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 September 30, 1998 ------------------------------------------------- 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 October 31, 1998 - -------------------------- ------------------------------- Common Stock, $1 par value 427,771,866 Shares

2 The Williams Companies, Inc. Index Page ---- Part I. Financial Information Item 1. Financial Statements Consolidated Statement of Income--Three and Nine Months Ended September 30, 1998 and 1997 2 Consolidated Balance Sheet--September 30, 1998 and December 31, 1997 3 Consolidated Statement of Cash Flows--Nine Months Ended September 30, 1998 and 1997 4 Notes to Consolidated Financial Statements 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 15 Item 3. Quantitative and Qualitative Disclosures about Market Risk 22 Part II. Other Information Item 6. Exhibits and Reports on Form 8-K 23 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 Current Report on Form 8-K dated May 18, 1998 and the Year 2000 disclosures contained in this document. 1

3 The Williams Companies, Inc. Consolidated Statement of Income (Unaudited) (Millions, except per-share amounts) --------------------------------------------- Three months ended Nine months ended September 30, September 30, --------------------------------------------- 1998 1997* 1998 1997* -------- -------- -------- --------- Revenues: Gas Pipelines (Note 3) $ 400.6 $ 398.3 $1,243.9 $1,237.4 Energy Services (Note 3) 1,240.7 1,517.0 3,741.5 4,386.3 Communications (Note 2) 418.5 413.7 1,219.6 989.4 Other 14.5 8.9 40.0 28.0 Intercompany eliminations (173.3) (238.9) (603.6) (742.6) -------- -------- -------- -------- Total revenues 1,901.0 2,099.0 5,641.4 5,898.5 -------- -------- -------- -------- Profit-center costs and expenses: Costs and operating expenses 1,377.2 1,609.5 4,059.4 4,454.3 Selling, general and administrative expenses 275.0 220.3 754.4 593.1 Other (income) expense--net (Notes 3 and 4) 13.3 (6.6) 68.3 (16.3) -------- -------- -------- -------- Total profit-center costs and expenses 1,665.5 1,823.2 4,882.1 5,031.1 -------- -------- -------- -------- Operating profit: Gas Pipelines (Note 3) 141.7 141.7 489.7 453.9 Energy Services (Note 3) 116.6 137.3 315.7 413.2 Communications (Note 2) (25.6) (5.2) (56.2) (3.9) Other 2.8 2.0 10.1 4.2 -------- -------- -------- -------- Total operating profit 235.5 275.8 759.3 867.4 General corporate expenses (Note 4) (17.2) (17.9) (76.1) (57.0) Interest accrued (131.5) (118.5) (376.0) (344.7) Interest capitalized 12.6 8.1 28.6 15.5 Investing income (loss) (Note 5) (33.7) 4.1 (30.7) 13.5 Gain on sale of interest in subsidiary (Note 6) -- -- -- 44.5 Gain on sale of assets (Note 7) -- -- -- 66.0 Minority interest in (income) loss of consolidated subsidiaries .1 (5.2) (5.5) (12.6) Other expense--net (10.0) (1.9) (22.4) (4.7) -------- -------- -------- -------- Income before income taxes 55.8 144.5 277.2 587.9 Provision for income taxes (Note 8) 23.7 57.1 111.5 203.4 -------- -------- -------- -------- Income before extraordinary loss 32.1 87.4 165.7 384.5 Extraordinary loss (Note 9) -- (73.7) (4.8) (73.7) -------- -------- -------- -------- Net income 32.1 13.7 160.9 310.8 Preferred stock dividends 1.9 2.4 5.7 7.6 -------- -------- -------- -------- Income applicable to common stock $ 30.2 $ 11.3 $ 155.2 $ 303.2 -------- -------- -------- -------- Basic earnings per common share (Note 10): Income before extraordinary loss $ .07 $ .21 $ .38 $ .92 Extraordinary loss (Note 9) -- (.18) (.01) (.18) -------- -------- -------- -------- Net income $ .07 $ .03 $ .37 $ .74 -------- -------- -------- -------- Average shares (thousands) 428,594 411,821 424,076 411,677 Diluted earnings per common share (Note 10): Income before extraordinary loss $ .07 $ .20 $ .38 $ .89 Extraordinary loss (Note 9) -- (.17) (.01) (.17) -------- -------- -------- -------- Net income $ .07 $ .03 $ .37 $ .72 ======== ======== ======== ======== Average shares (thousands) 442,080 429,155 440,874 428,980 Cash dividends per common share $ .15 $ .13 $ .45 $ .39 * Amounts have been restated to reflect the acquisition of MAPCO Inc., which has been accounted for as a pooling of interests, and certain revenue amounts have been reclassified to conform to current year classifications (see Note 2 for additional information). See accompanying notes. 2

4 The Williams Companies, Inc. Consolidated Balance Sheet (Unaudited) (Millions) ---------------------------- September 30, December 31, 1998 1997* ------------- ------------ ASSETS - ------ Current assets: Cash and cash equivalents $ 91.6 $ 122.1 Receivables 1,650.7 1,584.5 Transportation and exchange gas receivable 105.2 130.4 Inventories (Note 11) 434.9 433.9 Commodity trading assets 275.3 180.3 Deferred income taxes 227.6 236.6 Other 188.5 176.2 ----------- ----------- Total current assets 2,973.8 2,864.0 Investments 690.7 388.1 Property, plant and equipment, at cost 15,829.9 14,605.1 Less accumulated depreciation and depletion (3,441.9) (3,068.3) ----------- ----------- 12,388.0 11,536.8 Goodwill and other intangible assets--net 588.8 600.6 Other assets and deferred charges 1,092.6 888.1 ----------- ----------- Total assets $ 17,733.9 $ 16,277.6 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY - ------------------------------------ Current liabilities: Notes payable (Note 12) $ 797.8 $ 693.0 Accounts payable 1,051.3 1,288.5 Accrued liabilities 1,437.1 1,349.3 Commodity trading liabilities 273.7 182.0 Long-term debt due within one year (Note 12) 144.9 80.3 ----------- ----------- Total current liabilities 3,704.8 3,593.1 Long-term debt (Note 12) 6,323.4 5,351.5 Deferred income taxes 2,072.2 2,009.1 Other liabilities 1,027.3 946.5 Minority interest in consolidated subsidiaries 284.6 144.8 Contingent liabilities and commitments (Note 13) Stockholders' equity: Preferred stock, $1 par value, 30 million shares authorized, 1.8 million shares issued in 1998 and 2.5 million shares issued in 1997 102.2 142.2 Common stock, $1 par value, 960 million shares authorized, 431.7 million shares issued in 1998 and 431.5 million shares issued in 1997 431.7 431.5 Capital in excess of par value 973.2 1,041.6 Retained earnings 2,948.4 2,983.3 Other (85.7) (54.1) ----------- ----------- 4,369.8 4,544.5 Less treasury stock (at cost), 4 million shares of common stock in 1998 and 18.9 million shares of common stock in 1997 (Note 4) (48.2) (311.9) ----------- ----------- Total stockholders' equity 4,321.6 4,232.6 ----------- ----------- Total liabilities and stockholders' equity $ 17,733.9 $ 16,277.6 =========== =========== * Amounts have been restated to reflect the acquisition of MAPCO Inc., which has been accounted for as a pooling of interests (see Note 2 for additional information). See accompanying notes. 3

5 The Williams Companies, Inc. Consolidated Statement of Cash Flows (Unaudited) (Millions) ------------------------------- Nine months ended September 30, ------------------------------- 1998 1997* ------------------------------- OPERATING ACTIVITIES: Net income $ 160.9 $ 310.8 Adjustments to reconcile to cash provided from operations: Extraordinary loss 4.8 73.7 Premium on early extinguishment of debt (7.1) (154.2) Depreciation, depletion and amortization 471.8 432.8 Provision for deferred income taxes 67.1 59.0 Provision for loss on property and other assets 29.8 2.5 (Gain) loss on dispositions of property and interest in subsidiary .6 (119.9) Minority interest in income of consolidated subsidiaries 5.5 12.6 Cash provided (used) by changes in assets and liabilities: Receivables sold (55.9) 138.9 Receivables 24.0 164.1 Inventories (.7) (103.6) Other current assets (31.8) 25.7 Accounts payable (227.2) (55.8) Accrued liabilities 64.8 (142.1) Current commodity trading assets and liabilities (3.3) 11.4 Non-current commodity trading assets and liabilities (36.7) (15.8) Other, including changes in non-current assets and liabilities (22.0) 40.2 ---------- ---------- Net cash provided by operating activities 444.6 680.3 ---------- ---------- FINANCING ACTIVITIES: Proceeds from notes payable 708.9 1,439.1 Payments of notes payable (1,096.7) (282.1) Proceeds from long-term debt 2,623.4 1,329.1 Payments of long-term debt (1,089.7) (1,918.1) Proceeds from issuance of common stock 67.2 37.7 Purchases of treasury stock - (50.2) Dividends paid (195.8) (156.5) Contributions from minority interest owners 141.5 11.9 Other--net (16.1) (35.0) ---------- ---------- Net cash provided by financing activities 1,142.7 375.9 ---------- ---------- INVESTING ACTIVITIES: Property, plant and equipment: Capital expenditures (1,344.5) (931.4) Proceeds from dispositions 71.2 89.3 Changes in accounts payable and accrued liabilities (3.3) (17.3) Acquisition of businesses, net of cash acquired - (135.7) Proceeds from sale of assets - 66.0 Purchase of investments/advances to affiliates (347.9) (229.2) Other--net 6.7 20.5 ---------- ---------- Net cash used by investing activities (1,617.8) (1,137.8) ---------- ---------- Decrease in cash and cash equivalents (30.5) (81.6) Cash and cash equivalents at beginning of period 122.1 220.1 ---------- ---------- Cash and cash equivalents at end of period $ 91.6 $ 138.5 ========== ========== * Amounts have been restated to reflect the acquisition of MAPCO Inc., which has been accounted for as a pooling of interests (see Note 2 for additional information). 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' Current Report on Form 8-K dated May 18, 1998. 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 September 30, 1998, results of operations for the three and nine months ended September 30, 1998 and 1997, and cash flows for the nine months ended September 30, 1998 and 1997. Operating profit of operating companies may vary by quarter. Based on current rate structures and/or historical maintenance schedules, Transcontinental Gas Pipe Line and Texas Gas Transmission experience lower operating profits in the second and third quarters as compared to the first and fourth quarters. As a result of its power services activity, Energy Marketing & Trading experiences higher operating profit in the second and third quarters as compared to the first and fourth quarters. 2. Basis of presentation - ------------------------------------------------------------------------------- On March 28, 1998, Williams completed the acquisition of MAPCO Inc. by exchanging shares of Williams common stock for outstanding MAPCO common stock and employee stock options (see Note 4). The transaction has been accounted for as a pooling of interests and, accordingly, the consolidated financial statements and notes have been restated to reflect the results of operations, financial position and cash flows as if the companies had been combined throughout the periods presented. MAPCO is engaged in the NGL pipeline, petroleum refining and marketing and propane marketing businesses, and has become part of the Energy Services business unit. Effective April 1, 1998, certain marketing activities of natural gas liquids (previously reported in Midstream Gas & Liquids) and petroleum refining products (previously reported in Petroleum Services) were transferred to Energy Marketing & Trading and combined with its commodity risk trading operations. As a result, revenues and operating profit amounts for the three and nine months ended September 30, 1997, have been reclassified consistent with the activities. These marketing activities are reported through first quarter 1998 on a "gross" basis in the Consolidated Statement of Income as revenues and profit-center costs within Energy Marketing & Trading. Concurrent with completing the combination of such activities with the commodity risk trading operations of Energy Marketing & Trading, the related contract rights and obligations of certain of these operations were recorded in the Consolidated Balance Sheet on a market-value basis consistent with Energy Marketing & Trading's accounting policy, and the income statement presentation relating to these operations was changed effective April 1, 1998, to reflect these revenues net of the related costs to purchase such items. On April 30, 1997, Williams and Northern Telecom (Nortel) combined their customer-premise equipment sales and service operations into a limited liability company, Williams Communications Solutions, LLC (LLC). Communications' revenues and operating profit amounts include the operating results of the LLC beginning May 1, 1997 (see Note 6). 3. Revenues and operating profit - ------------------------------------------------------------------------------- Revenues and operating profit of Gas Pipelines and Energy Services for the three and nine months ended September 30, 1998 and 1997, are as follows: Three months ended September 30, ----------------------------------------- (Millions) Revenues Operating Profit 1998 1997 1998 1997 -------- -------- -------- -------- Gas Pipelines: Central $ 42.3 $ 49.4 $ 12.3 $ 19.1 Kern River Gas Transmission 40.3 43.1 27.3 30.6 Northwest Pipeline 73.9 71.2 35.7 35.3 Texas Gas Transmission 50.0 53.2 7.9 3.7 Transcontinental Gas Pipe Line 194.1 181.4 58.5 53.0 -------- -------- -------- -------- $ 400.6 $ 398.3 $ 141.7 $ 141.7 ======== ======== ======== ======== 5

7 Notes (continued) Three months ended September 30, ----------------------------------------- (Millions) Revenues Operating Profit 1998 1997 1998 1997 -------- -------- -------- -------- Energy Services: Energy Marketing & Trading $ 298.3 $ 524.4* $ 14.6 $ (2.5)* Exploration & Production 28.7 32.1 4.9 5.4 Midstream Gas & Liquids 208.5 260.3* 56.2 72.1* Petroleum Services 705.2 700.2* 44.8 62.3* Merger-related costs - - (3.9) - --------- -------- -------- -------- $ 1,240.7 $1,517.0* $ 116.6 $ 137.3* ========= ======== ======== ======== Nine months ended September 30, ----------------------------------------------------- (Millions) Revenues Operating Profit 1998 1997 1998 1997 ---------- ---------- ---------- ---------- Gas Pipelines: Central $ 128.2 $ 137.2 $ 41.7 $ 51.4 Kern River Gas Transmission 121.8 125.1 83.8 90.6 Northwest Pipeline 215.4 204.5 105.1 94.5 Texas Gas Transmission 193.8 210.4 61.2 55.5 Transcontinental Gas Pipe Line 584.7 560.2 197.9 161.9 ---------- ---------- ---------- ---------- $ 1,243.9 $ 1,237.4 $ 489.7 $ 453.9 ========== ========== ========== ========== Energy Services: Energy Marketing & Trading $ 953.5 $ 1,511.6* $ 35.3 $ 9.7* Exploration & Production 106.8 94.5 25.2 20.1 Midstream Gas & Liquids 650.4 782.9* 177.3 226.4* Petroleum Services 2,030.8 1,997.3* 123.8 157.0* Merger-related costs -- -- (45.9) -- ---------- ---------- ---------- ---------- $ 3,741.5 $ 4,386.3* $ 315.7 $ 413.2* ========== ========== ========== ========== * Amounts have been restated as described in Note 2. Included in the third quarter 1998 operating profit for Energy Marketing & Trading are credit loss accruals of $26.4 million for certain energy capital and retail energy activities. Included in the nine months ended September 30, 1998 other (income) expense-net and in operating profit for Petroleum Services is a $15.5 million loss provision for potential refunds to customers from a recent order from the Federal Energy Regulatory Commission (see Note 13 for additional information). 4. MAPCO acquisition - ------------------------------------------------------------------------------- On November 24, 1997, Williams and MAPCO Inc. announced that they had entered into a definitive merger agreement whereby Williams would acquire MAPCO by exchanging 1.665 shares of Williams common stock for each outstanding share of MAPCO common stock. In addition, outstanding MAPCO employee stock options would be converted into Williams common stock. The merger was consummated on March 28, 1998, with the issuance of 98.8 million shares of Williams common stock valued at $3.1 billion based on the closing price of Williams common stock on March 27, 1998. In connection with the merger, 8.4 million shares of MAPCO $1 par value common stock previously held in treasury were retired. These shares had a carrying value of $253.8 million. The merger constituted a tax-free reorganization and has been accounted for as a pooling of interests. Intercompany transactions between Williams and MAPCO prior to the merger have been eliminated, and no material adjustments were necessary to conform MAPCO's accounting policies. In connection with the merger, Williams has recognized approximately $74 million in merger-related costs comprised primarily of outside professional fees and early retirement and severance costs. Approximately $46 million of these merger-related costs are included in other (income) expense-net as a component of Energy Services' operating profit for the nine months ended September 30, 1998 (see Note 3), and approximately $28 million is included in general corporate expenses. During 1997, payments of $32.6 million were made for non-compete agreements. These costs are being amortized over one to three years from the merger completion date. 6

8 Notes (continued) The results of operations for each company and the combined amounts presented in the Williams' Consolidated Statement of Income are as follows: Three months Three months Nine months ended ended ended (Millions) March 31, September 30, September 30, ------------------------------------------------ 1998 1997 1997 ---------- ---------- ---------- Revenues: Williams $ 1,137.3 $ 1,121.0 $ 3,143.0 MAPCO 823.8 982.1 2,767.6 Intercompany eliminations (1.3) (4.1) (12.1) ---------- ---------- ---------- Combined $ 1,959.8 $ 2,099.0 $ 5,898.5 ========== ========== ========== Net income: Williams $ 59.7 $ (8.4) $ 205.3 MAPCO 8.4 22.1 105.5 ---------- ---------- ---------- Combined $ 68.1 $ 13.7 $ 310.8 ========== ========== ========== 5. Investing income (loss) - ------------------------------------------------------------------------------- Third-quarter 1998 investing loss includes a $23.2 million write-down related to a Communications network applications venture that was re-evaluated in the third quarter. 6. Sale of interest in subsidiary - ------------------------------------------------------------------------------- On April 30, 1997, Williams and Nortel combined their customer-premise equipment sales and service operations into a limited liability company, Williams Communications Solutions, LLC (LLC). In addition, Williams paid $68 million to Nortel. Williams has accounted for its 70 percent interest in the operations that Nortel contributed to the LLC as a purchase business combination, and beginning May 1, 1997, has included the results of operations of the acquired company in Williams' Consolidated Statement of Income. Williams recorded the 30 percent reduction in its operations contributed to the LLC as a sale to the minority shareholders of the LLC. Williams recognized a gain of $44.5 million based on the fair value of its operations contributed to the LLC. Income taxes were not provided on the gain, because the transaction did not effect the differences between the financial and tax bases of identifiable assets and liabilities. If the transaction had occurred on January 1, 1997, Williams' unaudited pro forma revenues for the nine months ended September 30, 1997, would have been approximately $6.1 billion. The pro forma effect of the transaction on Williams' net income is not significant. Pro forma financial information is not necessarily indicative of results of operations that would have occurred if the transaction had occurred on January 1, 1997, or of future results of operations of the combined companies. 7. Sale of assets - ------------------------------------------------------------------------------- In January 1997, Williams sold its interest in the natural gas liquids and condensate reserves in the West Panhandle field of Texas for $66 million in cash. The sale resulted in a $66 million pre-tax gain on the transaction, because the related reserves had no book value. 8. Provision for income taxes - ------------------------------------------------------------------------------- The provision for income taxes includes: Three months ended Nine months ended (Millions) September 30, September 30, --------------------------------------------- 1998 1997 1998 1997 --------- --------- --------- --------- Current: Federal $ 16.0 $ 34.5 $ 40.8 $ 122.3 State .1 9.7 2.1 22.1 Foreign .5 -- 1.5 -- --------- --------- --------- --------- 16.6 44.2 44.4 144.4 Deferred: Federal 4.1 11.8 54.6 48.7 State 3.0 1.1 12.5 10.3 --------- --------- --------- --------- 7.1 12.9 67.1 59.0 --------- --------- --------- --------- Total provision $ 23.7 $ 57.1 $ 111.5 $ 203.4 ========= ========= ========= ========= The effective income tax rate for 1998 is greater than the federal statutory rate due primarily to the effects of state income taxes. The effective income tax rate for the three months ended September 30, 1997, is greater than the federal statutory rate due primarily to the effects of state income taxes, partially offset by the effects of income tax credits from coal-seam gas production. The effective income tax rate for the nine months ended September 30, 1997, is less than the federal statutory rate due primarily to the effect of the non-taxable gain recognized in the second quarter (see Note 6) and income tax credits from coal-seam gas production, partially offset by the effects of state income taxes. 9. Extraordinary loss - ------------------------------------------------------------------------------- The extraordinary loss in 1998 resulted from the early extinguishment of debt. 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). During the third quarter of 1997, Williams initiated a restructuring of its debt portfolio. At September 30, 1997, Williams had paid approximately $1.2 million to redeem higher interest rate debt for a $73.7 million net loss (net of a $46.9 million benefit for income taxes). 8

9 Notes (continued) 10. Earnings per share - ------------------------------------------------------------------------------- Basic earnings per common share are computed for the three and nine months ended September 30, 1998 and 1997, as follows: (Millions, except Three months ended Nine months ended per-share amounts) September 30, September 30, -------------------------------------------- 1998 1997* 1998 1997* -------- -------- -------- -------- Basic earnings: Income before extraordinary loss $ 32.1 $ 87.4 $ 165.7 $ 384.5 Extraordinary loss -- (73.7) (4.8) (73.7) -------- -------- -------- -------- Net income 32.1 13.7 160.9 310.8 Preferred stock dividends: $2.21 cumulative preferred stock -- .2 -- 1.0 $3.50 cumulative convertible preferred stock 1.9 2.2 5.7 6.6 -------- -------- -------- -------- Income applicable to common stock $ 30.2 $ 11.3 $ 155.2 $ 303.2 -------- -------- -------- -------- Basic shares: Average number of common shares outstanding during the period 426,021 408,591 421,719 408,068 Shares attributable to deferred stock 2,573 3,230 2,357 3,609 -------- -------- -------- -------- Total basic weighted- average shares 428,594 411,821 424,076 411,677 -------- -------- -------- -------- Basic earnings per common share: Income before extraordinary loss $ .07 $ .21 $ .38 $ .92 Extraordinary loss -- (.18) (.01) (.18) -------- -------- -------- -------- Net income $ .07 $ .03 $ .37 $ .74 ======== ======== ======== ======== Diluted earnings per common share are computed for the three and nine months ended September 30, 1998 and 1997, as follows: (Millions, except Three months ended Nine months ended per-share amounts) September 30, September 30, ------------------------------------------------------- 1998 1997* 1998 1997* ----------- ----------- ----------- ----------- Diluted earnings: Income before extraordinary loss $ 32.1 $ 87.4 $ 165.7 $ 384.5 Extraordinary loss -- (73.7) (4.8) (73.7) ----------- ----------- ----------- ----------- Net income 32.1 13.7 160.9 310.8 Preferred stock dividends: $2.21 cumulative preferred stock -- .2 -- 1.0 ----------- ----------- ----------- ----------- Income applicable to common stock $ 32.1 $ 13.5 $ 160.9 $ 309.8 =========== =========== =========== =========== Diluted shares: Average number of common shares outstanding during the period 426,021 408,591 421,719 408,068 Shares attributable to options and deferred stock 7,029 8,848 9,222 9,195 Dilutive preferred shares 9,030 11,716 9,933 11,717 ----------- ----------- ----------- ----------- Total diluted weighted- average shares 442,080 429,155 440,874 428,980 =========== =========== =========== =========== Diluted earnings per common share: Income before extraordinary loss $ .07 $ .20 $ .38 $ .89 Extraordinary loss -- (.17) (.01) (.17) ----------- ----------- ----------- ----------- Net income $ .07 $ .03 $ .37 $ .72 =========== =========== =========== =========== * Share and per-share amounts for 1997 have been restated to reflect the effect of the December 29, 1997, two-for-one common stock split and the acquisition of MAPCO Inc., which has been accounted for as a pooling of interests. 8

10 Notes (continued) 11. Inventories - ------------------------------------------------------------------------------- September 30, December 31, (Millions) 1998 1997 -------------------------- Raw materials: Crude oil $ 45.7 $ 30.5 Other 1.2 5.2 --------- --------- 46.9 35.7 Finished goods: Refined products 79.6 122.3 Natural gas liquids 68.4 43.8 General merchandise & communications equipment 78.8 90.0 --------- --------- 226.8 256.1 Materials and supplies 87.3 82.5 Natural gas in underground storage 71.4 57.8 Other 2.5 1.8 --------- --------- $ 434.9 $ 433.9 ========= ========= 12. Debt and banking arrangements - ------------------------------------------------------------------------------- Notes payable During 1998, Williams Holdings of Delaware, Inc. (Williams Holdings) increased its commercial paper program to $1 billion. The commercial paper program is backed by short-term bank-credit facilities totaling $1 billion. At September 30, 1998, $593 million 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, and Williams Communications Solutions, LLC have access to varying amounts of the facility while Williams and Williams Holdings have access to all unborrowed amounts. Interest rates vary with current market conditions. For financial statement reporting purposes at September 30, 1998, $250 million in current debt obligations have been classified as non-current obligations based on Williams' intent and ability to refinance on a long-term basis. At September 30, 1998, the amount available on the $1 billion credit agreement of $318 million is sufficient to complete these refinancings. 9

11 Notes (continued) Debt - -------------------------------------------------------------------------------- Weighted- average interest September 30, December 31, (Millions) rate* 1998 1997 --------------------------------------- The Williams Companies, Inc. Revolving credit loans 5.9% $ 682.0 $ 383.0 Debentures, 8.875% - 10.25%, payable 2012, 2020 and 2021 8.3 136.9 137.0 Notes, 5.1% - 9.625%, pay- able through 2012** 6.4 2,275.1 1,042.1 Williams Gas Pipelines Central Variable rate notes, payable 1999 8.2 130.0 130.0 Kern River Gas Transmission Notes, 6.42% and 6.72%, payable through 2001 6.6 549.8 586.4 Northwest Pipeline Debentures, 7.125% - 10.65%, payable through 2025 8.3 151.4 151.6 Notes, 6.625%, payable 2007 6.6 250.0 250.0 Adjustable rate notes, payable through 2002 9.0 6.7 8.3 Texas Gas Transmission Debentures, 7.25%, payable 2027 7.3 99.1 99.0 Notes, 8.625%, payable 2004 8.6 152.1 152.4 Transcontinental Gas Pipe Line Revolving credit loans -- -- 160.0 Debentures, 7.08% and 7.25%, payable 2026** 7.2 399.7 399.7 Notes, 6.125% - 8.875%, payable 2002 through 2008 7.0 426.2 128.2 Adjustable rate note, payable 2002 5.7 150.0 150.0 Williams Holdings of Delaware Revolving credit loans -- -- 200.0 Debentures, 6.25% and 7.7%, payable 2006 and 2027 5.6 351.9 351.8 Notes, 6.365% - 8.87%, payable through 2022 7.6 536.6 625.3 MAPCO Inc. Commercial paper and bank money market lines -- -- 135.8 MAPCO Natural Gas Liquids, Inc. Notes, 6.67% - 8.95%, payable through 2022 7.8 165.0 165.0 Williams Communications Solutions Revolving credit loans -- -- 125.0 Other, payable through 2005 7.4 5.8 51.2 --------- --------- 6,468.3 5,431.8 Current portion of long-term debt (144.9) (80.3) --------- --------- $ 6,323.4 $ 5,351.5 ========= ========= * At September 30, 1998, including the effects of interest-rate swaps. ** $300 million, 5.95% notes, payable 2010; $200 million, 7.08% debentures, payable 2026; and $240 million, 6.125% notes, payable 2012 are subject to redemption at par at the option of the debtholder in 2000, 2001 and 2002, respectively. 13. 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 reserved $416 million for potential refund as of September 30, 1998. 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. In October 1997, the FERC voted not to reconsider an order issued in one of the three pipeline proceedings, but convened a conference on January 30, 1998, to consider, on an industry-wide basis, issues with respect to pipeline rates of return. In July 1998, the FERC issued orders in the other two pipeline rate cases, again modifying its rate of return methodology by adopting a formula that gives less weight to the long-term growth component. This most recent formula modification results in somewhat higher rates of return compared to the rates of return calculated under the FERC's prior formula. Neither pipeline has made any changes to its accounting reserves pending resolution of the issues discussed above. 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 recently ruled on by the U.S. Court of Appeals for the D.C. Circuit, require interstate gas pipeline companies to change the manner in which they provide services. Williams' gas pipelines subsidiaries implemented restructurings in 1993. Certain aspects of two of its pipeline companies' restructurings are under appeal. 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. On February 27, 1997, the FERC issued Order No. 636-C which dealt with the six issues remanded by the D.C. Circuit. In that order, the FERC reaffirmed that pipelines should be exempt from sharing gas supply realignment costs. Requests for rehearing have been filed for the order. 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-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. The deadline for comments on the NOPR and NOI has been extended until the first quarter of 1999. 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 $141 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. As a result of FERC Order 636, which requires interstate gas pipelines to change the way they do business, 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. 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. Order 636-D has been appealed. 10

12 Notes (continued) Pursuant to a stipulation and agreement approved by the FERC, Williams Gas Pipelines Central (Central) has made 13 filings to direct bill take-or-pay and gas supply realignment costs. The total amount approved for direct billing, net of certain amounts collected subject to refunds, is $73.1 million. An intervenor has 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 has filed for rehearing, and management plans to vigorously defend 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, which in turn must be acted upon by the FERC. If the FERC's final ruling on eligibility is unfavorable, Central will appeal these orders to the courts. On May 29, 1998, 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. The Order also denied, without prejudice to a later refiling, an indefinite extension of Central's recovery mechanism for non-settlement costs associated with these contracts. No party bid less than the fixed maximum reserve price in the approved auction and, as a result, the contracts were not assigned. In accordance with FERC's Orders, on September 30, 1998, Central filed a request for authority to conduct a second reverse auction of the contracts. Under the proposed reverse auction, which FERC has now approved, effective February 1, 1999, Central will assign the contracts to bidders at or below an aggregate reserve price of $112.6 million. If no unaffiliated bidders are willing to accept assignment on those terms, Central will be 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. Because of the uncertainties pertaining to the outcome of these issues currently pending at the FERC and the status of settlement negotiation and various other factors, Central cannot reasonably estimate the ultimate costs that may be incurred. Central is actively pursuing negotiations with the producers and others to resolve all outstanding obligations under the contracts. Based on the terms of what Central believes would be a reasonable settlement, $113 million has been accrued as a liability at September 30, 1998. Central also has a $111 million regulatory asset at September 30, 1998, for estimated recovery of future costs from customers. Central cannot predict the final outcome of the FERC's rulings on contract prudency and cost recovery under Order No. 636 and is unable to determine the ultimate liability and loss, if any, at this time. If Central does not prevail in these FERC proceedings or any subsequent appeals, and if Central is able to reach a settlement with the producers and others consistent with the $113 million accrued liability, the loss could be the total of the regulatory asset and the $40 million of protested costs. Central continues to believe that it entered into the gas purchase contracts in a prudent manner under FERC rules in place at the time. Central also believes that these costs will be found eligible for recovery under Order No. 636. In September 1995, Texas Gas received FERC approval of a settlement regarding Texas Gas' recovery of gas supply realignment costs. Through September 30, 1998, 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. 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 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. 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 September 30, 1998, these subsidiaries had reserves totaling approximately $26 million for these costs. 11

13 Notes (continued) 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 September 30, 1998, Central had recorded a liability for approximately $16 million, representing the current estimate of future environmental cleanup costs to be incurred over the next six to ten years. The Midstream Gas & Liquids unit of Energy Services (WES) has recorded an aggregate liability of approximately $11 million, representing the current estimate of its future environmental and remediation costs, including approximately $5 million relating to former Central facilities. 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. WES also accrues environmental remediation costs for its petroleum products pipelines, retail petroleum, refining and propane marketing operations primarily related to soil and groundwater contamination. At September 30, 1998, WES and its subsidiaries had reserves, in addition to the reserves listed above, totaling approximately $30 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 September 30, 1998, WES and its subsidiaries had receivables totaling $19 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. Such costs have exceeded this amount. At September 30, 1998, Williams had approximately $12 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 has 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 have been filed against Northwest Pipeline and others in U.S. district court in Colorado, making essentially the same claims. The district court has stayed all of the cases involving Northwest Pipeline until the plaintiffs exhaust 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. Other legal matters In 1988, certain royalty owners in a producing field in Cameron Parish, Louisiana, brought suit against a Williams subsidiary and other working interest owners seeking additional royalties or lease cancellation. An amended petition later added a second Williams subsidiary, Williams and additional working interest owners. All other defendants have been dismissed or have settled with plaintiffs. In their recently amended damage claim, the plaintiffs asserted royalty underpayments plus interest of approximately $12 million. The claimed damages are attributable to all working interests for a period of about 15 years. One of the two Williams subsidiaries sued owned a one-half interest in the field and served as operator for approximately eight years. The other subsidiary purchased produced gas from the field. Plaintiffs also request punitive damages equal to double the alleged damages and attorneys' fees. Williams believes all royalties due from its subsidiaries were properly paid, that the field was properly operated, and that it is not responsible for any amounts due from any other working interests or for the period after its subsidiary had sold its interest and terminated its status as operator of the field. The litigation pending in Cameron Parish, Louisiana, has recently been settled for payments of aggregating approximately $9 million, for which reserves have been fully accrued. 12

14 Notes (continued) 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. The only lawsuit remaining is 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. The defendants seek to have the judgment modified in many respects, including the elimination of punitive damages as well as a portion of the actual damages awarded. If the defendants prevail on appeal, it will result in an award significantly less than the judgment. The plaintiffs have cross-appealed and seek to modify the judgment to increase the total award plus interest to exceed $155 million. 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 decision, Williams believes will provide for aggregate payments of approximately $13 million, the full amount of which has been previously accrued. 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. The defendants are considering an appeal to the Supreme Court. The Supreme Court has granted an extension of time in which to file a writ of certiorari to November 18, 1998. Williams Communications, Inc. filed suit on March 20, 1998, against WorldCom Network Services, Inc. (WorldCom) in district court in Tulsa County in order to prevent WorldCom from disconnecting any of Williams' equipment on the WorldCom network. This suit sought a declaratory judgment that the single fiber retained by Williams on the WorldCom network could be used for specified multimedia uses, and that WorldCom was required to permit Williams to purchase additional fiber either acquired or constructed by WorldCom. WorldCom had denied Williams' claim and had asserted various counterclaims for monetary damages, rescission and injunctive relief. This lawsuit was settled on July 9, 1998. The settlement resolves all claims for monetary damages, permitted uses of Williams' fiber on the WorldCom network and Williams' right to purchase additional fiber on WorldCom fiber builds. There was no significant financial impact to Williams as a result of the settlement. 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 13

15 Notes (continued) 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 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, in a prior year, a liability representing an estimate of amounts it expects to incur in satisfaction of this indemnity. 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 During the second quarter of 1998, Energy Marketing & Trading entered into a 15 year contract giving Williams the right to receive fuel conversion services for purposes of generating electricity. This contract also gives Williams the right to receive installed capacity and certain ancillary services. Annual committed payments under the contract range from $140 million to $165 million, resulting in total committed payments of approximately $2.3 billion. 14. Adoption of accounting standards - ------------------------------------------------------------------------------- The Financial Accounting Standards Board issued three new accounting standards, Statement on Financial Accounting Standard (SFAS) No. 131, "Disclosures about Segments of an Enterprise and Related Information," SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits" and SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 131 and No. 132, effective for fiscal years beginning after December 15, 1997, are disclosure-oriented standards. Therefore, neither standard will affect Williams' reported consolidated net income or cash flows. SFAS No. 133 is effective for fiscal years beginning after June 15, 1999. This standard 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 has yet to be determined. The American Institute of Certified Public Accountants (AICPA) issued Statement of Position (SOP) 98-5, "Reporting on the Costs of Start-Up Activities," effective for fiscal years beginning after December 15, 1998. The SOP requires that all start-up costs be expensed and that the effect of adopting the SOP be reported as the cumulative effect of a change in accounting principle. The effect of this SOP on Williams' results of operations and financial position has yet to be determined. 15. Comprehensive income - ------------------------------------------------------------------------------- Comprehensive income for the three and nine months ended September 30 is as follows: Three months ended Nine months ended (Millions) September 30, September 30, -------------------- -------------------- 1998 1997 1998 1997 -------- -------- -------- -------- Net income $ 32.1 $ 13.7 $ 160.9 $ 310.8 Other comprehensive income (loss): Unrealized gains (losses) on securities (16.0) -- 10.8 -- Foreign currency translation adjustments (2.0) -- (4.5) -- -------- -------- -------- -------- Comprehensive income before taxes 14.1 13.7 167.2 310.8 Income taxes (6.2) -- 4.2 -- -------- -------- -------- -------- Comprehensive Income $ 20.3 $ 13.7 $ 163.0 $ 310.8 ======== ======== ======== ======== 14

16 ITEM 2. Management's Discussion and Analysis of Financial condition and Results of Operations MAPCO Acquisition On November 24, 1997, Williams and MAPCO Inc. announced that they had entered into a definitive merger agreement whereby Williams would acquire MAPCO by exchanging 1.665 shares of Williams common stock for each outstanding share of MAPCO common stock. In addition, outstanding MAPCO employee stock options would be converted into Williams common stock. The merger was consummated on March 28, 1998, with the issuance of 98.8 million shares of Williams common stock. MAPCO is engaged in the NGL pipeline, petroleum refining and marketing and propane marketing businesses, and became part of the Energy Services business unit. The merger constituted a tax-free reorganization and has been accounted for as a pooling of interests. Accordingly, all prior period financial information presented has been restated to include the combined results of operations and financial condition of MAPCO as though it had always been a part of Williams. Results of Operations Third Quarter 1998 vs. Third Quarter 1997 GAS PIPELINES CENTRAL'S revenues and operating profit decreased $7.1 million, or 14 percent, and $6.8 million, or 35 percent, respectively, due primarily to the net effect of favorable adjustments to certain accruals in 1997 and lower transportation revenues. Total throughput increased 8.2 TBtu, or 13 percent, due to higher firm and interruptible transportation volumes. KERN RIVER GAS TRANSMISSION'S (KERN RIVER) revenues and operating profit decreased $2.8 million, or 6 percent, and $3.3 million, or 11 percent, respectively, due primarily to the impact of its rate design and lower average commodity transportation rates. Additionally, operating profit decreased due to higher general and administrative expenses. Total throughput decreased less than 1 percent. NORTHWEST PIPELINE'S revenues increased $2.7 million, or 4 percent, due primarily to $2.9 million of favorable 1998 adjustments to rate refund accruals and demand charge reserves. Total throughput increased 15.5 TBtu, or 11 percent. Operating profit increased $.4 million, or 1 percent, due primarily to the rate refund accrual adjustment, substantially offset by higher general and administrative expenses. TEXAS GAS TRANSMISSION'S revenues decreased $3.2 million, or 6 percent, due primarily to lower cost of service recovery in the third quarter 1998 rates, partially offset by the impact of new services being offered. Total throughput decreased less than 1 percent. Operating profit increased $4.2 million, or 114 percent, due primarily to lower operating and maintenance expenses and the impact of new services being offered. Because of its rate structure, Texas Gas typically experiences lower operating profit in the second and third quarters as compared to the first and fourth quarters. TRANSCONTINENTAL GAS PIPE LINE'S (TRANSCO) revenues increased $12.7 million, or 7 percent, due primarily to expansion projects placed in service in 1998 and the fourth quarter of 1997. Total throughput increased 2.8 TBtu, or 1 percent. Operating profit increased $5.5 million, or 10 percent, due primarily to expansion projects, partially offset by the effect of a $5.4 million settlement received in 1997 related to a prior rate proceeding. Because of its rate structure and historical maintenance schedule, Transco typically experiences lower operating profit in the second and third quarter as compared to the first and fourth quarters. ENERGY SERVICES ENERGY MARKETING & TRADING'S revenues decreased $226.1 million, or 43 percent, due primarily to the $347 million impact in 1998 of reporting revenues on a net margin basis for certain crude oil, refined products and natural gas liquids trading operations previously reported on a "gross basis" (see Note 2 of the Notes to Consolidated Financial Statements). In addition, revenues associated with natural gas physical trading decreased $20 million due primarily to the adverse market and supply conditions experienced as a result of Hurricane Georges; crude oil and refined products revenues decreased $27 million including the impact of decreased average prices associated with the marketing of refined products from the Alaska refinery; and energy capital revenues were unfavorably impacted by $9.8 million of credit loss accruals. Partially offsetting these decreases were increased power services revenue of $178 million from power generation under a new contract and a $9.5 million favorable long-term natural gas transportation contract settlement. Costs and operating expenses decreased $279 million, or 54 percent, due primarily to the impact in 1998 of reporting revenues on a net margin basis for certain crude oil, refined products and natural gas liquids trading operations previously reported on a "gross basis" and 15

17 lower average prices associated with refined product purchases from the Alaska refinery, partially offset by electric power generation costs under the new power services contract. Selling, general and administrative expenses increased $29 million due primarily to a $16.6 million retail energy credit loss accrual and increased staffing and other costs associated with an expanded business base. Operating profit increased $17.1 million, from a $2.5 million operating loss in 1997, due primarily to $57 million from the new power services activity, and the favorable contract settlement. Partially offsetting these increases were lower natural gas physical trading revenues, total credit loss accruals of $26.4 million in 1998 for certain energy capital and retail energy activities and the effect of a $6 million recovery in 1997 of an account previously considered a bad debt. The new power services activity is associated with a power generation plant that is normally operational during the summer peak cooling season; therefore, operating profit from this activity will typically be higher in the second and third quarters as compared to the first and fourth quarters. EXPLORATION & PRODUCTION'S revenues decreased $3.4 million, or 11 percent, due primarily to a decrease in sales volumes from company-owned production and marketing volumes from Williams Coal Seam Gas Royalty Trust (Royalty Trust) combined with lower average natural gas sales prices. Partially offsetting these decreases is an additional $3 million in deferred income resulting from a transaction that transferred certain tax credits to a third party. Operating profit decreased $.5 million, or 9 percent, due primarily to higher depreciation, depletion and amortization, decreased company-owned production volumes and lower average natural gas sales prices, partially offset by increased recognition of deferred income. MIDSTREAM GAS & LIQUIDS' revenues decreased $51.8 million, or 20 percent, due primarily to the $17 million impact from the shutdown of the Canadian marketing operations, $16 million lower natural gas liquids sales from processing activities, $5 million lower gathering revenues and $4 million lower natural gas liquids pipeline transportation revenues resulting from decreased shipments. The lower liquids sales reflect lower average sales prices combined with a 7 percent decrease in volumes sold. Costs and operating expenses decreased $30 million, or 18 percent, due primarily to the shutdown of the Canadian marketing operations and lower fuel and replacement gas purchases. Operating profit decreased $15.9 million, or 22 percent, due primarily to $11 million lower per-unit liquids margins, lower gathering revenues and a decline in pipeline transportation revenues, partially offset by a 1998 gain of $6 million on settlement of product imbalances. PETROLEUM SERVICES' revenues increased $5 million, or 1 percent, due primarily to $44 million of pipeline construction revenues, $21 million higher convenience store sales, a 17 percent increase in ethanol sales volumes and $5 million higher revenues from fleet management and mobile computer technology operations. Substantially offsetting these increases were a $70 million decrease in revenues from refining operations due to lower average sales prices and lower average ethanol sales prices. The $21 million increase in convenience store sales reflects $13 million higher merchandise sales due to increased store count and higher average sales per store and $32 million from a 27 percent increase in gasoline and diesel sales volumes, partially offset by the $24 million impact of lower average gasoline and diesel sales prices. Costs and operating expenses increased $9 million, or 1 percent, due primarily to $42 million of pipeline construction costs, $17 million of increased convenience store product purchases and operating costs resulting primarily from increased store count and higher average sales per store, and $8 million higher costs from fleet management and mobile computer technology operations, partially offset by a $60 million decrease from refining operations due mainly to lower average crude oil purchase prices. Selling, general and administrative expenses increased $13 million due in part to increased activities in human resources development, investor/media/customer relations and business development. Operating profit decreased $17.5 million, or 28 percent, due primarily to lower per-unit refinery margins and $13 million higher selling, general and administrative expenses, partially offset by higher average transportation rates. COMMUNICATIONS COMMUNICATIONS' revenues increased $4.8 million, or 1 percent, due primarily to higher network services revenues, partially offset by lower customer premise equipment sales and services revenues. Sales order backlog at September 30, 1998 increased $17.3 million from September 30, 1997. Selling, general, and administrative expenses increased $19.9 million, or 19 percent, due primarily to expansion and enhancement of the infrastructure primarily in support of the solutions business and the development of a new national digital fiber-optic network. The construction of the network continues ahead of schedule and on budget. Operating profit decreased $20.4 million to a $25.6 million operating loss in 1998, due primarily to $6 million of charges by the solutions business for asset write-downs, and higher selling, information services and other costs associated with substantially expanding the solutions and network infrastructure, partially offset by improved results in the network applications businesses. 16

18 CONSOLIDATED INTEREST ACCRUED increased $13 million, or 11 percent, due primarily to higher borrowing levels including Williams Holdings' commercial paper program, partially offset by lower average interest rates following the late 1997 debt restructuring. Interest capitalized increased $4.5 million, or 56 percent, due primarily to international investment activities. Investing income decreased $37.8 million to a $33.7 million loss, as a result of a $23 million write-down related to a network applications venture (see Note 5) and a $16 million decrease in equity earnings primarily from international investments, slightly offset by $4 million higher interest income on long-term notes receivable. Minority interest in (income) loss of consolidated subsidiaries is $5.3 million favorable to 1997 due primarily to lower earnings experienced by Williams Communications Solutions, LLC and allocated to the 30 percent interest held by minority shareholders. Other expense - net is $8.1 million unfavorable as compared to 1997 due primarily to a litigation accrual and other reserve adjustments in 1998 totaling $5 million related to assets previously sold and the effect of a 1997 gain on the sale of an airplane. The $33.4 million, or 58 percent, decrease in the provision for income taxes is primarily a result of lower pre-tax income. The effective income tax rate in 1998 exceeds the federal statutory rate due primarily to the effects of state income taxes. The effective income tax rate in 1997 exceeds the federal statutory rate due primarily to the effects of state income taxes, partially offset by income tax credits from coal-seam gas production. Nine Months Ended September 30, 1998 vs. Nine Months Ended September 30, 1997 GAS PIPELINES OTHER In July 1998, the Federal Energy Regulatory Commission issued orders in two gas pipelines' rate cases that modified its rate of return methodology (see Note 13). CENTRAL'S revenues decreased $9 million, or 7 percent, due primarily to the net effect of favorable adjustments to certain accruals in 1997 and lower transportation revenues. Total throughput increased 6 TBtu, or 3 percent, due primarily to higher interruptible transportation volumes. Other (income) expense - net for 1998 and 1997 includes gains from the sale-in-place of natural gas from a decommissioned storage field of $3 million and $7 million, respectively. Operating profit decreased $9.7 million, or 19 percent, due primarily to the net effect of adjustments to certain accruals in 1997, a lower gain in 1998 compared to 1997 from the sale-in-place of natural gas and lower transportation revenues, partially offset by lower general and administrative expenses and operating and maintenance expenses. KERN RIVER'S revenues decreased $3.3 million, or 3 percent, due primarily to the impact of its rate design. Total throughput increased 9.2 TBtu, or 4 percent, primarily due to higher short-term firm and interruptible transportation volumes. Operating profit decreased $6.8 million, or 8 percent, due primarily to lower revenue, increased general and administrative expenses and higher ad valorem taxes. NORTHWEST PIPELINE'S revenues increased $10.9 million, or 5 percent, due primarily to a new rate design effective March 1, 1997 that enables greater short-term firm and interruptible transportation volumes, the $4.4 million net favorable effect of adjustments to rate refund accruals and demand charge reserves in 1998 and the impact of an unfavorable adjustment to rate refund accruals in 1997. Total throughput increased 24.7 TBtu, or 5 percent. Operating profit increased $10.6 million, or 11 percent, due primarily to the new rate design and the net favorable rate refund accrual adjustments. TEXAS GAS TRANSMISSION'S revenues decreased $16.6 million, or 8 percent, due primarily to $15 million lower reimbursable costs passed through to customers as provided in Texas Gas' rates and the $4 million impact of the favorable resolution of certain contractual issues in 1997, partially offset by higher revenues related to new services and increased cost recovery in the current rate structure. Total throughput decreased 12.7 TBtu, or 2 percent. Costs and operating expenses decreased $16.6 million, or 15 percent, due primarily to the lower reimbursable costs which are passed through to customers and lower operating, maintenance, general and administrative expenses. Operating profit increased $5.7 million, or 10 percent, due primarily to lower operating, maintenance, general and administrative expenses and the higher revenues related to new services and increased cost recovery, partially offset by the impact of the favorable resolution in 1997 of certain contractual issues. Because of its rate structure, Texas Gas typically experiences lower operating profit in the second and third quarters as compared to the first and fourth quarters. TRANSCO'S revenues increased $24.5 million, or 4 percent, due primarily to new rates placed into effect May 1, 1997 to recover costs associated with increased capital expenditures and expansion projects placed into service in 1998 and late 1997. Revenues were also favorably impacted by new services initiated in the last half of 1997 and a 1998 adjustment of $10 million related to the new rates placed into effect in 1997, partially offset by $12 million lower reimbursable costs passed through to customers as provided in Transco's rates. Total throughput decreased 10.3 TBtu, or 1 percent. Operating profit increased $36 million, or 22 percent, due primarily to the revenue increases described above and $5 million lower operating and maintenance expenses, partially offset by the effect of a $5.4 million settlement received in 1997 related to a prior rate proceeding. Because of its rate structure and historical maintenance schedule, Transco typically experiences lower operating profit in the second and third quarters as compared to the first and fourth quarters. 17

19 ENERGY SERVICES ENERGY MARKETING & TRADING'S revenues decreased $558.1 million, or 37 percent, due primarily to the $676 million impact in 1998 of reporting revenues on a net basis for certain crude oil, refined products and natural gas liquids trading operations previously reported on a "gross" basis (see Note 2). In addition, revenues associated with natural gas origination, price-risk management and physical trading decreased $41 million due primarily to unfavorable market movement against the natural gas portfolio and the adverse market and supply conditions which resulted from Hurricane Georges in September 1998; crude oil and refined products revenues decreased $25 million including the impact of decreased average prices associated with the marketing of refined products from the Alaska and Memphis refineries; and energy capital revenues were unfavorably impacted by $9.8 million of credit loss accruals. Partially offsetting these decreases were increased power services revenue of $185 million from power generation under a new contract, $16 million of long-term natural gas transportation contract settlements and increased physical and notional trading volumes. Costs and operating expenses decreased $642 million, or 44 percent, due primarily to the impact in 1998 of reporting revenues on a net margin basis for certain crude oil, refined products and natural gas liquids trading operations previously reported on a "gross basis" and lower average prices associated with refined product purchases from the Memphis and Alaska refineries, partially offset by electric power generation costs under the new power services contract. Selling, general and administrative expenses increased $52 million due primarily to a $16.6 million retail energy credit loss accrual and increased staffing and other costs associated with an expanded business base. Operating profit increased $25.6 million, to $35.3 million in 1998, due primarily to $58 million from power services, improved crude oil, refined products and liquids trading, favorable long-term transportation contract settlements, and lower retail propane operating costs. Partially offsetting these increases were a decrease in revenues from natural gas origination, price-risk management and physical trading activities, total 1998 credit loss accruals of $26.4 million for certain energy capital and retail energy activities and the effect of a $6 million recovery in 1997 of an account previously considered a bad debt. The new power services activity is associated with a power generation plant that is normally operational during the summer peak cooling season; therefore, operating profit from this activity will typically be higher in the second and third quarters as compared to the first and fourth quarters. EXPLORATION & PRODUCTION'S revenues increased $12.3 million, or 13 percent, due primarily to the recognition of additional deferred income resulting from a transaction that transferred certain tax credits to a third party, partially offset by lower average natural gas sales prices for both company-owned production and marketing of Royalty Trust volumes. Operating profit increased $5.1 million, or 26 percent, due primarily to increased recognition of deferred income, partially offset by $9 million higher depreciation, depletion and amortization resulting from downward adjustments to natural gas reserves, $5 million higher leasehold impairment expense and $3 million higher general and administrative expenses. MIDSTREAM GAS & LIQUIDS' revenues decreased $132.5 million, or 17 percent, due primarily to the $43 million impact from the shutdown of the Canadian marketing operations and $43 million lower natural gas liquids sales from processing activities resulting from a decline in average liquids sales prices. Revenues also declined due to $13 million lower natural gas liquids pipeline transportation revenues resulting from decreased shipments, the passthrough of $10 million lower operating costs to customers and adjustments of $12 million related to new rates placed into effect in 1997 for Midstream's regulated gathering activities (offset in costs and operating expenses), slightly offset by $7 million higher gathering revenues. Costs and operating expenses decreased $90 million, or 18 percent, due primarily to the shutdown of the Canadian marketing operations, the rate adjustments related to Midstream's regulated gathering activities, lower costs passed through to customers and lower fuel and replacement gas purchases. Operating profit decreased $49.1 million, or 22 percent, due primarily to $35 million from lower per-unit liquids margins, decreased pipeline transportation shipments, higher operating, maintenance and depreciation expenses and $6 million of unfavorable litigation loss provisions in 1998, partially offset by higher gathering revenues and a gain of $6 million on the settlement of product imbalances. PETROLEUM SERVICES' revenues increased $33.5 million, or 2 percent, due primarily to $74 million in pipeline construction revenue and $36 million higher convenience store merchandise sales resulting from the May 1997 EZ-Serve acquisition and increased per store sales. In addition, revenues increased due to $24 million higher revenues from fleet management and mobile computer technology operations begun in mid-1997, $14 million higher ethanol sales and $8 million higher product transportation revenues resulting primarily from an increased average transportation rate per barrel. Partially offsetting these increases were a $110 million decrease in revenues from refining operations and $9 million lower product sales from transportation activities. The $14 million higher ethanol sales reflects a 27 percent increase in sales volumes, partially offset by a decrease in average sales prices. The $110 million decline in refining revenues reflects $279 million from lower average sales prices, partially offset by $169 million from a 16 percent increase in barrels sold. A $64 million revenue increase from higher convenience store gasoline and diesel sales volumes was offset by 18

20 lower average gasoline and diesel sales prices. Costs and operating expenses increased $34 million, or 2 percent, due primarily to $70 million of pipeline construction costs and $24 million higher convenience store merchandise cost of sales resulting from the EZ-Serve acquisition and increased per store sales. In addition, costs and operating expenses increased due to $28 million higher costs from fleet management and mobile computer technology operations, $15 million higher convenience store operating costs resulting from the EZ-Serve acquisition and $13 million of increased ethanol cost of sales. Largely offsetting these increases were a $94 million decrease from refining operations, $8 million lower cost of product sales from transportation activities and a $6 million decrease in the cost of gasoline and diesel sales. The $94 million decrease from refining operations reflects a $240 million decrease due to lower average crude oil purchase prices, partially offset by $139 million due to increased processed volumes and higher operating costs at the Memphis refinery. Selling, general and administrative expenses increased $17 million due in part to increased activities in human resources development, investor/media/customer relations and business development. Other (income) expense - net in 1998 includes a $15.5 million accrual for potential transportation rate refunds to customers (see Note 3). Operating profit decreased $33.2 million, or 21 percent, due primarily to the $15.5 million accrual for potential refunds to transportation customers, $17 million higher selling, general and administrative expenses and lower refinery operating profit, partially offset by higher average transportation rates. Refinery operating profit decreased due to lower per-unit refinery margins and $6 million increased operating costs at the Memphis refinery due to higher production levels, partially offset by 8 percent higher refinery volumes processed. COMMUNICATIONS COMMUNICATIONS' revenues increased $230.2 million, or 23 percent, due primarily to the April 30, 1997 combination of the Nortel customer premise equipment sales and services operations which contributed an additional $196 million of revenue in 1998. In addition, revenues increased as a result of providing off-net services to new long-term customers associated with the fiber-optic network currently under construction. Sales order backlog at September 30, 1998 increased $17.3 million from September 30, 1997. Costs and operating expenses increased $170.4 million, or 23 percent, including $121 million associated with the combination with Nortel and higher costs in both the network and network applications businesses including off-net leased capacity costs associated with providing customer services prior to completion of the new network. Selling, general, and administrative expenses increased $102.9 million, or 41 percent, of which $90 million is attributable to the solutions business which includes the combination with Nortel. Included in the overall increase are $23 million of increased information systems costs associated with expansion and enhancement of the infrastructure and continued costs of maintaining multiple systems while common systems are being developed, and the expansion of the sales infrastructure to support the new national digital fiber-optic network including $6 million for a new national advertising campaign. The construction of the network continues ahead of schedule and on budget. Operating profit decreased $52.3 million to a $56.2 million operating loss in 1998, due primarily to the increase in selling, general and administrative expenses as a percentage of revenue resulting from the items discussed above, and $6 million of charges for asset write-downs by the solutions business. CONSOLIDATED GENERAL CORPORATE EXPENSE increased $19.1 million, or 34 percent, due primarily to MAPCO merger-related costs of $28 million, partially offset by expense savings realized following the MAPCO merger. An additional $45.9 million of merger-related costs are included in other (income) expense - net as a component of Energy Services' operating profit (see Note 3). Interest accrued increased $31.3 million, or 9 percent, due primarily to higher borrowing levels including Williams Holdings' commercial paper program, partially offset by lower average interest rates following the late 1997 debt restructuring. Interest capitalized increased $13.1 million to $28.6 million, due primarily to increased capital expenditures for the fiber-optic network, the Venezuelan gas injection plant and international investment activities. Investing income decreased $44.2 million to a $30.7 million loss, as a result of a $23.2 million write-down related to a network applications venture (see Note 5) and a $28 million decrease in equity earnings primarily from international investments, slightly offset by higher interest income on long-term notes receivable. For information concerning the $44.5 million 1997 gain on sale of interest in subsidiary, see Note 6. The $66 million 1997 gain on sale of assets results from the sale of Williams' interest in the liquids and condensate reserves in the West Panhandle field of Texas (see Note 7). Minority interest in (income) loss of consolidated subsidiaries is $7.1 million favorable as compared to 1997 due primarily to lower earnings experienced by Williams Communications Solutions, LLC and allocated to the 30 percent interest held by minority shareholders. Other expense - net is $17.7 million unfavorable as compared to 1997 due primarily to 1998 litigation loss accruals and other reserve adjustments totaling $11 million related to assets previously sold and the impact of a 1997 gain of $4 million on the termination of interest rate swap agreements. The $91.9 million, or 45 percent, decrease in the provision for income taxes is primarily a result of lower pre-tax income, partially offset by a higher effective income tax rate in 19

21 1998. The effective income tax rate in 1998 exceeds the federal statutory rate due primarily to the effects of state income taxes. The effective income tax rate for 1997 is less than the federal statutory rate due primarily to the effect of the non-taxable gain recognized in 1997 (see Note 6) and income tax credits from coal-seam gas production, partially offset by the effects of state income taxes. The $4.8 million 1998 extraordinary loss results from the early extinguishment of debt (see Note 9). 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 Williams Holdings' commercial paper program, which can be utilized without limitation under existing loan covenants. At September 30, 1998, Williams had access to $717 million of liquidity representing $318 million available under its $1 billion bank-credit facility, $372 million of commercial paper availability, and cash-equivalent investments. This compares with liquidity of $166 million at December 31, 1997, and $585 million at September 30, 1997. The lower level at December 31, 1997 reflected the use of the $1 billion bank-credit facility to provide interim financing related to the debt restructuring program. This restructuring program was completed during the first quarter of 1998 and a significant portion of the $1 billion bank-credit facility was repaid. In addition, Williams Holdings' commercial paper program, begun in mid-1997, was expanded to $1 billion in March 1998. At September 30, 1998, $250 million of current debt obligations have been classified as non-current obligations based on Williams' intent and ability to refinance them on a long-term basis. In 1998, capital expenditures and investments are estimated to be approximately $2.3 billion. During 1998, Williams expects to finance capital expenditures, investments, working-capital requirements and expenditures for the year 2000 compliance project through cash generated from operations and the use of the available portion of its $1 billion bank-credit facility, its commercial paper program, short-term uncommitted bank lines and public debt offerings. Financing Activities In January 1998, Williams issued $300 million of 6.125 percent notes due 2001 and $100 million of floating rate notes due 2000. In February 1998, Williams issued $240 million of 6.125 percent debt remarketable in 2002 and $300 million of 5.95 percent debt remarketable in 2000. In January 1998, Transcontinental Gas Pipe Line issued $200 million of 6.125 percent notes and $100 million of 6.25 percent notes due in 2005 and 2008, respectively. In July 1998, Williams issued $350 million of 6.2 percent notes due 2002 and $275 million of 6.5 percent notes due 2006. 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 59.4 percent at September 30, 1998, compared to 55.8 percent at December 31, 1997. If short-term notes payable and long-term debt due within one year are included in the calculations, these ratios would be 62.7 percent at September 30, 1998 and 59.1 percent at December 31, 1997. Investing Activities During the second quarter of 1998, Williams made a $150 million investment in and a $100 million advance to a foreign telecommunications business. Other Other Commitments During the second quarter, Energy Marketing & Trading entered into a 15-year contract giving Williams the right to receive fuel conversion services for purposes of generating electricity. This contract also gives Williams the right to receive installed capacity as well as certain ancillary services. Annual committed payments under the contract range from $140 million to $165 million, resulting in total committed payments of approximately $2.3 billion. Williams' intent is to resell power generated as a result of this service into markets in the western region of the United States. Williams also intends to resell capacity and ancillary services into such markets as the opportunities arise. 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 20

22 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, and 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 except with respect to international investments. 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 desireable but not required, and 5) unnecessary. Categories 1 - 3 were designated as critical and are the major focus of this project. Renovation/replacement and testing/validation of critical systems is expected to be completed by June 30, 1999, except for replacement of certain critical systems scheduled for completion by September 1, 1999. Certain non-critical systems may not be compliant by January 1, 2000. Testing and validation activities have begun and will continue throughout the process. Year 2000 test labs are in place and operational. As expected, few problems have been detected during testing for items believed to be compliant. The following table indicates the approximate project status 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. The unknown category includes items identified during the assessment phase which require additional follow-up to determine whether they are compliant. Not Business Unit Tested Untested Compliant Unknown - ------------- ------ -------- --------- ------- Traditional Information Technology: Gas Pipelines 14% 66% 20% --% Energy Services 12 46 18 24 Communications 8 62 27 3 Corporate/Other 45 43 11 1 Non-Traditional Infor- mation Technology: Gas Pipelines 37 38 25 -- Energy Services 27 73 -- -- Communications 15 64 16 5 Corporate/Other 73 11 1 15 Williams has initiated a formal communications process with other companies to determine the extent to which those companies are addressing their year 2000 compliance. In connection with this process, Williams has sent over 11,000 letters and questionnaires to third parties including customers, vendors, service providers, etc. Additional communications are being mailed during the fourth quarter of 1998. Williams is evaluating responses as they are received or otherwise investigating the status of these companies' year 2000 compliance efforts. As of September 30, 1998, approximately 22 percent of the companies contacted have responded and virtually all 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 expects to utilize both internal resources and external contractors to complete the year 2000 compliance project. Existing resources will be redeployed, and several previously planned system implementations currently in process are scheduled for completion on or before September 1, 1999, which are expected to lessen possible year 2000 impacts. For example, a new year 2000 compliant payroll/human resources system, scheduled to be online January 1, 1999, will replace multiple human resources administration and payroll processing systems currently 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 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. The Gas Pipelines recently completed implementation of a new telephone system and a new common financial system is scheduled for completion July 1, 1999. In situations where planned system implementations will not be in service timely, alternative steps are being taken to make existing systems compliant. Although all critical systems over which Williams has control are planned to be compliant and tested before the year 2000, there is a 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 effort to communicate with and evaluate third-party compliance 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. Contingency plans 21

23 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. Costs incurred for new software and hardware purchases are being capitalized and other costs are being expensed as incurred. While estimates of the total cost of Williams' enterprise-wide project continue to be refined, Williams estimates that future costs, including any accelerated system replacements, necessary to complete the project within the schedule described will total approximately $50 million. Of this total, approximately $45 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. Approximately $7 million of costs has been expensed to date and approximately $3 million has been capitalized. The costs of the project and the completion dates 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 year 2000 compliance modification plans and other factors. There can be no guarantee that these estimates will be achieved, and actual results could differ materially from these estimates. 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 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 nine months ended September 30, 1998, the percent of Williams' fixed rate debt approached targeted levels as Williams completed issuing long-term debt under the restructuring program and reduced its variable rate interim financings. Williams issued $1.8 billion of fixed rate debt at a weighted average interest rate of approximately 6.2 percent (see Financing Activities above). The debt matures $300 million in 2000, $300 million in 2001, $900 million in 2002 and $300 million thereafter. Williams also entered into an interest rate swap of $240 million converting fixed rate debt into variable rate debt. The interest rate swap matures in 2002. Williams has $400 million of interest rate locks, expiring primarily in 1998, at an average locked-in rate of 5.4 percent referenced to underlying treasury securities having a weighted-average maturity of 9 years. 22

24 PART II. OTHER INFORMATION 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 (b) During the third quarter of 1998, the Company filed a Form 8-K on July 22, 1998, which reported a significant event under Item 5 of the Form and included the exhibits required by Item 7 of the Form. 23

25 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) November 13, 1998

26 INDEX TO EXHIBITS Exhibit No. Description - ---------- ----------- Exhibit 12 -- Computation of Ratio of Earnings to Combined Fixed Charges Exhibit 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) Nine months ended September 30, 1998 ------------------ Earnings: Income before income taxes $277.2 Add: Interest expense - net 347.4 Rental expense representative of interest factor 31.7 Minority interest in income of consolidated subsidiaries 5.5 Other 23.0 ------ Total earnings as adjusted plus fixed charges $684.8 ====== Fixed charges and preferred stock dividend requirements: Interest expense - net $347.4 Capitalized interest 28.6 Rental expense representative of interest factor 31.7 Pretax effect of dividends on preferred stock of the Company 9.5 ------ Combined fixed charges and preferred stock dividend requirements $417.2 ====== Ratio of earnings to combined fixed charges and preferred stock dividend requirements 1.64 ======

5 1,000 9-MOS DEC-31-1998 JAN-01-1998 SEP-30-1998 91,629 0 1,796,198 40,231 434,899 2,973,768 15,829,860 3,441,879 17,733,867 3,704,761 6,323,396 0 102,164 431,712 3,787,770 17,733,867 0 5,641,402 0 4,882,221 0 23,415 375,999 277,179 111,469 165,710 0 (4,762) 0 160,948 .37 .37