Williams Companies, Inc

1 FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One) ( X ) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 1999 ------------------------------------------------ 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. - ------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) DELAWARE 73-0569878 ------------------------- ------------------------------------- (State of Incorporation) (IRS Employer Identification Number) ONE WILLIAMS CENTER TULSA, OKLAHOMA 74172 - --------------------------------------- -------------- (Address of principal executive office) (Zip Code) Registrant's telephone number: (918) 573-2000 ----------------------------------- NO CHANGE - ------------------------------------------------------------------------------- Former name, former address and former fiscal year, if changed since last report. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ----- ----- Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date. Class Outstanding at July 30, 1999 ------------------------------ -------------------------------- Common Stock, $1 par value 434,193,549 Shares

2 The Williams Companies, Inc. Index Part I. Financial Information Page Item 1. Financial Statements Consolidated Statement of Income--Three and Six Months Ended June 30, 1999 and 1998 2 Consolidated Balance Sheet--June 30, 1999 and December 31, 1998 3 Consolidated Statement of Cash Flows--Six Months Ended June 30, 1999 and 1998 4 Notes to Consolidated Financial Statements 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 16 Item 3. Quantitative and Qualitative Disclosures about Market Risk 27 Part II. Other Information 28 Item 4. Submission of Matters to a Vote of Security Holders Item 6. Exhibits and Reports on Form 8-K Exhibit 12--Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements Exhibit 27--Financial Data Schedule Certain matters discussed in this report, excluding historical information, include forward-looking statements. Although The Williams Companies, Inc. believes such forward-looking statements are based on reasonable assumptions, no assurance can be given that every objective will be achieved. Such statements are made in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. Additional information about issues that could lead to material changes in performance is contained in The Williams Companies, Inc.'s 1998 Form 10-K. 1

3 The Williams Companies, Inc. Consolidated Statement of Income (Unaudited) (Dollars in millions, except per-share amounts) Three months ended June 30, Six months ended June 30, ------------------------------- ------------------------------- 1999 1998* 1999 1998* ------------ ------------ ------------ ------------ Revenues (Note 15): Gas Pipeline (Note 3) $ 424.5 $ 399.2 $ 891.4 $ 841.4 Energy Services (Note 2) 1,469.7 1,429.7 2,722.8 2,733.9 Communications 504.5 425.0 1,010.5 823.4 Other 23.8 9.8 30.0 23.5 Intercompany eliminations (436.2) (489.4) (684.4) (689.1) ------------ ------------ ------------ ------------ Total revenues 1,986.3 1,774.3 3,970.3 3,733.1 ------------ ------------ ------------ ------------ Segment costs and expenses: Costs and operating expenses 1,431.0 1,259.1 2,873.6 2,682.2 Selling, general and administrative expenses 323.8 248.9 628.5 484.5 Other expense--net (Notes 4 and 5) 33.1 26.3 30.6 58.2 ------------ ------------ ------------ ------------ Total segment costs and expenses 1,787.9 1,534.3 3,532.7 3,224.9 ------------ ------------ ------------ ------------ General corporate expenses 16.6 18.1 33.5 58.9 ------------ ------------ ------------ ------------ Operating income (loss) (Note 15): Gas Pipeline (Note 3) 175.4 153.2 362.2 348.2 Energy Services (Note 4) 104.1 104.6 225.0 196.4 Communications (Note 4) (76.1) (11.8) (127.6) (33.4) Other (5.0) (6.0) (22.0) (3.0) General corporate expenses (Note 5) (16.6) (18.1) (33.5) (58.9) ------------ ------------ ------------ ------------ Total operating income 181.8 221.9 404.1 449.3 Interest accrued (134.6) (126.5) (277.9) (244.5) Interest capitalized 17.5 7.8 26.9 16.0 Investing income 5.6 9.7 12.3 13.4 Minority interest in income of consolidated subsidiaries (3.4) (3.3) (4.0) (5.6) Other income (expense)--net (1.1) (6.6) .2 (7.2) ------------ ------------ ------------ ------------ Income before income taxes, extraordinary loss and change in accounting principle 65.8 103.0 161.6 221.4 Provision for income taxes (Notes 4 and 6) 48.8 42.3 88.7 87.8 ------------ ------------ ------------ ------------ Income before extraordinary loss and change in accounting principle 17.0 60.7 72.9 133.6 Extraordinary loss (Note 7) -- -- -- (4.8) ------------ ------------ ------------ ------------ Income before change in accounting principle 17.0 60.7 72.9 128.8 Change in accounting principle (Note 8) -- -- (5.6) -- ------------ ------------ ------------ ------------ Net income 17.0 60.7 67.3 128.8 Preferred stock dividends .9 1.6 2.5 3.8 ------------ ------------ ------------ ------------ Income applicable to common stock $ 16.1 $ 59.1 $ 64.8 $ 125.0 ============ ============ ============ ============ Basic earnings per common share (Note 9): Income before extraordinary loss and change in accounting principle $ .04 $ .14 $ .16 $ .31 Extraordinary loss (Note 7) -- -- -- (.01) Change in accounting principle (Note 8) -- -- (.01) -- ------------ ------------ ------------ ------------ Net income $ .04 $ .14 $ .15 $ .30 ============ ============ ============ ============ Average shares (thousands) 435,052 426,163 433,580 421,780 Diluted earnings per common share (Note 9) Income before extraordinary loss and change in accounting principle $ .04 $ .14 $ .16 $ .30 Extraordinary loss (Note 7) -- -- -- (.01) Change in accounting principle (Note 8) -- -- (.01) -- ------------ ------------ ------------ ------------ Net income $ .04 $ .14 $ .15 $ .29 ============ ============ ============ ============ Average shares (thousands) 441,746 441,464 439,382 440,254 Cash dividends per common share $ .15 $ .15 $ .30 $ .30 *Certain amounts have been reclassified as described in Note 2 of Notes to Consolidated Financial Statements. See accompanying notes. 2

4 The Williams Companies, Inc. Consolidated Balance Sheet (Unaudited) (Dollars in millions, except per-share amounts) June 30, December 31, 1999 1998* ------------ ------------ ASSETS Current assets: Cash and cash equivalents $ 200.1 $ 503.3 Receivables 1,841.9 1,628.2 Transportation and exchange gas receivable 68.6 96.4 Inventories (Note 10) 569.1 497.5 Energy trading assets 399.0 354.5 Deferred income taxes 240.6 239.9 Other 244.3 166.1 ------------ ------------ Total current assets 3,563.6 3,485.9 Investments 1,341.0 866.1 Property, plant and equipment, at cost 17,244.9 16,206.3 Less accumulated depreciation and depletion (3,806.0) (3,621.0) ------------ ------------ 13,438.9 12,585.3 Goodwill and other intangible assets--net 558.4 583.6 Other assets and deferred charges 1,110.6 1,126.4 ------------ ------------ Total assets $ 20,012.5 $ 18,647.3 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Notes payable (Note 11) $ 1,685.6 $ 1,052.7 Accounts payable 1,214.2 1,158.2 Accrued rate refund liabilities 204.0 358.7 Other accrued liabilities 1,246.7 1,188.9 Energy trading liabilities 317.6 290.1 Long-term debt due within one year (Note 11) 719.4 390.6 ------------ ------------ Total current liabilities 5,387.5 4,439.2 Long-term debt (Note 11) 6,189.7 6,366.4 Deferred income taxes 2,489.3 2,060.8 Other liabilities and deferred income 1,099.2 1,015.2 Minority interest in consolidated subsidiaries 514.3 508.3 Contingent liabilities and commitments (Note 12) Stockholders' equity: Preferred stock, $1 par value, 30 million shares authorized, 1.3 million issued in 1999, 1.8 million in 1998 71.8 102.2 Common stock, $1 par value, 960 million shares authorized, 437.8 million issued in 1999, 432.3 million in 1998 437.8 432.3 Capital in excess of par value 1,089.1 982.4 Retained earnings 2,784.7 2,849.5 Accumulated other comprehensive income 76.3 16.7 Other (82.1) (78.5) ------------ ------------ 4,377.6 4,304.6 Less treasury stock (at cost) 3.8 million shares of common stock in 1999 and 4.0 million in 1998 (45.1) (47.2) ------------ ------------ Total stockholders' equity 4,332.5 4,257.4 ------------ ------------ Total liabilities and stockholders' equity $ 20,012.5 $ 18,647.3 ============ ============ *Certain amounts have been reclassified as discussed in Note 2 of Notes to Consolidated Financial Statements. See accompanying notes. 3

5 The Williams Companies, Inc. Consolidated Statement of Cash Flows (Unaudited) (Millions) Six months ended June 30, ------------------------------ 1999 1998* ------------ ------------ OPERATING ACTIVITIES: Net income $ 67.3 $ 128.8 Adjustments to reconcile to cash provided from operations: Extraordinary loss -- 4.8 Change in accounting principle 5.6 -- Depreciation, depletion and amortization 351.0 305.8 Provision for deferred income taxes 378.6 60.0 Provision for loss on property and other assets 30.7 4.2 Minority interest in income of consolidated subsidiaries 4.0 5.6 Cash provided (used) by changes in assets and liabilities: Receivables sold (8.8) (30.4) Receivables (225.2) 201.9 Inventories (52.5) (47.9) Other current assets (44.9) (46.7) Accounts payable 126.9 (230.1) Accrued rate refund liabilities (154.7) 79.2 Other accrued liabilities 27.6 (48.4) Changes in current energy trading assets and liabilities (16.9) 13.3 Changes in non-current energy trading assets and liabilities 5.9 (14.5) Changes in non-current deferred income 125.1 10.3 Other, including changes in non-current assets and liabilities 49.0 (43.1) ------------ ------------ Net cash provided by operating activities 668.7 352.8 ------------ ------------ FINANCING ACTIVITIES: Proceeds from notes payable 1,307.1 655.1 Payments of notes payable (435.6) (724.4) Proceeds from long-term debt 852.1 1,700.1 Payments of long-term debt (933.5) (821.3) Proceeds from issuance of common stock 124.8 62.9 Dividends paid (132.1) (129.9) Other--net 9.3 30.5 ------------ ------------ Net cash provided by financing activities 792.1 773.0 ------------ ------------ INVESTING ACTIVITIES: Property, plant and equipment: Capital expenditures (1,168.2) (835.3) Proceeds from dispositions and excess fiber capacity transactions 51.0 26.6 Changes in accounts payable and accrued liabilities (82.8) (12.0) Acquisition of business, net of cash acquired (162.9) -- Purchase of investments/advances to affiliates (404.5) (293.8) Other--net 3.4 2.1 ------------ ------------ Net cash used by investing activities (1,764.0) (1,112.4) ------------ ------------ Increase (decrease) in cash and cash equivalents (303.2) 13.4 Cash and cash equivalents at beginning of period 503.3 122.1 ------------ ------------ Cash and cash equivalents at end of period $ 200.1 $ 135.5 ============ ============ *Certain amounts have been reclassified as discussed in Note 2 of Notes to Consolidated Financial Statements. See accompanying notes. 4

6 The Williams Companies, Inc. Notes to Consolidated Financial Statements (Unaudited) 1. General - ------------------------------------------------------------------------------- The accompanying interim consolidated financial statements of The Williams Companies, Inc. (Williams) do not include all notes in annual financial statements and therefore should be read in conjunction with the consolidated financial statements and notes thereto in Williams' Annual Report on Form 10-K. The accompanying financial statements have not been audited by independent auditors but include all adjustments, both normal recurring and others, which, in the opinion of Williams' management, are necessary to present fairly its financial position at June 30, 1999, results of operations for the three and six months ended June 30, 1999 and 1998, and cash flows for the six months ended June 30, 1999 and 1998. Segment profit of operating companies may vary by quarter. Based on current rate structures and/or historical maintenance schedules of certain of its pipelines, Gas Pipeline experiences lower segment profits in the second and third quarters as compared to the first and fourth quarters. 2. Basis of presentation - ------------------------------------------------------------------------------- In fourth-quarter 1998, Williams adopted Statement of Financial Accounting Standards (SFAS) No. 131, "Disclosures about Segments of an Enterprise and Related Information." Beginning January 1, 1999, Communications' 1998 segment results have been restated to include the results of investments in certain Brazilian and Australian telecommunications projects, which had previously been reported in Other segment revenues and profit (loss). These investments, along with businesses previously reported as Network Applications and certain cost-basis investments previously reported in Network Services, are now collectively managed and reported as Strategic Investments. Effective April 1, 1998, certain marketing activities were transferred from other Energy Services segments to Energy Marketing & Trading and combined with its energy risk trading operations. The income statement presentation relating to certain of these operations was changed effective April 1, 1998, on a prospective basis, to reflect these revenues net of the related costs to purchase such items. Activity prior to this date is reflected on a "gross" basis in the Consolidated Statement of Income. Concurrent with completing the combination of such activities with the energy risk trading operations of Energy Marketing & Trading, the related contract rights and obligations of certain of these operations are recorded in the Consolidated Balance Sheet at fair value consistent with Energy Marketing & Trading's accounting policy. Certain other income statement, balance sheet, cash flow and segment asset amounts have been reclassified to conform to the current classifications. 3. Rate refund liability reductions - ------------------------------------------------------------------------------- Based on second-quarter 1999 regulatory proceedings involving rate-of-return methodology, three of the gas pipelines made reductions to certain rate refund liabilities and related interest accruals totaling approximately $51 million, of which $38.2 million is included in Gas Pipeline's segment revenues and segment profit. In addition, $2.7 million is included in Midstream Gas & Liquids segment revenues and segment profit, as a result of its management of certain regulated gathering facilities. The balance of $10.6 million is included as a reduction of interest accrued. 4. Asset impairments and other accruals - ------------------------------------------------------------------------------- Included in second-quarter 1999 other expense-net within segment costs and expenses and Strategic Investments' segment loss are pre-tax charges totaling $26.7 million relating to management's second-quarter decision and commitment to sell certain network application businesses. The $26.7 million charge consists of a $22.8 million impairment of the assets to fair value based on the expected net sales proceeds and $3.9 million in exit costs consisting of contractual obligations and employee-related costs. This transaction resulted in an income tax provision of approximately $7.9 million, which reflects the impact of goodwill not deductible for tax purposes. Segment losses for the operations related to these assets for the three and six months ended June 30, 1999, are $5.0 million and $9.1 million, respectively. Segment losses for the corresponding periods in 1998 were $4.7 million and $9.6 million, respectively. The sale of the audio and video conferencing business was completed on July 31, 1999, with no significant change required to the charges noted above. Included in other expense-net within segment costs and expenses and segment profit for Petroleum Services for the three and six months ended June 30, 1998, is a $15.5 million loss provision, including interest, for potential refunds to customers as a result of an order from the Federal Energy Regulatory Commission (see Note 12 for additional information). 5

7 Notes (continued) 5. Merger-related costs - ------------------------------------------------------------------------------- In connection with the 1998 acquisition of MAPCO Inc., Williams recognized approximately $68 million in merger-related costs comprised primarily of outside professional fees and early retirement and severance costs in the first and second quarters of 1998. Approximately $42 million of these merger-related costs is included in other expense-net within segment costs and expenses and as a component of Energy Services' segment profit, and $26 million, unrelated to the segments, is included in general corporate expenses. 6. Provision for income taxes - ------------------------------------------------------------------------------- The provision (benefit) for income taxes includes: Three months ended Six months ended (Millions) June 30, June 30, -------------------- -------------------- 1999 1998 1999 1998 -------- -------- -------- -------- Current: Federal $ (307.3) $ 19.2 $ (299.5) $ 24.8 State 4.4 .5 7.7 2.0 Foreign 1.0 .4 1.9 1.0 -------- -------- -------- -------- (301.9) 20.1 (289.9) 27.8 Deferred: Federal 345.9 17.6 369.0 50.5 State 4.8 4.6 9.6 9.5 -------- -------- -------- -------- 350.7 22.2 378.6 60.0 -------- -------- -------- -------- Total provision $ 48.8 $ 42.3 $ 88.7 $ 87.8 ======== ======== ======== ======== A federal tax refund of $321 million received in second-quarter 1999 is reflected as a current federal benefit with an offsetting deferred federal provision attributable to temporary differences between the book and tax basis of certain assets. The effective income tax rate for 1999 is greater than the federal statutory rate due primarily to the effects of state income taxes and the impact of goodwill not deductible for tax purposes related to assets impaired during the second quarter (see Note 4). The effective income tax rate for 1998 is greater than the federal statutory rate due primarily to the effects of state income taxes. 7. Extraordinary loss - ------------------------------------------------------------------------------- In 1998, Williams paid $54.4 million to redeem higher interest rate debt for a $4.8 million net loss (net of a $2.6 million benefit for income taxes). 8. Change in accounting principle - ------------------------------------------------------------------------------- Effective January 1, 1999, Williams adopted Statement of Position (SOP) 98-5, "Reporting on the Costs of Start-Up Activities." The SOP requires that all start-up costs be expensed as incurred, and the expense related to the initial application of this SOP of $5.6 million (net of a $3.6 million benefit for income taxes) is reported as the cumulative effect of a change in accounting principle. Additionally, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" which was adopted first-quarter 1999. The effect of initially applying the consensus at January 1, 1999, is immaterial to Williams' results of operations and financial position. In June 1999, the Financial Accounting Standards Board (FASB) issued interpretation No. 43, "Real Estate Sales, an interpretation of SFAS No. 66," which is effective for sales of real estate with property improvements or integral equipment entered into after June 30, 1999. Under this interpretation, sales-type lease accounting will not be appropriate for excess dark fiber capacity transactions entered into after June 30, 1999, and, therefore, unless title to the fibers under the lease transfers to the lessee, these transactions will be accounted for as operating leases. Williams has not assessed the effects of this FASB interpretation on its future operating results. 6

8 Notes (continued) 9. Earnings per share - ------------------------------------------------------------------------------- Basic and diluted earnings per common share are computed for the three and six months ended June 30, 1999 and 1998, as follows: (Dollars in millions, except per-share amounts; shares in Three months Six months thousands) ended June 30, ended June 30, --------------------------- --------------------------- 1999 1998 1999 1998 ------------ ------------ ------------ ------------ Income before extraordinary loss and change in accounting principle $ 17.0 $ 60.7 $ 72.9 $ 133.6 Preferred stock dividends .9 1.6 2.5 3.8 ------------ ------------ ------------ ------------ Income before extraordinary loss and change in accounting principle available to common stockholders for basic earnings per share 16.1 59.1 70.4 129.8 Effect of dilutive securities: Convertible preferred stock dividends -- 1.6 -- 3.8 ------------ ------------ ------------ ------------ Income before extraordinary loss and change in accounting principle available to common stockholders for diluted earnings per share $ 16.1 $ 60.7 $ 70.4 $ 133.6 ============ ============ ============ ============ Basic weighted-average shares 435,052 426,163 433,580 421,780 Effect of dilutive securities: Convertible preferred stock -- 9,646 -- 10,392 Stock options 6,694 5,655 5,802 8,082 ------------ ------------ ------------ ------------ 6,694 15,301 5,802 18,474 ------------ ------------ ------------ ------------ Diluted weighted-average shares 441,746 441,464 439,382 440,254 ============ ============ ============ ============ Earnings per common share before extraordinary loss and change in accounting principle: Basic .04 .14 .16 .31 Diluted .04 .14 .16 .30 ------------ ------------ ------------ ------------ For the three and six months ended June 30, 1999, approximately 6.4 million shares and 7.1 million shares, respectively, related to the assumed conversion of $3.50 convertible preferred stock have been excluded from the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive. 10. Inventories - ------------------------------------------------------------------------------- June 30, December 31, (Millions) 1999 1998 ---------- ---------- Raw materials: Crude oil $ 44.5 $ 43.2 Other 1.9 2.0 ---------- ---------- 46.4 45.2 Finished goods: Refined products 168.0 104.0 Natural gas liquids 42.4 58.6 General merchandise and communications equipment 119.6 92.8 ---------- ---------- 330.0 255.4 ---------- ---------- Materials and supplies 98.9 93.4 Natural gas in underground storage 91.7 95.7 Other 2.1 7.8 ---------- ---------- $ 569.1 $ 497.5 ========== ========== 11. Debt and banking arrangements - ------------------------------------------------------------------------------- NOTES PAYABLE In April 1999, Williams' communications business entered into a $1.4 billion temporary short-term bank-credit facility, guaranteed by Williams. Communications expects to replace this facility with a permanent bank-credit facility in the third quarter of 1999. At June 30, 1999, $610 million was outstanding under the temporary credit facility. During 1999, Williams increased its commercial paper program to $1.4 billion, backed by a short-term bank-credit facility. At June 30, 1999, $1.2 billion of commercial paper was outstanding under the program. Interest rates vary with current market conditions. DEBT Williams also has a $1 billion credit agreement under which Northwest Pipeline, Transcontinental Gas Pipe Line, Texas Gas Transmission, Williams Communications Solutions, LLC and Williams Communications Group, Inc. have access to varying amounts of the facility, while Williams has access to all unborrowed amounts. Interest rates vary with current market conditions. 7

9 Notes (continued) Debt -------------------------------------- Weighted- average interest June 30, December 31, (Millions) rate* 1999 1998 ---------- ---------- ---------- Revolving credit loans 5.8% $ 450.0 $ 694.0 Commercial paper 5.5 237.0 -- Debentures, 6.25% - 7.7%, payable 2001 - 2027 (1) 6.4 935.4 935.4 Debentures, 8.875% - 10.25%, payable 2003 - 2022 8.3 169.7 169.7 Notes, 5.1% - 7.6%, payable through 2012 (2) 6.3 3,828.8 3,871.6 Notes, 8.2% - 9.625%, payable through 2022 8.8 693.3 691.0 Notes, adjustable rate, payable through 2004 6.0 585.0 386.7 Other, payable through 2005 8.5 9.9 8.6 ---------- ---------- ---------- 6,909.1 6,757.0 Current portion of long-term debt (719.4) (390.6) ---------- ---------- $ 6,189.7 $ 6,366.4 ========== ========== * At June 30, 1999, including the effects of interest-rate swaps. (1) $200 million, 7.08% debentures, payable 2026, are subject to redemption at par at the option of the debtholder in 2001. (2) $300 million, 5.95% notes, payable 2010, and $240 million, 6.125% notes, payable 2012, are subject to redemption at par at the option of the debtholder in 2000 and 2002, respectively. Subsequent to June 30, 1999, Williams issued $700 million of 7.625 percent fixed rate notes due 2019. The proceeds from this issuance were used to pay off $450 million of obligations under William's $1 billion credit agreement and $237 million of commercial paper. As a result, $237 million of commercial paper is classified as a non-current obligation for financial reporting purposes at June 30, 1999. An additional $150 million in current debt obligations have been classified as non-current based on Williams' intent and ability to refinance on a long-term basis. At June 30, 1999, the amount available on the $1 billion credit agreement of $550 million is sufficient to complete the refinancing of these obligations. 12. Contingent liabilities and commitments - ------------------------------------------------------------------------------- Rate and regulatory matters and related litigation Williams' interstate pipeline subsidiaries, including Williams Pipe Line, 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 $189 million for potential refund as of June 30, 1999. In 1997, the Federal Energy Regulatory Commission (FERC) issued orders addressing, among other things, the authorized rates of return for three of the Williams interstate natural gas pipeline subsidiaries. All of the orders involve rate cases that became effective between 1993 and 1995 and, in each instance, these cases have been superseded by more recently filed rate cases. In the three orders, the FERC continued its practice of utilizing a methodology for calculating rates of return that incorporates a long-term growth rate component. However, the long-term growth rate component used by the FERC is now a projection of U.S. gross domestic product growth rates. Generally, calculating rates of return utilizing a methodology which includes a long-term growth rate component results in rates of return that are lower than they would be if the long-term growth rate component were not included in the methodology. Each of the three pipeline subsidiaries challenged its respective FERC order in an effort to have the FERC change its rate-of-return methodology with respect to these and other rate cases. On January 30, 1998, the FERC convened a public conference to consider, on an industry-wide basis, issues with respect to pipeline rates of return. In July 1998, the FERC issued orders in two of the three pipeline subsidiary rate cases, again modifying its rate-of-return methodology by adopting a formula that gives less weight to the long-term growth component. Certain parties are appealing the FERC's action, because the most recent formula modification results in somewhat higher rates of return compared to the rates of return calculated under the FERC's prior formula. In June and July 1999, the FERC applied the new methodology in the third pipeline subsidiary rate case, as well as in a fourth case involving the same pipeline subsidiary. As a result of these orders and developments in certain other regulatory proceedings in the second quarter, each of the three gas pipeline subsidiaries made reductions to its accrued liability for rate refunds to reflect application of the new rate-of-return methodology (see Note 3). In 1992, the FERC issued Order 636, Order 636-A and Order 636-B. These orders, which were challenged in various respects by various parties in proceedings ruled on by the U.S. Court of Appeals for the D.C. Circuit, required interstate gas pipeline companies to change the manner in which they provide services. Williams' gas pipelines subsidiaries implemented restructurings in 1993. The only appeal challenging Northwest Pipeline's restructuring has been dismissed. On April 14, 1998, all appeals concerning Transcontinental Gas Pipe Line's restructuring were denied by the D.C. Circuit. Williams Gas Pipelines Central's restructuring appeal was remanded to the FERC. The appeal of Texas Gas' restructuring remains pending. On February 27, 1997, the FERC issued Order No. 636-C in response to the D.C. Circuit's partial remand of the three previous 636 orders. In that order, the FERC reaffirmed that pipelines should be exempt from sharing gas supply realignment costs. Rehearing of Order 636-C was denied in Order 636-D. Orders 636-C and 636-D have been appealed. Recently, the FERC issued a Notice of Proposed Rulemaking (NOPR) and a Notice of Inquiry (NOI), proposing revisions to regulatory policies for interstate natural gas transportation service. In the NOPR, the FERC proposes to eliminate the rate cap on short-term transportation services and implement regulatory policies that are intended to maximize competition in the short- 8

10 Notes (continued) term transportation market, mitigate the ability of firms to exercise residual monopoly power and provide opportunities for greater flexibility in the provision of pipeline services and to revise certain other rate and certificate policies. In the NOI, the FERC seeks comments on its pricing policies in the existing long-term market and pricing policies for new capacity. Williams filed comments on the NOPR and NOI in the second quarter of 1999. As a result of the Order 636 decisions described, each of the natural gas pipeline subsidiaries has undertaken the reformation or termination of its respective gas supply contracts. None of the pipelines has any significant pending supplier take-or-pay, ratable take or minimum take claims. During second-quarter 1999, Williams Gas Pipelines Central (Central) reached an agreement with its customers, State Commissions and FERC staff concerning recovery of certain gas supply realignment costs which arose from supplier take-or-pay contracts. Current FERC policy associated with Orders 436 and 500 requires interstate gas pipelines to absorb some of the cost of reforming gas supply contracts before allowing any recovery through direct bill or surcharges to transportation as well as sales commodity rates. Under Orders 636, 636-A, 636-B, 636-C and 636-D, costs incurred to comply with these rules are permitted to be recovered in full, although a percentage of such costs must be allocated to interruptible transportation service. Pursuant to a stipulation and agreement approved by the FERC, Central has made 17 filings to recover take-or-pay and gas supply realignment costs of $201.3 million from its customers. An intervenor filed a protest seeking to have the FERC review the prudence of certain of the costs covered by these filings. On July 31, 1996, the administrative law judge issued an initial decision rejecting the intervenor's prudency challenge. On September 30, 1997, the FERC, by a two-to-one vote, reversed the administrative law judge's decision and determined that three contracts were imprudently entered into in 1982. Central filed for rehearing, and management has vigorously defended the prudency of these contracts. An intervenor also filed a protest seeking to have the FERC decide whether non-settlement costs are eligible for recovery under Order No. 636. In January 1997, the FERC held that none of the non-settlement costs and only 75 percent of settlement costs could be recovered by Central if the costs were not eligible for recovery under Order No. 636. This order was affirmed on rehearing in April 1997. On June 16, 1998, a FERC administrative law judge issued an initial decision finding that Central had not met all the tests necessary to show that these costs were eligible for recovery under Order No. 636. On July 20, 1998, Central filed exceptions to the administrative law judge's decision. On May 29, 1998, the FERC approved an Order which permitted Central to conduct a reverse auction of the gas purchase contracts which are the subject of the prudence challenges outlined above. No party bid less than the fixed maximum price in the approved auction and, as a result, the contracts were not assigned. In accordance with the FERC's Orders, on September 30, 1998, Central filed a request for authority to conduct a second reverse auction of the contracts. Under the approved reverse auction, Central was granted authority to assign the contracts to bidders at or below an aggregate reserve price of $112.6 million. If no unaffiliated bidders were willing to accept assignment on those terms, Central was authorized to assign the contracts to an affiliate or a third party and recover $112.6 million from its customers subject to the outcome of the prudence and eligibility cases described above. The FERC also approved an extension of the recovery mechanism for non-settlement costs through February 1, 1999. On January 21, 1999, Central assigned its obligations under the largest of the three contracts to an unaffiliated third party and paid the third party $100 million. Central also agreed to pay the third party a total of $18 million in installments over the next five years. Central received indemnities from the third party and a release of its obligations under the contract. No parties submitted bids at the second reverse auction, and in accordance with the tariff provisions for the reverse auction, Central assigned the two smaller contracts to an affiliate effective February 1, 1999. As a result of these assignments, Central has no remaining above-market price gas contracts. Central has filed with the FERC to recover all costs related to the three contracts. Central has been negotiating with the FERC and state regulators to resolve the amount of costs which are recoverable from its customers. As a result of these negotiations, Central expensed $58 million of costs previously expected to be recovered and capitalized as a regulatory asset in 1998. At June 30, 1999, Central had a $52.8 million regulatory asset representing an estimate of costs to be recovered in the future. On April 21, 1999, Central reached an agreement in principle with the FERC staff, the state commissions, and its customers on all issues related to recovery of Central's remaining take-or-pay and gas supply realignment costs. The settlement resolves all prudence, eligibility and absorption issues at a level consistent with Central's established accruals at June 30, 1999, and provides that Central would be allowed to recover the costs allocated to its customers by means of a direct bill to be paid, in some instances, over time. On June 18, 1999, Central filed a proposed stipulation and agreement with the FERC which documents the April 21 settlement. One interested party objected to the settlement, which is subject to FERC approval. The chief administrative law judge dismissed the objection and certified the settlement as "uncontested" to the FERC on July 28, 1999. In September 1995, Texas Gas received FERC approval of a settlement regarding Texas Gas' recovery of gas supply realignment costs. Through June 30, 1999, Texas Gas has paid approximately $76 million and expects to pay no more than $80 million for gas supply realignment costs, primarily as a result of contract terminations. Texas Gas has recovered approximately $66 million, plus interest, in gas supply realignment costs. On June 1, 1999, Texas Gas filed with the FERC under the 9

11 Notes (continued) provisions of Order No. 528 to recover 75 percent of approximately $1.8 million in costs it has been required to pay pursuant to indemnifications for royalties. Texas Gas began collecting these costs subject to refund effective July 1, 1999, pursuant to a FERC order. The foregoing accruals are in accordance with Williams' accounting policies regarding the establishment of such accruals which take into consideration estimated total exposure, as discounted and risk-weighted, as well as costs and other risks associated with the difference between the time costs are incurred and the time such costs are recovered from customers. The estimated portion of such costs recoverable from customers is deferred or recorded as a regulatory asset based on an estimate of expected recovery of the amounts allowed by the FERC policy. While Williams believes that these accruals are adequate and the associated regulatory assets are appropriate, costs actually incurred and amounts actually recovered from customers will depend upon the outcome of various court and FERC proceedings, the success of settlement negotiations and various other factors, not all of which are presently foreseeable. On July 15, 1998, Williams Pipe Line (WPL) received an Order from the FERC which affirmed an administrative law judge's 1996 initial decision regarding rate-making proceedings for the period September 15, 1990, through May 1, 1992. The FERC has ruled that WPL did not meet its burden of establishing that its transportation rates in its 12 noncompetitive markets were just and reasonable for the period and has ordered refunds. WPL continues to believe it should prevail upon appeal regarding collected rates for that period. However, due to this FERC decision, WPL accrued $15.5 million, including interest, in the second quarter of 1998, for potential refunds to customers for the issues described above. Since May 1, 1992, WPL has collected and recognized as revenues $170 million in noncompetitive markets that are in excess of tariff rates previously approved by the FERC and that are subject to refund with interest. WPL believes that the tariff rates collected in these markets during this period will be justified in accordance with the FERC's cost-basis guidelines and will be making the appropriate filings with the FERC to support this position. On May 20, 1999, WPL submitted an uncontested offer of settlement to the presiding administrative law judge that, if approved by the FERC, would resolve all outstanding rate issues on WPL from September 1, 1990 to the present. This settlement was certified to the FERC as uncontested on June 23, 1999. WPL is currently awaiting FERC action on the settlement. Environmental matters Since 1989, Texas Gas and Transcontinental Gas Pipe Line have had studies under way to test certain of their facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. Transcontinental Gas Pipe Line has responded to data requests regarding such potential contamination of certain of its sites. The costs of any such remediation will depend upon the scope of the remediation. At June 30, 1999, these subsidiaries had reserves totaling approximately $26 million for these costs. Certain Williams subsidiaries, including Texas Gas and Transcontinental Gas Pipe Line, 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. Although no assurances can be given, Williams does not believe that these obligations or the PRP status of these subsidiaries will have a material adverse effect on its financial position, results of operations or net cash flows. Transcontinental Gas Pipe Line, Texas Gas and Central have identified polychlorinated biphenyl (PCB) contamination in air compressor systems, soils and related properties at certain compressor station sites. Transcontinental Gas Pipe Line, Texas Gas and Central have 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, negotiations with certain environmental authorities and other programs concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites have been commenced by Central, Texas Gas and Transcontinental Gas Pipe Line. As of June 30, 1999, Central had recorded a liability for approximately $11 million, representing the current estimate of future environmental cleanup costs to be incurred over the next six to ten years. Texas Gas and Transcontinental Gas Pipe Line likewise had recorded liabilities for these costs which are included in the $26 million reserve mentioned above. Actual costs incurred will depend 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. Texas Gas, Transcontinental Gas Pipe Line and Central have deferred these costs as incurred pending recovery through future rates and other means. Transco received a letter stating that the U.S. Department of Justice (DOJ), at the request of the EPA, intends to file a civil action against Transco arising from its waste management practices at Transco's compressor stations and metering stations in eleven states from Texas to New Jersey. DOJ stated in the letter that its complaint will seek civil penalties and injunctive relief under federal environmental laws. DOJ has offered to discuss settlement of the claim. While no specific amount was proposed, DOJ stated that any settlement must include an appropriate civil penalty for the alleged violations. Transco cannot reasonably estimate the amount of its potential liability, if any, at this time. However, Transco believes it has substantially addressed environmental 10

12 Notes (continued) concerns on its system through ongoing voluntary remediation and management programs. Energy Services (WES) also accrues environmental remediation costs for its natural gas gathering and processing facilities, petroleum products pipelines, retail petroleum, refining and propane marketing operations primarily related to soil and groundwater contamination. At June 30, 1999, WES and its subsidiaries had liabilities totaling approximately $38 million. WES recognizes receivables related to environmental remediation costs from state funds as a result of laws permitting states to reimburse certain expenses associated with underground storage tank problems and repairs. At June 30, 1999, WES and its subsidiaries had receivables totaling $15 million. In connection with the 1987 sale of the assets of Agrico Chemical Company, Williams 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, 1999, Williams had approximately $11 million accrued for such excess costs. The actual costs incurred will depend on the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors. A lawsuit was filed in May 1993, in a state court in Colorado in which certain claims have been made against various defendants, including Northwest Pipeline, contending that gas exploration and development activities in portions of the San Juan Basin have caused air, water and other contamination. The plaintiffs in the case sought certification of a plaintiff class. In June 1994, the lawsuit was dismissed for failure to join an indispensable party over which the state court had no jurisdiction. The Colorado court of appeals affirmed the dismissal and remanded the case to Colorado district court for action consistent with the appeals court's decision. Since June 1994, eight individual lawsuits were filed against Northwest Pipeline and others in U.S. district court in Colorado, making essentially the same claims. The district court stayed all of the cases involving Northwest Pipeline until the plaintiffs exhausted their remedies before the Southern Ute Indian Tribal Court. Some plaintiffs filed cases in the Tribal Court, but none named Northwest Pipeline as a defendant. The parties have now executed a settlement agreement which settles all Federal and Tribal cases. Other legal matters On April 7, 1992, a liquefied petroleum gas explosion occurred near an underground salt dome storage facility located near Brenham, Texas and owned by an affiliate of MAPCO Inc., Seminole Pipeline Company ("Seminole"). MAPCO Inc., as well as Seminole, Mid-America Pipeline Company, MAPCO Natural Gas Liquids Inc., and other non-MAPCO entities were named as defendants in civil action lawsuits filed in state district courts located in four Texas counties. Seminole and the above-mentioned subsidiaries of MAPCO Inc. have settled in excess of 1,600 claims in these lawsuits. As of January 1999, the only lawsuit not fully resolved was the Dallmeyer case which was tried before a jury in Harris County. In Dallmeyer, the judgment rendered in March 1996 against defendants Seminole and MAPCO Inc. and its subsidiaries totaled approximately $72 million, which included nearly $65 million of punitive damages awarded to the 21 plaintiffs. Both plaintiffs and defendants have appealed the Dallmeyer judgment to the Court of Appeals for the Fourteenth District of Texas in Harris County. In February and March 1998, the defendants entered into settlement agreements involving 17 of the 21 plaintiffs to finally resolve their claims against all defendants for an aggregate payment of approximately $10 million. These settlements have satisfied and reduced the judgment on appeal by approximately $42 million as to the remaining four plaintiffs. The Court of Appeals issued its decision on October 15, 1998, which, while denying all of the plaintiffs' cross-appeal issues, affirmed in part and reversed in part the trial court's judgment. The defendants had entered into settlement agreements with the remaining plaintiffs which, in light of the decisions, provided for aggregate payments of approximately $13.6 million, the full amount of which has been previously accrued. The releases from the last remaining plaintiffs were received in February 1999. In 1991, the Southern Ute Indian Tribe (the Tribe) filed a lawsuit against Williams Production Company (Williams Production), a wholly owned subsidiary of Williams, and other gas producers in the San Juan Basin area, alleging that certain coal strata were reserved by the United States for the benefit of the Tribe and that the extraction of coal-seam gas from the coal strata was wrongful. The Tribe seeks compensation for the value of the coal-seam gas. The Tribe also seeks an order transferring to the Tribe ownership of all of the defendants' equipment and facilities utilized in the extraction of the coal-seam gas. In September 1994, the court granted summary judgment in favor of the defendants, and the Tribe lodged an interlocutory appeal with the U.S. Court of Appeals for the Tenth Circuit. Williams Production agreed to indemnify the Williams Coal Seam Gas Royalty Trust (Trust) against any losses that may arise in respect of certain properties subject to the lawsuit. On July 16, 1997, the U.S. Court of Appeals for the Tenth Circuit reversed the decision of the district court, held that the Tribe owns the coal-seam gas produced from certain coal strata on fee lands within the exterior boundaries of the Tribe's reservation, and remanded the case to the district court for further proceedings. On September 16, 1997, Amoco Production Company, the class representative for the defendant class (of which Williams Production is a part), filed its motion for rehearing en banc before the Court of Appeals. On July 20, 1998, the Court of Appeals sitting en banc affirmed the panel's decision. After the Court of Appeals decision, Williams Production entered into an agreement in principle to settle the Tribe's claims against it. Under the agreement, Williams has agreed to pay certain costs associated with production and transfer a portion of its 11

13 Notes (continued) interest to the Tribe. The Tribe would release Williams Production from the claims asserted in the lawsuit. Williams, Amoco and the Tribe continue to negotiate the terms of this settlement in principle. The Supreme Court granted a writ of certiorari in respect of the Court of Appeals affirmation of the decision en banc, and on June 7, 1999, the Supreme Court reversed the decision of the Court of Appeals and held that the Tribe did not own the coal seam gas produced from certain coal strata on fee lands within the exterior boundaries of the Tribe's reservation. In connection with agreements to resolve take-or-pay and other contract claims and to amend gas purchase contracts, Transcontinental Gas Pipe Line and Texas Gas each 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. As a result of such settlements, Transcontinental Gas Pipe Line is currently defending two lawsuits brought by producers. In one of the cases, a jury verdict found that Transcontinental Gas Pipe Line was required to pay a producer damages of $23.3 million including $3.8 million in attorneys' fees. Transcontinental Gas Pipe Line is pursuing an appeal. In the other case, a producer has asserted damages, including interest calculated through December 31, 1997, of approximately $6 million. Producers have received and may receive other demands, which could result in additional claims. Indemnification for royalties will depend on, among other things, the specific lease provisions between the producer and the lessor and the terms of the settlement between the producer and either Transcontinental Gas Pipe Line or Texas Gas. Texas Gas may file to recover 75 percent of any such additional amounts it may be required to pay pursuant to indemnities for royalties under the provisions of Order 528. In connection with the sale of certain coal assets in 1996, MAPCO entered into a Letter Agreement with the buyer providing for indemnification by MAPCO for reductions in the price or tonnage of coal delivered under a certain pre-existing Coal Sales Agreement dated December 1, 1986. The Letter Agreement is effective for reductions during the period July 1, 1996, through December 31, 2002, and provides for indemnification for such reductions as incurred on a quarterly basis. The buyer has stated it is entitled to indemnification from MAPCO for amounts of $7.8 million through June 30, 1998, and may claim indemnification for additional amounts in the future. MAPCO has filed for declaratory relief as to certain aspects of the buyer's claims. MAPCO also believes it would be entitled to substantial set-offs and credits against any amounts determined to be due and has accrued a liability representing an estimate of amounts it expects to incur in satisfaction of this indemnity. The parties are currently pursuing settlement negotiations as a part of a mediation. In 1998, the United States Department of Justice informed Williams that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly owned subsidiaries including Williams Gas Pipelines Central, Kern River Gas Transmission, Northwest Pipeline, Williams Gas Pipeline Company, Transcontinental Gas Pipe Line Corporation, Texas Gas, Williams Field Services Company and Williams Production Company. Mr. Grynberg has also filed claims against approximately 300 other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys' fees, and costs. On April 9, 1999, the United States Department of Justice announced that it was declining to intervene in any of the Grynberg qui tam cases, including the action filed against the Williams entities in the United States District Court for the District of Colorado. Class actions have been filed against certain communications carriers which challenge the carriers' rights to install and operate fiber-optic systems along railroad rights of way. Approximately 15 percent of Williams Communications Group's ("Communications") network is installed on railroad rights of way. Communications is a party to litigation challenging its right to use railroad rights of way over which it has installed approximately 28 miles of its network. The plaintiff in this action is seeking to have this matter certified as a class action. Communications cannot quantify the impact of such claims at this time. In addition to the foregoing, various other proceedings are pending against Williams or its subsidiaries which are incidental to their operations. Summary While no assurances may be given, Williams does not believe 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 have a materially adverse effect upon Williams' future financial position, results of operations or cash flow requirements. Other matters Energy Marketing & Trading has entered into certain contracts giving Williams the right to receive fuel conversion and certain other services for purposes of generating electricity. At June 30, 1999, annual estimated committed payments under these contracts range from $40 million to $214 million, resulting in total committed payments over the next 22 years of approximately $3.2 billion. 12

14 Notes (continued) 13. Adoption of accounting standards - ------------------------------------------------------------------------------- The FASB has issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This standard as amended, effective for fiscal years beginning after June 15, 2000, requires that all derivatives be recognized as assets or liabilities in the balance sheet and that those instruments be measured at fair value. The effect of this standard on Williams' results of operations and financial position is still being evaluated. 14. Comprehensive income - ------------------------------------------------------------------------------- Comprehensive income for the three months and six months ended June 30 is as follows: Three months Six months (Millions) ended June 30, ended June 30, ------------------- -------------------- 1999 1998 1999 1998 -------- -------- -------- -------- Net income $ 17.0 $ 60.7 $ 67.3 $ 128.8 Other comprehensive income (loss): Unrealized gains on securities 11.0 13.5 131.6 26.8 Foreign currency translation adjust- ments 1.1 (.4) (20.9) (2.5) -------- -------- -------- -------- Other comprehensive income before taxes 12.1 13.1 110.7 24.3 Income taxes on other comprehensive income 4.3 5.2 51.2 10.4 -------- -------- -------- -------- Comprehensive income $ 24.8 $ 68.6 $ 126.8 $ 142.7 ======== ======== ======== ======== 15. Segment disclosures - ------------------------------------------------------------------------------- Williams evaluates performance based upon segment profit or loss from operations which includes revenues from external and internal customers, equity earnings, operating costs and expenses, and depreciation, depletion and amortization. Intersegment sales are generally accounted for as if the sales were to unaffiliated third parties, that is, at current market prices. Williams' 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 includes investments in international energy and certain communications-related ventures, as well as corporate operations. The following table reflects the reconciliation of segment profit, per the tables on pages 14 and 15, to operating income as reported in the Consolidated Statement of Income for the three and six months ended June 30: Three months Six months ended ended (Millions) June 30, June 30, -------------------- -------------------- 1999 1998 1999 1998 -------- -------- -------- -------- Segment profit $ 198.4 $ 240.0 $ 437.6 $ 508.2 General corporate expenses (16.6) (18.1) (33.5) (58.9) -------- -------- -------- -------- Operating income $ 181.8 $ 221.9 $ 404.1 $ 449.3 ======== ======== ======== ======== The increase in Network Services' total assets, as noted on page 15, is due primarily to the construction of its fiber-optic network. The increase in Strategic Investments' total assets, also noted on page 15 and the investment balance in the Consolidated Balance Sheet, is due primarily to the additional investments in a Brazilian telecommunications project and the increase in the carrying value of a publicly traded marketable equity security. 13

15 Notes (continued) 15. Segment disclosures (continued) - ------------------------------------------------------------------------------- Revenues ---------------------------------------------------- External Inter- Equity Earnings Segment (Millions) Customers segment (Losses) Total Profit (Loss) ---------- ---------- ---------- ---------- ---------- FOR THE THREE MONTHS ENDED JUNE 30, 1999 GAS PIPELINE $ 412.6 $ 11.3 $ .6 $ 424.5 $ 175.4 ENERGY SERVICES Energy Marketing & Trading 530.8 (28.1)* (.2) 502.5 15.5 Exploration & Production 10.9 32.1 -- 43.0 7.0 Midstream Gas & Liquids 137.1 105.8 (5.6) 237.3 53.6 Petroleum Services 393.0 293.8 .1 686.9 30.7 Merger-related costs and non-compete amortization -- -- -- -- (2.7) ---------- ---------- ---------- ---------- ---------- 1,071.8 403.6 (5.7) 1,469.7 104.1 ---------- ---------- ---------- ---------- ---------- COMMUNICATIONS Communications Solutions 355.2 -- -- 355.2 (8.0) Network Services 77.5 11.4 -- 88.9 (20.3) Strategic Investments 65.2 .1 (4.9) 60.4 (47.8) ---------- ---------- ---------- ---------- ---------- 497.9 11.5 (4.9) 504.5 (76.1) ---------- ---------- ---------- ---------- ---------- OTHER 18.0 9.8 (4.0) 23.8 (5.0) ELIMINATIONS -- (436.2) -- (436.2) -- ---------- ---------- ---------- ---------- ---------- TOTAL $ 2,000.3 $ -- $ (14.0) $ 1,986.3 $ 198.4 ========== ========== ========== ========== ========== FOR THE THREE MONTHS ENDED JUNE 30, 1998 GAS PIPELINE $ 387.1 $ 11.9 $ .2 $ 399.2 $ 153.2 ENERGY SERVICES Energy Marketing & Trading 631.9 (99.3)* (1.8) 530.8 2.3 Exploration & Production 11.3 26.2 -- 37.5 8.0 Midstream Gas & Liquids 188.6 13.5 .4 202.5 54.8 Petroleum Services 139.7 519.1 .1 658.9 45.6 Merger-related costs and non-compete amortization -- -- -- -- (6.1) ---------- ---------- ---------- ---------- ---------- 971.5 459.5 (1.3) 1,429.7 104.6 ---------- ---------- ---------- ---------- ---------- COMMUNICATIONS Communications Solutions 344.1 -- -- 344.1 11.0 Network Services 18.1 12.7 -- 30.8 (6.5) Strategic Investments 50.0 1.3 (1.2) 50.1 (16.3) ---------- ---------- ---------- ---------- ---------- 412.2 14.0 (1.2) 425.0 (11.8) ---------- ---------- ---------- ---------- ---------- OTHER 9.3 4.0 (3.5) 9.8 (6.0) ELIMINATIONS -- (489.4) -- (489.4) -- ---------- ---------- ---------- ---------- ---------- TOTAL $ 1,780.1 $ -- $ (5.8) $ 1,774.3 $ 240.0 ========== ========== ========== ========== ========== * Energy Marketing & Trading intercompany cost of sales, which are netted in revenues consistent with fair value accounting, exceed intercompany revenue. 14

16 Notes (Continued) 15. Segment disclosures (continued) - ------------------------------------------------------------------------------- Revenues ---------------------------------------------------- External Inter- Equity Earnings Segment (Millions) Customers segment (Losses) Total Profit (Loss) ---------- ---------- ---------- ---------- ---------- FOR THE SIX MONTHS ENDED JUNE 30, 1999 GAS PIPELINE $ 864.9 $ 25.8 $ .7 $ 891.4 $ 362.2 ENERGY SERVICES Energy Marketing & Trading 1,046.4 (71.6)* (.3) 974.5 56.2 Exploration & Production 12.1 58.4 -- 70.5 11.7 Midstream Gas & Liquids 330.2 132.7 (7.9) 455.0 100.2 Petroleum Services 727.4 495.1 .3 1,222.8 63.7 Merger-related costs and non-compete amortization -- -- -- -- (6.8) ---------- ---------- ---------- ---------- ---------- 2,116.1 614.6 (7.9) 2,722.8 225.0 ---------- ---------- ---------- ---------- ---------- COMMUNICATIONS Communications Solutions 692.5 -- -- 692.5 (16.8) Network Services 173.3 24.1 -- 197.4 (37.5) Strategic Investments 133.3 .3 (13.0) 120.6 (73.3) ---------- ---------- ---------- ---------- ---------- 999.1 24.4 (13.0) 1,010.5 (127.6) ---------- ---------- ---------- ---------- ---------- OTHER 30.8 19.6 (20.4) 30.0 (22.0) ELIMINATIONS -- (684.4) -- (684.4) -- ---------- ---------- ---------- ---------- ---------- TOTAL $ 4,010.9 $ -- $ (40.6) $ 3,970.3 $ 437.6 ========== ========== ========== ========== ========== FOR THE SIX MONTHS ENDED JUNE 30, 1998 GAS PIPELINE $ 817.4 $ 23.8 $ .2 $ 841.4 $ 348.2 ENERGY SERVICES Energy Marketing & Trading 1,040.6 (27.4)* (2.9) 1,010.3 17.8 Exploration & Production 23.1 55.0 -- 78.1 20.3 Midstream Gas & Liquids 408.0 32.0 1.9 441.9 121.1 Petroleum Services 645.5 557.9 .2 1,203.6 79.2 Merger-related costs and non-compete amortization -- -- -- -- (42.0) ---------- ---------- ---------- ---------- ---------- 2,117.2 617.5 (.8) 2,733.9 196.4 ---------- ---------- ---------- ---------- ---------- COMMUNICATIONS Communications Solutions 671.5 -- -- 671.5 14.3 Network Services 27.2 24.8 -- 52.0 (14.4) Strategic Investments 100.2 2.4 (2.7) 99.9 (33.3) ---------- ---------- ---------- ---------- ---------- 798.9 27.2 (2.7) 823.4 (33.4) ---------- ---------- ---------- ---------- ---------- OTHER 4.9 20.6 (2.0) 23.5 (3.0) ELIMINATIONS -- (689.1) -- (689.1) -- ---------- ---------- ---------- ---------- ---------- TOTAL $ 3,738.4 $ -- $ (5.3) $ 3,733.1 $ 508.2 ========== ========== ========== ========== ========== TOTAL ASSETS (Millions) June 30, 1999 December 31, 1998 ------------------ ------------------ GAS PIPELINE $ 8,305.8 $ 8,386.2 ENERGY SERVICES Energy Marketing & Trading 2,660.9 2,596.8 Exploration & Production 569.3 484.1 Midstream Gas & Liquids 3,377.5 3,201.8 Petroleum Services 2,441.1 2,525.2 ------------------ ------------------ 9,048.8 8,807.9 ------------------ ------------------ COMMUNICATIONS Communications Solutions 1,006.5 946.4 Network Services 1,152.7 712.9 Strategic Investments 1,122.0 638.4 ------------------ ------------------ 3,281.2 2,297.7 ------------------ ------------------ OTHER 5,281.9 4,782.4 ELIMINATIONS (5,905.2) (5,626.9) ------------------ ------------------ TOTAL $ 20,012.5 $ 18,647.3 ================== ================== * Energy Marketing & Trading intercompany cost of sales, which are netted in revenues consistent with fair-value accounting, exceed intercompany revenues. 15

17 16. Communications initial public offering - ------------------------------------------------------------------------------- On April 9, 1999, Williams' communications business filed a registration statement for an initial public equity offering which is expected to yield proceeds of $500 million to $750 million, representing a minority interest in its communications business. During the first quarter of 1999, Williams announced that SBC Communications plans to acquire up to a 10 percent interest in Williams' communications business for an investment up to $500 million. During second-quarter 1999, Williams announced that two additional parties, Intel and Telefonos de Mexico, had also agreed to invest in its communications business. Communications has entered into agreements with the three companies to receive up to a total of $725 million, subject to certain conditions. In addition, Communications is expected to issue high-yield public debt of $1.3 billion in 1999. All of these transactions will occur simultaneously with the public equity offering. Proceeds are expected to be reinvested in the continued construction of Communications' national fiber-optic network and other expansion opportunities. ITEM 2 Management's Discussion and Analysis of Financial Condition and Results of Operations Results of Operations Second Quarter 1999 vs. Second Quarter 1998 CONSOLIDATED OVERVIEW Williams' revenues increased $212 million, or 12 percent, due primarily to Communications' dark fiber capacity lease revenues and new business growth, reductions to rate refund liabilities at Gas Pipeline and increased revenues at Energy Services from electric power services activities, convenience store sales, natural gas liquids activities, and fleet management and mobile computer technology operations. Partially offsetting these increases were lower crude and refined products revenues. Segment costs and expenses increased $254 million, or 17 percent, due primarily to higher costs and expenses within Communications, including $26.7 million of asset impairment charges and exit costs, and increased costs at Energy Services from electric power services activities, convenience stores and fleet management and mobile computer technology operations. In addition, second-quarter 1999 includes $10.5 million of expense associated with a Williams-wide incentive program (of which $3.1 million is included in general corporate expense). These increases were partially offset by lower crude and refined products costs. Operating income decreased $40 million, or 18 percent, due primarily to a $64 million decrease at Communications, reflecting $26.7 million of asset impairment charges and exit costs, losses from international ventures during initial operations, and costs associated with infrastructure growth and improvement. Partially offsetting this decrease was a $22 million increase at Gas Pipeline, reflecting the net effect of 1999 and 1998 reductions to rate refund liabilities. Income before income taxes, extraordinary loss and change in accounting principle decreased $37 million, or 36 percent, due primarily to the decrease in operating income. GAS PIPELINE GAS PIPELINE'S revenues increased $25.3 million, or 6 percent, due primarily to a total of $38 million of reductions to rate refund liabilities by three of the gas pipelines resulting from second-quarter 1999 regulatory proceedings involving rate-of-return methodology and $8 million from expansion projects and new services. These increases were partially offset by lower rates, primarily from transportation rate discounting and rate design, and $11 million of favorable adjustments in 1998 from the settlement of rate case issues. Segment profit increased $22.2 million, or 14 percent, due primarily to the $27 million net effect of the regulatory and rate issues discussed above, partially offset by $5 million higher general and administrative expenses in 1999, including expenses related to information system initiatives. Based on current rate structures and/or historical maintenance schedules of certain of its pipelines, Gas Pipeline experiences lower segment profits in the second and third quarters as compared with the first and fourth quarters. 16

18 ENERGY SERVICES ENERGY MARKETING & TRADING'S operating results can be significantly impacted by energy commodity price volatility. In addition, physical trading sales revenues are reported net of the related purchase costs while non-trading activities are not netted. As a result, net revenues (revenues less cost of sales) is used to analyze Energy Marketing & Trading's operating results as shown below: 1999 1998 ---------- ---------- Revenues $ 502.5 $ 530.8 Cost of sales 427.4 475.8 ---------- ---------- Net revenues $ 75.1 $ 55.0 ========== ========== Revenues decreased $28.3 million, or 5 percent, due primarily to $95 million lower crude and refined products revenues. Partially offsetting this decrease were $41 million higher electric power services revenues resulting from activity in southern California initiated in June of 1998 and $27 million higher revenues from natural gas liquids activities, which includes $7 million associated with a petrochemical plant acquisition made on March 31, 1999 and increased physical trading activity. Cost of sales decreased $48.4 million, or 10 percent, due primarily to $83 million lower costs for crude and refined products. Partially offsetting this decrease was $21 million of costs associated with electric power services activities in southern California initiated in June of 1998. Net revenues increased $20.1 million, or 37 percent, due primarily to $20 million higher electric power services margins resulting from activity in southern California, including the recognition of $7 million of revenues associated with a 1998 contractual dispute which was settled in the second quarter of 1999, and $20 million higher natural gas liquids margins. The natural gas liquids margin increase reflects improved per-unit margins experienced on all natural gas liquids products and $7 million associated with the petrochemical plant acquisition. Partially offsetting these increases were $12 million lower crude and refined products margins primarily due to higher trading origination revenues in 1998, and $6 million lower margins from energy financing activities. Segment profit increased $13.2 million, from $2.3 million in 1998, due primarily to the $20 million increase in net revenues and a $5.6 million gain on the sale of certain retail gas and electric assets, partially offset by $11 million higher selling, general and administrative expenses. The increase in selling, general and administrative expenses reflects higher compensation levels associated with improved operating performance, growth in electric power services operations, the late 1998 Volunteer Energy acquisition and increased activities in human resources development, investor/media/customer relations and business development. EXPLORATION & PRODUCTION'S revenues increased $5.5 million, or 15 percent, due primarily to $8 million associated with increases in both company-owned production volumes and marketing volumes from Williams Coal Seam Gas Royalty Trust (Royalty Trust) and royalty interest owners, and $5 million from the April 1999 acquisition of oil and gas producing properties. Company-owned production has increased due mainly to a drilling program initiated in the San Juan basin in 1998. These increases were partially offset by a $7 million decrease in the recognition of income previously deferred from a 1997 transaction that transferred certain nonoperating economic benefits to a third party. Segment profit decreased $1 million, or 12 percent, due primarily to $7 million decreased recognition of deferred income and $3 million higher operating and maintenance expense, partially offset by the $4 million favorable effect of the April 1999 acquisition and $5 million higher revenue from increased company-owned production volumes. MIDSTREAM GAS & LIQUIDS' revenues increased $34.8 million, or 17 percent, due primarily to unfavorable adjustments in 1998 of $12 million related to rates placed into effect in 1997 for Midstream's regulated gathering activities (offset in costs and operating expenses), a $3 million favorable rate adjustment in 1999, $13 million higher natural gas liquids sales from processing activities and $5 million higher natural gas liquids storage revenues following the acquisition of a Kansas storage facility during the second quarter of 1999, partially offset by $6 million lower equity earnings including a $4 million adjustment on the Discovery pipeline project related to a prior year (offset in interest capitalized). The $13 million higher natural gas liquids sales reflects $7 million from a 24 percent increase in volumes sold and $6 million from a 17 percent increase in average natural gas liquids sales prices. Costs and operating expenses increased $27 million due primarily to the 1998 rate adjustments related to Midstream's regulated gathering activities and $8 million of higher fuel and replacement gas purchases. Segment profit decreased $1.2 million, or 2 percent, due primarily to the $6 million lower equity earnings discussed above, $5 million of costs associated with a cancelled pipeline construction project, $3 million higher general and administrative expenses and $4 million higher operating and maintenance expenses. Partially offsetting these decreases were $5 million higher natural gas liquids storage revenues, $4 million higher natural gas liquids margins, $3 million higher 17

19 gathering revenues, the $3 million favorable rate adjustment in 1999 and the impact of a $3 million unfavorable litigation judgement in 1998. PETROLEUM SERVICES' revenues increased $28 million, or 4 percent, due primarily to $33 million higher convenience store sales, $25 million higher revenues from growth in fleet management and mobile computer technology operations, and $8 million in revenues from a recently acquired petrochemical plant. Partially offsetting these increases were $19 million lower pipeline construction revenues following substantial completion of the project, $10 million lower refining revenues and $6 million lower ethanol sales revenues reflecting lower average ethanol sales prices. The $33 million increase in convenience store sales reflects $21 million from 17 percent higher gasoline and diesel sales volumes, $3 million from slightly higher average sales prices and $9 million higher merchandise sales. The average number of convenience stores and per-store sales in second-quarter 1999 have increased as compared to 1998. The $10 million decrease in refining revenues reflects a 2 percent decrease in refined product volumes sold, partially offset by 3 percent higher average sales prices. Costs and operating expenses increased $49 million, or 9 percent, due primarily to $25 million higher costs from growth in fleet management and mobile computer technology operations, $23 million higher refining costs, $13 million higher convenience store external cost of sales and $7 million higher convenience store operating costs, partially offset by $18 million lower pipeline construction costs. Increased refining costs of $23 million reflect $24 million from a 9 percent increase in average per-unit cost of sales and $3 million higher operating costs at the Alaska refinery, partially offset by $4 million associated with a 2 percent decrease in volumes sold. The $13 million increase in convenience store external cost of sales reflects $7 million higher merchandise costs, increased volumes sold and higher average gasoline and diesel purchase prices. Segment profit decreased $14.9 million, or 33 percent, due primarily to $13 million from lower per-unit refining margins, $10 million higher selling, general and administrative expenses and $7 million higher convenience store operating costs, partially offset by the impact of a $15.5 million accrual in 1998 for potential refunds to transportation customers. COMMUNICATIONS COMMUNICATIONS SOLUTIONS' revenues increased $11.1 million, or 3 percent, due primarily to $14 million higher sales from new systems and upgrades and $6 million of other revenue in 1999 associated with the sale of rights to future cash flows from equipment lease renewals, partially offset by $9 million lower customer service orders resulting, in part, from competitive pressures. Segment profit decreased $19 million, from an $11 million segment profit in 1998 to an $8 million segment loss in 1999, due primarily to $21 million higher selling, general and administrative expenses. Selling, general and administrative expenses increased primarily as a result of costs necessary to improve managing and integrating complex business operations and systems including $6 million of higher information and technology costs, $3 million of process related consulting fees, $2 million higher depreciation expense and $2 million of severance costs. Also contributing to the selling, general and administrative expense increase are a $2 million increase in the provision for uncollectible trade receivables and $3 million of expense associated with a Williams-wide incentive program. NETWORK SERVICES' revenues increased $58.1 million from $30.8 million in 1998, due primarily to $20 million of revenue in 1999 from dark fiber capacity leases accounted for as sales-type leases on the newly constructed digital fiber-optic network and $34 million from business growth from data and switched voice services. Costs and operating expenses increased $57 million, from $27 million in 1998, due primarily to $30 million of increased costs from providing data and switched voice services which includes $18 million of higher leased capacity costs associated with providing customer services prior to completion of the new network. Also contributing to the increase are $12 million higher operations and maintenance expenses on the newly completed portions of the network, $7 million of construction costs associated with the dark fiber capacity leases and $4 million higher depreciation expense. Segment loss increased $13.8 million, from a $6.5 million loss in 1998 to a $20.3 million loss in 1999, due primarily to a $15 million increase in selling, general and administrative expenses primarily associated with expanding the infrastructure in support of the network expansion, losses experienced from providing customer services prior to completion of the new network and $4 million higher depreciation expense, partially offset by $13 million of profit from the dark fiber capacity leases. STRATEGIC INVESTMENTS' revenues increased $10.3 million, or 21 percent, due primarily to $8 million of revenue contributed by an Australian telecommunications company acquired in August 1998 and $6 million associated with business growth, partially offset by equity investment losses of $5 million from ATL-Algar Telecom Leste S.A. (ATL), a Brazilian telecommunications business in initial operations. 18

20 Costs and operating expenses increased $9 million, or 18 percent, and selling, general and administrative expenses increased $7 million, or 38 percent, due primarily to the Australian operations. Segment loss increased $31.5 million, from a $16.3 million loss in 1998 to a $47.8 million loss in 1999, due primarily to $26.7 million of asset impairment charges and exit costs in 1999 (included in other expense - net within segment costs and expenses) relating to management's second-quarter 1999 decision and commitment to sell the audio and video conferencing and closed-circuit video broadcasting businesses (see Note 4 of Notes to Consolidated Financial Statements) and $10 million of losses from the start-up activities of the Australian and Brazilian communications operations. CONSOLIDATED INTEREST ACCRUED increased $8.1 million, or 6 percent, due primarily to higher borrowing levels including the commercial paper program, Williams Communications Group's (Communications) short-term credit facility and the July 1998 issuance of additional public debt, partially offset by a $10.6 million favorable adjustment related to the reduction of certain rate refund liabilities (see Note 3) and lower average interest rates. Interest capitalized increased $9.7 million, from $7.8 million in 1998, due primarily to adjustments totaling $7 million related to Williams' equity investments in pipelines under construction. Investing income decreased $4.1 million, or 42 percent, due primarily to lower interest income on long-term notes receivable. Other income (expense) - net is $5.5 million favorable as compared to 1998 due primarily to a 1998 litigation loss accrual related to assets previously sold. The $6.5 million, or 15 percent, increase in the provision for income taxes is primarily a result of a higher effective income tax rate, partially offset by lower pre-tax income. The effective income tax rate in 1999 is significantly higher than the federal statutory rate due primarily to the impact of goodwill not deductible for tax purposes related to assets impaired during the second quarter of 1999 (see Note 4) and the effects of state income taxes. The effective income tax rate in 1998 exceeds the federal statutory rate due primarily to the effects of state income taxes. Six Months Ended June 30, 1999 vs. Six Months Ended June 30, 1998 CONSOLIDATED OVERVIEW Williams' revenues increased $237 million, or 6 percent, due primarily to Communications' dark fiber capacity lease revenues and new business growth, increased revenues from retail natural gas and electric activities following a late 1998 acquisition, higher electric power services revenues, increased convenience store sales and reductions to rate refund liabilities at Gas Pipeline. Partially offsetting these increases were the effects in 1999 of reporting certain crude and refined products revenues and natural gas liquids revenues net of costs within Energy Services (see Note 2). Segment costs and expenses increased $308 million, or 10 percent, due primarily to higher costs and expenses within Communications, including $26.7 million of asset impairment charges and exit costs, and increased costs at Energy Services from retail gas and electric activities following a late 1998 acquisition, electric power services and convenience stores. In addition, second-quarter 1999 includes $10.5 million of expense associated with a Williams-wide incentive program (of which $3.1 million is included in general corporate expense). Partially offsetting these increases were the effects in 1999 of reporting certain crude and refined products costs and natural gas liquids costs net in revenues within Energy Services (see Note 2), and the effect in 1998 of MAPCO merger-related costs totaling $68 million (including $26 million within general corporate expenses). Operating income decreased $45 million, or 10 percent, due primarily to a $94 million decrease at Communications, reflecting $26.7 million of asset impairment charges and exit costs, losses from international ventures during initial operations, and costs associated with infrastructure growth and improvement, and a $21 million decrease from International activities (included in the Other segment operating loss), reflecting losses from start-up operations. Partially offsetting these decreases was the effect in 1998 of MAPCO merger-related costs totaling $68 million. Income before income taxes, extraordinary loss and change in accounting principle decreased $60 million, or 27 percent, due primarily to lower operating income and $23 million higher net interest expense reflecting continued expansion and new projects. GAS PIPELINE GAS PIPELINE'S revenues increased $50 million, or 6 percent, due primarily to a total of $41 million of reductions to rate refund liabilities by three of the gas pipelines resulting primarily from second-quarter 1999 regulatory proceedings involving rate-of-return methodology. Revenues also increased by $27 million related to the settlement of historical gas exchange imbalances, which are offset in costs and operating expenses, and $15 million from expansion projects and new services. These increases were partially offset by lower transportation rates, primarily from transportation rate discounting and rate design, and $11 million of favorable adjustments in 1998 from the settlement of rate case issues. Segment profit increased $14 million, or 4 percent, due primarily to the $30 million net effect of the regulatory and rate issues discussed above and $9 million in lower transportation expenses. These increases were partially offset by $9 million higher general and administrative expenses, 19

21 $8 million in higher depreciation and amortization expense and a $3.4 million gain in 1998 from the sale-in-place of natural gas from a decommissioned storage field. General and administrative expenses increased primarily from information system initiatives and a $2.3 million accrual for damages associated with two pipeline ruptures in the northwest. Based on current rate structures and/or historical maintenance schedules of certain of its pipelines, Gas Pipeline experiences lower segment profits in the second and third quarters as compared with the first and fourth quarters. ENERGY SERVICES ENERGY MARKETING & TRADING'S operating results can be significantly impacted by energy commodity price volatility. In addition, physical trading sales revenues are reported net of the related purchase costs while non-trading activities are not netted. As a result, net revenues (revenues less cost of sales) is used to analyze Energy Marketing & Trading's operating results as shown below: 1999 1998 ------------ ------------ Revenues $ 974.5 $ 1,010.3 Cost of sales 788.2 884.1 ------------ ------------ Net revenues $ 186.3 $ 126.2 ============ ============ Revenues decreased $35.8 million, or 4 percent, due primarily to $144 million lower crude and refined products revenues and $106 million lower natural gas liquids trading revenues resulting primarily from the impact in the first quarter of 1999 of reporting revenues on a net basis for certain operations previously reported on a "gross" basis (see Note 2). Partially offsetting these decreases were $113 million higher retail gas and electric revenues following the late 1998 acquisition of Volunteer Energy and $94 million higher electric power services revenues resulting from activity in southern California initiated in June 1998. Cost of sales decreased $95.9 million, or 11 percent, due primarily to $145 million lower costs for crude and refined products and $123 million lower natural gas liquids trading costs resulting primarily from the impact in the first quarter of 1999 of reporting revenues on a net basis for certain operations previously reported on a "gross" basis (see Note 2). Partially offsetting these decreases were $107 million higher costs for retail gas and electric operations following the late 1998 acquisition of Volunteer Energy and $61 million higher costs associated with electric power services activity in southern California initiated in June of 1998. Net revenues increased $60.1 million, or 48 percent, due primarily to $33 million higher electric power services margins resulting from activity in southern California, including the recognition of $7 million of revenues associated with a 1998 contractual dispute which was settled in the second quarter of 1999. Net revenues also increased due to $17 million higher natural gas liquids margins, $7 million higher retail propane margins reflecting an 8 percent increase in volumes sold, and $6 million higher margins from retail gas and electric activities. The natural gas liquids margin increase reflects improved per-unit margins experienced on all natural gas liquids products and $7 million associated with the acquisition of a petrochemical plant in early 1999. The improved margins from retail gas and electric activities reflects, in part, the effect of general and administrative expenses included in equity losses in 1998 from partially owned companies that are now consolidated. Segment profit increased $38.4 million, from $17.8 million in 1998, due primarily to the $60 million increase in net revenues and a $5.6 million gain on the sale of certain retail gas and electric assets, partially offset by $27 million higher selling, general and administrative expenses. The increase in selling, general and administrative expenses reflects higher compensation levels associated with improved operating performance, growth in electric power services operations, the Volunteer Energy acquisition and increased activities in human resources development, investor/media/customer relations and business development. EXPLORATION & PRODUCTION'S revenues decreased $7.6 million, or 10 percent, due primarily to an $11 million decrease in the recognition of income previously deferred from a 1997 transaction that transferred certain nonoperating economic benefits to a third party and an $11 million reduction associated with lower average natural gas sales prices mainly during the first quarter of 1999. These decreases were partially offset by a $10 million increase associated with increases in both company-owned production volumes and marketing volumes from the Royalty Trust and royalty interest owners, and $5 million from the April 1999 acquisition of oil and gas producing properties. Company-owned production has increased due mainly to a drilling program initiated in the San Juan basin in 1998. Segment profit decreased $8.6 million, or 42 percent, due primarily to $11 million decreased recognition of deferred income, a $7 million unfavorable effect of lower average natural gas sales prices for company-owned production and $5 million higher operating and maintenance expenses. Partially offsetting these decreases were $7 million higher 20

22 revenue from increased company-owned production volumes, the $4 million favorable effect of the April 1999 acquisition and $3 million higher margins on natural gas marketing activities. MIDSTREAM GAS & LIQUIDS' revenues increased $13.1 million, or 3 percent, due primarily to unfavorable adjustments in 1998 of $12 million related to rates placed into effect in 1997 for Midstream's regulated gathering activities (offset in costs and operating expenses), a $3 million favorable rate adjustment in 1999, $5 million higher natural gas liquids sales from processing activities, and $5 million higher natural gas liquids storage revenues following the acquisition of a Kansas storage facility during the second quarter of 1999. Partially offsetting these increases were $10 million lower equity earnings including a $4 million adjustment on the Discovery pipeline project related to a prior year (offset in capitalized interest), and $7 million lower condensate revenues related to a shift in the revenue mix from sales of condensate for customers to providing gathering and transportation services under fee-based contracts. The $5 million higher natural gas liquids sales reflects $13 million from a 19 percent increase in volumes sold, partially offset by $8 million from a 10 percent decrease in average natural gas liquids prices. Costs and operating expenses increased $21 million due primarily to the 1998 rate adjustments related to Midstream's regulated gathering activities and $3 million of higher fuel and replacement gas purchases. Segment profit decreased $20.9 million, or 17 percent, due primarily to the $10 million lower equity earnings discussed above, $7 million higher general and administrative expenses, $5 of costs associated with a cancelled pipeline construction project and $8 million higher operating and maintenance expenses. Partially offsetting these segment profit decreases were $5 million higher natural gas storage revenues, the $3 million favorable rate adjustment in 1999 and the impact of a $3 million unfavorable litigation judgement in 1998. Midstream is in the process of evaluating its organization in a portion of the Gulf Coast operations area. As a part of this organizational assessment, Williams will be offering certain employees enhanced retirement benefits under an early retirement incentive program in August 1999. Preliminary estimates indicate that this program may result in a pre-tax charge to third-quarter 1999 operating results of approximately $2 million. PETROLEUM SERVICES' revenues increased $19.2 million, or 2 percent, due primarily to $50 million higher convenience store sales, $37 million higher revenues from growth in fleet management and mobile computer technology operations and $8 million in revenues from a recently acquired petrochemical plant. Partially offsetting these increases were $48 million lower refining revenues, $17 million lower pipeline construction revenues following substantial completion of the project and $14 million lower ethanol sales reflecting lower average ethanol sales prices. The $50 million increase in convenience store sales reflects $46 million from 20 percent higher gasoline and diesel sales volumes and $19 million higher merchandise sales, partially offset by $15 million from lower average retail gasoline and diesel sales prices in the first quarter of 1999. The average number of convenience stores and per-store sales in 1999 have increased as compared to 1998. The $48 million decrease in refining revenues reflects an 8 percent decrease in average sales prices, partially offset by a 3 percent increase in refined product volumes sold. Costs and operating expenses increased $40 million, or 4 percent, due primarily to $36 million higher costs from growth in fleet management and mobile computer technology operations, $29 million higher convenience store external cost of sales and $15 million higher convenience store operating costs. Partially offsetting these increases were $16 million lower refining costs, $16 million lower pipeline construction costs and $10 million lower ethanol production costs. The $29 million increase in convenience store external cost of sales reflects $13 million higher merchandise costs and a 20 percent increase in gasoline and diesel sales volumes, partially offset by a 6 percent decrease in average gasoline and diesel purchase prices. Decreased refining costs of $16 million reflects $39 million from lower average per-unit cost of sales, partially offset by $15 million related to increased volumes sold and $8 million higher operating costs at the refineries. Selling, general and administrative expenses increased $16 million due, in part, to increased activities in human resources development, investor/media/customer relations and business development. Segment profit decreased $15.5 million, or 20 percent, due primarily to $16 million higher selling, general and administrative expenses, $15 million higher convenience store operating costs, $14 million from lower per-unit refinery margins and $8 million higher refinery operating costs. These decreases to segment profit were partially offset by the impact of a $15.5 million accrual in 1998 for potential refunds to transportation customers, $6 million higher margins on convenience store merchandise sales, $5 million of margins from the recently acquired petrochemical plant, $4 million higher margins from growth in the terminalling and distribution operations and the recovery of $4 million of environmental expenses previously incurred. The new products pipeline, which was expected to be in service in 1998, has been delayed until early 2000 due to environmental assessment and related mitigation. 21

23 COMMUNICATIONS COMMUNICATIONS SOLUTIONS' revenues increased $21 million, or 3 percent, due primarily to $28 million higher new system sales and upgrades and $6 million of other revenue in 1999 associated with the sale of rights to future cash flows from equipment lease renewals, partially offset by $17 million lower customer service orders resulting, in part, from competitive pressures. Segment profit decreased $31.1 million, from a $14.3 million segment profit in 1998 to a $16.8 million segment loss in 1999, due primarily to $37 million higher selling, general and administrative expenses, partially offset by $4 million realized on the sale of rights to future cash flows from equipment lease renewals. Selling, general and administrative expenses increased due primarily to costs necessary to improve managing and integrating complex business operations and systems including $11 million of higher information technology costs, $4 million of process related consulting fees, $3 million higher depreciation expense and $2 million of severance costs. Also contributing to the selling, general and administrative expense increase are a $10 million increase in the provision for uncollectible trade receivables and $3 million of expense associated with a Williams-wide incentive program. NETWORK SERVICES' revenues increased $145.4 million from $52 million in 1998, due primarily to $72 million of revenue in 1999 from dark fiber capacity leases accounted for as sales-type leases on the newly constructed digital fiber-optic network and $66 million from business growth from data and switched voice services. Costs and operating expenses increased $146 million, from $45 million in 1998, due primarily to $66 million of increased costs from providing data and switched voice services which includes $47 million of higher leased capacity costs associated with providing customer services prior to completion of the new network. Also contributing to the increase are $48 million of construction costs associated with the dark fiber capacity leases, $17 million higher operations and maintenance expenses on the newly completed portions of the network and $7 million higher depreciation expense. Segment loss increased $23.1 million, from a loss of $14.4 million in 1998 to a loss of $37.5 million in 1999, due primarily to a $22 million increase in selling, general and administrative expenses primarily associated with expanding the infrastructure in support of the network expansion, losses experienced from providing customer services prior to completion of the new network and $7 million higher depreciation expense, partially offset by $24 million of profit from the dark fiber capacity leases. As each phase of the on-going construction of the planned 32,000 mile full-services wholesale communications network goes into service, revenues and costs are expected to increase. During 1998, 9,000 miles of new network were added increasing the network to 19,000 cable miles at December 31, 1998, of which 17,000 were lit. At June 30, 1999, the network had increased to 21,000 cable miles, of which 19,000 are lit. The remaining 11,000 miles are planned to come online during the remainder of 1999 and 2000. As a result of the expansion of the network and as a result of alliances with SBC Communications, Intel Corporation and Telefonos de Mexico, a significant increase in revenues as well as a significant change in the revenue mix is expected over the next few years. In June 1999, the Financial Accounting Standards Board (FASB) issued interpretation No. 43, "Real Estate Sales, an interpretation of SFAS No. 66," which is effective for sales of real estate with property improvements or integral equipment entered into after June 30, 1999. Under this interpretation, sales-type lease accounting will not be appropriate for excess dark fiber capacity transactions entered into after June 30, 1999, and, therefore, unless title to the fibers under the lease transfers to the lessee, these transactions will be accounted for as operating leases. Williams has not assessed the effects of this FASB interpretation on its future operating results. STRATEGIC INVESTMENTS' revenues increased $20.7 million, or 21 percent, due primarily to $19 million of revenue contributed by an Australian telecommunications company acquired in August 1998 and $14 million associated with business growth, partially offset by equity investment losses of $13 million from ATL, a Brazilian telecommunications business in initial operations. Costs and operating expenses increased $19 million, or 20 percent, and selling, general and administrative expenses increased $15 million, or 39 percent, due primarily to the Australian operations. Segment loss increased $40 million, from a $33.3 million loss in 1998 to a $73.3 million loss in 1999, due primarily to $26.7 million of asset impairment charges and exit costs in 1999 (included in other expense - net within segment costs and expenses) relating to management's second-quarter 1999 decision and commitment to sell the audio and video conferencing and closed-circuit video broadcasting businesses (see Note 4) and $23 million of losses from the start-up activities of the Australian and Brazilian communications operations, partially offset by improved results and business growth in other areas. OTHER OTHER segment loss of $22 million in 1999 compares to a segment loss of $3 million in 1998, due primarily to $21 million higher international equity investment losses, including $14 million from investing activities in another Brazilian 22

24 communications company in which Williams has an equity interest. The equity losses result primarily from start-up operations of certain communications ventures within this investment. CONSOLIDATED GENERAL CORPORATE EXPENSES decreased $25.4 million, or 43 percent, due primarily to MAPCO merger-related costs of $26 million included in 1998 general corporate expenses. An additional $42 million of merger-related costs are included in 1998 as a component of Energy Services' segment profit (see Note 5). Interest accrued increased $33.4 million, or 14 percent, due primarily to higher borrowing levels including the commercial paper program, Communications' short-term credit facility and the July 1998 issuance of additional public debt, partially offset by a $10.6 million favorable adjustment related to the reduction of certain rate refund liabilities (see Note 3) and lower average interest rates. Interest capitalized increased $10.9 million, or 68 percent, due primarily to adjustments totaling $7 million related to Williams' equity investments in pipelines under construction. Other income (expense) - net is $7.4 million favorable as compared to 1998 due primarily to a 1998 litigation loss accrual related to assets previously sold. The $.9 million, or 1 percent, increase in the provision for income taxes is primarily a result of a higher effective income tax rate, substantially offset by lower pre-tax income. The effective income tax rate in 1999 is significantly higher than the federal statutory rate due primarily to the impact of goodwill not deductible for tax purposes related to assets impaired during the second quarter of 1999 (see Note 4) and the effects of state income taxes. The effective income tax rate in 1998 exceeds the federal statutory rate due primarily to the effects of state income taxes. The $4.8 million 1998 extraordinary loss results from the early extinguishment of debt (see Note 7). The $5.6 million 1999 change in accounting principle relates to the adoption of Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities" (see Note 8). FINANCIAL CONDITION AND LIQUIDITY Liquidity Williams considers its liquidity to come from two sources: internal liquidity, consisting of available cash investments, and external liquidity, consisting of borrowing capacity from available bank-credit facilities and the commercial paper program, which can be utilized without limitation under existing loan covenants. At June 30, 1999, Williams had access to $790 million of liquidity including $550 million available under its $1 billion bank-credit facility, $216 million of commercial paper availability, and cash-equivalent investments. This compares with liquidity of $738 million at December 31, 1998, and $530 million at June 30, 1998. Registration statements have been filed with the Securities and Exchange Commission by Williams and Northwest Pipeline, Texas Gas Transmission and Transcontinental Gas Pipe Line (each a wholly owned subsidiary of Williams). Following a July 1999 issuance of $700 million of notes, approximately $755 million of shelf availability remains under these outstanding registration statements and may be used to issue a variety of debt or equity securities. Williams believes any additional financing arrangements can be obtained on reasonable terms if required. On April 9, 1999, Williams' communications business filed a registration statement for an initial public equity offering which is expected to yield proceeds of $500 million to $750 million, representing a minority interest in its communications business. During first-quarter 1999, Williams announced that SBC Communications plans to acquire up to a 10 percent interest in its communications business for an investment up to $500 million. During second-quarter 1999, Williams announced that two additional parties, Intel and Telefonos de Mexico, have also agreed to invest in its communications business. Communications has entered into agreements with the three companies to receive up to a total of $725 million, subject to certain conditions. In addition, Communications is expected to issue high-yield public debt of $1.3 billion in 1999. All of these transactions are expected to occur simultaneously with the public equity offering. Proceeds are expected to be reinvested in the continued construction of Communications' national fiber-optic network and other expansion opportunities. Williams' management has announced that it expects the initial public equity offering to close in October 1999. In April 1999, Communications entered into a $1.4 billion interim short-term bank-credit facility expected to be replaced with a permanent bank-credit facility in September 1999. At June 30, 1999, $790 million remains available under this facility. During 1998, Williams entered into an operating lease agreement covering a portion of its fiber-optic network designed to fund up to $750 million of capital expenditures for the fiber-optic network. As of June 30, 1999, $449 million of costs have been incurred and the remaining capacity under the program is $301 million. In 1999, capital expenditures and investments are estimated to be approximately $5 billion. During 1999, Williams expects to finance capital expenditures, investments and working-capital requirements through (1) cash generated from operations, (2) Communications' initial equity and high-yield debt offerings, (3) the use of the available portion of its $1 billion bank-credit facility, Communications' $1.4 billion short-term bank-credit facility and the asset lease program, (4) commercial 23

25 paper, (5) short-term uncommitted bank lines, (6) private borrowings and (7) debt or equity public offerings. Financing Activities In January 1999, the commercial paper program increased to $1.4 billion from $1 billion. The commercial paper program is backed by short-term bank-credit facilities totaling $1.4 billion. At June 30, 1999, $1.2 billion of commercial paper was outstanding under the program. In January 1999, Williams entered into a $200 million adjustable rate term loan due 2004, and in July 1999, Williams issued $700 million of 7.625 percent notes due 2019. During second-quarter 1999, $610 million of borrowings were made under the Communications' $1.4 billion interim short-term bank-credit facility. The proceeds were used for general corporate purposes, including the repayment of outstanding debt. The consolidated long-term debt to debt-plus-equity ratio was 58.9 percent at June 30, 1999, compared to 59.9 percent at December 31, 1998. If short-term notes payable and long-term debt due within one year are included in the calculations, these ratios would be 66.5 percent at June 30, 1999, and 64.7 percent at December 31, 1998. Investing Activities During first-quarter 1999, Williams exercised an option to increase its investment in ATL, a Brazilian telecommunications business, by an additional 35 percent equity interest for $265 million. This investment was funded through borrowings under the $1 billion bank-credit facility. Also in first-quarter 1999, Williams purchased a company with a petrochemical plant and natural gas liquids transportation, storage and other facilities for $163 million in cash. Operating Activities The increase in receivables and accounts payable reflects increased power and crude oil trading activity at Energy Marketing & Trading. The change in accounts payable also reflects an $84 million payment pursuant to a wireless fiber capacity agreement. The decrease in accrued liabilities is due primarily to the payment in 1999 of $100 million in connection with the assignment of Williams' obligations under a gas purchase contract to an unaffiliated third party (see Note 12). The decrease in accrued rate refund liabilities reflects the payment in 1999 of $113 million of rate refunds to natural gas transportation customers and the second-quarter 1999 reductions to rate refund liabilities (see Note 3). In addition, during 1999 Williams has received federal income tax refunds totaling $380 million (see Note 6). Other - ----- Other Commitments Energy Marketing & Trading entered into certain contracts during 1998 and 1999 giving Williams the right to receive fuel conversion and certain other services for purposes of generating electricity. At June 30, 1999, annual estimated committed payments under these contracts range from $40 million to $214 million, resulting in total committed payments over the next 22 years of approximately $3.2 billion. Environmental Transcontinental Gas Pipe Line (Transco) received a letter stating that the U.S. Department of Justice (DOJ), at the request of the U.S. Environmental Protection Agency, intends to file a civil action against Transco arising from its waste management practices at Transco's compressor stations and metering stations in eleven states from Texas to New Jersey. DOJ stated in the letter that its complaint will seek civil penalties and injunctive relief under federal environmental laws. DOJ has offered to discuss settlement of the claim. While no specific amount was proposed, DOJ stated that any settlement must include an appropriate civil penalty for the alleged violations. Transco cannot reasonably estimate the amount of its potential liability, if any, at this time. However, Transco believes it has substantially addressed environmental concerns on its system through ongoing voluntary remediation and management programs. Year 2000 Compliance Williams initiated an enterprise-wide project in 1997 to address the year 2000 compliance issue for both traditional information technology areas and non-traditional areas, including embedded technology which is prevalent throughout the company. This project focuses on all technology hardware and software, external interfaces with customers and suppliers, operations process control, automation and instrumentation systems, and facility items. The phases of the project are awareness, inventory and assessment, renovation and replacement, testing and validation. The awareness and inventory/assessment phases of this project as they relate to both traditional and non-traditional information technology areas have been substantially completed. During the inventory and assessment phase, all systems with possible year 2000 implications were inventoried and classified into five categories: 1) highest, business critical, 2) high, compliance necessary within a short period of time following January 1, 2000, 3) medium, compliance necessary within 30 days from January 1, 2000, 4) low, compliance desirable but not required, and 5) unnecessary. Categories 1 through 3 were 24

26 designated as critical and are the major focus of this project. Some non-critical systems may not be compliant by January 1, 2000. Renovation/replacement and testing/validation of critical systems has been substantially completed, except for replacement of certain critical systems scheduled for completion later in 1999. Testing and validation activities will continue throughout the process as replacement systems come online and as remediation of systems pursuant to an implemented contingency plan are completed. The following table indicates the project status as of June 30, 1999, for traditional information technology and non-traditional areas by business unit. The tested category indicates the percentage that has been fully tested or otherwise validated as compliant. The untested category includes items that are believed to be compliant but which have not yet been validated. The not compliant category includes items which have been identified as not year 2000 compliant. Not Business Unit Tested Untested Compliant - ------------- ------ -------- --------- Traditional Information Technology: Gas Pipeline 100% 0% 0% Energy Services 94 4 2 Communications 94 2 4 Corporate/Other 100 0 0 Non-Traditional Information Technology: Gas Pipeline 100 0 0 Energy Services 99 0 1 Communications 99 1 0 Corporate/Other 98 2 0 Williams initiated a formal communications process with other companies in 1998 to determine the extent to which those companies are addressing year 2000 compliance. In connection with this process, Williams has sent approximately 17,800 letters and questionnaires to third parties including customers, vendors and service providers. Williams is evaluating responses as they are received or otherwise investigating the status of these companies' year 2000 compliance efforts. As of June 30, 1999, approximately 43 percent of the companies contacted have responded and virtually all of these have indicated that they are already compliant or will be compliant on a timely basis. Where necessary, Williams will be working with key business partners to reduce the risk of a break in service or supply and with non-compliant companies to mitigate any material adverse effect on Williams. Williams is utilizing both internal resources and external contractors to complete the year 2000 compliance project. Williams has a core group of 236 people involved in this enterprise-wide project. This includes 17 individuals responsible for coordinating, organizing, managing, communicating, and monitoring the project and another 219 staff members responsible for completing the project. Depending on which phase the project is in and what area is being focused on at any given point in time, there can be an additional 500 to 1,200 employees who are also contributing a portion of their time to the completion of this project. The Communications business unit has contracted with an external contractor at a cost of approximately $3 million to assist in all phases and various areas of the project. Gas Pipeline has contracted with an external contractor for a cost of up to $6 million for the remediation of the customer service software. Within Energy Services, two external contractors are being utilized at a total cost of approximately $2 million. Several previously planned system implementations have been or are scheduled for completion during 1999, which will lessen possible year 2000 impacts. For example, a new year 2000 compliant payroll/human resources system was implemented January 1, 1999. It replaced multiple human resources administration and payroll processing systems previously in place. The Communications business unit has a major service information management system implementation and other system implementations currently in process necessary to integrate the operations of its many components acquired in past acquisitions. These systems are coming online in stages during 1999 and will address the year 2000 compliance issues in certain areas. Within the Energy Services business unit, major applications had been replaced or were being replaced by MAPCO prior to its acquisition by Williams in early 1998. Those applications have been incorporated into the enterprise-wide project and remaining system replacements are proceeding on schedule. In addition, the Petroleum Services business unit of Energy Services is replacing its current ATLAS and revenue billing systems. The new ATLAS system will be used to manage refined product pipeline transportation, manage customer product inventories, authorize supplier and customer terminal loading and track loading balances. The new revenue billing system will interface with ATLAS to appropriately bill customers and account for the transactions. Current plans are to implement these new systems before November 1, 1999. The Midstream Gas & Liquids business unit of Energy Services plans to implement a new Gas Management and Gathering & Processing Accounting System (GasKit). GasKit, which is targeted to be online for November 1999 business, will integrate management of gas nominations and volume allocations with revenue billing. Gas Pipeline completed implementation of a new telephone system in 1998, and a new common financial system was implemented July 1, 1999 at one of the pipelines. Although all critical systems over which Williams has control are planned to be compliant and tested before the year 2000, Williams has identified two areas that would equate to a most reasonably 25

27 likely worst case scenario. First is the possibility of service interruptions due to non-compliance by third parties. For example, power failures along the communications network or transportation systems would cause service interruptions. This risk should be minimized by the enterprise-wide communications effort with and evaluation of third-party compliance plans and by the development of contingency plans. Another area of risk for non-compliance is the delay of system replacements scheduled for completion during 1999. The status of these systems is being closely monitored to reduce the chance of delays in completion dates. In situations where planned system implementations will not be in service timely or are delayed past an implementation date of September 1, 1999, alternative steps are being taken to make existing systems compliant. It is not possible to quantify the possible financial impact if this most reasonably likely worst case scenario were to come to fruition. Significant focus on the contingency plan phase of the project has been taking place in 1999. Guidelines for the contingency planning process were issued in January 1999. Contingency plans are being developed for critical business processes, critical business partners, suppliers and system replacements that experience significant delays. These plans are expected to be defined by August 31, 1999, and implemented where appropriate. The following is a discussion of contingency plans that have been developed to date. Gas Pipeline's contingency plans include manning all operational stations twenty-four hours a day, putting extra security measures into place and stocking up on supplies. In addition, most of Gas Pipeline's compressor stations are capable of independently generating electricity in the event of a loss of electricity, and operation of the pipelines can be done manually in case there is a loss of telecommunications capability. Because of the delay in the implementation date of the new ATLAS and revenue billing systems at Petroleum Services to October 1999, the contingency plan for those systems has been implemented. That plan includes the modification and testing of the existing ATLAS and revenue billing systems by the end of October 1999 to ensure that a compliant system is in place in case the new systems' implementation date is delayed further. Due to the delay in the implementation of the GasKit system at Midstream Gas & Liquids from June 1999 to November 1999, the current system is currently being assessed and is targeted to be year 2000 compliant by November 15, 1999. Communications engaged an outside consultant to assist in identifying potential impacts to its business areas and processes. This review was completed in June 1999 and the information is now being used to enhance the development of contingency plans at Communications. Contingency plans for the corporate headquarters' data centers include onsite or on-call personnel to monitor systems and resolve problems, backup generators in the event of loss of electric power, and backup chiller systems/trailer mounted chillers in case of the loss of chiller capability from the third-party supplier. Costs incurred for new software and hardware purchases are being capitalized and other costs are being expensed as incurred. Williams currently estimates the total cost of the enterprise-wide project, including any accelerated system replacements, to be approximately $49 million. This $49 million has been or is expected to be spent as follows: o Prior to 1998 and during the first quarter of 1998, Williams was conducting the project awareness and inventory/assessment phases of the project and incurred costs totaling $3 million. o During the second quarter of 1998, $2 million was spent on the renovation/replacement and testing/validation phases and completion of the inventory/assessment phase. o The third and fourth quarters of 1998 focused on the renovation/replacement and testing/validation phases, and $10 million was incurred. o During the first quarter of 1999, renovation/replacement and testing/validation continued, contingency planning began and $9 million was incurred. o During the second quarter of 1999, the primary focus shifted to testing/validation and contingency planning, and $10 million was spent. o The third and fourth quarters of 1999 will focus mainly on contingency planning and final testing with $13 million expected to be spent. o Approximately $2 million is estimated to be spent during the first two quarters of 2000 for monitoring and problem resolution. Of the $34 million incurred to date, approximately $31 million has been expensed, and approximately $3 million has been capitalized. Of the $15 million of future costs necessary to complete the project within the schedule described, approximately $12 million will be expensed and the remainder capitalized. This estimate does not include Williams' potential share of year 2000 costs that may be incurred by partnerships and joint ventures in which the company participates but is not the operator. The costs of previously planned system replacements are not considered to be year 2000 costs and are, therefore, excluded from the amounts discussed above. The preceding discussion contains forward-looking statements including, without limitation, statements relating to the company's plans, strategies, objectives, expectations, intentions, and adequate resources, that are made pursuant to the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995. Readers are cautioned that such forward-looking statements contained in the year 2000 update are based on certain assumptions which 26

28 may vary from actual results. Specifically, the dates on which the company believes the year 2000 project will be completed and computer systems will be implemented are based on management's best estimates, which were derived utilizing numerous assumptions of future events, including the continued availability of certain resources, third-party modification plans and other factors. However, there can be no guarantee that these estimates will be achieved, or that there will not be a delay in, or increased costs associated with, the implementation of the year 2000 project. Other specific factors that might cause differences between the estimates and actual results include, but are not limited to, the availability and cost of personnel trained in these areas, the ability to locate and correct all relevant computer code, timely responses to and corrections by third parties and suppliers, the ability to implement interfaces between the new systems and the systems not being replaced, and similar uncertainties. Due to the general uncertainty inherent in the year 2000 problem, resulting in large part from the uncertainty of the year 2000 readiness of third parties, the company cannot ensure its ability to timely and cost effectively resolve problems associated with the year 2000 issue that may affect its operations and business, or expose it to third-party liability. ITEM 3. Quantitative and Qualitative Disclosures About Market Risk During the first quarter of 1999, Williams issued $200 million in adjustable rate debt due in 2004 at an initial rate of approximately 5.3 percent. Subsequent to June 30, 1999, Williams issued $700 million of 7.625 percent fixed rate notes due 2019. At June 30, 1999, Williams has preferred stock interests in certain Brazilian ventures totaling $362 million. Estimating cash flows from these investments is not practical given that the cash flows from or liquidation of these investments are uncertain. The Brazilian economy has experienced significant volatility in 1999 resulting in an approximate 32 percent reduction in the Brazilian Real against the U.S. dollar. However, Williams believes the fair value of these investments approximates the carrying value. An additional 20 percent reduction in the value of the Brazilian Real against the U.S. dollar could result in up to a $72 million reduction in the fair value of these investments. This analysis assumes a direct correlation in the fluctuation of the Brazilian Real against the value of our investments. The ultimate duration and severity of the conditions in Brazil remains uncertain, as does the long-term impact on our interests in the ventures. Williams continues to monitor currency fluctuations in this region and considers the employment of strategies to hedge currency movements when cash flows from these investments warrant the need for such consideration. 27

29 PART II. OTHER INFORMATION Item 4. Submission of Matters to a Vote of Security Holders The Annual Meeting of Stockholders of the Company was held on May 20, 1999. At the Annual Meeting, three individuals were elected as directors of the Company and nine individuals continue to serve as directors pursuant to their prior election. In addition, the appointment of Ernst &Young LLP as the independent auditor of the Company for 1999 was ratified. A tabulation of the voting at the Annual Meeting with respect to the matters indicated is as follows: Election of Directors Name For Withheld - ------------------- ----------- --------- Frank T. MacInnis 380,412,332 2,867,362 Jack A. MacAllister 380,235,648 3,044,046 Peter C. Meinig 380,950,565 2,329,129 Ratification of Appointment of Independent Auditor For Against Abstain - ----------- --------- --------- 380,019,461 1,688,779 1,571,454 Item 6. Exhibits and Reports on Form 8-K (a) The exhibits listed below are filed as part of this report: Exhibit 12--Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements Exhibit 27--Financial Data Schedule (b) During the second quarter of 1999, the Company filed a Form 8-K on April 29,1999 which reported a significant event under Item 5 of the Form and included the exhibits required by Item 7 of the Form. 28

30 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. THE WILLIAMS COMPANIES, INC. ---------------------------------- (Registrant) /s/ Gary R. Belitz ---------------------------------- Gary R. Belitz Controller (Duly Authorized Officer and Principal Accounting Officer) August 16, 1999

31 INDEX TO EXHIBITS Exhibit Number Description - ------- ----------- 12 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements 27 Financial Data Schedule

1 EXHIBIT 12 The Williams Companies, Inc. and Subsidiaries Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements (Dollars in millions) Six months ended June 30, 1999 -------------- Earnings: Income before income taxes, extraordinary loss and change in accounting principle $ 161.6 Add: Interest expense - net 251.0 Rental expense representative of interest factor 38.1 Minority interest in income of consolidated subsidiaries 4.0 Interest accrued - 50% owned company 3.5 Equity losses in less than 50% owned companies 32.7 Other 5.9 -------------- Total earnings as adjusted plus fixed charges $ 496.8 ============== Fixed charges and preferred stock dividend requirements: Interest expense - net $ 251.0 Capitalized interest 26.9 Rental expense representative of interest factor 38.1 Pretax effect of dividends on preferred stock of the Company 4.3 Interest accrued - 50% owned company 3.5 -------------- Combined fixed charges and preferred stock dividend requirements $ 323.8 ============== Ratio of earnings to combined fixed charges and preferred stock dividend requirements 1.53 ==============

5 1,000 6-MOS DEC-31-1999 JAN-01-1999 JUN-30-1999 200,073 0 1,950,914 40,380 569,099 3,563,635 17,244,915 3,806,038 20,012,533 5,387,464 6,189,721 0 71,840 437,827 3,822,803 20,012,533 0 3,970,283 0 2,873,623 30,549 12,789 277,949 161,616 88,667 72,949 0 0 (5,600) 67,349 .15 .15