Williams Companies, Inc

1 FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One) (X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 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 July 31, 1998 - -------------------------------------- -------------------------------------- Common Stock, $1 par value 424,858,918 Shares

2 The Williams Companies, Inc. Index Part I. Financial Information Page ---- Item 1. Financial Statements Consolidated Statement of Income--Three and Six Months Ended June 30, 1998 and 1997 2 Consolidated Balance Sheet--June 30, 1998 and December 31, 1997 3 Consolidated Statement of Cash Flows--Six Months Ended June 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 14 Part II. Other Information Item 4. Submission of Matters to a Vote of Security Holders 21 Item 6. Exhibits and Reports on Form 8-K 21 Exhibit 12--Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements Exhibit 27--Finance 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. 1

3 The Williams Companies, Inc. Consolidated Statement of Income (Unaudited) (Millions, except per-share amounts) ------------------------------------------------------------ Three months ended Six months ended June 30, June 30, ------------------------------------------------------------ 1998 1997* 1998 1997* ------------ ------------ ------------ ------------ Revenues: Gas Pipelines (Note 3) $ 400.0 $ 397.4 $ 843.3 $ 839.1 Energy Services (Note 3) 1,137.1 1,362.4 2,500.8 2,869.3 Communications (Note 2) 413.3 359.1 801.1 575.7 Other 13.3 9.2 25.5 19.1 Intercompany eliminations (183.1) (257.2) (430.3) (503.7) ------------ ------------ ------------ ------------ Total revenues 1,780.6 1,870.9 3,740.4 3,799.5 ------------ ------------ ------------ ------------ Profit-center costs and expenses: Costs and operating expenses 1,259.1 1,419.2 2,682.2 2,844.8 Selling, general and administrative expenses 245.5 201.1 479.4 372.8 Other (income) expense--net (Notes 3 and 4) 23.1 (5.5) 55.0 (9.7) ------------ ------------ ------------ ------------ Total profit-center costs and expenses 1,527.7 1,614.8 3,216.6 3,207.9 ------------ ------------ ------------ ------------ Operating profit: Gas Pipelines (Note 3) 153.0 131.2 348.0 312.2 Energy Services (Note 3) 106.3 115.2 199.1 275.9 Communications (Note 2) (10.5) 3.3 (30.6) 1.3 Other 4.1 6.4 7.3 2.2 ------------ ------------ ------------ ------------ Total operating profit 252.9 256.1 523.8 591.6 General corporate expenses (Note 4) (18.1) (22.0) (58.9) (39.1) Interest accrued (126.5) (116.9) (244.5) (226.2) Interest capitalized 7.8 5.1 16.0 7.4 Investing income .3 2.6 3.0 9.4 Gain on sale of interest in subsidiary (Note 5) -- 44.5 -- 44.5 Gain on sale of assets (Note 6) -- -- -- 66.0 Minority interest in income of consolidated subsidiaries (3.3) (6.2) (5.6) (7.4) Other expense--net (10.1) (3.5) (12.4) (2.8) ------------ ------------ ------------ ------------ Income before income taxes and extraordinary loss 103.0 159.7 221.4 443.4 Provision for income taxes (Note 7) 42.3 41.2 87.8 146.3 ------------ ------------ ------------ ------------ Income before extraordinary loss 60.7 118.5 133.6 297.1 Extraordinary loss (Note 8) -- -- (4.8) -- ------------ ------------ ------------ ------------ Net income 60.7 118.5 128.8 297.1 Preferred stock dividends 1.6 2.6 3.8 5.2 ------------ ------------ ------------ ------------ Income applicable to common stock $ 59.1 $ 115.9 $ 125.0 $ 291.9 ============ ============ ============ ============ Basic earnings per common share (Note 9): Income before extraordinary loss $ .14 $ .28 $ .31 $ .71 Extraordinary loss (Note 8) -- -- (.01) -- ------------ ------------ ------------ ------------ Net income $ .14 $ .28 $ .30 $ .71 ============ ============ ============ ============ Average shares (thousands) 426,163 411,423 421,780 411,534 Diluted earnings per common share (Note 9): Income before extraordinary loss $ .14 $ .28 $ .30 $ .69 Extraordinary loss (Note 8) -- -- (.01) -- ------------ ------------ ------------ ------------ Net income $ .14 $ .28 $ .29 $ .69 ============ ============ ============ ============ Average shares (thousands) 441,464 428,496 440,254 428,824 Cash dividends per common share $ .15 $ .13 $ .30 $ .26 * 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) -------------------------- June 30, December 31, 1998 1997* ----------- ----------- ASSETS Current assets: Cash and cash equivalents $ 135.5 $ 122.1 Receivables 1,462.4 1,584.5 Transportation and exchange gas receivable 118.2 130.4 Inventories (Note 10) 482.2 433.9 Commodity trading assets 577.2 180.3 Deferred income taxes 226.0 236.6 Other 201.6 176.2 ----------- ----------- Total current assets 3,203.1 2,864.0 Investments 689.5 388.1 Property, plant and equipment, at cost 15,377.9 14,605.1 Less accumulated depreciation and depletion (3,310.3) (3,068.3) ----------- ----------- 12,067.6 11,536.8 Goodwill and other intangible assets--net 598.8 600.6 Other assets and deferred charges 1,013.0 888.1 ----------- ----------- Total assets $ 17,572.0 $ 16,277.6 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Notes payable (Note 11) $ 1,021.5 $ 693.0 Accounts payable 1,048.9 1,288.5 Accrued liabilities 1,371.9 1,349.3 Commodity trading liabilities 592.1 182.0 Long-term debt due within one year (Note 11) 70.1 80.3 ----------- ----------- Total current liabilities 4,104.5 3,593.1 Long-term debt (Note 11) 5,843.0 5,351.5 Deferred income taxes 2,069.6 2,009.1 Other liabilities 1,003.8 946.5 Minority interest in consolidated subsidiaries 183.1 144.8 Contingent liabilities and commitments (Note 12) Stockholders' equity: Preferred stock, $1 par value, 30 million shares authorized, 2 million shares issued in 1998 and 2.5 million shares issued in 1997 116.5 142.2 Common stock, $1 par value, 960 million shares authorized, 428.5 million shares issued in 1998 and 431.5 million shares issued in 1997 428.5 431.5 Capital in excess of par value 926.9 1,041.6 Retained earnings 2,982.4 2,983.3 Other (38.1) (54.1) ----------- ----------- 4,416.2 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 4,368.0 4,232.6 ----------- ----------- Total liabilities and stockholders' equity $ 17,572.0 $ 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) ------------------------ Six months ended June 30, ------------------------ 1998 1997* ---------- ---------- OPERATING ACTIVITIES: Net income $ 128.8 $ 297.1 Adjustments to reconcile to cash provided from operations: Extraordinary loss 4.8 -- Depreciation, depletion and amortization 305.8 286.7 Provision for deferred income taxes 60.0 46.1 Gain on dispositions of property and interest in subsidiary (4.7) (109.3) Minority interest in income of consolidated subsidiaries 5.6 7.4 Cash provided (used) by changes in assets and liabilities: Receivables sold (30.4) 143.8 Receivables 201.9 322.6 Inventories (47.9) (78.3) Other current assets (46.7) 34.0 Accounts payable (230.1) (303.6) Accrued liabilities 30.8 (147.0) Current commodity trading assets and liabilities 13.3 (4.1) Non-current commodity trading assets and liabilities (14.5) (10.2) Other, including changes in non-current assets and liabilities (23.9) 13.2 ---------- ---------- Net cash provided by operating activities 352.8 498.4 ---------- ---------- FINANCING ACTIVITIES: Proceeds from notes payable 655.1 45.6 Payments of notes payable (724.4) (334.3) Proceeds from long-term debt 1,700.1 722.3 Payments of long-term debt (821.3) (191.5) Proceeds from issuance of common stock 62.9 26.0 Purchases of treasury stock -- (50.2) Dividends paid (129.9) (104.3) Other--net 30.5 (4.5) ---------- ---------- Net cash provided by financing activities 773.0 109.1 ---------- ---------- INVESTING ACTIVITIES: Property, plant and equipment: Capital expenditures (835.3) (478.1) Proceeds from dispositions 26.6 75.2 Changes in accounts payable and accrued liabilities (12.0) (17.2) Acquisition of businesses, net of cash acquired -- (130.2) Proceeds from sale of assets -- 66.0 Purchase of investments/advances to affiliates (293.6) (170.3) Other--net 2.1 12.3 ---------- ---------- Net cash used by investing activities (1,112.4) (642.3) ---------- ---------- Increase (decrease) in cash and cash equivalents 13.4 (34.8) Cash and cash equivalents at beginning of period 122.1 220.1 ---------- ---------- Cash and cash equivalents at end of period $ 135.5 $ 185.3 ========== ========== * 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 June 30, 1998, results of operations for the three and six months ended June 30, 1998 and 1997, and cash flows for the six months ended June 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. 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 months and six months ended June 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 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 5).

7 Notes (continued) 3. Revenues and operating profit Revenues and operating profit of Gas Pipelines and Energy Services for the three and six months ended June 30, 1998 and 1997, are as follows: Three months ended June 30, ----------------------------------------------------- (Millions) Revenues Operating Profit ------------------------ ------------------------- 1998 1997 1998 1997 ---------- ---------- ---------- ---------- Gas Pipelines: Central $ 40.3 $ 40.9 $ 11.4 $ 11.6 Kern River Gas Transmission 40.3 42.3 27.5 31.0 Northwest Pipeline 70.3 66.1 35.3 30.0 Texas Gas Transmission 56.2 60.0 10.5 8.4 Transcontinental Gas Pipe Line 192.9 188.1 68.3 50.2 ---------- ---------- ---------- ---------- $ 400.0 $ 397.4 $ 153.0 $ 131.2 ========== ========== ========== ========== Energy Services: Energy Marketing & Trading $ 174.6 $ 429.6* $ 4.1 $ (20.3)* Exploration & Production 37.5 24.6 8.0 4.1 Midstream Gas & Liquids 202.5 249.6* 54.8 69.8* Petroleum Services 722.5 658.6* 45.5 61.6* Merger-related costs -- -- (6.1) -- ---------- ---------- ---------- ---------- $ 1,137.1 $ 1,362.4* $ 106.3 $ 115.2* ========== ========== ========== ========== * Amounts have been restated as described in Note 2. 5

8 Notes (continued) Six months ended June 30, ------------------------ (Millions) Revenues Operating Profit ------------------------ ------------------------- 1998 1997 1998 1997 ---------- ---------- ---------- ---------- Gas Pipelines: Central $ 85.9 $ 87.8 $ 29.4 $ 32.3 Kern River Gas Transmission 81.5 82.0 56.5 60.0 Northwest Pipeline 141.5 133.3 69.4 59.2 Texas Gas Transmission 143.8 157.2 53.3 51.8 Transcontinental Gas Pipe Line 390.6 378.8 139.4 108.9 ---------- ---------- ---------- ---------- $ 843.3 $ 839.1 $ 348.0 $ 312.2 ========== ========== ========== ========== Energy Services: Energy Marketing & Trading $ 655.2 $ 987.2* $ 20.7 $ 12.2* Exploration & Production 78.1 62.4 20.3 14.7 Midstream Gas & Liquids 441.9 522.6* 121.1 154.3* Petroleum Services 1,325.6 1,297.1* 79.0 94.7* Merger-related costs -- -- (42.0) -- ---------- ---------- ---------- ---------- $ 2,500.8 $ 2,869.3* $ 199.1 $ 275.9* ========== ========== ========== ========== * Amounts have been restated as described in Note 2. Included in the second-quarter 1998 other (income) expense-net on the Consolidated Statement of Income 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 12 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 $68 million in merger-related costs comprised primarily of outside professional fees and early retirement and severance costs. Approximately $42 million of these merger-related costs are included in other (income) expense-net as a component of Energy Services' operating profit for the six months ended June 30, 1998 (see Note 3), and approximately $26 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.

9 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 Six months ended March 31, ended June 30, ended June 30, (Millions) 1998 1997 1997 ---------- ---------- ---------- Revenues: Williams $ 1,137.3 $ 1,020.6 $ 2,022.0 MAPCO 823.8 854.3 1,785.5 Intercompany eliminations (1.3) (4.0) (8.0) ---------- ---------- ---------- Combined $ 1,959.8 $ 1,870.9 $ 3,799.5 ========== ========== ========== Net income: Williams $ 59.7 $ 107.8 $ 213.7 MAPCO 8.4 10.7 83.4 ---------- ---------- ---------- Combined $ 68.1 $ 118.5 $ 297.1 ========== ========== ========== 6

10 Notes (continued) 5. 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 occurred on January 1, 1997, Williams' unaudited pro forma revenues for the six months ended June 30, 1997, would have been approximately $4 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. 6. 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. 7. Provision for income taxes The provision for income taxes includes: Three months ended Six months ended (Millions) June 30, June 30, ----------------------- ----------------------- 1998 1997 1998 1997 ---------- ---------- ---------- ---------- Current: Federal $ 19.2 $ 14.8 $ 24.8 $ 87.8 State .5 5.7 2.0 12.4 Foreign .4 -- 1.0 -- ---------- ---------- ---------- ---------- 20.1 20.5 27.8 100.2 Deferred: Federal 17.6 17.3 50.5 36.9 State 4.6 3.4 9.5 9.2 ---------- ---------- ---------- ---------- 22.2 20.7 60.0 46.1 ---------- ---------- ---------- ---------- Total provision $ 42.3 $ 41.2 $ 87.8 $ 146.3 ========== ========== ========== ========== 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 1997 is less than the federal statutory rate due primarily to the non-taxable gain recognized in the second quarter (see Note 5) and income tax credits from coal-seam gas production, partially offset by the effects of state income taxes. 8. 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). 7

11 Notes (continued) 9. Earnings per share Basic earnings per common share are computed for the three and six months ended June 30, 1998 and 1997, as follows: (Millions, except Three months ended Six months ended per-share amounts) June 30, June 30, - ----------------- --------------------------- ---------------------------- 1998 1997* 1998 1997* ------------ ------------ ------------ ------------ Basic earnings: Income before extraordinary loss $ 60.7 $ 118.5 $ 133.6 $ 297.1 Extraordinary loss -- -- (4.8) -- ------------ ------------ ------------ ------------ Net income 60.7 118.5 128.8 297.1 Preferred stock dividends: $2.21 cumulative preferred stock -- .4 -- .8 $3.50 cumulative convertible preferred stock 1.6 2.2 3.8 4.4 ------------ ------------ ------------ ------------ Income applicable to common stock $ 59.1 $ 115.9 $ 125.0 $ 291.9 ============ ============ ============ ============ Basic shares: Average number of common shares outstanding during the period 423,977 407,737 419,532 407,733 Shares attributable to deferred stock 2,186 3,686 2,248 3,801 ------------ ------------ ------------ ------------ Total basic weighted- average shares 426,163 411,423 421,780 411,534 ============ ============ ============ ============ Basic earnings per common share: Income before extraordinary loss $ .14 $ .28 $ .31 $ .71 Extraordinary loss -- -- (.01) -- ------------ ------------ ------------ ------------ Net income $ .14 $ .28 $ .30 $ .71 ============ ============ ============ ============ Diluted earnings per common share are computed for the three and six months ended June 30, 1998 and 1997, as follows: (Millions, except Three months ended Six months ended per-share amounts) June 30, June 30, - ----------------- --------------------------- ---------------------------- 1998 1997* 1998 1997* ------------ ------------ ------------ ------------ Diluted earnings: Income before extraordinary loss $ 60.7 $ 118.5 $ 133.6 $ 297.1 Extraordinary loss -- -- (4.8) -- ------------ ------------ ------------ ------------ Net income 60.7 118.5 128.8 297.1 Preferred stock dividends: $2.21 cumulative preferred stock -- .4 -- .8 ------------ ------------ ------------ ------------ Income applicable to common stock $ 60.7 $ 118.1 $ 128.8 $ 296.3 ============ ============ ============ ============ Diluted shares: Average number of common shares outstanding during the period 423,977 407,737 419,532 407,733 Shares attributable to options and deferred stock 7,841 9,043 10,330 9,374 Dilutive preferred shares 9,646 11,716 10,392 11,717 ------------ ------------ ------------ ------------ Total diluted weighted- average shares 441,464 428,496 440,254 428,824 ============ ============ ============ ============ Diluted earnings per common share: Income before extraordinary loss $ .14 $ .28 $ .30 $ .69 Extraordinary loss -- -- (.01) -- ------------ ------------ ------------ ------------ Net income $ .14 $ .28 $ .29 $ .69 ============ ============ ============ ============ *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

12 Notes (continued) 10. Inventories ------------------- (Millions) June 30, December 31, -------- 1998 1997 -------- -------- Raw materials: Crude oil $ 47.7 $ 30.5 Other 4.9 5.2 -------- -------- 52.6 35.7 Finished goods: Refined products 119.0 122.3 Fertilizer and natural gas liquids 65.6 43.8 General merchandise & communications equipment 79.6 90.0 -------- -------- 264.2 256.1 Materials and supplies 84.6 82.5 Natural gas in underground storage 78.7 57.8 Other 2.1 1.8 -------- -------- $ 482.2 $ 433.9 ======== ======== 11. 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 June 30, 1998, $914 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 June 30, 1998, $248 million in current debt obligations, including $98 million of commercial paper, have been classified as non-current obligations based on Williams' intent and ability to refinance on a long-term basis. At June 30, 1998, the amount available on the $1 billion credit agreement of $400 million is sufficient to complete these refinancings. Subsequent to June 30, 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. Debt - ---- Weighted- average interest June 30, December 31, (Millions) rate* 1998 1997 -------- ---------- ---------- ---------- The Williams Companies, Inc. Revolving credit loans -- % $ -- $ 383.0 Debentures, 8.875% - 10.25%, payable 2012, 2020 and 2021 8.5 136.9 137.0 Notes, 5.1% - 9.625%, pay- able through 2012** 6.5 1,652.2 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 6.6 568.9 586.4 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 8.6 152.2 152.4 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 7.0 426.3 128.2 Adjustable rate note, payable 2002 5.7 150.0 150.0 Williams Holdings of Delaware Revolving credit loans 6.0 600.0 200.0 Commercial paper 5.8 98.0 -- Debentures, 6.25% and 7.7%, payable 2006 and 2027 5.5 351.9 351.8 Notes, 6.365% - 8.87%, payable through 2022 7.7 567.2 625.3 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 7.6 7.6 51.2 ---------- ---------- ---------- 5,913.1 5,431.8 Current portion of long-term debt (70.1) (80.3) ---------- ---------- $ 5,843.0 $ 5,351.5 ========== ========== * At June 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. 9

13 Notes (continued) 12. Contingent liabilities and commitments Rate and regulatory matters and related litigation Williams' interstate pipeline subsidiaries, including Williams Pipe Line, have various regulatory proceedings pending. As a result of rulings in certain of these proceedings, a portion of the revenues of these subsidiaries has been collected subject to refund. The natural gas pipeline subsidiaries have reserved $401 million for potential refund as of June 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. 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. Comments on the NOPR and NOI are due during the fourth quarter 1998. On July 15, 1998, Williams Pipe Line 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 the company 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. The company continues to believe it should prevail upon appeal regarding collected rates for that period. However, due to this FERC decision, the company 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, Williams Pipe Line has collected and recognized as revenues $113 million in noncompetitive markets that are in excess of tariff rates previously approved by the FERC and that are subject to refund with interest. The company 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 and 636-C, costs incurred to comply with these rules are permitted to be recovered in full, although a percentage of such costs must be allocated to interruptible transportation service. Pursuant to a stipulation and agreement approved by the FERC, Williams Gas Pipelines Central (Central) has made 12 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 $70 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 10

14 Notes (continued) the administrative law judge's decision and determined that a contract was 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 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 non-settlement 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, the FERC approved an order, which permits Central to hold a reverse auction for the gas purchase contracts which are the subject of the prudency challenges outlined above. Under the reverse auction, Central will pay the lowest bid under a fixed maximum figure, with the bidder assuming Central's above-market costs of gas. Such order also denied, without prejudice to later refiling, an indefinite extension of Central's recovery mechanism for non-settlement costs associated with these contracts. Unless extended, non-settlement costs, presently approximating $1 million per month, incurred beyond November 1, 1998 would not be recoverable. 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 costs that may be incurred nor the related amounts that could be recovered from customers. Central is actively pursuing negotiations with the producers to resolve all outstanding obligations under the contracts. Based on the terms of what Central believes would be a reasonable settlement, $94 million has been accrued as a liability at June 30, 1998. Central also has a $91 million regulatory asset at June 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 consistent with the $94 million accrued liability, the loss could be the total of the regulatory asset and the $40 million of protested assets. 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 the future recovery of these costs would be in accordance with the terms of Order No. 636. In September 1995, Texas Gas received FERC approval of a settlement regarding Texas Gas' recovery of gas supply realignment costs. Through June 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 June 30, 1998, these subsidiaries had reserves totaling approximately $27 million for these costs. Certain Williams subsidiaries, including Texas Gas and Transcontinental Gas Pipe Line, have been identified as potentially responsible parties (PRP) at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. Although no assurances can be given, Williams does not believe that these obligations or the PRP status of these subsidiaries will have a material adverse effect on its financial position, results of operations or net cash flows. Transcontinental Gas Pipe Line, Texas Gas and Central have identified polychlorinated biphenyl (PCB) contamination in air compressor systems, soils and related properties at certain compressor station sites. Transcontinental Gas Pipe Line, Texas Gas and Central have also been involved in negotiations with the U.S. Environmental Protection Agency (EPA) and state agencies to develop screening, sampling and cleanup programs. In addition, negotiations with certain environmental authorities and other programs concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites have been commenced by Central, Texas Gas and Transcontinental Gas Pipe Line. As of June 30, 1998, Central had recorded a liability for approximately $17 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) had 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 11

15 Notes (continued) Pipe Line likewise had recorded liabilities for these costs which are included in the $27 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 retail petroleum, refining and propane marketing operations primarily related to soil and groundwater contamination. At June 30, 1998, WES and its subsidiaries had reserves, in addition to the reserves listed above, totaling approximately $23 million. WES recognizes receivables related to environmental remediation costs from state funds as a result of laws permitting states to reimburse certain expenses associated with underground storage tank problems and repairs. At June 30, 1998, WES and its subsidiaries had receivables totaling $12 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 June 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 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 Company 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 Company is continuing with settlement negotiations and believes that any final agreement reached with these plaintiffs will significantly reduce the Company's liability under the judgment. The Company has accrued a liability representing an estimate of amounts it expects to incur to finally resolve all litigation. 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. Williams Communications, Inc. filed suit on March 20, 1998, against WorldCom Network Services, Inc. (WorldCom) in 12

16 Notes (continued) 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 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 $4.4 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, Williams entered into a 15 year contract giving them 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. 13. Adoption of accounting standards The Financial Accounting Standards Board issued three new accounting standards, Statement on Financial Accounting Standards (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.

17 Notes (continued) 14. Comprehensive income Comprehensive income for the three and six months ended June 30 is as follows: Three months Six months (Millions) ended June 30, ended June 30, -------- ----------------- ------------------ 1998 1997 1998 1997 -------- -------- -------- -------- Net income $ 60.7 $ 118.5 $ 128.8 $ 297.1 Other comprehensive income (loss): Unrealized gains on securities 13.5 -- 26.8 -- Foreign currency translation adjustments (.4) -- (2.5) -- -------- -------- -------- -------- Comprehensive income before taxes 73.8 118.5 153.1 297.1 Income taxes 5.2 -- 10.4 -- -------- -------- -------- -------- Comprehensive income $ 68.6 $ 118.5 $ 142.7 $ 297.1 ======== ======== ======== ======== 13

18 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 Second Quarter 1998 vs. Second Quarter 1997 GAS PIPELINES CENTRAL'S revenues and operating profit decreased $.6 million, or 2 percent, and $.2 million, or 3 percent, respectively. Total throughput increased 6 TBtu, or 10 percent, due primarily to higher firm and interruptible transportation volumes. KERN RIVER GAS TRANSMISSION'S (KERN RIVER) revenues and operating profit decreased $2 million, or 5 percent, and $3.5 million, or 11 percent, respectively, due primarily to the impact of its rate design. In addition, operating profit decreased due to higher operating and maintenance expenses and ad valorem taxes. Total throughput increased less than 1 percent. NORTHWEST PIPELINE'S revenues increased $4.2 million, or 6 percent, due primarily to increased firm transportation and the net favorable effect of adjustments to rate refund accruals in 1998 combined with the impact of an unfavorable adjustment to rate refund accruals in 1997. Total throughput increased less than 1 percent. Operating profit increased $5.3 million, or 18 percent, due primarily to increased firm transportation and the net favorable effect of the adjustments to rate refund accruals in 1998 and 1997 and lower general and administrative expenses, slightly offset by higher operating and maintenance expenses. TEXAS GAS TRANSMISSION'S revenues decreased $3.8 million, or 6 percent, and costs and operating expenses decreased $4 million, or 10 percent, due primarily to $5 million lower reimbursable costs passed through to customers as provided in Texas Gas' rates. Total throughput decreased 5.3 TBtu, or 3 percent, due primarily to a warmer 1998 winter heating season as compared to 1997. Operating profit increased $2.1 million, or 25 percent, due primarily to lower general and administrative expenses. 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 $4.8 million, or 3 percent, due primarily to new rates placed into effect on May 1, 1997 to recover costs associated with increased capital expenditures, expansion projects placed into service in late 1997, and a 1998 adjustment of $10 million related to new rates placed into effect in 1997, largely offset by $9 million lower reimbursable costs passed through to customers as provided in Transco's rates. Total throughput decreased 16.1 TBtu, or 4 percent. Operating profit increased $18.1 million, or 36 percent, due primarily to the revenue increases described above and $3 million lower operating and maintenance expenses. 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. ENERGY SERVICES ENERGY MARKETING & TRADING'S revenues decreased $255 million, or 59 percent, and costs and operating expenses decreased $278 million, or 62 percent, due primarily to the $223 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 Notes to Consolidated Financial Statements). In addition, crude oil and refined products revenues decreased $21 million due primarily to 14

19 decreased average sales prices associated with the marketing of refined products from the Alaska refinery. Revenues associated with natural gas physical trading decreased $14 million due primarily to depressed prices caused by warmer weather conditions as compared to 1997. Retail propane sales decreased $7 million due primarily to 10 percent lower sales volumes combined with lower average sales prices. Partially offsetting these decreases were $6 million higher revenues from energy capital financing activities and the favorable settlement of a long-term transportation contract. Operating profit increased $24.4 million to a $4.1 million operating profit in 1998, due primarily to improved crude oil and refined products trading activities, lower retail propane operating costs, increased energy capital financing activities and the favorable settlement of a long-term transportation contract, partially offset by lower natural gas trading revenues and an $11 million increase in general and administrative expenses resulting from increased staffing levels. EXPLORATION & PRODUCTION'S revenues increased $12.9 million, or 52 percent, due primarily to the recognition of $10 million in deferred income resulting from a transaction that transferred certain tax credits to a third party, and an increase in both company-owned production volumes sold and marketing volumes from Williams Coal Seam Gas Royalty Trust (Royalty Trust). Operating profit increased $3.9 million, or 98 percent, due primarily to the recognition of deferred income and increased company-owned production, largely offset by $4 million higher leasehold impairment expense and $3 million higher depreciation, depletion and amortization. MIDSTREAM GAS & LIQUIDS' revenues decreased $47.1 million, or 19 percent, due primarily to the $12 million impact from the shutdown of the Canadian marketing operations, $13 million related to lower average sales prices from liquids processing activities, 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) and the pass-through of $7 million lower operating cost to customers, partially offset by $5 million resulting from higher average gathering rates. Costs and operating expenses decreased $35 million, or 21 percent, due primarily to the shutdown of the Canadian marketing operations, the rate adjustments related to Midstream's regulated gathering activities and lower costs passed through to customers. Operating profit decreased $15 million, or 21 percent, due primarily to $10 million from lower per-unit liquids margins, higher operating maintenance and depreciation expenses, a $3 million unfavorable litigation judgement in 1998 and the impact of a $2 million favorable business interruption insurance estimate adjustment in 1997, partially offset by an increase in average gathering rates. PETROLEUM SERVICES' revenues increased $63.9 million, or 10 percent, due primarily to $23 million in pipeline construction revenue, $15 million higher convenience store sales primarily resulting from the May 1997 EZ-Serve acquisition, a $13 million increase in revenues from refining operations, $7 million higher ethanol sales, $7 million higher revenues from fleet management and mobile computer technology operations begun in mid-1997, and $5 million higher product transportation revenues. The $15 million increase in convenience store sales reflects $13 million from increased merchandise sales and $22 million from 17 percent higher gasoline and diesel sales volumes, partially offset by lower average gasoline and diesel sales prices. The $13 million in refining revenues reflects $68 million from a 20 percent increase in barrels sold resulting from plant expansions and improved liquids recovery, partially offset by $55 million from lower average sales prices. Costs and expenses increased $65 million, or 11 percent, due primarily to $22 million in pipeline construction costs, a $19 million increase from refining operations, increased convenience store product purchases and operating costs primarily resulting from the EZ-Serve acquisition, $5 million higher costs from fleet management and mobile computer technology operations and increased general and administrative expenses. The $19 million increase from refining operations reflects $53 million due to increased processed volumes, partially offset by $35 million due to lower average crude oil purchase prices. Other (income) expense - net in 1998 includes a $15.5 million accrual for potential transportation rate refunds to customers (see Note 12). Operating profit decreased $16.1 million, or 26 percent, due primarily to the $15.5 million accrual for potential refunds to product transportation customers, lower per-unit refinery margins and higher general and administrative expenses, partially offset by higher product transportation revenues and increased refinery volumes processed. COMMUNICATIONS COMMUNICATIONS' revenues increased $54.2 million, or 15 percent, due primarily to the April 30, 1997 combination of the Northern Telecom (Nortel) customer premise equipment sales and services operations which contributed an additional $49 million of revenue in 1998 and $11 million of revenues from providing services to new long-term customers associated with the fiber-optic network currently under construction. New orders related to the customer premise equipment sales and services operations increased $38.3 million, or 12 percent, in the 15

20 second-quarter 1998 as compared to 1997, and sales order backlog at June 30, 1998 increased $14.1 million from June 30, 1997. Costs and operating expenses increased $36 million, or 13 percent, including $30 million associated with the combination with Nortel and leased capacity costs associated with providing customer services prior to completion of the new network. Selling, general, and administrative expenses increased $28 million, or 32 percent, due primarily to the combination with Nortel, $2 million for a new national advertising campaign and the expansion of the infrastructure including $5 million for information systems in support of 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 $13.8 million to a $10.5 million operating loss, due primarily to the increased cost of substantially expanding the infrastructure related to completion of the new fiber-optic network and $5 million lower operating profit from the customer premise equipment sales and services operations. GENERAL CORPORATE EXPENSES decreased $3.9 million, or 18 percent, due primarily to expense savings realized following the MAPCO merger, partially offset by an additional $3 million of MAPCO merger-related costs. An additional $6.1 million of such costs are included in other (income) expense - net as a component of Energy Services' operating profit (see Note 3). Interest accrued increased $9.6 million, or 8 percent, due primarily to higher borrowing levels including Williams Holdings' commercial paper program, partially offset by lower average interest rates following the recent debt restructuring. Investing income decreased $2.3 million, or 88 percent, as a result of an $8 million decrease in equity earnings primarily from international investments, largely offset by interest income on long-term notes receivable. For information concerning the $44.5 million 1997 gain on sale of interest in subsidiary, see Note 5. Other expense - net is $6.6 million unfavorable as compared to 1997 due primarily to a 1998 litigation loss accrual related to assets previously sold (see Note 12 for additional information). The $1.1 million, or 3 percent, increase in the provision for income taxes is primarily a result of an increase in the effective income tax rate substantially offset by 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 is significantly less than the federal statutory rate due primarily to the effect of the non-taxable gain recognized in 1997 (see Note 5) and income tax credits from coal-seam gas production, partially offset by the effects of state income taxes. 16

21 Six Months Ended June 30, 1998 vs. Six Months Ended June 30, 1997 GAS PIPELINES CENTRAL'S revenues decreased $1.9 million, or 2 percent. Total throughput decreased 2.2 TBtu, or 1 percent, due primarily to lower firm transportation volumes, partially offset by 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 $2.9 million, or 9 percent, due primarily to a lower gain in 1998 compared to 1997 from the sale-in-place of natural gas and higher depreciation expense in 1998, partially offset by lower operating and maintenance expenses and general and administrative expenses. KERN RIVER'S revenues decreased $.5 million, or 1 percent. Total throughput increased 9.3 TBtu, or 7 percent, due primarily to higher short-term firm and interruptible transportation volumes. Operating profit decreased $3.5 million, or 6 percent, due primarily to lower revenue and increased general and administrative expenses, depreciation and ad valorem taxes. NORTHWEST PIPELINE'S revenues increased $8.2 million, or 6 percent, due primarily to a new rate design effective March 1, 1997 that enables greater short-term firm and interruptible transportation volumes, the net favorable effect of adjustments to rate refund accruals in 1998 and the impact of an unfavorable adjustment to rate refund accruals in 1997. Total throughput increased 9.2 TBtu, or 2 percent. Operating profit increased $10.2 million, or 17 percent, due primarily to the new rate design, the net favorable effects of the adjustments to rate refund accruals in 1998 and 1997 and lower general and administrative expenses. TEXAS GAS TRANSMISSION'S revenues decreased $13.4 million, or 9 percent, and costs and operating expenses decreased $11 million, or 14 percent, due primarily to $10 million lower reimbursable costs passed through to customers as provided in Texas Gas' rates. In addition, revenues in 1997 were favorably impacted $4 million by the resolution of certain contractual issues. Total throughput decreased 11.6 TBtu, or 3 percent, due primarily to a warmer 1998 winter heating season as compared to 1997. Operating profit increased $1.5 million, or 3 percent, due primarily to lower general and administrative and operating and maintenance expenses, substantially 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 $11.8 million, or 3 percent, due primarily to new rates placed into effect on May 1, 1997 to recover costs associated with increased capital expenditures, new expansion projects placed into service in late 1997, new services begun in the last half of 1997 and a 1998 adjustment of $10 million related to new rates placed into effect in 1997, partially offset by $14 million lower reimbursable costs passed through to customers as provided in Transco's rates. Operating profit increased $30.5 million, or 28 percent, due primarily to the revenue increases described above and $4 million lower operating and maintenance expenses. 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. ENERGY SERVICES ENERGY MARKETING & TRADING'S revenues decreased $332 million, or 34 percent, and costs and operating expenses decreased $325 million, or 34 percent, due primarily to the $247 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). In addition, crude oil and refined products revenues decreased $50 million due primarily to decreased average prices associated with the marketing of refined products from the Alaska and Memphis refineries. Revenues associated with natural gas price-risk management and physical trading decreased $22 million as a result of market movement against the natural gas portfolio, partially offset by increased physical and notional trading volumes and a $6 million favorable settlement of a long-term transportation contract. The unfavorable market movement was attributable in part to a warmer than normal winter over much of the country and low market volatility during the first quarter of 1998. Retail propane sales decreased $24 million due primarily to lower average sales prices. Partially offsetting these decreases were $8 million higher electric power marketing revenues and $7 million higher revenues from energy financing activities. Operating profit increased $8.5 million, or 70 percent, due primarily to improved crude oil, refined products and liquids trading activities, lower retail propane operating costs, increased electric power marketing and energy capital financing revenues and the favorable settlement of a long-term transportation contract, 17

22 largely offset by the decrease in revenues from natural gas price-risk management and physical trading and a $23 million increase in general and administrative expenses resulting from increased staffing levels. EXPLORATION & PRODUCTION'S revenues increased $15.7 million, or 25 percent, due primarily to the recognition of $18 million in deferred income resulting from a transaction that transferred certain tax credits to a third party, and an increase in both company-owned production volumes sold and marketing volumes from the Royalty Trust, partially offset by lower average natural gas sales prices. Operating profit increased $5.6 million, or 39 percent, due primarily to the recognition of deferred income and increased company-owned production, largely offset by $6 million higher depreciation, depletion and amortization, $4 million higher leasehold impairment expense and $3 million higher general and administrative expenses. MIDSTREAM GAS & LIQUIDS' revenues decreased $80.7 million, or 15 percent, due primarily to the $28 million impact from the shutdown of the Canadian marketing operations, $23 million lower liquids sales from processing activities, 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), the pass-through of $12 million lower operating costs to customers, and $9 million lower pipeline transportation revenues resulting from decreased shipments, partially offset by $11 million resulting from higher average gathering rates. The $23 million decrease in liquids sales from processing activities is due to lower average liquids sales prices, partially offset by an 8 percent increase in sales volumes. Costs and operating expenses decreased $51 million, or 15 percent, due primarily to the shutdown of the Canadian marketing operations, the rate adjustments related to Midstream's regulated gathering activities and lower costs passed through to customers. Operating profit decreased $33.2 million, or 22 percent, due primarily to $24 million from lower per-unit liquids margins, higher operating, maintenance and depreciation expenses, decreased pipeline shipments, a $3 million unfavorable litigation judgement in 1998 and the impact of a $2 million favorable business interruption insurance estimate adjustment in 1997, partially offset by an increase in average gathering rates. PETROLEUM SERVICES' revenues increased $28.5 million, or 2 percent, due primarily to $29 million in pipeline construction revenue, $19 million higher revenues from fleet management and mobile computer technology operations begun in mid-1997, $15 million higher convenience store sales primarily resulting from the May 1997 EZ-Serve acquisition, $13 million higher ethanol sales and $5 million higher product transportation revenues, partially offset by a $41 million decrease in revenues from refining operations. The $15 million increase in convenience store sales reflects $24 million from increased merchandise sales and $32 million from 13 percent higher gasoline and diesel sales volumes, largely offset by lower average gasoline and diesel sales prices. The $41 million decline in refining revenues reflects $170 million from lower average sales prices, partially offset by $129 million from a 19 percent increase in barrels sold. Costs and expenses increased $29 million, or 2 percent, due primarily to $28 million in pipeline construction costs, $20 million higher costs from fleet management and mobile computer technology operations, increased convenience store product purchases and operating costs primarily resulting from the EZ-Serve acquisition, $12 million from increased ethanol cost of sales and increased general and administrative expenses, partially offset by a $34 million decrease from refining operations. The $34 million decline from refining operations reflects a $147 million decrease due to lower average crude oil purchase prices, partially offset by $106 million due to increased processed volumes, and increased operating costs at the Memphis refinery. Other (income) expense - net in 1998 includes a $15.5 million accrual for potential transportation rate refunds to customers (see Note 12). Operating profit decreased $15.7 million, or 17 percent, due primarily to the $15.5 million accrual for potential refunds to transportation customers, lower per-unit refinery margins, increased operating costs due to higher production levels at the Memphis refinery and higher general and administrative expenses, partially offset by higher product transportation revenues and increased refinery production. COMMUNICATIONS COMMUNICATIONS' revenues increased $225.4 million, or 39 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, $12 million of revenues from providing services to new long-term customers associated with the fiber-optic network currently under construction, and increased business activity in the customer premise equipment sales and services operations. New orders related to customer premise equipment sales and services operations increased 18

23 $274.9 million, or 53 percent, during 1998 as compared to 1997, and sales order backlog at June 30, 1998 increased $14.1 million from June 30, 1997. Costs and operating expenses increased $171 million, or 40 percent, including $121 million associated with the combination with Nortel, $23 million from additional increased customer premise equipment sales and services operations, and higher costs in both the network and network applications businesses including leased capacity costs associated with providing customer services prior to completion of the new network. Selling, general, and administrative expenses increased $83 million, or 58 percent, of which $73 million is attributable to the customer premise equipment sales and services operations due primarily to the combination with Nortel, $5 million for a new national advertising campaign and the expansion of the infrastructure including $9 million for information systems and $2 million for sales support in support of 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 $31.9 million to a $30.6 million operating loss, due primarily to the increased costs of substantially expanding the infrastructure related to completion of the new fiber-optic network, $6 million lower operating profit from the customer premise equipment sales and services operations and increased operating losses in the network applications businesses. CONSOLIDATED GENERAL CORPORATE EXPENSES increased $19.8 million, or 51 percent, due primarily to MAPCO merger-related costs of $26 million, partially offset by expense savings realized following the MAPCO merger. An additional $42 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 $18.3 million, or 8 percent, due primarily to higher borrowing levels including Williams Holdings' commercial paper program, partially offset by lower average interest rates following the recent debt restructuring. Interest capitalized increased $8.6 million to $16 million, due primarily to capital expenditures for the fiber-optic network and the Venezuelan gas injection plant. Investing income decreased $6.4 million, or 68 percent, as a result of a $12 million decrease in equity earnings primarily from international investments, partially offset by interest income on long-term notes receivable. For information concerning the $44.5 million 1997 gain on sale of interest in subsidiary, see Note 5. 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 6). Other expense - net is $9.6 million unfavorable as compared to 1997 due primarily to a 1998 litigation loss accrual related to assets previously sold and a 1997 gain of $4 million on the termination of interest rate swap agreements. The $58.5 million, or 40 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 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 in 1997 is less than the federal statutory rate due primarily to the effect of the non-taxable gain recognized in 1997 (see Note 5) 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 8). Financial Condition and Liquidity Liquidity Williams considers its liquidity to come from two sources: internal liquidity, consisting of available cash investments, and external liquidity, consisting of borrowing capacity from available bank-credit facilities and Williams Holdings' commercial paper program, which can be utilized without limitation under existing loan covenants. At June 30, 1998, Williams had access to $530 million of liquidity representing $400 million available under its $1 billion bank-credit facility, $81 million of commercial paper availability, and cash-equivalent investments. This compares with liquidity of $166 million at December 31, 1997, and $273 million at June 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 June 30, 1998, $248 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 $3.1 billion. During 1998, Williams expects to finance capital expenditures, investments and working-capital requirements through 19

24 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 debt public offerings. 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. Total committed payments under the contract are 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. 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. 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 57.2 percent at June 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 61.4 percent at June 30, 1998, and 59.1 percent at December 31, 1997. 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. 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. Operating Activities The increase in commodity trading assets and commodity trading liabilities from December 31, 1997, is due primarily to the increased volatility in the electric power market during June 1998. Market Risk Disclosures During the six months ended June 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 $1.1 billion of fixed rate debt at a weighted average interest rate of approximately 6.1 percent (see Financing Activities above). The debt matures $300 million in 2000, $300 million in 2001, $200 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 $300 million of interest rate locks, expiring in 1998, at an average locked in rate of 5.6 percent referenced to underlying treasury securities having a weighted-average maturity of 9 years. 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 embedded technology which is prevalent throughout the organization. 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 assessment phase of this project as it relates to both traditional and non-traditional information technology areas has been substantially completed except for international projects in which we are involved and the non-traditional information technology areas within the Communications business unit. Communications' assessment is planned for completion during the third quarter of 1998. Necessary conversion and replacement activities have begun and are targeted for completion by December 31, 1998 with some exceptions. These exceptions include system replacements, items dependent on information from third parties, and certain areas within Communications, for which the targeted completion date is fourth-quarter 1999. Testing activities have begun and will continue throughout the process with substantial completion expected in the third quarter of 1999. Year 2000 test labs are in place and others will be by August 31, 1998. Within the Gas Pipelines, Energy Services and Corporate/Information Services business units, the percent of inventoried items confirmed to be compliant through testing activities ranges from 12 to 28 percent. As was expected, few problems have been detected during testing with items believed to be compliant. Williams has initiated a formal communications process with other companies with which Williams' systems interface or rely on to determine the extent to which those companies are addressing their year 2000 compliance. In connection with this process, Williams has sent over 7000 letters and questionnaires to third parties and is evaluating those responses as they are received. Where necessary, Williams will be working with those companies to mitigate any material adverse

25 effect on Williams. Williams expects to utilize both internal and external resources to complete this process. Existing resources have been redeployed and certain previously planned system replacements will be accelerated during this time. For example, implementation of a previously planned human resources system is currently in process. This system will address the year 2000 compliance issues in certain areas. In addition, one of Williams' business units has replaced or is replacing six major applications. Costs incurred for new software and hardware purchases will be capitalized and other costs will be expensed as incurred. While the total cost of Williams' enterprise-wide project is still being evaluated, Williams estimates that future costs, excluding previously planned system replacements, necessary to complete the project within the schedule described will total at least $45 million. Williams will update this estimate as additional information becomes available. Approximately $5 million of costs (including capital expenditures) have been incurred to date. 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. 20

26 Part II. Other Information Item 4. Submission of Matters to a Vote of Security Holders. The Annual Meeting of Stockholders of the Company was held on May 21, 1998. At the Annual Meeting, seven individuals were elected as directors of the Company and seven individuals continue to serve as directors pursuant to their prior election. In addition, the appointment of Ernst & Young LLP as the independent auditor of the Company for 1998 was ratified. A tabulation of the voting at the Annual Meeting with respect to the matters indicated is as follows: Election of Directors Name For Withheld - --------------------- ----------- ------------ Glenn A. Cox 283,872,670 1,828,981 Thomas H. Cruikshank 283,871,669 1,829,982 William E. Green 283,767,791 1,933,860 Patricia L. Higgins 283,894,894 1,806,757 Frank T. MacInnis 283,795,446 1,906,205 Gordon R. Parker 283,944,381 1,757,270 Joseph H. Williams 282,614,004 3,087,647 Ratification of Appointment of Independent Auditor For Against Abstain - ----------- --------- --------- 283,301,634 1,318,098 1,081,919 Item 6. Exhibits and Reports on Form 8-K (a) The exhibits listed below are filed as part of this report: Exhibit 12--Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements (b) During the second quarter of 1998, the Company filed a Form 8-K on April 22, 1998 and May 18, 1998, which reported a significant event under Item 5 of the Form and included the exhibits required by Item 7 of the Form. 21

27 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) Gary R. Belitz ----------------------------------- Gary R. Belitz Controller (Duly Authorized Officer and Principal Accounting Officer) August 14, 1998

28 INDEX TO EXHIBITS Exhibit Number Exhibit - ------ ------- 12 Computation of Rate of Earnings to combined Fixed Charges and Preferred Stock Dividend Requirements 27 Financial Data Schedule

1 Exhibit 12 The Williams Companies, Inc. and Subsidiaries Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements (Dollars in millions) Six months ended June 30, 1998 ---------------- Earnings: Income before income taxes and extraordinary losses $ 221.4 Add: Interest expense - net 228.5 Rental expense representative of interest factor 21.8 Minority interest in income of consolidated subsidiaries 5.6 Other 6.2 ---------- Total earnings as adjusted plus fixed charges $ 483.5 ========== Fixed charges and preferred stock dividend requirements: Interest expense - net $ 228.5 Capitalized interest 16.0 Rental expense representative of interest factor 21.8 Pretax effect of dividends on preferred stock of the Company 6.3 ---------- Combined fixed charges and preferred stock dividend requirements $ 272.6 ========== Ratio of earnings to combined fixed charges and preferred stock dividend requirements 1.77 ==========

5 1,000,000 6-MOS DEC-31-1998 JAN-01-1998 JUN-30-1998 136 0 1,604 23 482 3,203 15,378 3,310 17,572 4,105 5,843 0 117 429 3,823 17,572 0 3,740 0 3,217 0 3 245 221 88 134 0 (5) 0 129 .30 .29