UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

For the quarterly period ended June 30, 2004

OR

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.
Index

     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.

1

The Williams Companies, Inc.

*

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, $2.6 million and $85.6 million at December 31, 2003, June 30, 2003 and December 31, 2002, respectively.

See accompanying notes

4

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 initially 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. On July 28, 2004, we completed the sale of three straddle plants in western Canada for approximately $536 million (see Note 6). In addition to these transactions, we currently expect to generate additional proceeds from the sale of assets of approximately $50 to $100 million.

     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 new facilities released approximately $500 million of restricted cash, restricted investments and margin deposits (see Note 12). Also, on May 3, 2004, we entered into a new three-year $1 billion secured revolving credit facility. The revolving credit facility is secured by certain Midstream assets and a guarantee from Williams Gas Pipeline Company, LLC. (WGP) (see Note 12).

     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 $1.17 billion of the notes for purchase (see Note 12). In May 2004, we also repurchased debt of approximately $255 million of various maturities on the open market. Our repurchase of these notes served to decrease debt and will result in reduced annual interest expense.

Power Business Status

     Since mid-2002, we have been pursuing a strategy of exiting the Power business and have worked with financial advisors to assist with this effort. To date, several factors have contributed to the difficulty of achieving a complete exit from this business, including the following with respect to the wholesale power industry:

•		oversupply position in most markets expected through the balance of the decade;
•		slow North American gas supply response to high gas prices; and
•		expectations of hybrid regulated/deregulated market structure for several years.

     As a result of these factors and the size of our Power business, the number of financially viable parties expressing an interest in purchasing the entire business has been 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)

     Because market conditions may change, and we cannot determine the impact of this on a buyer’s point of view, amounts ultimately received in any portfolio sale, contract liquidation or realization may be significantly different from the estimated economic value or carrying values reflected in the Consolidated Balance Sheet. In addition, our tolling agreements are not derivatives and thus have no carrying value in the Consolidated Balance Sheet pursuant to the application of Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). Based on current market conditions, certain of these agreements are forecasted to realize significant future losses. It is possible that we may sell contracts for less than their carrying value or enter into agreements to terminate certain obligations, either of which could result in significant future loss recognition or reductions of future cash flows.

     We continue to evaluate alternatives and discuss our plans and operating strategy for the Power business with our Board of Directors. As an alternative to continuing a plan of pursuing a complete exit from the Power business, we are evaluating whether the benefits of realizing the positive cash flows expected to be generated by this business through continued ownership exceed the benefits of a sale at a depressed price. If we pursue this alternative, we expect to continue our current program of managing this business to minimize financial risk, generate cash and manage existing contractual commitments.

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. 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 June 30, 2004, and results of operations for the three and six months ended June 30, 2004 and 2003 and cash flows for the six months ended June 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 June 30, 2003, include $106.8 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.

     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.

6

Notes (Continued)

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 certain components as discontinued operations (see Note 6).

     During second-quarter 2004, our Board of Directors approved a plan authorizing management to negotiate and facilitate a sale of our straddle plants in western Canada, which were part of the Midstream segment. As a result, these assets and their related income and cash flows are now reported as discontinued operations. In addition, the following components are included as discontinued operations:

•		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;
•		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; and
•		Gulf Liquids New River Project LLC, previously part of the Midstream segment.

     Since May 1995, an entity within our Midstream segment has operated production area facilities owned by entities within our Gas Pipeline segment. These regulated gas gathering assets have been operated pursuant to the terms of an operating agreement. Effective June 1, 2004, and due in part to FERC Order 2004, the operating agreement was terminated and management and decision-making control transferred to the Gas Pipeline segment. Consequently, the results of operations were similarly reclassified. All prior periods 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.

7

Notes (Continued)

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 new 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.

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 (loss) are included in the following tables.

8

Notes (Continued)

5. Provision (benefit) for income taxes

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

     The effective income tax rate benefit for the three months ended June 30, 2004, is greater than the federal statutory rate due primarily to the effect of state income taxes partially offset by net foreign operations and an accrual for income tax contingencies.

     The effective income tax rate benefit for the six months ended June 30, 2004, is less than the federal statutory rate due primarily to net foreign operations and an accrual for income tax contingencies partially offset by the effect of state income taxes.

     The effective income tax rate for the three and six months ended June 30, 2003, is greater than the federal statutory rate due primarily to the financial impairment of certain investments, capital losses generated for which valuation allowances were established, nondeductible expenses and an accrual for income tax contingencies.

9

Notes (Continued)

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 June 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 six months ended June 30, 2004 and June 30, 2003. Income from discontinued operations before income taxes for the six months ended June 30, 2004 includes a first-quarter charge of $17.4 million to increase our accrued liability associated with certain Quality Bank litigation matters (see Note 13).

Summarized assets and liabilities of discontinued operations

     The following table presents the summarized assets and liabilities of discontinued operations as of June 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 June 30, 2004 balances include the Canadian straddle plants, Gulf Liquids and certain remaining working capital amounts of the Alaska refining, retail and pipeline operations. 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.

10

Notes (Continued)

Held for sale at June 30, 2004

Canadian straddle plants

     During second-quarter 2004, our Board of Directors approved a plan to negotiate and facilitate the sale of our three natural gas liquid extraction plants (straddle plants) in western Canada. On July 28, 2004, we closed the sale of these facilities for approximately $536 million in U.S. funds. We expect to recognize a pre-tax gain of approximately $190 million on the sale in third-quarter 2004. 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.

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 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 second half 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 $7.7 million, for a total award to Gulf Liquids of approximately $83.3 million. Winterthur has filed a Petition to Vacate the Arbitration Award in the New York State court.

     Because the final outcome of the arbitration is uncertain, we have not recognized the award in the consolidated financial statements.

2004 completed transactions

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 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. These operations were part of the Midstream segment.

Soda ash operations

     On September 9, 2003, we completed the sale of our soda ash mining facility located in Colorado. During 2003, ongoing sale negotiations continued to provide new information regarding estimated fair value, and, as a result, the carrying value of these assets was adjusted periodically as necessary. We recognized impairment charges of $5 million and $11.1 million during the first and second quarters of 2003, respectively. These impairments are included in (impairments) and gain (loss) on sales 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 of $275.6 million which is included in (impairments) and gain (loss) on sales 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).

11

Notes (Continued)

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 in the preceding table of summarized results of discontinued operations. 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 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 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 in the preceding table of summarized results of discontinued operations. These operations were part of the previously reported Petroleum Services segment.

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.

12

Notes (Continued)

7. Earnings (loss) per share

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

     For the three and six months ended June 30, 2004, approximately 3.5 million and 3.7 million weighted-average stock options, respectively, and approximately 2.8 million and 2.6 million weighted-average unvested deferred shares, respectively, that otherwise would have been included, have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive. The unvested deferred shares will vest over the period from July 2004 to January 2008.

     In addition, for the three and six months ended June 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 earnings per common share as their inclusion would be antidilutive. If no other components used to calculate diluted earnings per share (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 $48.8 million and $97.4 million for the three and six months ended June 30, 2004, respectively.

     Approximately 9.4 million options to purchase shares of common stock with a weighted-average exercise price of $27.43 were outstanding at June 30, 2004, but have been excluded from the computation of diluted earnings per share. Inclusion of these shares would have been antidilutive, as the exercise prices of the options exceeded the second-quarter weighted average market price of the common shares of $11.03 for the three months ended June 30, 2004.

     For the three and six months ended June 30, 2003, approximately 11.3 million and 13 million weighted-average shares, respectively, related to the assumed conversion of 9 7/8 percent cumulative convertible preferred stock have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive. The preferred stock was redeemed in June 2003.

     For the six months ended June 30, 2003, approximately 5.2 million weighted-average shares related to the assumed conversion of convertible debentures, as well as the related interest, were excluded from the computation of diluted earnings per common share 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 $148.4 million.

13

Notes (Continued)

8. Employee benefit plans

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

     The $29 million settlement/curtailment income included in net periodic postretirement (income) expense for the three and six months ended June 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, 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 six months ended June 30, 2004, we contributed $16.5 million to our pension plans and $5.8 million to our other postretirement benefit plans. We presently anticipate contributing approximately an additional $44 million to fund our pension plans in 2004 for a total of approximately $61 million. We presently anticipate contributing approximately an additional $9 million to our other postretirement benefit plans in 2004 for a total of approximately $15 million.

     Net periodic pension income for the three months ended June 30, 2004 includes a favorable adjustment to reflect revised 2004 actuarial information. The improvement results largely from a reduction in the number of employees and higher than expected asset performance.

     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 plan for retirees includes 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 are not reflected in any measures of benefit obligations or other postretirement benefit expense in the financial statements or accompanying notes. In May 2004, the FASB issued FSP No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” This guidance is effective for us beginning in third quarter 2004 and supersedes FSP No. FAS 106-1. We are evaluating the impact of the Act on future obligations of the plan. If the plan is determined to be actuarially equivalent and eligible for the subsidy, the change in the obligation attributable to prior service will be deferred and recognized over future periods beginning in third quarter 2004.

14

Notes (Continued)

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 six months ended June 30, 2004, is $700,000 and $1.7 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.

15

Notes (Continued)

10. Inventories

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

11. Accrued liabilities and other liabilities and deferred income

     On May 27, 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 June 30, 2004, the net present value of this settlement is $107.5 million. Of this amount, $35 million is classified as current and was subsequently paid on July 1, 2004. The remaining amount will be paid in three installments of $27.5 million, $20 million, and $35 million in 2005, 2006, and 2007, respectively.

16

Notes (Continued)

12. Debt and banking arrangements

Notes payable and long-term debt

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

(1)

At June 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.

     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 $30.00 per $1,000.00 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 $96.8 million, were recorded in second-quarter 2004 as early debt retirement costs.

     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 $219 million and could result in an adverse effect with respect to other of our debt instruments, we believe that we will be able to resolve any issues arising from the alleged notice of default without any such results occurring with respect to 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.

     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.

17

Notes (Continued)

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 June 30, 2004, letters of credit totaling $489 million have been issued by the participating financial institution under this facility 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.

     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 (however, we are limited to $.02 per common share under a more restrictive covenant contained in our $800 million 8.625 percent senior unsecured notes);
•		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. At June 30, 2004, letters of credit totaling $181 million have been issued by the participating institutions under this facility and no revolving credit loans were outstanding. We also have a commitment from our agent bank to expand our credit facility by an additional $275 million. Northwest Pipeline Corporation (Northwest) and Transcontinental Gas Pipeline 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.

18

Notes (Continued)

     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 subsequent to 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. 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.

     A summary of significant retirements, payments, prepayments and tenders of long-term debt for the six months ended June 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 $7 million for potential refund as of June 30, 2004.

Issues resulting from California energy crisis

     Power subsidiaries 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 a settlement with the State of California and others that has resolved each of these issues as to the State, and in February 2004 we announced a settlement with certain California utilities that resolves these issues as to such utilities. However, certain of these issues remain open as to the FERC and other non-settling parties.

Refund proceedings

     We and other suppliers of electricity in the California market are the subject of refund proceedings before the FERC. In December 2000, the FERC issued an order initiating the proceeding, which ultimately (by order dated June 19, 2001) established a refund methodology and set a refund period of October 2, 2000 to June 19, 2001. As a result of a hearing to determine refund liability for the market participants, a FERC administrative law judge issued findings on December 12, 2002, that estimated our refund obligation to the ISO at $192 million, excluding emissions costs and interest. The judge estimated that our refund obligation to the California Power Exchange (PX) was $21.5 million, excluding interest. However, the judge estimated that the ISO owes us $246.8 million, excluding interest, and that the PX owes us $17.4 million, excluding interest, and $2.9 million in charge backs. The estimates did not include $17 million in emissions costs that the judge found we are entitled to use as an offset to the refund liability, and the judge’s refund estimates are not based on final mitigated market clearing prices. On March 26, 2003, the FERC acted to largely adopt the judge’s order with a change to the gas methodology used to set the clearing price. As a result, Power recorded a first-quarter 2003 charge for refund obligations of $37 million. Net interest income related to amounts due from the counterparties is approximately $31 million through June 30, 2004. On October 16, 2003, the FERC issued an additional refund order granting rehearing in part and denying rehearing in part. This order is not expected to have a material effect on the refund calculation for us. However, pursuant to the October 16 order, the ISO has been ordered to calculate refunds for the market. This study is expected to be complete in 2004.

     On February 25, 2004, we announced a settlement agreement with California utilities, Southern California Edison and Pacific Gas & Electric (PG&E), to resolve our refund liability to the utilities as well as all other known disputes related to the California energy crisis of 2000 and 2001 (the “Utility Settlement”). We recorded a charge of approximately $33 million in the fourth quarter of 2003 associated with the terms of this settlement. San Diego Gas and Electric also joined in the settlement as a party. The Utility Settlement was filed with the FERC on April 27, 2004 and was approved by the FERC on July 2, 2004 to be effective on July 12, 2004. While only these three utilities were originally parties to the Utility Settlement with us, additional parties have now opted in and the Utility Settlement includes funding for refunds to all buyers in equal kind in the FERC refund period. Should any buyer not opt into the Utility Settlement, the refund amount in the Utility Settlement would be reduced and we would continue to litigate with that buyer regarding the refund issue and amount. Pursuant to this settlement our outstanding receivables for the period of approximately $261 million will be partially offset by our settlement obligation of approximately $136 million. We have received $2 million of our net receivable in the second quarter. During July, we received approximately $104 million of our remaining net $123 million receivable. Approximately the same amount of funds ($109 million) was used on June 24, 2004 to repurchase PG&E receivables previously sold to Bear Stearns. As for the $19 million receivable that remains at the end of July, $16 million is being held in escrow until released by the FERC and $3 million is being held by the PX. Approval by the FERC also resolved FERC investigations into physical and economic withholding. The Utility Settlement also resolved any claims by the settling parties regarding these issues.

     In a separate but related proceeding, certain entities have also asked the FERC to revoke our authority to sell power from California-based generating units at market-based rates, to limit us to cost-based rates for future sales from such units and to order refunds of excessive rates, with interest, retroactive to May 1, 2000, and possibly earlier. As a result of the Utility Settlement, this issue is resolved and we will maintain all existing authorities.

20

Notes (Continued)

     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). 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.

ISO fines

     On July 3, 2002, the ISO announced fines against several energy producers including us, for failure to deliver electricity during the period December 2000 through May 2001. The ISO fined us $25.5 million during this period, which was offset against our claims for payment from the ISO. These amounts will be adjusted as part of the refund proceeding described above. As the result of a settlement reached with the ISO pursuant to a FERC-approved dispute resolution process contained in the ISO tariff, these fines will be significantly reduced through the re-run of the market that takes place in the refund proceeding.

Summer 2002 90-day contracts

     On May 2, 2002, PacifiCorp filed a complaint with the FERC against Power 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.

     On February 13, 2002, the FERC issued an Order Directing Staff Investigation commencing a proceeding titled Fact-Finding Investigation of Potential Manipulation of Electric and Natural Gas Prices prior to the California parties (who include the California Attorney General, the Electricity Oversight Board, the Public Utilities Commission and two investor-owned utilities) filing of their report. Through the investigation, the FERC intends to determine whether “any entity, including Enron Corporation (Enron) (through any of its affiliates or subsidiaries), manipulated short-term prices for electric energy or natural gas in the West or otherwise exercised undue influence over wholesale electric prices in the West since January 1, 2000, resulting in potentially unjust and unreasonable rates in long-term power sales contracts subsequently entered into by sellers in the West.” On May 8, 2002, we received data requests from the FERC related to a disclosure by Enron of certain trading practices in which it may have been engaged in the California market. On May 21, and May 22, 2002, the FERC supplemented the request inquiring as to “wash” or “round-trip” transactions. We responded on May 22, 2002, May 31, 2002, and June 5, 2002, to the data requests. On June 4, 2002, the FERC issued an order to us to show cause why our market-based rate authority should not be revoked as the FERC found that certain of our responses related to the Enron trading practices constituted a failure to cooperate with the staff’s investigation. We subsequently supplemented our responses to address the show cause order. On July 26, 2002, we received a letter from the FERC informing us that it had reviewed all of our supplemental responses and concluded that we responded to the initial May 8, 2002 request.

     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 States Department of Justice (DOJ) investigation regarding gas and power trading.

     Pursuant to an order from the Ninth Circuit, the FERC permitted certain California parties to conduct additional discovery into market manipulation by sellers in the California markets. The California parties sought this discovery in order to potentially expand the scope of the refunds. On March 3, 2003, the California parties submitted evidence from this discovery on market manipulation (“March 3rd Report”). We and other sellers submitted comments regarding the additional evidence on March 20, 2003.

     On March 26, 2003, the FERC issued a Staff Report addressing: (1) Enron trading practices, (2) an allegation in a June 2, 2002 New York Times article that we had attempted to corner the gas market, and (3) the allegations of gas price index manipulation which are discussed in more detail below in Reporting of natural gas-related information to trade publications. The Staff Report cleared us on the issue of cornering the market and contemplated or established further proceedings on the other two issues as to us and numerous other market participants. On June 25, 2003, the FERC issued a series of orders in response to the California parties’ March

21

Notes (Continued)

3rd Report and the Staff Report. These orders resulted in further investigations regarding potential allegations of physical withholding, economic withholding, and a show cause order alleging that various companies engaged in Enron trading practices. On August 29, 2003, we entered into a settlement with the FERC trial staff of all Enron trading practices for approximately $45,000. The settlement was approved by the FERC on January 22, 2004. The investigations of physical and economic withholding are also continuing. Each of these FERC investigations of alleged market manipulation are resolved pursuant to the Utility Settlement that is discussed above in Refund proceedings.

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. This contract was later challenged by the State of California. This challenge resulted in settlement discussions being held between the State and us on the contract issue as well as other state initiated proceedings and allegations of market manipulation. A settlement was reached that resulted in us entering 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. The settlement was reduced to writing and executed on November 11, 2002. The settlement closed on December 31, 2002, after FERC issued an order granting our motion for partial dismissal from the refund proceedings. The dismissal affects our refund obligations to the settling parties, but not to other parties, such as investor-owned utilities. Pursuant to the settlement, the California Public Utilities Commission (CPUC) and California Electricity Oversight Board (CEOB) filed a motion on January 13, 2003 to withdraw their complaints against us regarding the original block energy sales contract. On June 26, 2003, the FERC granted the CPUC and CEOB joint motion to withdraw their respective complaints against us. 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. Final approval by the court is needed to make the settlement effective as to plaintiffs and to terminate the class actions as to us. The Court granted approval on June 29, 2004. Some litigation by non-California plaintiffs, or relating to reporting of natural gas information to trade publications, as discussed below, will continue. As of June 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 natural gas storage inventory issues. We believe that these inquiries are a part of an ongoing general industry-wide investigation. The inquiries relate to the formal reporting of inventory levels, the sharing of non-public data concerning inventory levels, and the potential uses of such data in natural gas trading. Through some of our subsidiaries, we own and operate natural gas storage facilities.

22

Notes (Continued)

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 $50 million, excluding interest, through June 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.

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 7.5 percent per annum, for that portion of the claims still subject to objections 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 under way 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 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 U.S. Environmental Protection Agency (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 June 30, 2004, Transco had accrued liabilities of $27 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 June 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.

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.

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 June 30, 2004, we had accrued liabilities of approximately $10 million for such excess costs.

     We are also in discussions with defendants involved in two class action damages lawsuits involving this former chemical fertilizer business. We are 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.

23

Notes (Continued)

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.

     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. Yearly payments will be made through 2007. The agreement releases Williams from all environmental indemnity obligations under the June 2003 Sale of Williams Energy Partners and two related agreements. Williams is now indemnified by the purchaser for third party environmental claims made against Williams for claims covered under the June 2003 purchase and sale agreement (PSA) and related agreements as well as all environmental occurrences before the closing date of the 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. This matter has not become an enforcement proceeding. On March 11, 2004, the Department of Justice (DOJ) invited the new owner of the Williams Pipe Line, 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. Williams will participate in the EPA/DOJ negotiations and respond to requests for information related to three release events not related to Magellan-owned assets.

Other

     At June 30, 2004, we had accrued environmental liabilities totaling approximately $16 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. The EPA anticipates releasing a report of its audit findings in 2004. The EPA will likely assess a penalty on Williams Refining due to the benzene waste NESHAP issue, but the amount of any such penalty is not known. In connection with the sale of the Memphis refinery in March 2003, we indemnified 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 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 occurred 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.

24

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 June 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. The amounts accrued for these indemnifications are insignificant. 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.

     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 Williams Production RMT Company 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. Theories for relief include breach of contract, breach of implied covenant of good faith and fair dealing, anticipatory repudiation, declaratory relief, equitable accounting, civil theft, deceptive trade practices, negligent misrepresentation, deceit based on fraud, conversion, breach of fiduciary duty, and violations of the state racketeering statute. Plaintiff is seeking actual damages of

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Notes (Continued)

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 on January 15, 2003.

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 underwriters of this offering 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 on September 27, 2002, and the amended complaint of our securities holders was filed on October 7, 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.

     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. On July 14, 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 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. Derivative shareholder suits have been filed in state court in Oklahoma, all based on similar allegations. On August 1, 2002, a motion to consolidate and a motion to stay these Oklahoma suits pending action by the federal court in the shareholder suits was approved.

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 Williams Gas Processing - Gulf Coast Company, L.P. (WGPGCC), Williams Gulf Coast Gathering Company (WGCGC), 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. On September 5, 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. Transco, WGPGCC, WGCGC and WFS believe their actions were reasonable and lawful and each has filed petitions for review of the FERC’s orders with the U.S. Court of Appeals for the District of Columbia. 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.

TAPS Quality Bank

     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. WAPI’s interest in these proceedings is material as the matter involves claims by crude producers and the State of Alaska for retroactive payments plus interest of up to $181 million. Due to the sale of WAPI’s interests on March 31, 2004, no future Quality Bank liability will accrue but any liability that existed as of the date of the sale will remain a Williams liability. Because of the complexity of the issues involved, however, the outcome cannot be predicted with certainty nor can the likely result be quantified. Certain periodic discussions have been held and continue among some of the litigants. Because of the number of parties involved and the diversity of positions, no comprehensive

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Notes (Continued)

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 June 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 a recently 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 June 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 June 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 June 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 June 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.

     Effective June 1, 2004, and due in part to FERC Order 2004, management and decision-making control of certain regulated gas gathering assets was transferred from our Midstream segment to our Gas Pipeline segment. Consequently, the results of operations were similarly reclassified. All prior periods 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).