to reduce the overall deferred income tax liabilities and favorable settlements on federal and state income tax matters. The effective income tax rate for 2004 is higher than the federal statutory rate due primarily to state income taxes and a charge associated with charitable contribution carryovers. A 2004 accrual for income tax contingencies was offset by favorable settlements of certain federal and state income tax matters. (See Note 5 of Notes to Consolidated Financial Statements.)

     Income (loss) from discontinued operations in 2004 is comprised of gains on the sales of the Canadian straddle plants and the Alaska refinery of $189.8 million and $3.6 million, respectively, as well as $22 million in income from our Canadian straddles discontinued operation. Partially offsetting these are $153 million of charges to increase our accrued liability associated with certain Quality Bank litigation matters and a $55.4 million net-of-tax loss related to our discontinued power business.

Results of Operations — Segments

     We are currently organized into the following segments: Exploration & Production, Gas Pipeline, Midstream, Gas Marketing Services, and Other. Other primarily consists of corporate operations. Our management currently evaluates performance based on segment profit (loss) from operations. (See Note 17 of Notes to Consolidated Financial Statements.)

Exploration & Production

     Overview of 2006

     In 2006, we focused on our objective to rapidly expand development of our drilling inventory. This resulted in significant growth as evidenced by the following accomplishments:

•

We increased average daily domestic production levels by approximately 23 percent over last year, surpassing our goal of 15 to 20 percent. The average daily domestic production was approximately 752 million cubic feet of gas equivalent (MMcfe) compared to 612 MMcfe in 2005. The increased production is primarily due to increased development within the Piceance and Powder River basins.

2006 domestic production grew 23 percent or 140 MMcfe per day over 2005

•

We continued to increase our development drilling program during 2006. We drilled 1,783 gross wells in 2006 compared to 1,627 in 2005. This contributed to the addition of 597 billion cubic feet equivalent (Bcfe) in net reserves — a replacement rate for our domestic production of 216 percent in 2006 compared to 277 percent in 2005. Capital expenditures for domestic drilling, development, gathering facilities and acquisition activity in 2006 were approximately $1.4 billion compared to approximately $768 million in 2005.

     The benefit of higher production volumes to operating results was more than offset by the downward trending of natural gas market prices during the year and increased operating costs. The increase in operating costs reflects an

increase in our production volumes combined with a general industry condition of greater demand for services and products as production activities increase in our key basins.

      Significant events

     At December 31, 2006, all ten new state-of-the-art FlexRig4^® drilling rigs have been placed into service pursuant to our lease agreement with Helmerich & Payne. The March 2005 contract provided for the operation of the drilling rigs, each for a primary lease term of three years. This arrangement supports our continuing objective to accelerate the pace of natural gas development in the Piceance basin through both deployment of the additional rigs and through the drilling and operational efficiencies of the new rigs.

     In 2006, we increased our position in the Fort Worth basin by acquiring producing properties and undeveloped leasehold interests for approximately $64 million. These acquisitions increased our diversification into the Mid-Continent region and will allow us to use our horizontal drilling expertise to develop wells in the Barnett Shale formation.

     Outlook for 2007

     Our expectations and objectives for 2007 include:

	•		Maintaining our development drilling program in our key basins of Piceance, Powder River, San Juan, Arkoma, and Fort Worth through planned capital expenditures of $1.3 to $1.4 billion.
	•		Continuing to grow our domestic average daily production level with a goal of 10 to 20 percent annual growth.

     Approximately 172 MMcfe, or 18 percent, of our forecasted 2007 daily production is hedged by NYMEX and basis fixed price contracts at prices that average $3.90 per Mcfe at a basin level. In addition, we have collar agreements for each month in 2007 as follows:

	•		NYMEX collar agreement for approximately 15 MMcfe per day at a weighted-average floor price of $6.50 per Mcfe and a weighted-average ceiling price of $8.25 per Mcfe.
	•		Northwest Pipeline/Rockies collar agreement for approximately 50 MMcfe per day at a floor price of $5.65 per Mcfe and a ceiling price of $7.45 per Mcfe at a basin level.
	•		El Paso/San Juan collar agreements totaling approximately 130 MMcfe per day at a weighted average floor price of $5.98 per Mcfe and a weighted average ceiling price of $9.63 per Mcfe at a basin level.
	•		Mid-Continent (PEPL) collar agreements totaling approximately 75 MMcfe per day at a weighted average floor price of $6.82 per Mcfe and a weighted average ceiling price of $10.80 per Mcfe at a basin level.

     We have recently 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. Margin requirements, if any, under this new facility are dependent on the level of hedging and on natural gas reserves value.

     Additional risks to achieving our expectations include weather conditions at certain of our locations during the first and fourth quarters of 2007, drilling rig availability, obtaining permits as planned for drilling, and market price movements.

      Year-Over-Year Operating Results

		Years Ended December 31,
		2006				2005				2004
		(Millions)
Segment revenues		$	1,487.6			$	1,269.1			$	777.6
Segment profit		$	551.5			$	587.2			$	235.8

     2006 vs. 2005

     Total segment revenues increased $218.5 million, or 17 percent, primarily due to the following:

	•		$165 million, or 15 percent, increase in domestic production revenues reflecting $245 million primarily associated with a 23 percent increase in natural gas production volumes sold, offset by a decrease of $80 million associated with a 6 percent decrease in net realized average prices. The increase in production volumes is primarily from the Piceance and Powder River basins and the decrease in prices reflects the downward trending of market prices in the latter part of 2006.
	•		$10 million increase in production revenues from our international operations primarily due to increases in net realized average prices for crude oil production volumes sold.
	•		$14 million of net unrealized gains in 2006 from hedge ineffectiveness and forward mark-to-market gains on certain basis swaps not designated as hedges as compared to $10 million in net unrealized losses attributable to hedge ineffectiveness from NYMEX collars in 2005.

     To manage the commodity price risk and volatility of owning producing gas properties, we enter into derivative sales contracts that fix the sales price relating to a portion of our future production. Approximately 40 percent of domestic production in 2006 was hedged by NYMEX and basis fixed price contracts at a weighted average price of $3.82 per Mcfe at a basin level compared to 47 percent hedged at a weighted average price of $3.99 per Mcfe in 2005. In addition, approximately 15 percent of domestic production was hedged by the following collar agreements in 2006:

	•		NYMEX collar agreement for approximately 49 MMcfe per day at a floor price of $6.50 per Mcfe and a ceiling price of $8.25 per Mcfe.
	•		NYMEX collar agreement for approximately 15 MMcfe per day at a floor price of $7.00 per Mcfe and a ceiling price of $9.00 per Mcfe.
	•		Northwest Pipeline/Rockies collar agreement for approximately 50 MMcfe per day at a floor price of $6.05 per Mcfe and a ceiling price of $7.90 per Mcfe at a basin level.

     In 2005, approximately 10 percent of domestic production was hedged by a NYMEX collar agreement for approximately 50 MMcfe per day at a floor price of $7.50 per Mcfe and a ceiling price of $10.49 per Mcfe in the first quarter and at a floor price of $6.75 per Mcfe and a ceiling price of $8.50 per Mcfe in the second, third, and fourth quarters, and a Northwest Pipeline/Rockies collar agreement for approximately 50 MMcfe per day in the fourth quarter at a floor price of $6.10 per Mcfe and a ceiling price of $7.70 per Mcfe.

     Our hedges are executed with our Gas Marketing Services segment, which, in turn, executes offsetting derivative contracts with unrelated third parties. Generally, Gas Marketing Services bears the counterparty performance risks associated with unrelated third parties. Hedging decisions are made considering our overall commodity risk exposure and are not executed independently by Exploration & Production.

     Total costs and expenses increased $257 million, primarily due to the following:

	•		$107 million higher depreciation, depletion and amortization expense primarily due to higher production volumes and increased capitalized drilling costs;
	•		$54 million higher lease operating expense primarily due to the increased number of producing wells and higher well service and industry costs due to increased demand and approximately $6 million for out-of-period expenses related to 2005. Our management has concluded that the effect of this item is not material to our consolidated results for 2006, or prior periods, or to our trend of earnings;
	•		$19 million higher operating taxes primarily due to higher production volumes sold and increased tax rates;

	•		$33 million higher selling, general and administrative expenses primarily due to higher compensation for additional staffing in support of increased drilling and operational activity. In addition, we incurred higher legal, insurance, and information technology support costs related to the increased activity;
	•		The absence in 2006 of $29.6 million of gains on the sales of properties in 2005.

     The $35.7 million decrease in segment profit is primarily due to lower net realized average prices and higher costs and expenses as discussed previously, and the absence in 2006 of $29.6 million of gains on the sales of properties in 2005. Partially offsetting these decreases are a 23 percent increase in domestic production volumes sold and an increase in income from ineffectiveness and forward mark-to-market gains. Segment profit also includes an $8 million increase in our international operations primarily due to higher revenue and equity earnings as a result of increases in net realized average prices for crude oil production volumes sold.

     2005 vs. 2004

     The $491.5 million, or 63 percent increase in segment revenues is primarily due to an increase in domestic production revenues of $434 million during 2005 reflecting higher net realized average prices and higher production volumes sold. Also contributing to the increase is a $58 million increase in revenues from gas management activities, offset in costs and expenses, and $13 million increased production revenues from our international operations. Partially offsetting these increases is $10 million in net unrealized losses attributable to NYMEX collars from hedge ineffectiveness.

     The increase in domestic production revenues primarily results from $319 million higher revenues associated with a 42 percent increase in net realized average prices for production sold as well as a $115 million increase associated with an 18 percent increase in average daily production volumes. The higher net realized average prices reflect the benefit of the lower volumes hedged in 2005 as compared to 2004 coupled with higher market prices for natural gas in 2005. The increase in production volumes primarily reflects an increase in the number of producing wells resulting from our successful 2005 drilling program.

     Approximately 77 percent of domestic production in 2004 was hedged at a weighted average price of $3.65 per Mcfe at a basin level.

     Total costs and expenses increased $147 million, primarily due to the following:

	•		$62 million higher depreciation, depletion and amortization expense primarily due to higher production volumes and increased capitalized drilling costs;
	•		$16 million higher lease operating expense from the increased number of producing wells and generally higher industry costs;
	•		$23 million higher operating taxes primarily due to increased market prices and production volumes sold;
	•		$18 million higher selling, general and administrative expenses primarily due to higher compensation and increased staffing in 2005 in support of increased drilling and operational activity;
	•		$58 million higher gas management expenses associated with higher revenues from gas management activities, offset in segment revenues;
	•		$11 million lower gain in 2005 than in 2004 on the sale of securities associated with our coal seam royalty trust that were previously purchased for resale.

These increased costs and expenses are partially offset by the absence in 2005 of a $15.4 million loss provision related to an ownership dispute on prior period production in 2004, a $7.9 million gain on the sale of an undeveloped leasehold position in Colorado in the first quarter of 2005, and a $21.7 million gain on the sale of certain outside operated properties in the Powder River basin area of Wyoming in the third quarter of 2005.

     The $351.4 million increase in segment profit is primarily due to increased revenues from higher volumes and higher net realized average prices, as well as the gains on sales of assets, partially offset by higher expenses as discussed above. Segment profit also includes a $19 million increase in our international operations reflecting higher revenue and equity earnings resulting from higher net realized oil and gas prices.

Gas Pipeline

     Overview

     We operate, through our Northwest Pipeline and Transco subsidiaries, approximately 14,400 miles of pipeline from the Gulf Coast to the northeast United States and from northern New Mexico to the Pacific Northwest with a total annual throughput of approximately 2,500 trillion BTUs. Additionally, we hold a 50 percent interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream). This asset, which extends from the Mobile Bay area in Alabama to markets in Florida, has current transportation capacity of 1.1 MMdt/d.

     Our strategy to create value for our shareholders focuses on maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets.

     Gas Pipeline’s interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have little impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

     Significant events of 2006 include:

     Filing of rate cases

     During 2006, Northwest Pipeline and Transco each filed general rate cases with the FERC for increases in rates due to higher costs in recent years. The new rates are effective, subject to refund, in January 2007 for Northwest Pipeline and in March 2007 for Transco. We expect the new rates to result in significantly higher revenues.

     In January 2007, Northwest Pipeline reached a settlement in its pending rate case. The settlement is subject to FERC approval, which is expected by mid-2007.

     Gulfstream

     In March 2006, our equity method investee, Gulfstream, announced a new long-term agreement with a Florida utility company, which fully subscribed the pipeline’s mainline capacity on a long-term basis. Under the agreement, Gulfstream will extend its existing pipeline approximately 35 miles within Florida. The agreement is subject to the approval of various authorities. Construction of the extension is anticipated to begin in early 2008 with a targeted completion of summer 2008.

     In May 2006, Gulfstream announced a new agreement to provide 155 Mdt/d of natural gas to a Florida utility. In December 2006, Gulfstream filed an application with the FERC seeking approval to expand its pipeline system to provide the additional capacity. Under this agreement, Gulfstream will construct approximately 17.5 miles of 20 inch pipeline and the installation of a new compressor facility. If approved, all of the facilities will be placed into service by January 2009.

     Parachute Lateral project

     In August 2006, we received FERC approval to construct a 37.6-mile expansion that will provide additional natural gas transportation capacity in northwest Colorado. The planned expansion will increase capacity by 450 Mdt/d through the 30-inch diameter line and is estimated to cost approximately $86 million. The expansion is expected to be in service in March 2007.

     Grays Harbor

     Effective January 2005, Duke Energy Trading and Marketing, LLC (Duke) terminated its firm transportation agreement related to Northwest Pipeline’s Grays Harbor lateral. In January 2005, Duke paid Northwest Pipeline $94 million for the remaining book value of the asset and the related income taxes. We and Duke have not agreed on the amount of the income taxes due Northwest Pipeline as a result of the contract termination. We have deferred the $6 million difference between the proceeds and net book value of the lateral pending resolution of the disputed early termination obligation.

     On June 16, 2005, we filed a Petition for a Declaratory Order with the FERC requesting that it rule on our interpretation of our tariff to aid in resolving the dispute with Duke. On July 15, 2005, Duke filed a motion to intervene and provided comments supporting its position concerning the issues in dispute.

     On October 4, 2006, the FERC issued its Order on Petition for Declaratory Order, providing clarification on issues relating to Duke’s obligation to reimburse us for future tax expenses. We reviewed the Order and filed a request for rehearing requesting further clarification of certain items. Based upon the order, as written, we do not anticipate any adverse impact to our results of operations or financial position.

     Northwest Pipeline capacity replacement project

     In September 2005, we received FERC approval to construct and operate approximately 80 miles of 36-inch pipeline loop as a replacement for most of the capacity previously served by 268 miles of 26-inch pipeline in the Washington state area. The capacity replacement as well as the abandonment of the old capacity was completed in December 2006. In addition to the capacity replacement, five existing compressor stations were modified, and we increased net horsepower.

     Outlook for 2007

     Leidy to Long Island expansion project

     In May 2006, we received FERC approval to expand Transco’s natural gas pipeline in the northeast United States. The estimated cost of the project is approximately $141 million with three-quarters of that spending expected to occur in 2007. The expansion will provide 100 Mdt/d of incremental firm capacity and is expected to be in service by November 2007.

     Potomac expansion project

     In July 2006, we filed an application with the FERC to expand Transco’s existing facilities in the Mid-Atlantic region of the United States by constructing 16.5 miles of 42-inch pipeline. The project will provide 165 Mdt/d of incremental firm capacity. The estimated cost of the project is approximately $74 million, with an anticipated in-service date of November 2007.

     Year-Over-Year Operating Results

		Years Ended December 31,
		2006				2005				2004
		(Millions)
Segment revenues		$	1,347.7			$	1,412.8			$	1,362.3
Segment profit		$	467.4			$	585.8			$	585.8

     Significant 2005 adjustments

     Operating results for 2005 included:

•

Adjustments of $17.7 million reflected as a $12.1 million reduction of costs and operating expenses and a $5.6 million reduction of SG&A expenses. These cost reductions were corrections of the carrying value of certain liabilities that were recorded in prior periods. Based on a review by management, these liabilities were no longer required.

	•		Pension expense reduction of $17.1 million in the second quarter of 2005 to reflect the cumulative impact of a correction of an error attributable to 2003 and 2004. The error was associated with our third-party actuarial computation of annual net periodic pension expense and resulted from the identification of errors in certain Transco participant data involving annuity contract information utilized for 2003 and 2004.
	•		Adjustments of $37.3 million reflected as increases in costs and operating expenses related to $32.1 million of prior period accounting and valuation corrections for certain inventory items and an accrual of $5.2 million for contingent refund obligations.

     Our management concluded that the effects of these adjustments were not material to our consolidated results for 2005 or prior periods, or to our trend of earnings.

     2006 vs. 2005

     Revenues decreased $65.1 million, or 5 percent, due primarily to $75 million lower revenues associated with exchange imbalance settlements (offset in costs and operating expenses). Partially offsetting this decrease is a $9 million increase in revenue due to an adjustment for the recovery of state income tax rate changes (offset in provision for income taxes).

     Costs and operating expenses decreased $17 million, or 2 percent, due primarily to:

	•		A decrease in costs of $75 million associated with exchange imbalance settlements (offset in revenues);
	•		A decrease in costs of $37.3 million related to the absence of $32.1 million of 2005 prior period accounting and valuation corrections for certain inventory items and an accrual of $5.2 million for contingent refund obligations.

Partially offsetting these decreases are:

	•		An increase in contract and outside service costs of $23 million due primarily to higher pipeline assessment and repair costs;
	•		An increase in depreciation expense of $15 million due to property additions;
	•		An increase in operating and maintenance expenses of $15 million;
	•		An increase in operating taxes of $10 million;
	•		The absence of $14.2 million of income in 2005 associated with the resolution of litigation;
	•		The absence of $12.1 million of expense reductions during 2005 related to the carrying value of certain liabilities.

     SG&A expenses increased $77 million, or 92 percent, due primarily to:

	•		An increase in personnel costs of $18 million;
	•		The absence of a 2005 $17.1 million reduction in pension costs to correct an error in prior periods;
	•		An increase in information systems support costs of $16 million;
	•		An increase in property insurance expenses of $14 million;
	•		The absence of $5.6 million of cost reductions in 2005 that related to correcting the carrying value of certain liabilities.

     The $118.4 million, or 20 percent, decrease in segment profit is due primarily to the absence of significant 2005 adjustments as previously discussed, increases in costs and operating expenses and SG&A expenses as previously discussed, and the absence of a $4.6 million construction completion fee recognized in 2005 related to our investment in Gulfstream.

     2005 vs. 2004

     The $50.5 million, or 4 percent, increase in Gas Pipeline revenues is due primarily to $86 million higher revenues associated with exchange imbalance cash-out settlements (offset in costs and operating expenses). Partially offsetting this increase is $24 million lower transportation revenues due primarily to the termination of the Grays Harbor contract, and $11 million lower revenues associated with reimbursable costs, which are passed through to customers (offset in costs and operating expenses and SG&A expenses).

     Costs and operating expenses increased $109 million, or 16 percent, due primarily to:

	•		An increase in costs of $86 million associated with exchange imbalances (offset in revenues);
	•		The increase in costs of $32.1 million due to prior period accounting and valuation corrections related to inventory, as previously discussed;
	•		An increase in operating and maintenance expense of $14 million due primarily to increased contract service costs, materials and supplies and rental fees;
	•		The increase in costs of $5.2 million due to an accrual for contingent refund obligations, as previously discussed.

Partially offsetting these increases are decreases due to:

	•		Income of $14.2 million associated with the resolution of the litigation related to recovery of gas costs;
	•		The cost reduction of $12.1 million due to adjusting the carrying value of certain liabilities, as previously discussed;
	•		Lower reimbursable costs of $5 million (offset in revenues).

     SG&A expenses decreased approximately $38 million, or 31 percent, due to the $17.1 million reduction in pension costs to correct a prior period error, $6 million lower reimbursable costs (offset in revenues), and the reversal of $5.6 million of prior period accruals.

     Comparative segment profit is unchanged from 2004. The following are significant components of 2005 segment profit:

	•		The reduction in pension costs of $17.1 million to correct a prior period error, as previously discussed;
	•		An increase in Gulfstream equity earnings of $14 million due to the realization of a $4.6 million construction fee award on the completion of the Phase II expansion project coupled with increased revenues associated with the Gulfstream expansions;
	•		Income of $14.2 million from the reversal of the contingency related to recovery of gas costs;
	•		The $17.7 million reversal of prior period accruals;
	•		The increase in costs of $32.1 million due to prior period accounting and valuation corrections related to inventory;

	•		An increase in operating and maintenance expense of $14 million due primarily to increased contract service costs, materials and supplies and rental fees;
	•		A decrease in transportation revenue of $24 million due primarily to the termination of the Grays Harbor contract.

Midstream Gas & Liquids

     Overview of 2006

     Midstream’s ongoing strategy is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. Our business is focused on consistently attracting new business by providing highly reliable service to our customers.

     Significant events during 2006 included the following:

     Favorable commodity price margins

     The actual realized NGL per unit margins at our processing plants exceeded Midstream’s rolling five-year average for the last four quarters. The geographic diversification of Midstream assets contributed significantly to our actual realized unit margins resulting in margins generally greater than that of the industry benchmarks for gas processed in the Henry Hub area and fractionated and sold at Mont Belvieu. The largest impact was realized at our western United States gas processing plants, which benefited from lower regional market natural gas prices. During 2006, NGL production rebounded from levels experienced in fourth-quarter 2005 in response to improved gas processing spreads as crude prices, which correlate to NGL prices, averaged $66 per barrel and natural gas prices decreased.

     Expansion efforts in growth areas

     Consistent with our strategy, we continued to expand our midstream operations where we have large-scale assets in growth basins.

     We continued construction at our existing gas processing plant located near Opal, Wyoming, to add a fifth cryogenic train capable of processing up to 350 MMcf/d, bringing total Opal capacity to approximately

1,450 MMcf/d. This plant expansion is being placed into service during the first quarter of 2007 to begin processing gas from the Pinedale Anticline field.

     Also, we continued construction on a 37-mile extension of our oil and gas pipelines from our Devils Tower spar to the Blind Faith prospect located in Mississippi Canyon. This extension, estimated to cost approximately $200 million, is expected to be ready for service by the second quarter of 2008.

     In May 2006, we entered into an agreement to develop new pipeline capacity for transporting natural gas liquids from production areas in southwestern Wyoming to central Kansas. The other party to the agreement reimbursed us for the development costs we incurred to date for the proposed pipeline and initially will own 99 percent of the pipeline, known as Overland Pass Pipeline Company, LLC. We retained a 1 percent interest and have the option to increase our ownership to 50 percent and become the operator within two years of the pipeline becoming operational. Start-up is planned for early 2008. Additionally, we have agreed to dedicate our equity NGL volumes from our two Wyoming plants for transport under a long-term shipping agreement. The terms represent significant savings compared with the existing tariff and other alternatives considered.

     Williams Partners L.P. acquires Four Corners gathering and processing business

     In June 2006, Williams Partners L.P. acquired 25.1 percent of our interest in Williams Four Corners LLC for $360 million. The acquisition was completed after Williams Partners L.P. closed a $150 million private debt offering of senior unsecured notes due 2011 and an equity offering of approximately $225 million in net proceeds. In December 2006, Williams Partners L.P. acquired the remaining 74.9 percent interest in Williams Four Corners LLC for $1.223 billion. The acquisition was completed after Williams Partners L.P. closed a $600 million private debt offering of senior unsecured notes due 2017, a private equity offering of approximately $350 million of common and Class B units, and a public equity offering of approximately $294 million in net proceeds. Williams Four Corners LLC owns certain gathering, processing and treating assets in the San Juan basin in Colorado and New Mexico.

     We currently own approximately 22.5 percent of Williams Partners L.P., including the interests of the general partner, which is wholly owned by us. Considering the presumption of control of the general partner in accordance with EITF Issue No. 04-5, Williams Partners L.P. is consolidated within the Midstream segment. (See Note 1 of Notes to Consolidated Financial Statements.) Midstream’s segment profit includes 100 percent of Williams Partners L.P.’s segment profit, with the minority interest’s share deducted below segment profit. The debt and equity issued by Williams Partners L.P. is reported as a component of our consolidated debt balance and minority interest balance, respectively.

     Gulf Coast operations return to normal after 2005’s hurricanes

     In 2005, Hurricanes Dennis, Katrina and Rita caused temporary shut-downs of most of our facilities and our producers’ facilities in the Gulf Coast region, which reduced product flows in the second half of 2005. Our major facilities resumed normal operations shortly after the passage of each hurricane except for our Devils Tower spar which returned to service in early November 2005 and our Cameron Meadows gas processing plant which returned to partial service in February 2006 and achieved full service in January 2007. Generally, overall product flows returned to pre-hurricane levels during the first quarter of 2006.

     Gulf Liquids litigation

     We recorded pre-tax charges totaling $94.7 million resulting from jury verdicts in civil litigation. (See Note 15 of Notes to Consolidated Financial Statements.) These charges reflect our estimated exposure for actual damages of $72.7 million, including estimated legal fees of $4.7 million, and potential pre-judgment interest of $22 million. Midstream Other segment profit reflects the $72.7 million charge for the estimated actual damages and legal fees. The matter is related to a contractual dispute surrounding construction in 2000 and 2001 of certain refinery off-gas processing facilities by Gulf Liquids. In addition, it is reasonably possible that any ultimate judgment may include additional amounts of $199 million in excess of our accrual, which represents our estimate of potential punitive damage exposure under Texas law. The jury verdicts are subject to trial and appellate court review. Entry of a

judgment in the trial court is expected in the second or third quarter of 2007. If the trial court enters a judgment consistent with the jury’s verdicts against us, we will seek a reversal through appeal.

     Outlook for 2007

     The following factors could impact our business in 2007 and beyond.

	•		As evidenced in recent years, natural gas and crude oil markets are highly volatile. NGL margins earned at our gas processing plants in the last four quarters were above our rolling five-year average, due to global economics maintaining high crude prices which correlate to strong NGL prices in relationship to natural gas prices. Forecasted domestic demand for ethylene and propylene, whose feedstock are ethane and propane, along with political instability in many of the key oil producing countries will continue to support unit margins in 2007 exceeding our rolling five-year average. We do not expect to achieve the record levels we experienced in 2006.
	•		Margins in our olefins unit are highly dependent upon continued economic growth within the U.S. and any significant slow down in the economy would reduce the demand for the petrochemical products we produce in both Canada and the U.S. Based on recent market price forecasts, we anticipate olefins unit margins to be slightly lower than 2006 levels.
	•		Gathering and processing revenues at our facilities are expected to be at or above levels of previous years due to continued strong drilling activities in our core basins.
	•		Revenues from deepwater production areas are often subject to risks associated with the interruption and timing of product flows which can be influenced by weather and other third-party operational issues.
	•		We will continue to invest in facilities in the growth basins in which we provide services. We expect continued expansion of our gathering and processing systems in our Gulf Coast and West regions to keep pace with increased demand for our services.
	•		We expect continued growth in the deepwater areas of the Gulf of Mexico to contribute to, and become a larger component of, our future segment revenues and segment profit. We expect these additional fee- based revenues to lower our proportionate exposure to commodity price risks. We expect revenues from our deepwater production areas to decrease as volumes decline in 2007 and increase in 2008 as the extension of our oil and gas pipelines from our Devils Tower spar to the Blind Faith prospect is placed into service.
	•		In 2007 we will begin construction on our Perdido Norte project which includes oil and gas lines that expand the scale of our existing infrastructure in the western deepwater of the Gulf of Mexico. Additionally, we will be expanding our Markham gas processing facility to adequately serve this new gas production. The project is estimated to cost approximately $480 million and be in service in the third quarter of 2009.
	•		We are currently negotiating with our customer in Venezuela to resolve approximately $14 million in past due invoices related to labor escalation charges. The customer is not disputing the index used to calculate these charges and we have calculated the charges according to the terms of the contract. The customer does, however, believe the index has resulted in a disproportionate escalation over time. We believe the receivables, net of associated reserves, are fully collectible. Although we believe our negotiations will be successful, failure to resolve this matter could ultimately trigger default noncompliance provisions in the services agreement.
	•		The Venezuelan government continues its public criticism of U.S. economic and political policy, has implemented unilateral changes to existing energy related contracts, continues to publicly declare that additional energy contracts will be unilaterally amended, and that privately held assets will be expropriated, indicating that a level of political risk still remains.

     Year-Over-Year Results

		Years Ended December 31,
		2006				2005				2004
		(Millions)
Segment revenues		$	4,124.7			$	3,232.7			$	2,882.6
Segment profit
Domestic gathering & processing			626.8				379.7				385.8
Venezuela			98.4				94.7				85.6
Other			16.4				42.4				137.9
Indirect general and administrative expense			(70.3	)			(65.5	)			(55.7	)
Total		$	671.3			$	451.3			$	553.6

     In order to provide additional clarity, our management’s discussion and analysis of operating results separately reflects the portion of general and administrative expense not allocated to an asset group as indirect general and administrative expense. These charges represent any overhead cost not directly attributable to one of the specific asset groups noted in this discussion.

     2006 vs. 2005

     The $892.0 million increase in segment revenues is largely due to:

	•		A $561 million increase in crude marketing revenues, which is offset by a similar change in costs, resulting from additional deepwater production coming on-line in November 2005;
	•		A $165 million increase in revenues associated with the production of NGLs, primarily due to higher NGL prices combined with higher volumes;
	•		A $137 million increase in the marketing of NGLs and olefins, which is offset by a similar change in costs;
	•		An $83 million increase in fee-based revenues including $52 million in higher production handling revenues;
	•		A $44 million increase in revenues in our olefins unit due to higher volumes.

     These increases were partially offset by an $84 million reduction in NGL revenues due to a change in classification of NGL transportation and fractionation expenses from costs of goods sold to net revenues (offset in costs and operating expenses).

     Segment costs and expenses increased $707.3 million primarily as a result of:

	•		A $561 million increase in crude marketing purchases, which is offset by a similar change in revenues;
	•		A $137 million increase in NGL and olefins marketing purchases, offset by a similar change in revenues;
	•		An $82 million increase in operating expenses including a $10.6 million accounts payable accrual adjustment, higher system losses, depreciation, insurance expense, personnel and related benefit expenses, turbine overhauls, materials and supplies, compression and post-hurricane inspection and survey costs required by a government agency;
	•		A $59 million increase in other expense including the $68 million estimated exposure for actual damages for the Gulf Liquids litigation, partially offset by a $9 million favorable settlement of a contract dispute;
	•		A $20 million increase in costs associated with production in our olefins unit.

These increases were partially offset by:

	•		An $84 million reduction in NGL transportation and fractionation expenses due to the above-noted change in classification (offset in revenues);
	•		A $77 million decrease in plant fuel and costs associated with the production of NGLs due primarily to lower gas prices.

     The $220 million increase in Midstream segment profit is primarily due to higher NGL margins, higher deepwater production handling revenues, higher gathering and processing revenues, higher margins from our olefins unit, a settlement of an international contract dispute, and the absence of a $23 million impairment of our equity investment in Aux Sable Liquid Products L.P. (Aux Sable) recorded in 2005. These increases were largely offset by the $72.7 million charge related to the Gulf Liquids litigation contingency combined with higher operating costs and lower margins related to the marketing of olefins and NGLs. A more detailed analysis of the segment profit of Midstream’s various operations is presented as follows.

     Domestic gathering & processing

     The $247.1 million increase in domestic gathering and processing segment profit includes a $143 million increase in the West region and a $104 million increase in the Gulf Coast region.

     The $143 million increase in our West region’s segment profit primarily results from higher product margins and higher gathering and processing revenues, partially offset by higher operating expenses. The significant components of this increase include the following:

	•		NGL margins increased $166 million compared to 2005. This increase was driven by a decrease in costs associated with the production of NGLs, an increase in average per unit NGL prices and higher volumes resulting from lower NGL recoveries during the fourth quarter of 2005 caused by intermittent periods of uneconomical market commodity prices and a power outage and associated operational issues at our Opal, Wyoming facility. NGL margins are defined as NGL revenues less BTU replacement cost, plant fuel, transportation and fractionation expense.
	•		Gathering and processing fee revenues increased $26 million. Gathering fees are higher as a result of higher average per-unit gathering rates. Processing volumes are higher due to customers electing to take liquids and pay processing fees.
	•		Operating expenses increased $51 million including $11 million in higher net system product losses as a result of system gains in 2005 compared to losses in 2006, a $7 million accounts payable accrual adjustment; $8 million in higher personnel and related benefit expenses; $6 million in higher materials and supplies; $6 million in higher gathering fuel, $4 million in higher leased compression costs; $4 million in higher turbine overhaul costs; and $4 million in higher depreciation.

     The $104 million increase in the Gulf Coast region’s segment profit is primarily a result of higher NGL margins, higher volumes from our deepwater facilities, partially offset by higher operating expenses. The significant components of this increase include the following:

	•		NGL margins increased $77 million compared to 2005. This increase was driven by an increase in average per unit NGL prices and a decrease in costs associated with the production of NGLs.
	•		Fee revenues from our deepwater assets increased $52 million as a result of $51 million in higher volumes flowing across the Devils Tower facility and $22 million in higher Devils Tower unit-of-production rates recognized as a result of a new reserve study. These increases are partially offset by a $21 million decline in other gathering and production handling revenues due to volume declines in other areas.

•

Operating expenses increased $25 million primarily as a result of $12 million in higher insurance costs, $4 million in higher depreciation expense on our deepwater assets, $3 million in higher net system product losses as a result of lower gain volumes in 2006, $2 million in post-hurricane inspection and survey costs required by a government agency, and a $1 million accounts payable accrual adjustment.

     Venezuela

     Segment profit for our Venezuela assets increased $3.7 million and includes $9 million resulting from the settlement of a contract dispute and $1 million in higher revenues due to higher natural gas volumes and prices at our compression facility. These are partially offset by $4 million in higher expenses related to higher insurance, personnel and contract labor costs and a $2 million increase in the reserve for uncollectible accounts.

     Other

     The $26 million decrease in segment profit of our other operations is largely due to the $72.7 million of charges related to the Gulf Liquids litigation contingency combined with $13 million in lower margins related to the marketing of olefins. The decrease also reflects $12 million in lower margins related to the marketing of NGLs due to more favorable changes in pricing while product was in transit during 2005 as compared to 2006. These were partially offset by the absence of a $23 million impairment of our equity investment in Aux Sable in 2005, $24 million in higher margins in our olefins unit, $7 million in higher earnings from our equity investment in Discovery Producer Services, L.L.C. (Discovery), $7 million in higher fractionation, storage and other fee revenues, and a $4 million favorable transportation settlement.

     2005 vs. 2004

     The $350.1 million increase in segment revenues is largely due to:

	•		A $196 million increase in crude marketing revenues, which is offset by a similar change in costs, resulting from the start up of a deepwater pipeline in the second quarter of 2004;
	•		A $72 million increase in revenues associated with production of NGLs, primarily due to $180 million in higher NGL prices partially offset by $108 million in lower sales volumes. The decline in sales volumes in our Gulf Coast region is largely due to the impact of summer hurricanes, while the decline in the West region is largely due to the higher levels of NGL rejection as well as maintenance issues with our gas processing facility at Opal, Wyoming;
	•		A $58 million increase in the marketing of NGLs, which is offset by a similar change in costs, resulting from higher prices and additional spot sales;
	•		A $21 million increase in fee-based revenues in part due to higher customer production volumes flowing to our West region and deepwater assets.

     Costs and operating expenses increased $364.1 million primarily as a result of:

	•		A $196 million increase in crude marketing purchases, which is offset by a similar change in revenues;
	•		A $92 million increase in costs related to the production of NGLs as a result of $100 million in higher natural gas purchases due largely to higher prices, partially offset by lower volumes;
	•		A $58 million increase related to the marketing of NGLs and additional spot purchases, which is offset by a similar change in revenues;
	•		A $33 million increase in operating expenses mostly due to higher fuel expense and commodity costs associated with our NGL storage and fractionation business and higher depreciation expense.

     The $102.3 million decline in Midstream segment profit is primarily due to the absence of the $93.6 million gain from the Gulf Liquids’ insurance arbitration award in 2004 and a $23 million impairment of our equity investment in Aux Sable in 2005. The offsetting increase in segment profit is primarily due to higher fee revenues from our domestic gathering and processing and Venezuela businesses and higher earnings from our investment in the Discovery partnership, partially offset by lower NGL margins and higher operating costs. A more detailed analysis of the segment profit of Midstream’s various operations is presented below.

     Domestic gathering & processing

     The $6.1 million decrease in domestic gathering and processing segment profit includes a $30 million decline in the Gulf Coast region, largely offset by a $24 million increase in the West region.

     The $24 million increase in our West region’s segment profit primarily results from higher gathering and processing fee revenues, and the absence of an asset write-down and other 2004 charges, offset partially by higher operating expenses and lower NGL margins. The significant drivers to these items are as follows:

	•		Gathering and processing fee revenues increased $18 million primarily as a result of higher average per-unit gathering and processing rates and higher volumes in the Rocky Mountain production area due to increased drilling activity. A portion of this increase is also due to the increase in volumes subject to fee-based processing contracts.
	•		A favorable variance due to the absence of the write-down of $7.6 million for an idle treating facility in 2004.
	•		NGL margins decreased $6 million due to a $17 million impact from lower sales volumes resulting from lower fourth quarter 2005 NGL recoveries caused by intermittent periods of uneconomical market commodity prices and a power outage and associated operational issues at our Opal, Wyoming facility. NGL margins are defined as NGL revenues less BTU replacement cost, plant fuel, transportation and fractionation expense. The impact of lower volumes is partially offset by an $11 million impact of higher per unit NGL margins.

     The $30 million decrease in the Gulf Coast region’s segment profit is primarily a result of higher operating and depreciation expenses and lower NGL margins. The significant components of this decline include the following:

	•		Operating expenses increased $10 million primarily due to higher maintenance expenses related to our gathering assets, compressor overhauls, and an increase in hurricane-related costs of $2 million. Inspection and repair expenses related to the hurricanes were recorded as incurred up to the level of our insurance deductible.
	•		Depreciation expense increased $13 million primarily due to placing in service our Devils Tower spar and associated deepwater gas and oil pipelines in May and June 2004, respectively.
	•		NGL margins declined $14 million due to lower volumes, largely due to the impact of summer hurricanes, and the increase in natural gas prices. While revenues from the Devils Tower deepwater facility are recognized as volumes are delivered over the life of the reserves, cash payments from our customers are based on a contractual fixed fee received over a defined term. As a result, $44 million of cash received in 2005, which is included in cash flow from operations, was deferred at December 31, 2005 and will be recognized as revenue in periods subsequent to 2005. The total amount deferred for all years as of December 31, 2005 was $80 million.

     Venezuela

     Segment profit for our Venezuela assets increased $9.1 million as a result of higher plant volumes and higher equity earnings from our investment in the ACCROVEN partnership. The higher equity earnings are largely due to the renegotiation of a power supply contract and the absence of 2004 legal fees associated with the Jose Terminal.

     Other

     The $95.5 million decrease in segment profit of our other operations is largely due to the absence of the $93.6 million gain from the Gulf Liquids’ insurance arbitration award in 2004, a $23 million impairment of our equity investment in Aux Sable in 2005, and a $9.5 million gain on the sale of the Choctaw ethylene distribution assets in 2004. Partially offsetting these decreases were $7 million in higher olefins and commodity margins, $6 million in higher earnings from our equity investment in the Discovery partnership, and the absence of a 2004 $16.9 million impairment charge also related to our equity investment in the Discovery partnership.

     Indirect general and administrative expense

     The $9.8 million unfavorable variance for our indirect general and administrative expenses is primarily due to higher employee expenses and administrative costs associated with the creation of Williams Partners L.P.

Gas Marketing Services

     Gas Marketing Services (Gas Marketing) primarily supports our natural gas businesses by providing marketing and risk management services, which include marketing and hedging the gas produced by Exploration & Production and procuring fuel and shrink gas for Midstream. In addition, Gas Marketing manages various natural gas-related contracts such as transportation, storage, and related hedges, which were part of our former Power segment, including certain legacy natural gas contracts and positions.

Overview of 2006

     Gas Marketing’s operating results for 2006 reflect unrealized mark-to-market losses primarily caused by a decrease in forward natural gas prices against a net long derivative legacy position. Most of these derivative positions are economic hedges but are not designated as hedges for accounting purposes or do not qualify for hedge accounting.

Outlook for 2007

     For 2007, Gas Marketing intends to focus on providing services that support our natural gas businesses. Certain legacy natural gas contracts and positions from our former Power segment are included in the Gas Marketing segment. We intend to manage or liquidate a substantial portion of these legacy contracts in order to reduce risk and volatility.

     Until such legacy positions are liquidated, Gas Marketing’s earnings may continue to reflect mark-to-market volatility from commodity-based derivatives that represent economic hedges but do not qualify for hedge accounting or are not designated as hedges for accounting purposes.

Year-Over-Year Results

		Years Ended December 31,
		2006				2005				2004
		(Millions)
Realized revenues		$	5,184.3			$	6,146.7			$	4,991.3
Net forward unrealized mark-to-market gains (losses)			(135.7	)			188.3				217.0
Segment revenues			5,048.6				6,335.0				5,208.3
Costs and operating expenses			5,257.5				6,237.6				5,043.2
Gross margin			(208.9	)			97.4				165.1
Selling, general and administrative (income) expense			(12.7	)			(.5	)			7.8
Other (income) expense — net			(1.4	)			88.8				3.9
Segment profit (loss)		$	(194.8	)		$	9.1			$	153.4

     2006 vs. 2005

     Realized revenues represent (1) revenue from the sale of natural gas or completion of energy-related services and (2) gains and losses from the net financial settlement of derivative contracts. Realized revenues decreased $962.4 million primarily due to a 17 percent decrease in average natural gas sales prices.

     Net forward unrealized mark-to-market gains (losses) primarily represent changes in the fair values of certain legacy derivative contracts with a future settlement or delivery date that are not designated as hedges for accounting purposes or do not qualify for hedge accounting. The effect of a change in forward prices on legacy natural gas derivative contracts primarily caused the $324 million unfavorable change in net forward unrealized mark-to-market gains (losses). A decrease in forward natural gas prices during 2006 caused losses on legacy net forward gas fixed-price purchase contracts, while an increase in forward natural gas prices during 2005 caused gains on legacy net forward gas fixed-price purchase contracts.

     The $980.1 million decrease in Gas Marketing’s costs and operating expenses is primarily due to an 18 percent decrease in average natural gas purchase prices.

     The favorable change in selling, general and administrative (income) expense is due primarily to increased gains from the sale of certain receivables to a third party. Gas Marketing recognized a $24.8 million gain in 2006 compared to a $9.7 million gain in 2005.

     Other (income) expense — net in 2005 includes an $82.2 million accrual for estimated litigation contingencies, primarily associated with agreements reached to substantially resolve exposure related to natural gas price and volume reporting issues (see Note 15 of Notes to Consolidated Financial Statements) and a $4.6 million accrual for a regulatory settlement.

     The $203.9 million change from a segment profit to a segment loss is primarily due to the effect of a change in forward prices on legacy natural gas derivative contracts, partially offset by favorable changes in other (income) expense—net described above.

     2005 vs. 2004

     The $1.2 billion increase in realized revenues is primarily due to a 33 percent increase in average natural gas sales prices. Hurricane Katrina, among other factors, contributed to the increase in prices.

     A change in notional volumes on legacy natural gas derivative contracts, partially offset by the effect of a change in forward prices, primarily caused the $28.7 million decrease in net forward unrealized mark-to-market gains (losses). The effect of a greater increase in forward natural gas prices on a lower notional volume of net forward gas fixed-price purchase contracts in 2005 compared to 2004 resulted in decreased unrealized mark-to-market gains. Also in 2005, Gas Marketing recognized losses of $6.8 million representing a correction of unrealized losses associated with a prior year. Our management concluded that the effects of this correction are not material to prior periods, 2005 results, or our trend of earnings.

     The $1.2 billion increase in Gas Marketing’s costs and operating expenses is primarily due to a 44 percent increase in average natural gas purchase prices. Hurricane Katrina, among other factors, contributed to the increase in prices.

     The favorable change in selling, general and administrative (income) expense is primarily due to decreased employee incentive compensation and decreased costs for outside services. A $9.7 million reduction of allowance for bad debts resulting from the sale of certain receivables to a third party also contributed to the favorable change in SG&A (income) expense. SG&A (income) expense in 2004 includes a $6.3 million reduction of allowance for bad debts resulting from a 2004 settlement with certain California utilities.

     Other (income) expense — net in 2005 includes an $82.2 million accrual for estimated litigation contingencies as previously discussed. Other (income) expense — net in 2004 includes $6.1 million in fees paid related to the sale of certain receivables to a third party.

     The $144.3 million decrease in segment profit is primarily due to accruals in 2005 for litigation contingencies. In addition, the unfavorable changes in gross margin contributed to the decrease as well.

Other

     Overview of 2006

     While we continue to have an equity ownership interest in Longhorn, the management of Longhorn completed an asset sale of the pipeline during the third quarter of 2006. As a result, we received full payment of the $10 million secured bridge loan that we provided Longhorn during 2005. The carrying value of our equity investment in Longhorn is zero as of December 31, 2006.

     We continue to receive payments associated with the 2005 transfer of the Longhorn operating agreement to a third party. These payments totaled approximately $3.3 million for the year ended December 31, 2006. Any ongoing payments received or through monetization of the contract will be recognized as income when received. These ongoing payments were not impacted by the sale of the pipeline.

     Our natural gas-fired electric generating plant near Bloomfield, New Mexico (Milagro facility), is now reported within the Other segment. (See Note 2 of Notes to Consolidated Financial Statements.)

     Year-Over-Year Operating Results

		Years Ended December 31,
		2006				2005				2004
		(Millions)
Segment revenues		$	61.0			$	85.5			$	51.1
Segment loss		$	(9.1	)		$	(113.9	)		$	(54.1	)

     2006 vs. 2005

     Other segment loss for 2006 includes $3.3 million in payments received related to the 2005 transfer of the Longhorn operating agreement.

     Other segment loss for 2005 includes $87.2 million of impairment charges, of which $38.1 million was recorded during the fourth quarter, related to our investment in Longhorn. In a related matter, we wrote off $4 million of capitalized project costs associated with Longhorn. We also recorded $23.7 million of equity losses associated with our investment in Longhorn. Partially offsetting these charges and losses was a $9 million fourth quarter gain on the sale of land.

     2005 vs. 2004

     Other segment loss for 2005 includes various items which are discussed above.

     Other segment loss for 2004 includes $11.8 million of accrued environmental remediation expense associated with the Augusta refinery. Also included in Other segment loss is $10.8 million of impairment charges related to our investment in Longhorn, $9.8 million of equity losses associated with our investment in Longhorn, and $6.5 million of net unreimbursed advisory fees related to the recapitalization of Longhorn.

Energy Trading Activities

     Fair Value of Trading and Nontrading Derivatives

     The chart below reflects the fair value of derivatives held for trading purposes as of December 31, 2006. We have presented the fair value of assets and liabilities by the period in which they would be realized under their contractual terms and not as a result of a sale. We have reported the fair value of a portion of these derivatives in assets and liabilities of discontinued operations. (See Note 2 of Notes to Consolidated Financial Statements.)

Net Assets (Liabilities) — Trading
(Millions)

To be		To be		To be		To be		To be
Realized in		Realized in		Realized in		Realized in		Realized in
1-12 Months		13-36 Months		37-60 Months		61-120 Months		121+ Months		Net
(Year 1)		(Years 2-3)		(Years 4-5)		(Years 6-10)		(Years 11+)		Fair Value
$3		$ —		$ —		$ —		$ —		$3

     As the table above illustrates, we are not materially engaged in trading activities. However, we hold a substantial portfolio of nontrading derivative contracts. Nontrading derivative contracts are those that hedge or could possibly hedge forecasted transactions on an economic basis. We have designated certain of these contracts as cash flow hedges of Exploration & Production’s forecasted sales of natural gas production and certain forecasted purchases of gas and purchases and sales of power related to our former Power segment’s long-term structured contracts and owned generation under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). Of the total fair value of nontrading derivatives, SFAS 133 cash flow hedges had a net asset value of $360 million as of December 31, 2006, which includes the existing fair value of the derivatives at the time of their designation as SFAS 133 cash flow hedges. The chart below reflects the fair value of derivatives held for nontrading purposes as of December 31, 2006, for Gas Marketing Services, Exploration & Production, Midstream, Other, and nontrading derivatives reported in assets and liabilities of discontinued operations.

Net Assets (Liabilities) — Nontrading
(Millions)

To be		To be		To be		To be		To be
Realized in		Realized in		Realized in		Realized in		Realized in
1-12 Months		13-36 Months		37-60 Months		61-120 Months		121+ Months		Net
(Year 1)		(Years 2-3)		(Years 4-5)		(Years 6-10)		(Years 11+)		Fair Value
$94		$227		$88		$24		$ —		$433

     Methods of Estimating Fair Value

     Most of the derivatives we hold settle in active periods and markets in which quoted market prices are available. These include futures contracts, option contracts, swap agreements and physical commodity purchases and sales in the commodity markets in which we transact. While an active market may not exist for the entire period, quoted prices can generally be obtained for natural gas through 2012 and power through 2011.

     These prices reflect current economic and regulatory conditions and may change because of market conditions. The availability of quoted market prices in active markets varies between periods and commodities based upon changes in market conditions. The ability to obtain quoted market prices also varies greatly from region to region. The time periods noted above are an estimation of aggregate availability of quoted prices. An immaterial portion of our total net derivative value of $436 million relates to periods in which active quotes cannot be obtained. We estimate energy commodity prices in these illiquid periods by incorporating information about commodity prices in actively quoted markets, quoted prices in less active markets, and other market fundamental analysis. Modeling and other valuation techniques, however, are not used significantly in determining the fair value of our derivatives.

     Counterparty Credit Considerations

     We include an assessment of the risk of counterparty nonperformance in our estimate of fair value for all contracts. Such assessment considers (1) the credit rating of each counterparty as represented by public rating agencies such as Standard & Poor’s and Moody’s Investors Service, (2) the inherent default probabilities within these ratings, (3) the regulatory environment that the contract is subject to and (4) the terms of each individual contract.

     Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. We continually assess this risk. We have credit protection within various agreements to call on additional collateral support if necessary. At December 31, 2006, we held collateral support, including letters of credit, of $695 million.

     We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2006 and 2005, we did not incur any significant losses due to recent counterparty bankruptcy filings.

     The gross credit exposure from our derivative contracts, a portion of which is included in assets of discontinued operations (see Note 2 of Notes to Consolidated Financial Statements), as of December 31, 2006, is summarized below.

		Investment
Counterparty Type		Grade(a)				Total
		(Millions)
Gas and electric utilities		$	248.0			$	249.9
Energy marketers and traders			412.7				1,784.3
Financial institutions			2,219.4				2,219.4
Other			23.3				29.8
		$	2,903.4				4,283.4
Credit reserves							(20.3	)
Gross credit exposure from derivatives						$	4,263.1

     We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts. The net credit exposure from our derivatives as of December 31, 2006, is summarized below.

		Investment
Counterparty Type		Grade(a)				Total
		(Millions)
Gas and electric utilities		$	120.4			$	120.5
Energy marketers and traders			209.0				455.4
Financial institutions			325.5				325.5
Other			20.4				20.4
		$	675.3				921.8
Credit reserves							(20.3	)
Net credit exposure from derivatives						$	901.5

     Trading Policy

     We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations. Value-at-risk is limited in aggregate and calculated at a 95 percent confidence level.

Management’s Discussion and Analysis of Financial Condition

     Outlook

     We believe we have, or have access to, the financial resources and liquidity necessary to meet future requirements for working capital, capital and investment expenditures and debt payments while maintaining a sufficient level of liquidity to reasonably protect against unforeseen circumstances requiring the use of funds. In 2007, we expect to maintain liquidity from cash and cash equivalents and unused revolving credit facilities of at least $1 billion. We maintain adequate liquidity to manage margin requirements related to significant movements in commodity prices, unplanned capital spending needs, near term scheduled debt payments, and litigation and other settlements. We expect to fund capital and investment expenditures, debt payments, dividends, and working capital requirements through cash flow from operations, which is currently estimated to be between $2 billion and $2.3 billion in 2007, proceeds from debt issuances and sales of units of Williams Partners L.P., as well as cash and cash equivalents on hand as needed.

     We enter 2007 positioned for growth through disciplined investments in our natural gas businesses. Examples of this planned growth include:

	•		Exploration & Production will continue to maintain its development drilling program in its key basins of Piceance, Powder River, San Juan, Arkoma, and Fort Worth. During 2006, all ten state-of-the-art FlexRig4® drilling rigs were placed in service in the Piceance basin pursuant to our March 2005 contract with Helmerich & Payne. Each rig is leased for three years.
	•		Gas Pipeline will continue to expand its system to meet the demand of growth markets.
	•		Midstream will continue to pursue significant deepwater production commitments and expand capacity in the western United States.

     We estimate capital and investment expenditures will total approximately $2.2 billion to $2.4 billion in 2007. As a result of increasing our development drilling program, $1.3 billion to $1.4 billion of the total estimated 2007 capital expenditures is related to Exploration & Production. Also within the total estimated expenditures for 2007 is approximately $215 million to $270 million for maintenance-related projects at Gas Pipeline, including pipeline replacement and Clean Air Act compliance. Commitments for construction and acquisition of property, plant and equipment are approximately $406 million at December 31, 2006.

     Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:

	•		Lower than expected levels of cash flow from operations due to commodity pricing volatility. To mitigate this exposure, Exploration & Production has economically hedged the price of natural gas for approximately 172 MMcfe per day of its expected 2007 production. In addition, Exploration & Production has collar agreements for each month of 2007 which hedge approximately 270 MMcfe per day of expected 2007 production. Also, our former power business has entered into various sales contracts that economically cover substantially all of its fixed demand obligations through 2010. These sales contracts and related fixed demand obligations are included in the anticipated sale of substantially all of our power business.
	•		Sensitivity of margin requirements associated with our marginable commodity contracts. As of December 31, 2006, we estimate our exposure to additional margin requirements through 2007 to be no more than $521 million, using a statistical analysis at a 99 percent confidence level.
	•		Exposure associated with our efforts to resolve regulatory and litigation issues (see Note 15 of Notes to Consolidated Financial Statements).

     In August 2006, the Pension Protection Act of 2006 was signed into law. The Act makes significant changes to the requirements for employer-sponsored retirement plans, including revisions affecting the funding of defined benefit pension plans beginning in 2008. We are assessing the impact of the legislation on our future funding

requirements, but do not expect a significant increase in required contributions over current levels, assuming long-term rates of return on assets and current discount rates do not experience a significant decline.

     Overview

     In November 2005, we initiated an offer to induce conversion of up to $300 million of the 5.5 percent junior subordinated convertible debentures into our common stock. The conversion was executed in January 2006 and approximately $220.2 million of the debentures were exchanged for common stock. We paid $25.8 million in premiums that are included in early debt retirement costs in the Consolidated Statement of Income. See Note 12 of Notes to Consolidated Financial Statements for further information.

     In April 2006, Transco issued $200 million aggregate principal amount of 6.4 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement to fund general corporate expenses and capital expenditures. In October 2006, Transco completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

     In April 2006, we retired a secured floating-rate term loan for $488.9 million, including outstanding principal and accrued interest. The loan was due in 2008 and secured by substantially all of the assets of Williams Production RMT Company. The loan was retired using a combination of cash and revolving credit borrowings.

     In May 2006, we replaced our $1.275 billion secured revolving credit facility with a $1.5 billion unsecured revolving credit facility. The new facility contains similar terms and financial covenants as the secured facility, but contains certain additional restrictions. (See Note 11 of Notes to Consolidated Financial Statements.)

     In June 2006, Northwest Pipeline issued $175 million aggregate principal amount of 7 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement to fund general corporate expenses and capital expenditures. In October 2006, Northwest Pipeline completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

     In June 2006, we reached an agreement-in-principle to settle class-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000 and July 22, 2002, for a total payment of $290 million to plaintiffs. On February 9, 2007, the court gave its final approval of the settlement. We recorded a pre-tax charge for approximately $161 million in second quarter 2006. Our portion of the total payment was $145 million.

     On June 1, 2006, the FERC entered its final order (FERC Final Order) concerning the Trans-Alaska Pipeline System (TAPS) Quality Bank litigation. The Quality Bank Administrator will determine and invoice for amounts due based on the FERC Final Order, subject to the final disposition of the FERC Final Order appeals. We estimate that our net obligation could be as much as $116 million. (See Note 15 of Notes to Consolidated Financial Statements.)

     In June 2006, Williams Partners L.P. acquired 25.1 percent of our interest in Williams Four Corners LLC for $360 million. The acquisition was completed after Williams Partners L.P. successfully closed a $150 million private debt offering of 7.5 percent senior unsecured notes due 2011 and an equity offering of approximately $225 million in net proceeds. In December 2006, Williams Partners L.P. acquired the remaining 74.9 percent interest in Williams Four Corners LLC for $1.223 billion. The acquisition was completed after Williams Partners L.P. successfully closed a $600 million private debt offering of 7.25 percent senior unsecured notes due 2017, a private equity offering of approximately $350 million of common and Class B units, and a public equity offering of approximately $294 million in net proceeds. The debt and equity issued by Williams Partners L.P. is reported as a component of our consolidated debt balance and minority interest balance, respectively. Williams Four Corners LLC owns certain gathering, processing and treating assets in the San Juan Basin in Colorado and New Mexico.

     Exploration & Production has recently 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. Margin requirements, if any, under this new facility are dependent on the level of hedging and on natural gas reserves value.

     Credit ratings

     On May 4, 2006, Standard & Poor’s raised our senior unsecured debt rating from a B+ to a BB- with a positive ratings outlook. With respect to Standard & Poor’s, a rating of “BBB” or above indicates an investment grade rating.

A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard & Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard & Poor’s may modify it’s ratings with a “+” or a “—” sign to show the obligor’s relative standing within a major rating category.

     On June 7, 2006, Moody’s Investors Service raised our senior unsecured debt rating from a B1 to a Ba2 with a stable ratings outlook. With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. A “Ba” rating indicates an obligation that is judged to have speculative elements and is subject to substantial credit risk. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” ranking at the lower end of the category.

     On May 15, 2006, Fitch Ratings raised our senior unsecured rating from BB to BB+ with a stable ratings outlook. With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from Fitch indicates that there is a possibility of credit risk developing, particularly as the result of adverse economic change over time; however, business or financial alternatives may be available to allow financial commitments to be met. Fitch may add a “+” or a “—” sign to show the obligor’s relative standing within a major rating category.

     Our goal is to attain investment grade ratios at some point in the future.

     Liquidity

     Our internal and external sources of liquidity include cash generated from our operations, bank financings, and proceeds from the issuance of long-term debt and equity securities, and proceeds from asset sales. While most of our sources are available to us at the parent level, others are available to certain of our subsidiaries, including equity and debt issuances from Williams Partners L.P. Our ability to raise funds in the capital markets will be impacted by our financial condition, interest rates, market conditions, and industry conditions.

Available Liquidity

		Year Ended
		December 31, 2006
		(Millions)
Cash and cash equivalents*		$	2,268.6
Auction rate securities and other liquid securities			103.2
Available capacity under our four unsecured revolving and letter of credit facilities totaling $1.2 billion			304.9
Available capacity under our $1.5 billion unsecured revolving and letter of credit facility**			1,471.2
		$	4,147.9

     In addition to the above, Northwest Pipeline and Transco have shelf registration statements available for the issuance of up to $350 million aggregate principal amount of debt securities. The ability of Northwest Pipeline to utilize their registration statement to issue debt securities is restricted by certain covenants of its debt agreements. If the credit rating of Northwest Pipeline or Transco is below investment grade, they can only use their shelf registration statements to issue debt if such debt is guaranteed by us.

     Williams Partners L.P. has a shelf registration statement available for the issuance of approximately $1.2 billion aggregate principal amount of debt and limited partnership unit securities.

     In addition, at the parent-company level, we have a shelf registration statement that allows us to issue publicly registered debt and equity securities as needed. This registration statement, filed May 19, 2006, replaces our previously filed shelf registration.

     Sources (Uses) of Cash

		Years Ended December 31,
		2006				2005				2004
		(Millions)
Net cash provided (used) by:
Operating activities		$	1,889.6			$	1,449.9			$	1,487.9
Financing activities			1,103.2				36.5				(3,505.5	)
Investing activities			(2,321.4	)			(819.2	)			629.4
Increase (decrease) in cash and cash equivalents		$	671.4			$	667.2			$	(1,388.2	)

     Operating Activities

     Our net cash provided by operating activities in 2006 increased from 2005 due largely to higher operating income at Midstream, partially offset by a $145 million securities litigation settlement payment in fourth quarter 2006.

     Our 2005 net cash provided by operating activities decreased slightly from 2004. A primary driver in net cash provided by operating activities is income from continuing operations, which increased primarily as a result of higher gas production volumes and net average realized prices for production sold. Also contributing to the increase in income from continuing operations is the reduction in interest expense due to lower average borrowing levels. Cash payments for interest decreased $224 million from 2004. In addition to the changes in results of operations, net cash inflows from margin deposits and customer margin deposits payable decreased significantly from 2004. In 2004, our former power business issued a significant number of letters of credit to replace its cash margin deposits. As the letters of credit were issued, the counterparties returned our cash margin deposits to us. Due to fewer letters of credit being issued to replace cash margin deposits in 2005, we have fewer receipts of margin deposits than in 2004.

     Other, including changes in noncurrent assets and liabilities, includes contributions to our tax-qualified pension plans of $42.1 million in 2006, $52.1 million in 2005 and $136.8 million in 2004. It is our policy to make annual contributions to our tax-qualified pension plans in an amount at least equal to the greater of the actuarially computed annual normal cost plus any unfunded actuarial accrued liability, amortized over approximately five years, or the minimum required contribution under existing laws. Additional amounts may be contributed to increase the funded status of the plans. In an effort to strengthen our funded status and take advantage of strong cash flows, we contributed approximately $26.5 million, $41.1 million and $98.9 million more than our funding policy required in 2006, 2005 and 2004, respectively.

     Financing Activities

     During the first quarter of 2006, we paid $25.8 million in premiums for early debt retirement costs relating to the debt conversion previously discussed.

     See Overview, within this section, for a discussion of 2006 debt issuances, debt retirement, and additional financing by Williams Partners L.P.

     During January 2005, we retired $200 million of 6.125 percent notes issued by Transco, which matured January 15, 2005. In the first quarter of 2005, we received approximately $273 million in proceeds from the issuance of common stock purchased under the FELINE PACS equity forward contracts. During August 2005, we completed an initial public offering of approximately 40 percent of our interest in Williams Partners L.P. resulting in net proceeds of $111 million.

     During 2004, we repaid long-term debt through tender offers and early retirements. We also reduced our debt through our FELINE PACS exchange. This noncash exchange resulted in payments of fees and expenses reported as premiums paid on tender offer, early debt retirements and FELINE PACS exchange.

     Quarterly dividends paid on common stock increased from 7.5 cents to 9 cents per common share during the second quarter of 2006 and totaled $206.6 million for year ended December 31, 2006. For the fourth quarter of 2005, dividends paid on common stock were 7.5 cents per share and totaled $143 million for the year ended December 31, 2005.

     Investing Activities

     During 2006, capital expenditures totaled $2,509.2 million and were primarily related to Exploration & Production’s increased drilling activity, mostly in the Piceance basin, and Northwest Pipeline’s capacity replacement project.

     During 2006, we purchased $386.3 million and received $414.1 million from the sale of auction rate securities. These instruments are utilized as a component of our overall cash management program.

     In January 2005, Northwest Pipeline received an $87.9 million contract termination payment, representing reimbursement of the net book value of the related assets.

     In January 2005, we received approximately $54.7 million proceeds from the sale of our note with Williams Communications Group, our previously owned subsidiary (WilTel).

     During 2005, we received $310.5 million in proceeds from the Gulfstream recapitalization.

     In 2004, we sold all of our restricted investments resulting in proceeds of $851.4 million. When our $800 million revolving and letter of credit facility that required 105 percent cash collateral was replaced with a new revolving credit facility in January 2005, we were no longer required to hold the restricted investments.

     In 2004, we had numerous asset sales resulting in proceeds in 2004 of $877.8 million.

Off-balance sheet financing arrangements and guarantees of debt or other commitments

     In January 2005, we terminated our two unsecured revolving and letter of credit facilities totaling $500 million and replaced them with two new facilities that contain similar terms but fewer restrictions. In September 2005, we also entered into two new revolving and letter of credit facilities that have a similar structure. (See Note 11 of Notes to Consolidated Financial Statements.)

     We have provided a guarantee for obligations of Williams Partners L.P. under the $1.5 billion unsecured revolving and letter of credit facility.

     We have various other guarantees and commitments which are disclosed in Notes 2, 3, 10, 11, 14, and 15 of Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible fulfillment of them will prevent us from meeting our liquidity needs.

     Contractual Obligations

     The table below summarizes the maturity dates of our contractual obligations, including obligations related to discontinued operations.

						2008-				2010-
		2007				2009				2011				Thereafter				Total
		(Millions)
Long-term debt, including current portion:
Principal		$	391			$	291			$	1,385			$	5,974			$	8,041
Interest			606				1,147				1,083				5,713				8,549
Capital leases			2				3				—				—				5
Operating leases (1)			227				433				366				1,121				2,147
Purchase obligations:
Fuel conversion and other service contracts (2) (5)			249				505				495				2,377				3,626
Other (5) (6)			877				1,134				1,144				2,943	(4)			6,098
Other long-term liabilities, including current portion:
Physical and financial derivatives (3) (5)			628				392				204				304				1,528
Other (7)			72				31				16				—				119
Total		$	3,052			$	3,936			$	4,693			$	18,432			$	30,113

     Contractual obligations related to discontinued operations included in the table above are as follows:

						2008-				2010-
		2007				2009				2011				Thereafter				Total
		(Millions)
Operating leases (1)		$	158			$	321			$	326			$	1,080			$	1,885
Purchase obligations:
Fuel conversion and other service contracts (2) (5)			249				505				495				2,377				3,626
Other			1				3				3				10				17
Other long-term liabilities, including current portion:
Physical and financial derivatives (3) (5)			181				63				18				10				272
Total		$	589			$	892			$	842			$	3,477			$	5,800

Effects of Inflation

     Our operations in recent years have benefited from relatively low inflation rates. Approximately 46 percent of our gross property, plant and equipment is at Gas Pipeline and the remainder is at other operating units. Gas Pipeline is subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulation, along with competition and other market factors, may limit our ability to recover such increased costs. For the other operating units, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in oil and natural gas and related commodities than by changes in general inflation. Crude, refined product, natural gas, natural gas liquids and power prices are particularly sensitive to OPEC production levels and/or the market perceptions concerning the supply and demand balance in the near future. However, our exposure to these price changes is reduced through the use of hedging instruments.

Environmental

     We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and/or remedial processes at certain sites, some of which we currently do not own. (See Note 15 of Notes to Consolidated Financial Statements.) We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $52 million, all of which are recorded as liabilities on our balance sheet at December 31, 2006. We will seek recovery of approximately $11 million of the accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2006, we paid approximately $12 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $17 million in 2007 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. At December 31, 2006, certain assessment studies were still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

     We are subject to the federal Clean Air Act and to the federal Clean Air Act Amendments of 1990, which require the EPA to issue new regulations. We are also subject to regulation at the state and local level. In September 1998, the EPA promulgated rules designed to mitigate the migration of ground-level ozone in certain states. In March 2004 and June 2004, the EPA promulgated additional regulation regarding hazardous air pollutants, which may impose additional controls. Capital expenditures necessary to install emission control devices on our Transco gas pipeline system to comply with rules were approximately $41 million in 2006 and are estimated to be between $35 million and $40 million through 2010. The actual costs incurred will depend on the final implementation plans developed by each state to comply with these regulations. We consider these costs on our Transco system associated with compliance with these environmental laws and regulations to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through its rates.

Item 7A. Qualitative and Quantitative Disclosures About Market Risk

Interest Rate Risk

     Our current interest rate risk exposure is related primarily to our debt portfolio. The majority of our debt portfolio is comprised of fixed rate debt in order to mitigate the impact of fluctuations in interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets.

     The tables below provide information about our interest rate risk-sensitive instruments as of December 31, 2006 and 2005. Long-term debt in the tables represents principal cash flows, net of (discount) premium, and weighted-average interest rates by expected maturity dates. The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on the prices of similar securities with similar terms and credit ratings.

																														Fair Value
																														December 31,
		2007				2008				2009				2010				2011				Thereafter(1)				Total				2006
		(Dollars in millions)
Long-term debt, including current portion(4):
Fixed rate		$	381			$	153			$	41			$	205			$	1,161			$	5,922			$	7,863			$	8,343
Interest rate			7.7	%			7.7	%			7.7	%			7.5	%			7.6	%			7.8	%
Variable rate		$	10			$	85			$	12			$	12			$	7			$	23			$	149			$	137
Interest rate(2)

																														Fair Value
																														December 31,
		2006				2007				2008				2009				2010				Thereafter(1)				Total				2005
		(Dollars in millions)
Long-term debt, including current portion(4):
Fixed rate		$	104			$	381			$	153			$	41			$	205			$	6,179			$	7,063			$	7,952
Interest rate			7.7	%			7.7	%			7.8	%			7.8	%			7.8	%			7.8	%
Variable rate		$	15			$	15			$	563			$	12			$	12			$	30			$	647			$	647
Interest rate(3)

Commodity Price Risk

     We are exposed to the impact of fluctuations in the market price of natural gas, electricity, and natural gas liquids, as well as other market factors, such as market volatility and commodity price correlations, including correlations between natural gas and power prices. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our proprietary trading activities. We manage the risks associated with these market fluctuations using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to changes in energy-commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. We measure the risk in our portfolios using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolios.

     Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolios. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolios will not exceed the value at risk. The

simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolio in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.

     We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Derivative contracts designated as normal purchases or sales under SFAS 133 and nonderivative energy contracts have been excluded from our estimation of value at risk.

     Trading

     Our trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. A portion of these derivative contracts are included in our assets and liabilities of discontinued operations. Our value at risk for contracts held for trading purposes was approximately $1 million at December 31, 2006, and $4 million at December 31, 2005. During the year ended December 31, 2006, our value at risk for these contracts ranged from a high of $4 million to a low of $1 million.

     Nontrading

     Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from the following activities:

Segment		Commodity Price Risk Exposure
Exploration & Production		•   Natural gas sales
Midstream		•   Natural gas purchases
Gas Marketing Services		•   Natural gas purchases and sales