UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2004

OR

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

For the transition period from                     to                    

Commission file number 1-4174

THE WILLIAMS COMPANIES, INC.

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

NO CHANGE

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes (X) No (   )

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes (X) No (   )

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

The Williams Companies, Inc.

     Certain matters discussed in this report, excluding historical information, include forward-looking statements — statements that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

     Forward-looking statements can be identified by words such as “anticipates,” “believes,” “expects,” “planned,” “scheduled,” “could,” “continues,” “estimates,” “forecasts,” “might,” “potential,” “projects” or similar expressions. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in this document. Additional information about issues that could cause actual results to differ materially from forward-looking statements is contained in our 2003 Form 10-K as restated and amended.

1

*

Certain amounts have been reclassified as described in Note 2 of Notes to Consolidated Financial Statements.

See accompanying notes.

2

The Williams Companies, Inc.

*

Certain amounts have been reclassified as described in Note 2 to Consolidated Financial Statements.

See accompanying notes.

3

The Williams Companies, Inc.

*		Certain amounts have been reclassified as described in Note 2 of Notes to Consolidated Financial Statements.
**		Includes cash and cash equivalents of discontinued operations of $2.5 million, $2.9 million and $85.6 million at December 31, 2003, September 30, 2003 and December 31, 2002, respectively.

See accompanying notes

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The Williams Companies, Inc.

1. General

Company overview and outlook

     In February 2003, we outlined our planned business strategy in response to the events that significantly impacted the energy sector and our company during late 2001 and much of 2002, including the collapse of Enron and the severe decline of the telecommunications industry. The plan focused on migrating to an integrated natural gas business comprised of a strong, but smaller, portfolio of natural gas businesses; reducing debt; and increasing our liquidity through asset sales, strategic levels of financing and reductions in operating costs. The plan was designed to address near-term and medium-term debt and liquidity issues, to de-leverage the company with the objective of returning to investment grade status and to develop a balance sheet and cash flows capable of supporting and ultimately growing our remaining businesses.

     As discussed in our Annual Report on Form 10-K for the year ended December 31, 2003, we successfully executed certain critical components of our plan during 2003. Key execution steps for 2004 and beyond included the completion of planned asset sales; additional reductions of our selling, general and administrative (SG&A) costs; the replacement of our cash-collateralized letter of credit and revolver facility with facilities that do not encumber cash; and continuation of efforts to exit from the Power business (see below).

     Asset sales during 2004 were expected to generate proceeds of approximately $800 million. In first-quarter 2004, we completed the sale of our Alaska refinery and related assets for approximately $304 million. We completed the sale of three straddle plants in western Canada on July 28, 2004, for net proceeds of approximately $544 million (see Note 6).

     On March 15, 2004, we retired $679 million of senior unsecured 9.25 percent notes. The amount represented the outstanding balance remaining after the fourth-quarter 2003 tender which retired $721 million of the original $1.4 billion balance.

     In April 2004, we entered into two new unsecured credit facilities totaling $500 million, which will be used primarily for issuing letters of credit. During April 2004, use of these facilities released approximately $500 million of restricted cash, restricted investments and margin deposits. Also, on May 3, 2004, we entered into a new three-year $1 billion secured revolving credit facility. In August, we expanded the credit facility by an additional $275 million. The revolving credit facility is secured by certain Midstream assets and a guarantee from Williams Gas Pipeline Company, LLC. (WGP).

     In May 2004, we made cash tender offers for approximately $1.34 billion aggregate principal amount of a specified series of our outstanding notes and debentures. We accepted $1.17 billion of the notes for purchase. In May 2004, we also repurchased debt of approximately $255 million of various maturities on the open market.

     In August 2004, we made cash tender offers and consent solicitations for $800 million all of our 8.625 percent senior notes due 2010. We accepted $793 million of the notes for purchase.

     See Note 12 for additional discussion of debt and banking arrangements.

Power business status

     In mid-2002, we initiated a strategy of exiting the Power business and have worked with financial advisors to assist with this effort. However, the number of financially viable parties expressing an interest in purchasing the entire business was limited. Additionally, the current and near term view of the wholesale power market, which we interpret as depressed, has strongly influenced these parties’ view of value and related risk associated with this business.

5

Notes (Continued)

     In September 2004, our Board of Directors approved the decision to retain Power and end our efforts to exit that business. Several factors affected our decision including:

•

the cash flow expected to be generated by the business (Power has contracts in place expected to generate cash in amounts that substantially cover its obligations through 2010);

•

the negative effect of depressed wholesale power markets on the marketability of the Power segment; and

•

our progress over the last two years in reducing the risk of and increasing the certainty of cash flow from long-term power contracts.

We will continue our current program of managing this business to minimize financial risk and maximize cash flow associated with our long-term contracts.

Other

     Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto in our Annual Report on Form 10-K, as restated and amended. The accompanying unaudited financial statements include all normal recurring adjustments and others, including asset impairments, loss accruals, and the change in accounting principles which, in the opinion of our management, are necessary to present fairly our financial position at September 30, 2004 and 2003, and results of operations for the three and nine months ended September 30, 2004 and 2003 and cash flows for the nine months ended September 30, 2004 and 2003.

     During the second quarter of 2003, we corrected the accounting treatment previously applied to certain third-party derivative contracts during 2002 and 2001. We previously disclosed this in our Form 10-Q for the second quarter of 2003 and in our Form 10-K for the year ended December 31, 2003. Results through September 30, 2003, include $107.8 million of revenue attributable to prior periods. Our management, after consultation with our independent auditor, concluded that the effect of the previous accounting treatment was not material to 2003 and earlier periods and the trend of earnings.

     During the third quarter of 2004, we corrected the accounting method previously applied to revenues from our Devils Tower production handling facility in the second quarter of 2004. The change to a units of production method resulted in a reduction of revenues of approximately $16.5 million in the third quarter related to revenues recorded in the second quarter. Our management, after consultation with our independent auditor, concluded that the effect of the previous accounting treatment was not material to the results of the second or third quarters.

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

2. Basis of presentation

     In accordance with the provisions related to discontinued operations within Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the accompanying consolidated financial statements and notes reflect the results of operations, financial position and cash flows of the following components as discontinued operations (see Note 6):

•

retail travel centers concentrated in the Midsouth, part of the previously reported Petroleum Services segment;

•

refining and marketing operations in the Midsouth, including the Midsouth refinery, part of the previously reported Petroleum Services segment;

•

Texas Gas Transmission Corporation, previously one of Gas Pipeline’s segments;

•

natural gas properties in the Hugoton and Raton basins, previously part of the Exploration & Production segment;

6

Notes (Continued)

•

bio-energy operations, part of the previously reported Petroleum Services segment;

•

our general partnership interest and limited partner investment in Williams Energy Partners, previously the Williams Energy Partners segment;

•

the Colorado soda ash mining operations, part of the previously reported International segment;

•

certain gas processing, natural gas liquids fractionation, storage and distribution operations in western Canada and at a plant in Redwater, Alberta, previously part of the Midstream segment;

•

refining, retail and pipeline operations in Alaska, part of the previously reported Petroleum Services segment;

•		Gulf Liquids New River Project LLC, previously part of the Midstream segment; and
•		the straddle plants in western Canada, previously part of the Midstream segment.

     Management and decision-making control of certain activities have been transferred between segments. Consequently, the results of operations have been similarly reclassified. All periods presented reflect these classifications.

     Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations. Other components of our business may be classified as discontinued operations in the future as those operations are sold or classified as held-for-sale.

     We have restated all segment information in the Notes to Consolidated Financial Statements for the prior periods presented to reflect the discontinued operations noted above. Certain other statement of operations, balance sheet and cash flow amounts have been reclassified to conform to the current classifications.

3. Cumulative effect of change in accounting principles

Energy commodity risk management and trading activities and revenues

     Effective January 1, 2003, we adopted EITF 02-3. As a result of initial application of this Issue, we reduced net income by $762.5 million (net of a $471.4 million benefit for income taxes) in first-quarter 2003. Approximately $755 million of the reduction in net income relates to Power, with the remainder relating to Midstream. The reduction of net income is reported as a cumulative effect of a change in accounting principle. The change resulted primarily from power tolling, load serving, transportation and storage contracts not meeting the definition of a derivative and no longer being reported at fair value.

Asset retirement obligations

     Effective January 1, 2003, we also adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” As required by the standard, we recorded liabilities equal to the present value of expected future asset retirement obligations at January 1, 2003. As a result of the adoption of SFAS No. 143, we recorded a credit to earnings of $1.2 million (net of a $.1 million provision for income taxes) reflected as a cumulative effect of a change in accounting principle. In connection with adoption of SFAS No. 143, we changed our method of accounting to include salvage value of equipment related to producing wells in the calculation of depreciation. The impact of this change is included in the effect of adoption.

7

Notes (Continued)

4. Asset sales, impairments and other accruals

     Significant gains or losses from asset sales, impairments and other accruals included in other (income) expense — net within segment costs and expenses and investing income are included in the following tables.

5. Provision (benefit) for income taxes

     The provision (benefit) for income taxes from continuing operations includes:

8

Notes (Continued)

     The effective income tax rate for the three and nine months ended September 30, 2004, is significantly greater than the federal statutory rate due primarily to the effect of state income taxes (including no state income tax benefit recognized for state net operating losses) and net foreign operations.

     The effective income tax rate for the three months ended September 30, 2003, is greater than the federal statutory rate due primarily to the effect of state income taxes, net foreign operations and an accrual for income tax contingencies. For the nine months ended September 30, 2003, the effective income tax rate is greater than the federal statutory rate due primarily to the effect of state income taxes, net foreign operations, an accrual for income tax contingencies, nondeductible expenses, the financial impairment of certain investments and capital losses generated for which valuation allowances were established.

     On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was signed into law. The Act repeals the foreign sales corporation/extraterritorial income exclusion provision of the Internal Revenue Code, provides a deduction with respect to income of certain U.S. manufacturing activities, allows for tax-favored repatriation of offshore earnings, and makes numerous other changes to the U.S. tax rules. We are evaluating the potential accounting impact of this new legislation.

6. Discontinued operations

     During 2002, we began the process of selling assets and/or businesses to address liquidity issues. The businesses discussed below represent components that have been sold or approved for sale by our Board of Directors as of September 30, 2004; therefore, their results of operations (including any impairments, gains or losses), financial position and cash flows have been reflected in the consolidated financial statements and notes as discontinued operations.

Summarized results of discontinued operations

     The following table presents the summarized results of discontinued operations for the three and nine months ended September 30, 2004 and September 30, 2003. Loss from discontinued operations before income taxes for the three and nine months ended September 30, 2004 includes charges of $134.4 million and $151.8 million, respectively, to increase our accrued liability associated with certain Quality Bank litigation matters (see Note 13). The benefit for income taxes for the three months ended September 30, 2004, includes the favorable effect of net Canadian tax benefits realized from the sale of the Canadian straddle plants.

Summarized assets and liabilities of discontinued operations

     The following table presents the summarized assets and liabilities of discontinued operations as of September 30, 2004 and December 31, 2003. The December 31, 2003 balances include the assets and liabilities of the Canadian straddle plants, the Gulf Liquids New River Project LLC (Gulf Liquids) and the Alaska refining, retail and pipeline operations. The September 30, 2004 balances include Gulf Liquids and certain Alaska retail operations that were not included in the March 31, 2004 sale but that remain held for sale. The assets and liabilities from discontinued operations are reflected on the Consolidated Balance Sheet as current beginning in the period they are both approved for sale and expected to be sold within twelve months.

9

Notes (Continued)

Held for sale at September 30, 2004

Gulf Liquids New River Project LLC

     During second-quarter 2003, our Board of Directors approved a plan authorizing management to negotiate and facilitate a sale of the assets of Gulf Liquids. The Gulf Liquids assets were written down to their estimated fair value less cost to sell resulting in a second-quarter 2003 impairment charge of $92.6 million, which is included in (Impairments) and gain (loss) on sales - net in the preceding table of summarized results of discontinued operations. We estimated fair value based on a probability-weighted analysis of various scenarios, including expected sales prices, discounted cash flows and salvage valuations. During first-quarter 2004, we initiated a second bid process and expect the sale of these operations to be completed in the fourth-quarter of 2004. These operations were part of the Midstream segment.

     Winterthur International Insurance Company (Winterthur) issued policies to Gulf Liquids providing financial assurance related to construction contracts among Gulf Liquids, Gulsby Engineering, Inc. and Gulsby-Bay. After disputes arose regarding obligations under the construction contracts, Winterthur disputed coverage resulting in arbitration between Winterthur and Gulf Liquids. In July 2004, the arbitration panel awarded Gulf Liquids $93.6 million, offset by $18 million previously paid to Gulf Liquids, plus interest of $9.4 million, for a total award to Gulf Liquids of approximately $85 million including interest through November 1, 2004. Following the arbitration decision, Winterthur filed a Petition to Vacate the Final Award in the New York State court and Gulf Liquids filed a Cross-Petition to Confirm the Final Award. Prior to the State court’s ruling, Winterthur agreed to the terms of the award and on November 1, 2004 remitted approximately $85 million to us. As a result, we will recognize pre-tax income of $95 to $100 million within Income from discontinued operations in the fourth quarter.

2004 completed transactions

Canadian straddle plants

     On July 28, 2004, we completed the sale of the Canadian straddle plants for approximately $544 million in U.S. funds, including amounts paid to our subsidiaries for amounts previously due from the straddle plants. During third-quarter 2004, we recognized a pre-tax gain on the sale of $189.8 million, which is included in (Impairments) and gain (loss) on sales — net in the preceding table of summarized results of discontinued operations. These assets were previously written down to estimated fair value, resulting in a $36.8 million impairment in fourth-quarter 2002 and an additional $41.7 million impairment in fourth-quarter 2003. In 2004, the fair value of the assets increased substantially due primarily to renegotiation of certain customer contracts and a general improvement in the market for processing assets. These operations were part of the Midstream segment.

Alaska refining, retail and pipeline operations

     On March 31, 2004, we completed the sale of our Alaska refinery, retail and pipeline and related assets for approximately $304 million, subject to closing adjustments for items such as the value of petroleum inventories. We received $279 million in cash at the time of sale and $25 million in cash during the second quarter of 2004. Throughout the sales negotiation process, we regularly reassessed the estimated fair value of these assets based on information obtained from the sales negotiations using a probability-weighted approach. We recognized a $3.6 million gain on the sale during first-quarter 2004. The gain and an $8 million first-quarter 2003 impairment charge are included in (Impairments) and gain (loss) on sales — net in the preceding table of summarized results of discontinued operations. These operations were part of the previously reported Petroleum Services segment.

2003 Completed transactions

Canadian liquids operations

     During the third quarter of 2003, we completed the sale of certain gas processing, natural gas liquids fractionation, storage and distribution operations in western Canada and at our Redwater, Alberta plant for total proceeds of $246 million in cash. We recognized pre-tax gains totaling $86.6 million on the sales which are included in (Impairments) and gain (loss) on sales — net in the preceding table of summarized results of discontinued operations. These operations were part of the Midstream segment.

10

Notes (Continued)

Soda ash operations

     On September 9, 2003, we completed the sale of our soda ash mining facility located in Colorado. These assets were written down to their estimated fair value less cost to sell in 2002. During 2003, ongoing sale negotiations continued to provide new information regarding estimated fair value, and, as a result, additional impairment charges of $17.4 million were recognized in 2003. We also recognized a loss on the sale of $4.2 million. The 2003 impairments and the loss on sale are included in (Impairments) and gain (loss) on sales - net in the preceding table of summarized results of discontinued operations. The soda ash operations were part of the previously reported International segment.

Williams Energy Partners

     On June 17, 2003, we completed the sale of our 100 percent general partnership interest and 54.6 percent limited partner investment in Williams Energy Partners for approximately $512 million in cash and assumption by the purchasers of $570 million in debt. In December 2003, we received additional cash proceeds of $20 million following the occurrence of a contingent event. In second-quarter 2003 we recognized a gain on sale — net of $275.6 million which is included in (Impairments) and gain (loss) on sales — net in the preceding table of summarized results of discontinued operations and deferred an additional $113 million associated with certain environmental indemnifications we provided to the purchasers under the sales agreement. In second-quarter 2004, we settled these indemnifications with an agreement to pay $117.5 million over a four-year period (see Note 11).

Bio-energy facilities

     On May 30, 2003, we completed the sale of our bio-energy operations for approximately $59 million in cash. During second-quarter 2003, we recognized a loss on sale of $6.4 million, which is included in (Impairments) and gain (loss) on sales — net in the preceding table of summarized results of discontinued operations. These assets were previously written down to their estimated fair value less cost to sell at December 31, 2002. These operations were part of the previously reported Petroleum Services segment.

Natural gas properties

     On May 30, 2003, we completed the sale of natural gas exploration and production properties in the Raton Basin in southern Colorado and the Hugoton Embayment in southwestern Kansas. This sale included all of our interests within these basins. During second-quarter 2003, we recognized a gain on sale of $39.9 million which is included in (Impairments) and gain (loss) on sales - net in the preceding table of summarized results of discontinued operations. These properties were part of the Exploration & Production segment.

Texas Gas

     On May 16, 2003, we completed the sale of Texas Gas Transmission Corporation for $795 million in cash and the assumption by the purchaser of $250 million in existing Texas Gas debt. There was no significant gain or loss recognized on the sale. We recorded a $109 million impairment charge in first-quarter 2003 reflecting the excess of the carrying cost of the long-lived assets over our estimate of fair value based on our assessment of the expected sales price pursuant to the purchase and sale agreement. The impairment charge is included in (Impairments) and gain (loss) on sales — net in the preceding table of summarized results of discontinued operations. Texas Gas was a segment within Gas Pipeline.

Midsouth refinery and related assets

     On March 4, 2003, we completed the sale of our refinery and other related operations located in Memphis, Tennessee for $455 million in cash. These assets were previously written down to their estimated fair value less cost to sell at December 31, 2002. We recognized a pre-tax gain on sale of $4.7 million in the first quarter of 2003. During the second quarter of 2003, we recognized a $24.7 million gain on the sale of an earn-out agreement we retained in the sale of the refinery. These gains are included in (Impairments) and gain (loss) on sales — net in the preceding table of summarized results of discontinued operations. These operations were part of the previously reported Petroleum Services segment.

11

Notes (Continued)

Williams travel centers

     On February 27, 2003, we completed the sale of our travel centers for approximately $189 million in cash. We had previously written these assets down to their estimated fair value to sell at December 31, 2002, and did not recognize a significant gain or loss on the sale. These operations were part of the previously reported Petroleum Services segment.

7. Earnings (loss) per share

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

     For the nine months ended September 30, 2004, approximately 3.7 million weighted-average stock options and approximately 2.7 million weighted-average unvested deferred shares that otherwise would have been included, have been excluded from the computation of diluted earnings per common share (EPS) as their inclusion would be antidilutive due to our loss from continuing operations. The unvested deferred shares will vest over the period from November 2004 to January 2008.

     In addition, for the three and nine months ended September 30, 2004, approximately 27.5 million weighted-average shares related to the assumed conversion of convertible debentures, as well as the related interest, have been excluded from the computation of diluted EPS as their inclusion would be antidilutive. If no other components used to calculate diluted EPS change, we estimate the assumed conversion of the convertible debentures would become dilutive and, therefore, be included in diluted EPS at an Income from continuing operations amount of $49 million and $144.7 million for the three and nine months ended September 30, 2004, respectively.

     Approximately 9.3 million options to purchase shares of common stock with a weighted-average exercise price of $27.44 and an exercise price range of $12.22 — $42.29 were outstanding at September 30, 2004, but have been excluded from the computation of diluted EPS. Inclusion of these shares would have been antidilutive, as the exercise prices of the options exceeded the third-quarter weighted average market price of the common shares of $11.97 for the three months ended September 30, 2004.

     For the nine months ended September 30, 2003, approximately 8.6 million weighted-average shares related to the assumed conversion of 9.875 percent cumulative convertible preferred stock have been excluded from the computation of diluted EPS as their inclusion would be antidilutive. The preferred stock was redeemed in June 2003.

     For the three and nine months ended September 30, 2003, approximately 27.5 million and 12.7 million weighted-average shares, respectively, related to the assumed conversion of convertible debentures, as well as the related interest, were excluded from the computation of diluted EPS as their inclusion would be antidilutive. If no other components used to calculate diluted EPS change, we estimate the assumed conversion of the convertible debentures would become dilutive and, therefore, be included in diluted EPS at an Income from continuing operations applicable to common stock amount of $48.5 million and 143.5 million for the three and nine months ended September 30, 2003, respectively.

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Notes (Continued)

     On September 17, 2004, we initiated an offer to exchange up to 43.9 million FELINE PACS units for one share of our common stock plus $1.47 in cash for each unit (see Note 12). On October 22, 2004, we issued approximately 33.1 million shares of our common stock related to this exchange offer. The increase in shares will have a dilutive effect on EPS in the future.

8. Employee benefit plans

     Net periodic pension and other postretirement benefit (income) expense for the three and nine months ended September 30, 2004 and 2003 is as follows:

     The $29 million settlement/curtailment income included in net periodic postretirement benefit (income) expense for the nine months ended September 30, 2003, is included in income (loss) from discontinued operations in the Consolidated Statement of Operations due to the settlement/curtailment directly resulting from the sale of the operations included within discontinued operations.

     As previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2003, as restated and amended, we expected to contribute approximately $60 million to our pension plans and approximately $15 million to our other postretirement benefit plans in 2004. For the nine months ended September 30, 2004, we contributed $44.5 million to our pension plans and $9.7 million to our other postretirement benefit plans. We presently anticipate contributing approximately an additional $16 million to fund our pension plans in 2004 for a total of approximately $61 million. We presently anticipate contributing approximately an additional $4 million to our other postretirement benefit plans in 2004 for a total of approximately $14 million.

     In December 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Act) was signed into law. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Our health care plans for retirees include prescription drug coverage. In accordance with FASB Staff Position (FSP) No. FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” the provisions of the Act were not reflected in any measures of benefit obligations or other postretirement benefit expense in the financial statements or accompanying notes until further guidance was effective. In May 2004, the FASB issued FSP No. FAS 106-2, “Accounting and

13

Notes (Continued)

Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” Although final guidance has not been issued, we believe the prescription drug benefits included in our health care plans for retirees, as of September 30, 2004, are actuarially equivalent to Medicare Part D. In accordance with FSP No. FAS 106-2, we have reflected the effect of the subsidy on the measurement of net periodic postretirement benefit (income) expense beginning July 1, 2004. Net periodic postretirement benefit (income) expense for the three and nine months ended September 30, 2004, reflects a reduction of $2.6 million, including a decrease in service cost of $.3 million and decrease in interest cost of $2.0 million. The reduction in the benefit obligation is approximately $43 million as of January 1, 2004. Although we believe our plans, as of September 30, 2004, are actuarially equivalent to Medicare Part D, we expect to amend our plans in the fourth quarter of 2004 to coordinate and pay secondary to any part of Medicare, including prescription drug benefits covered by Medicare Part D. If this amendment had been effective January 1, 2004, we would have expected this amendment to have further decreased the benefit obligation by approximately $60 million.

9. Stock-based compensation

     Employee stock-based awards are accounted for under Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25) and related interpretations. Fixed-plan common stock options generally do not result in compensation expense because the exercise price of the stock options equals the market price of the underlying stock on the date of grant. The following table illustrates the effect on net income (loss) and earnings (loss) per share if we had applied the fair value recognition provisions of SFAS No. 123 “Accounting for Stock-Based Compensation.”

     Pro forma amounts for 2004 include compensation expense from awards of our company stock made in 2004, 2003, 2002 and 2001. Also included in pro forma expense for the three and nine months ended September 30, 2004, is $886,000 and $2.6 million, respectively, of incremental expense associated with the stock option exchange program described below. Pro forma amounts for 2003 include compensation expense from awards made in 2003, 2002 and 2001.

     Since compensation expense for stock options is recognized over the future years’ vesting period for pro forma disclosure purposes and additional awards are generally made each year, pro forma amounts may not be representative of future years’ amounts.

     On May 15, 2003, our shareholders approved a stock option exchange program. Under this exchange program, eligible employees were given a one-time opportunity to exchange certain outstanding options for a proportionately lesser number of options at an exercise price to be determined at the grant date of the new options. Surrendered options were cancelled June 26, 2003, and replacement options were granted on December 29, 2003. We did not recognize any expense pursuant to the stock option exchange. However, for purposes of pro forma disclosures, we recognized additional expense related to these new options and will amortize the remaining expense on the cancelled options through year-end 2004.

14

Notes (Continued)

10. Inventories

     Inventories at September 30, 2004 and December 31, 2003 are as follows:

11. Accrued liabilities and other liabilities and deferred income

     On May 26, 2004, we were released from certain historical indemnities, primarily related to environmental remediation, for an agreement to pay $117.5 million (see Note 13). We had previously deferred $113 million of a gain on sale related to these indemnities. At the date of sale, the deferred revenue and identified obligations related to the indemnities totaled $102 million. At September 30, 2004, the net book value of this settlement is $73.7 million. We will pay the balance in three installments of $27.5 million, $20 million, and $35 million on July 1, 2005, 2006, and 2007, respectively.

     During the third quarter of 2004, we recorded an additional accrual in Accrued liabilities of approximately $134 million related to certain Quality Bank litigation matters (see Note 13).

15

Notes (Continued)

12. Debt and banking arrangements

Notes payable and long-term debt

     Notes payable and long-term debt at September 30, 2004 and December 31, 2003, are as follows:

(1)

At September 30, 2004.

(2)

Includes $1.1 billion of 6.5 percent notes payable 2007, subject to remarketing in November 2004, discussed below.

     Long-term debt includes $1.1 billion of 6.5 percent notes, payable in 2007, which are subject to remarketing in November 2004. These FELINE PACS include equity forward contracts that require the holder to purchase shares of our common stock in February 2005. If a remarketing is unsuccessful in 2004 and a second remarketing in February 2005 is unsuccessful as defined in the offering document for the FELINE PACS, then we could exercise our right to foreclose on the notes in order to satisfy the obligation of the holders of the equity forward contracts requiring the holder to purchase our common stock. This would be a non-cash transaction. If either remarketing of the notes is successful, we will receive the proceeds from the remarketing in February 2005 and issue stock to the holders of the forward contracts (see Recent events below).

Recent events

     On February 25, 2004, our Exploration & Production segment amended its $500 million secured variable rate note. The amendment reduced the floating interest rate from the London InterBank Offered Rate (LIBOR) plus 3.75 percent to LIBOR plus 2.5 percent. The amendment also extended the maturity date from May 30, 2007 to May 30, 2008. The amendment provides for an additional reduction in the interest rate by 25 basis points, or 0.25 percent, if we meet certain credit-rating requirements. The significant covenants were not altered by the amendment.

     In May 2004, we made cash tender offers for approximately $1.34 billion aggregate principal amount of a specified series of our outstanding notes and debentures. As of the June 8, 2004, tender offer expiration date, we had accepted for purchase tenders of notes and debentures with an aggregate principal amount of approximately $1.17 billion. Holders of notes and debentures tendered by the early tender expiration date received an early tender payment premium of $30 per $1,000 principal amount of notes and debentures. In May 2004, we also repurchased approximately $255 million of various notes with maturity dates ranging from 2006 to 2011. In conjunction with these tendered notes and debentures and related consents, and early retirements, we paid premiums of approximately $79 million. The premiums, as well as related fees and expenses, together totaling approximately $97 million, have been recorded during 2004 as early debt retirement costs.

16

Notes (Continued)

     On July 20, 2004, Wilpro Energy Services (PIGAP II) Limited, one of our subsidiaries, received a notice of default from the Venezuelan state oil company, PDVSA, relating to certain operational issues alleging that our subsidiary is not in compliance under a services agreement. We do not believe a basis exists for such notice and are contesting the giving of this notice. Although this notice of default could result in an event of default with respect to project loans totaling approximately $208 million, such an event would not adversely affect any of our other debt instruments. The lenders under the project loan agreement have confirmed to us in writing that based on the facts they currently know, they have no intention of exercising any rights or remedies under the project loan agreement until the issues raised in the notice and our response are clarified.

     In August 2004, we made cash tender offers and consent solicitations for all $800 million of our 8.625 percent senior notes due 2010. As of the September 2, 2004, tender offer expiration date, we had accepted $793 million of notes for purchase. Holders of notes tendered by the early tender expiration date received an early tender payment premium of $20 per $1,000 principal amount of notes. In conjunction with these tendered notes and related consents, we paid premiums of approximately $134.5 million. The premiums, as well as related fees and expenses, together totaling approximately $154.7 million were recorded in third-quarter 2004 as early debt retirement costs.

     On September 17, 2004, we initiated an offer to exchange up to 43.9 million FELINE PACS units for one share of our common stock plus $1.47 in cash for each unit. The offer expired October 18, 2004, and resulted in approximately 33.1 million of the 44 million issued and outstanding units being tendered and accepted for exchange. The exchange offer reduced our 6.5 percent notes, due 2007, by approximately $827 million and increased our common stock outstanding by 33.1 million shares. The effect of the exchange, including a pre-tax charge for related expenses of approximately $25 million, will be reflected in the fourth quarter. At September 30, 2004, the $1.1 billion obligation associated with the FELINE PACS is classified as long-term debt. Following the exchange and in connection with the remarketing of the senior notes that is scheduled to take place on November 10, 2004, we have provided notice that we may submit an order to purchase a portion of the senior notes not to exceed approximately $200 million. We propose to retire all the senior notes we purchase in the remarketing.

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

Revolving credit and letter of credit facilities

     In April 2004, we entered into two unsecured bank revolving credit facilities totaling $500 million. These facilities provide for both borrowings and issuing letters of credit, but are used primarily for issuing letters of credit. At September 30, 2004, letters of credit totaling $493 million have been issued by the participating financial institution under these facilities and no revolving credit loans were outstanding. We are required to pay to the bank fixed fees at a weighted-average rate of 3.64 percent on the total committed amount of the facilities. In addition, we pay interest on any borrowings at a fluctuating rate comprised of either a base rate or LIBOR. We were able to obtain the unsecured credit facilities because the funding bank syndicated its associated credit risk into the institutional investor market via a 144A offering, which allows for the resale of certain restricted securities to qualified institutional buyers. Upon the occurrence of certain credit events, letters of credit outstanding under the agreement become cash collateralized creating a borrowing under the facilities. Concurrently the bank can deliver the facilities to the institutional investors, whereby the investors replace the bank as lender under the facilities. Upon such occurrence, we will pay:

•

a fixed facility fee at a weighted average rate of 3.19 percent to the investors,

•

interest on borrowings under the $400 million facility equal to a fixed rate of 3.57 percent, and

•

interest on borrowings under the $100 million facility at a fluctuating LIBOR interest rate.

17

Notes (Continued)

     To facilitate the syndication of these facilities, the bank established trusts funded by the institutional investors. The assets of the trusts serve as collateral to reimburse the bank for our borrowings in the event the facilities are delivered to the investors. Thus, we have no asset securitization or collateral requirements under the new facilities. During second-quarter 2004, use of these new facilities replaced existing facilities and released approximately $500 million of restricted cash, restricted investments and margin deposits which secured our previous $800 million revolving and letter of credit facility. Significant covenants under these new facilities include the following:

•

limitations on certain payments, including a limitation on the payment of quarterly dividends to no greater than $.05 per common share;

•

limitations on asset sales;

•

limitations on the use of proceeds from permitted asset sales;

•

limitations on transactions with affiliates; and

•

limitations on the incurrence of additional indebtedness and issuance of disqualified stock, unless the fixed charge coverage ratio for our most recently ended four full fiscal quarters is at least 2 to 1, determined on a proforma basis.

     On May 3, 2004, we entered into a new three-year, $1 billion secured revolving credit facility which is available for borrowings and letters of credit. In August 2004, we expanded the credit facility by an additional $275 million. At September 30, 2004, letters of credit totaling $438 million have been issued by the participating institutions under this facility and no revolving credit loans were outstanding. Northwest Pipeline Corporation (Northwest) and Transcontinental Gas Pipe Line Corporation (Transco) have access to $400 million each under the facility. The new facility is secured by certain Midstream assets, including substantially all of our southwest Wyoming, Wamsutter, San Juan Conventional, Manzanares and Torre Alta systems. Additionally, the facility is guaranteed by WGP. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the facilitating bank’s base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. We are also required to pay a commitment fee based on the unused portion of the facility, currently .375 percent. The applicable margins and commitment fee are based on the relevant borrower’s senior unsecured long-term debt ratings. Significant financial covenants under the credit agreement include:

•

ratio of debt to capitalization no greater than (i) 75 percent for the period June 30, 2004 through December 31, 2004, (ii) 70 percent for the period after December 31, 2004 through December 31, 2005, and (iii) 65 percent for the remaining term of the agreement;

•

ratio of debt to capitalization no greater than 55 percent for Northwest and Transco; and

•

ratio of EBITDA to Interest, on a rolling four quarter basis (or, in the first year, building up to a rolling four quarter basis), no less than (i) 1.5 for the periods ending September 30, 2004 through March 31, 2005, (ii) 2.0 for any period after March 31, 2005 through December 31, 2005, and (iii) 2.5 for the remaining term of the agreement.

     Upon entering into the new $1 billion secured revolving credit facility on May 3, 2004, we terminated the $800 million revolving and letter of credit facility which we entered into in June 2003. Termination of the facility resulted in a $3.8 million charge which is recorded in Interest accrued in the Consolidated Statement of Operations.

Retirements

     On March 15, 2004, we retired $679 million of senior, unsecured 9.25 percent notes. The amount represented the outstanding balance remaining after the fourth-quarter 2003 tender which retired $721 million of the original $1.4 billion balance.

     As previously discussed, in May 2004, we made cash tender offers for approximately $1.34 billion aggregate principal amount of our specified series of outstanding notes and debentures. We accepted for purchase tenders of notes and debentures with an aggregate principal amount of approximately $1.17 billion. In May 2004, we also repurchased approximately $255 million of various notes with maturity dates ranging from 2006 to 2011.

     In August 2004, we made cash tender offers and consent solicitations for all $800 million of our 8.625 percent senior notes due 2010. We accepted for purchase tenders of notes with an aggregate principal amount of approximately $793 million.

18

Notes (Continued)

     A summary of significant payments of long-term debt for the nine months ended September 30, 2004 is as follows:

19

Notes (Continued)

13. Contingent liabilities and commitments

Rate and regulatory matters and related litigation

     Our interstate pipeline subsidiaries have various regulatory proceedings pending. As a result of rulings in certain of these proceedings, a portion of the revenues of these subsidiaries has been collected subject to refund. The natural gas pipeline subsidiaries have accrued approximately $9 million for potential refund as of September 30, 2004.

Issues resulting from California energy crisis

     Subsidiaries of our Power segment are engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 have been challenged in various proceedings including those before the Federal Energy Regulatory Commission (FERC). These challenges include refund proceedings, California Independent System Operator (ISO) fines, summer 2002 90-day contracts, investigations of alleged market manipulation including withholding, gas indices and other gaming of the market, new long-term power sales to the State of California that were subsequently challenged and civil litigation relating to certain of these issues. We have entered into settlements with the State of California, major California utilities, and others that have substantially resolved each of these issues. However, certain of these issues remain open at the FERC and for other non-settling parties.

Refund proceedings

     Although we have entered into a global settlement with the State of California, certain California utilities, and various other parties that resolve the refund issues among the settling parties, we have potential refund exposure to non-settling parties (e.g., various California end users that have not agreed to opt into the utility settlement). As a part of the utility settlement, Williams funded escrow accounts that we anticipate will satisfy any ultimate refund determinations in favor of the non-settling parties. Williams is also owed interest from counterparties in the California market during the refund period of approximately $29 million through September 30, 2004. A request for rehearing of the order approving the utility settlement is pending at the FERC. Therefore, we continue to participate in the FERC refund case and related proceedings. Challenges to virtually every aspect of the refund proceeding, including the refund period, are now pending at the Ninth Circuit Court of Appeals. No schedule has yet been established for hearing the appeals.

Summer 2002 90-day contracts

     On May 2, 2002, PacifiCorp filed a complaint with the FERC against us seeking relief from rates contained in three separate confirmation agreements between PacifiCorp and Power (known as the Summer 2002 90-Day Contracts). PacifiCorp filed similar complaints against three other suppliers. PacifiCorp alleged that the rates contained in the contracts are unjust and unreasonable. On June 26, 2003, the FERC affirmed the administrative law judge’s initial decision dismissing the complaints. PacifiCorp has appealed the FERC’s order to the United States Court of Appeals for the DC Circuit after the FERC denied rehearing of its order on November 10, 2003.

Investigations of alleged market manipulation

     As a result of various allegations and FERC orders, in 2002 the FERC initiated investigations of manipulation of the California gas and power markets. As they related to us, these investigations included economic and physical withholding, so-called “Enron Gaming Practices” and gas index manipulation.

     Each of these FERC investigations of alleged market manipulation were resolved pursuant to the utility settlement that is discussed above in Refund proceedings.

     As also discussed below in Reporting of natural gas-related information to trade publications, on November 8, 2002, we received a subpoena from a federal grand jury in Northern California seeking documents related to our involvement in California markets. We have completed our response to the subpoena. This subpoena is a part of the broad United Sates Department of Justice (DOJ) investigation regarding gas and power trading.

20

Notes (Continued)

Long-term contracts

     In February 2001, during the height of the California energy crisis, we entered into a long-term power contract with the State of California to assist in stabilizing its market. The State of California later sought to rescind this contract. Following settlement discussions between the State and us on the contract issue as well as other state initiated proceedings and allegations of market manipulation, we entered into a settlement agreement with the State of California and other non-federal parties that includes renegotiated long-term energy contracts. These contracts are made up of block energy sales, dispatchable products and a gas contract. The settlement does not extend to criminal matters or matters of willful fraud, but also resolved civil complaints brought by the California Attorney General against us and the State of California’s refund claims that are discussed above. In addition, the settlement resolved ongoing investigations by the States of California, Oregon and Washington. Certain private class action and other civil plaintiffs who have initiated class action litigation against us and others in California based on allegations against us with respect to the California energy crisis also executed the settlement. On June 29, 2004, the court approved the settlement, making it effective as to plaintiffs and terminating the class actions as to us. An appeal of this order is currently pending. Some litigation by non-California plaintiffs, or relating to reporting of natural gas information to trade publications, as discussed below, will continue. As of September 30, 2004, pursuant to the terms of the settlement, we have transferred ownership of six LM6000 gas powered electric turbines, have made two payments totaling $72 million to the California Attorney General, and have funded a $15 million fee and expense fund associated with civil actions that are subject to the settlement. An additional $75 million remains to be paid to the California Attorney General (or his designee) over the next six years, with the final payment of $15 million due on January 1, 2010.

Reporting of natural gas-related information to trade publications

     We disclosed on October 25, 2002, that certain of our natural gas traders had reported inaccurate information to a trade publication that published gas price indices. As noted above, on November 8, 2002, we received a subpoena from a federal grand jury in Northern California seeking documents related to our involvement in California markets, including our reporting to trade publications for both gas and power transactions. We completed our response to the subpoena. The DOJ’s investigation into this matter is continuing. In addition, the Commodity Futures Trading Commission (CFTC) has conducted an investigation of us regarding this issue. On July 29, 2003, we reached a settlement with the CFTC where in exchange for $20 million, the CFTC closed its investigation and we did not admit or deny allegations that we had engaged in false reporting or attempted manipulation. Civil suits based on allegations of manipulating the gas indices have been brought against us and others in federal court in New York, Washington, Oregon and California and in state court in California.

Investigations related to natural gas storage inventory

     We responded to a subpoena from the CFTC and inquiries from the FERC related to investigations involving natural gas storage inventory issues. Through some of our subsidiaries, we own and operate natural gas storage facilities. On August 30, 2004, the CFTC announced that it had concluded its investigation. The FERC investigation is continuing. The FERC inquiries relate to the sharing of non-public data concerning inventory levels and the potential uses of such data in natural gas trading.

Mobile Bay expansion

     On December 3, 2002, an administrative law judge at the FERC issued an initial decision in Transco’s general rate case which, among other things, rejected the recovery of the costs of Transco’s Mobile Bay expansion project from its shippers on a “rolled-in” basis and found that incremental pricing for the Mobile Bay expansion project is just and reasonable. The administrative law judge’s initial decision is subject to review by the FERC. On March 26, 2004, the FERC issued an Order on Initial Decision in which it reversed the administrative law judge’s holding and accepted Transco’s proposal for rolled-in rates. Power holds long-term transportation capacity on the Mobile Bay expansion project. If the FERC had adopted the decision of the administrative law judge on the pricing of the Mobile Bay expansion project and also required that the decision be implemented effective September 1, 2001, Power could have been subject to surcharges of approximately $55 million, excluding interest, through September 30, 2004, in addition to increased costs going forward. On April 26, 2004, several parties, including Transco filed requests for rehearing of the FERC’s March 26, 2004 order.

21

Notes (Continued)

Enron bankruptcy

     We have outstanding claims against Enron Corp. and various of its subsidiaries (collectively “Enron”) related to Enron’s bankruptcy filed in December 2001. In March 2002, we sold $100 million of our claims against Enron to a third party for $24.5 million. On December 23, 2003, Enron filed objections to these claims. Under the sales agreement, the purchaser of the claims may demand repayment of the purchase price, plus interest assessed at an annual rate of 7.5 percent, for that portion of the claims still subject to objections beginning 90 days following the initial objection. To date, the purchaser has not demanded repayment.

Environmental matters

Continuing operations

     Since 1989, our Transco subsidiary has had studies underway to test certain of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. Transco has responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of its sites. Transco has identified polychlorinated biphenyl (PCB) contamination in compressor systems, soils and related properties at certain compressor station sites. Transco has also been involved in negotiations with the EPA and state agencies to develop screening, sampling and cleanup programs. In addition, Transco commenced negotiations with certain environmental authorities and other programs concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. The costs of any such remediation will depend upon the scope of the remediation. At September 30, 2004, Transco had accrued liabilities of $26 million related to PCB contamination, potential mercury contamination, and other toxic and hazardous substances.

     We also accrued environmental remediation costs for our natural gas gathering and processing facilities, primarily related to soil and groundwater contamination. At September 30, 2004, we had accrued liabilities totaling approximately $8 million for these costs.

     Actual costs incurred for these matters will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by the EPA and other governmental authorities and other factors.

     In August 2004, the New Mexico Environment Department (NMED) issued a Notice of Violation (NOV) to one of our subsidiaries, Williams Field Services Company (WFS), alleging various air permit violations primarily related to WFS’s alleged failure to control volatile organic compound emissions from three conventional dehydrators in 2001. The NOV specified that the maximum statutory penalty for such violations is approximately $13.7 million. NMED and WFS are negotiating a possible resolution to this matter and WFS anticipates that any proposed penalty will be significantly lower than the maximum statutory amount. Additionally, in August 2004, WFS discovered and self-disclosed to the NMED that WFS was out of compliance with certain requirements of the operating permit issued under Title V of the Clean Air Act Amendments of 1990 at the Kutz gas processing plant. NMED and WFS are also negotiating a possible resolution to this matter.

Former operations, including operations classified as discontinued

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

Agrico

     In connection with the 1987 sale of the assets of Agrico Chemical Company, we agreed to indemnify the purchaser for environmental cleanup costs resulting from certain conditions at specified locations to the extent such costs exceed a specified amount. At September 30, 2004, we had accrued liabilities of approximately $10 million for such excess costs.

     We are also in discussions with defendants involved in two settled class action damages lawsuits involving one former chemical fertilizer site in Florida. We were not a named defendant in the lawsuits, but have contractual obligations to participate with the named defendants in the ongoing remediation. One named defendant has filed a motion to compel us to participate in arbitration over the contractual obligations for a site in Florida. A hearing was held on that motion on September 2, 2004, and we await the court’s ruling.

Williams Energy Partners

     As part of our June 17, 2003 sale of Williams Energy Partners (see Note 6), we indemnified the purchaser for:

(1)		environmental cleanup costs resulting from certain conditions, primarily soil and groundwater contamination, at specified locations, to the extent such costs exceed a specified amount, and
(2)		currently unidentified environmental contamination relating to operations prior to April 2002 and identified prior to April 2008.

22

Notes (Continued)

     On May 26, 2004, the parties reached an agreement for buyout of certain indemnities in the form of a structured cash settlement totaling $117.5 million (see Note 11). Yearly payments will be made through 2007. The agreement releases us from all environmental indemnity obligations under the June 2003 sale of Williams Energy Partners and two related agreements. We are now indemnified by the purchaser for third party environmental claims made against us for claims covered under the June 2003 purchase and sale agreement (Williams Energy Partners PSA) and related agreements as well as all environmental occurrences before the closing date of the Williams Energy Partners PSA. The agreement also transferred most third party litigation matters related to Williams Energy Partners’ assets to the purchaser.

     On July 2, 2001, the EPA issued an information request asking for information on oil releases and discharges in any amount from our pipelines, pipeline systems, and pipeline facilities used in the movement of oil or petroleum products, during the period from July 1, 1998 through July 2, 2001. In November 2001, we furnished our response. On March 11, 2004, the DOJ invited the new owner of Williams Energy Partners, Magellan Midstream Partners, L.P. (Magellan), to enter into negotiations regarding alleged violations of the Clean Water Act and to sign a tolling agreement. No penalty has been assessed by the EPA; however, the DOJ stated in its letter that the maximum possible penalties were approximately $22 million for the alleged violations. It is anticipated that by providing additional clarification and through negotiations with the EPA and DOJ, that any proposed penalty will be reduced. All environmental indemnity obligations to Magellan were released in the May 26, 2004 buyout agreement described above. We will participate in the EPA and DOJ negotiations and respond to requests for information related to three release events not related to Magellan-owned assets.

Other

     At September 30, 2004, we had accrued environmental liabilities totaling approximately $17 million related primarily to our:

•

potential indemnification obligations to purchasers of our former retail petroleum and refining operations;

•

former propane marketing operations, petroleum products and natural gas pipelines;

•

a discontinued petroleum refining facility; and

•

exploration and production and mining operations.

     These costs include (1) certain conditions at specified locations related primarily to soil and groundwater contamination and (2) any penalty assessed on Williams Refining & Marketing, LLC (Williams Refining) associated with noncompliance with EPA’s benzene waste “NESHAP” regulations. In 2002, Williams Refining submitted to the EPA a self-disclosure letter indicating noncompliance with those regulations. This unintentional noncompliance had occurred due to a regulatory interpretation that resulted in under-counting the total annual benzene level at Williams Refining’s Memphis refinery. Also in 2002, the EPA conducted an all-media audit of the Memphis refinery. On August 25, 2004, Williams Refining and its new owner met with the EPA and the DOJ to discuss alleged violations and proposed penalties due to noncompliance issues identified in the multi-media report, including the benzene NESHAP issue. Discussion between the EPA, the DOJ and Williams Refining will continue on December 7, 2004, and are expected to continue into 2005 to resolve the allegations of noncompliance. In connection with the sale of the Memphis refinery in March 2003, we agreed to indemnify the purchaser for any such penalty.

     We are a plaintiff in litigation involving the environmental investigation and subsequent cleanup of our former retail petroleum and refining operations. In April 2004, we received a court order to participate in mediation before the end of June with the defendant to attempt to reach a settlement prior to going to trial. Mediation began in June and discussions are ongoing.

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

23

Notes (Continued)

Summary of environmental matters

     Actual costs incurred for these matters could be substantially greater than amounts accrued depending on the actual number of contaminated sites identified, the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA and other governmental authorities and other factors.

Other legal matters

Royalty indemnifications

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

     As a result of these settlements, Transco has been sued by certain producers seeking indemnification from Transco. Transco is currently a defendant in one lawsuit in which a producer has asserted damages, including interest calculated through September 30, 2004, of approximately $10 million. On July 11, 2003, at the conclusion of the trial, the judge ruled in Transco’s favor and subsequently entered a formal judgment. The plaintiff is seeking an appeal.

Will Price (formerly Quinque)

     On June 8, 2001, fourteen of our entities were named as defendants in a nationwide class action lawsuit which had been pending against other defendants, generally pipeline and gathering companies, for more than one year. The plaintiffs allege that the defendants, including us, have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs. After the court denied class action certification and while motions to dismiss for lack of personal jurisdiction were pending, the court granted the plaintiffs’ motion to amend their petition on July 29, 2003. The fourth amended petition, which was filed on July 29, 2003, deletes all of our defendants except two Midstream subsidiaries. All defendants intend to continue their opposition to class certification.

Grynberg

     In 1998, the DOJ informed us that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against us and certain of our wholly owned subsidiaries. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In connection with our sale of Kern River and Texas Gas, we agreed to indemnify the purchasers for any liability relating to this claim, including legal fees. The maximum amount of future payments that we could potentially be required to pay under these indemnifications depends upon the ultimate resolution of the claim and cannot currently be determined. Grynberg has also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. On April 9, 1999, the DOJ announced that it was declining to intervene in any of the Grynberg qui tam cases, including the action filed in federal court in Colorado against us. On October 21, 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tam cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. Grynberg’s measurement claims remain pending against us and the other defendants; the court previously dismissed Grynberg’s royalty valuation claims.

24

Notes (Continued)

     On August 6, 2002, Jack J. Grynberg, and Celeste C. Grynberg, Trustee on Behalf of the Rachel Susan Grynberg Trust, and the Stephen Mark Grynberg Trust, served us and one of our Exploration & Production subsidiaries with a complaint in the state court in Denver, Colorado. The complaint alleges that the defendants have used mismeasurement techniques that distort the BTU heating content of natural gas, resulting in the alleged underpayment of royalties to Grynberg and other independent natural gas producers. The complaint also alleges that defendants inappropriately took deductions from the gross value of their natural gas and made other royalty valuation errors. Under various theories of relief, the plaintiff is seeking actual damages of between $2 million and $20 million based on interest rate variations and punitive damages in the amount of approximately $1.4 million dollars. Our motion to stay the proceedings in this case based on the pendency of the False Claims Act litigation discussed in the preceding paragraph was granted in January 2003. In September 2004, Grynberg moved to lift the stay and filed an amended complaint against one of our Exploration & Production subsidiaries.

Securities class actions

     Numerous shareholder class action suits have been filed against us in the United States District Court for the Northern District of Oklahoma. The majority of the suits allege that we and co-defendants, WilTel Communications (WilTel), previously an owned subsidiary known as Williams Communications, and certain corporate officers, have acted jointly and separately to inflate the stock price of both companies. Other suits allege similar causes of action related to a public offering in early January 2002, known as the FELINE PACS offering. These cases were filed against us, certain corporate officers, all members of our board of directors and all of the offerings’ underwriters. These cases have all been consolidated and an order has been issued requiring separate amended consolidated complaints by our equity holders and WilTel equity holders. The underwriter defendants have requested indemnification from these cases. If granted, costs incurred as a result of these indemnifications will not be covered by our insurance policies. The amended complaint of the WilTel securities holders was filed in September 2002, and the amended complaint of our securities holders was filed in October 2002. This amendment added numerous claims related to Power. On April 2, 2004, the purported class of our securities holders filed a partial motion for summary judgment with respect to certain disclosures made in connection with our public offerings during the class period. Derivative shareholder suits have been filed in state court in Oklahoma, all based on similar allegations. The state court approved motions to consolidate and to stay these Oklahoma suits pending action by the federal court in the shareholder suits.

     In addition, four class action complaints have been filed against us, the members of our board of directors and members of our benefits and investment committees under the Employee Retirement Income Security Act (ERISA) by participants in our 401(k) plan. A motion to consolidate these suits has been approved. In July 2003, the court dismissed us and our board from the ERISA suits, but not the members of the benefits and investment committees to whom we might have an indemnity obligation. If it is determined that we have an indemnity obligation, we expect that any costs incurred will be covered by our insurance policies. The U.S. Department of Labor is also independently investigating our employee benefit plans. On May 3, 2004, plaintiffs requested permission to amend their complaint to add additional investment committee members and to again name the board of directors. That permission was granted June 7, 2004, and a motion to dismiss was filed on behalf of the board on July 15, 2004.

Oklahoma securities investigation

     On April 26, 2002, the Oklahoma Department of Securities issued an order initiating an investigation of us and WilTel regarding issues associated with the spin-off of WilTel and regarding the WilTel bankruptcy. We have no pending inquiries in this investigation, but are committed to cooperate fully in the investigation.

Shell offshore litigation

     On November 30, 2001, Shell Offshore, Inc. filed a complaint at the FERC against four of our subsidiaries, including Williams Field Services Company (WFS) and Transco, alleging concerted actions by the affiliates frustrating the FERC’s regulation of Transco. The alleged actions are related to offers of gathering service by WFS and its subsidiaries on the deregulated North Padre Island offshore gathering system. In September 2002, the FERC issued an order reasserting jurisdiction over that portion of the North Padre Island facilities previously transferred to WFS. The FERC also determined an unbundled gathering rate for service on these facilities which is to be collected by Transco. On July 13, 2004, the Court of Appeals reversed the FERC’s decision, ruling that FERC’s attempt to impose regulated rates was without legal basis.

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Notes (Continued)

TAPS Quality Bank

     One of our subsidiaries, Williams Alaska Petroleum, Inc. (WAPI) is actively engaged in administrative litigation being conducted jointly by the FERC and the Regulatory Commission of Alaska (RCA) concerning the Trans-Alaska Pipeline System (TAPS) Quality Bank. Primary issues being litigated include the appropriate valuation of the naphtha, heavy distillate, vacuum gas oil and residual product cuts within the TAPS Quality Bank as well as the appropriate retroactive effects of the determinations. Due to the sale of WAPI’s interests on March 31, 2004, no future Quality Bank liability will accrue but we are responsible for any liability that existed as of that date including potential liability for any retroactive payments that might be awarded in these proceedings for the period prior to March 31, 2004. The FERC and RCA presiding administrative law judges rendered their joint and individual initial decisions during the third quarter of 2004. The initial decisions set forth methodologies for determining the valuations of the product cuts under review and also approved the retroactive application of the approved methodologies for the heavy distillate and residual product cuts. Based on our computation and assessment of ultimate ruling terms that would be considered probable, we recorded an accrual of approximately $134 million in the third quarter of 2004. Because the application of certain aspects of the initial decisions are subject to interpretation, we have calculated the reasonably possible impact of the decisions, if fully adopted by the FERC and RCA, to result in additional exposure to us of approximately $32 million more than we have accrued at September 30, 2004. We will be filing a brief on exceptions to the initial decisions to both the FERC and RCA on November 16, 2004, and reply briefs are due on February 1, 2005. Decisions from the Commissions will then be issued, likely before the end of 2005. It is unlikely that we will be required to make any payments with respect to this matter until sometime after the Commission decisions.

Deepwater construction litigation

     On February 12, 2004, Technip Offshore Contractors, Inc. (TOCI) served WFS, as agent for Williams Fields Services — Gulf Coast Company, L.P. and Williams Oil Gathering, L.L.C., with a lawsuit brought in federal court in Houston, Texas. TOCI alleges breach of its contract with us for the construction of export pipelines connected to the Devils Tower Spar in the Gulf of Mexico. TOCI seeks acceleration of our obligation to pay amounts held as retention and payment of almost $10 million for the value of disputed change orders. We have filed counterclaims seeking approximately $7 million arising from damages suffered due to TOCI’s breaches of the contract, including liquidated delay damages. The litigation is in the early stages of discovery. On October 21, 2004, we partially settled the litigation with TOCI, which resulted in the release of the retention amounts and of a lien and in the delivery of various documents and commitments by TOCI. In addition, TOCI posted a letter of credit assuring its completion of certain regulatory approvals. Each party also posted letters of credit covering the value of remaining claims against it. The remaining claims to be litigated total approximately $10 million by TOCI against us and approximately $7 million by us against TOCI.

Colorado royalty litigation

     On June 27, 2002, a royalty owner in the Piceance basin of Colorado filed suit against one of our Exploration & Production subsidiaries alleging that we breached our lease agreements and violated the Colorado Deceptive Trade Practices Act by making various deductions from his royalty payments from 1996 to date. On August 2, 2004, the jury returned its verdict in the amount of $4.1 million for the plaintiff. The verdict included a finding of bad faith which could potentially triple the damage award. The verdict is not yet final pending post-trial motions, but we expect to appeal the verdict if it is not set aside by the court.

San Juan basin gas entitlements

     One of our Exploration & Production subsidiaries is involved in a dispute with another joint interest owner in multiple federal oil and gas units located in the San Juan basin. The dispute involves various accounting issues relating to payout determinations in these federal units and associated claims for retroactive adjustment of entitlements to gas production. We are engaged in discussions with the joint interest owner regarding proper adjustment calculations, and we have proposed to settle these disputes for approximately $11.3 million plus interest of $3 million. We are in the early states of review of additional, unsubstantiated claims recently received from the joint interest owner. These additional claims total approximately $12 million.

Other divestiture indemnifications

     Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided. At September 30, 2004, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on results of operations in the period in which the claim is made.

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Notes (Continued)

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

Summary

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

Commitments

     Power has entered into certain contracts giving it the right to receive fuel conversion services as well as certain other services associated with electric generation facilities that are currently in operation throughout the continental United States. At September 30, 2004, Power’s estimated committed payments under these contracts are approximately $85 million for the remainder of 2004, range from approximately $398 million to $425 million annually through 2017 and decline over the remaining five years to $59 million in 2022. Total committed payments under these contracts over the next eighteen years are approximately $6.4 billion.

Guarantees

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

     In connection with the construction of a joint venture pipeline project, we guaranteed, through a put agreement, certain portions of the joint venture’s project financing in the event of nonpayment by the joint venture. Our potential liability under this guarantee ranges from zero percent to 100 percent of the outstanding project financing, depending on our ability and the other project member’s ability to meet certain performance criteria. As of September 30, 2004, the total outstanding project financing is $32.8 million. While our maximum potential liability is the full amount of the financing, based on an executed Memorandum of Agreement (MOA), our exposure has been significantly reduced. On March 8, 2004, we entered into the MOA, in which the partner in the joint venture assumed 100 percent of project development costs to date as well as responsibility for any ongoing additional costs, pending a final determination of whether the project will go forward. Based on the MOA and the current status of the project, it is highly unlikely that any obligation would be incurred with respect to the project. The put agreement expires in March 2005. We have not accrued any amounts related to the guarantee at September 30, 2004.

     We have guaranteed commercial letters of credit totaling $17 million on behalf of an equity method investee. These expire in January 2005, and have no carrying value.

     We have provided guarantees in the event of nonpayment by our previously owned communications subsidiary, WilTel, on certain lease performance obligations that extend through 2042 and have a maximum potential exposure of approximately $50 million at September 30, 2004. Our exposure declines systematically throughout the remaining term of WilTel’s obligations. The carrying value of these guarantees is approximately $45 million at September 30, 2004 and is recorded as a non-current liability.

     We have provided guarantees on behalf of certain partnerships in which we have an equity ownership interest. These generally guarantee operating performance measures and the maximum potential future exposure cannot be determined. These guarantees continue until we withdraw from the partnerships. No amounts have been accrued at September 30, 2004.

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Notes (Continued)

14. Comprehensive income (loss)

     Comprehensive income (loss) from both continuing and discontinued operations is as follows:

15. Segment disclosures

Segments and reclassification of operations

     Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different technology, marketing strategies and industry knowledge. Other primarily consists of corporate operations and certain continuing operations previously reported within the International and Petroleum Services segments.

     Due in part to FERC Order 2004, management and decision-making control of certain activities were transferred from our Midstream segment. Certain regulated gas gathering assets were transferred from our Midstream segment to our Gas Pipeline segment effective June 1, 2004, and our equity method investment in the Aux Sable gas processing plant and related business were transferred from our Midstream segment to our Power segment effective September 21, 2004. Consequently, the results of operations were similarly reclassified. All periods presented reflect these classifications.

Segments — performance measurement

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

     Power has entered into intercompany interest rate swaps with the corporate parent, the effect of which is included in Power’s segment revenues and segment profit (loss) as shown in the reconciliation within the following tables. The results of interest rate swaps with external counterparties are shown as interest rate swap income (loss) in the Consolidated Statement of Operations below operating income.

     The majority of energy commodity hedging by certain of our business units is done through intercompany derivatives with Power which, in turn, enters into offsetting derivative contracts with unrelated third parties. Power bears the counterparty performance risks associated with unrelated third parties.

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Notes (Continued)

15. Segment disclosures (Continued)

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