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, 1997 ---------------------------------------------- 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) 588-2000 ------------------------------------------------- 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, 1997 - ------------------------------------ ----------------------------------- Common Stock, $1 par value 158,954,065 Shares

2 The Williams Companies, Inc. Index Page ---- Part I. Financial Information Item 1. Financial Statements Consolidated Statement of Income--Three Months and Six Months Ended June 30, 1997 and 1996 2 Consolidated Balance Sheet--June 30, 1997 and December 31, 1996 3 Consolidated Statement of Cash Flows--Six Months Ended June 30, 1997 and 1996 4 Notes to Consolidated Financial Statements 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 10 Part II. Other Information Item 4. Submission of Matters to a Vote of Security Holders 14 Item 6. Exhibits and Reports on Form 8-K 14 Exhibit 11--Computation of Earnings Per Common and Common- equivalent Share Exhibit 12--Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements Exhibit 27--Financial Data Schedule Certain matters discussed in this report, excluding historical information, include forward-looking statements. Although The Williams Companies 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 Reform Act of 1995. Additional information about issues that could lead to material changes in performance is contained in The Williams Companies, Inc.'s Annual Report on Form 10-K. 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, ---------------------------------------------------------- 1997 1996 1997 1996 ------------ ------------ ------------ ------------ Revenues: Williams Interstate Natural Gas Systems (Note 3) $ 397.4 $ 402.7 $ 839.1 $ 858.4 Williams Energy Group (Note 3) 341.8 340.8 726.0 707.7 Williams Communications Group (Note 4) 359.1 161.5 575.7 302.1 Other 9.2 12.6 19.1 25.2 Intercompany eliminations (86.9) (80.1) (137.9) (162.2) ------------ ------------ ------------ ------------ Total revenues 1,020.6 837.5 2,022.0 1,731.2 ------------ ------------ ------------ ------------ Profit-center costs and expenses: Costs and operating expenses 625.1 493.9 1,206.4 993.3 Selling, general and administrative expenses 186.0 142.0 347.0 277.4 Other income--net (5.2) (3.8) (9.4) (1.0) ------------ ------------ ------------ ------------ Total profit-center costs and expenses 805.9 632.1 1,544.0 1,269.7 ------------ ------------ ------------ ------------ Operating profit: Williams Interstate Natural Gas Systems (Note 3) 131.2 124.0 312.2 288.1 Williams Energy Group (Note 3) 73.8 79.1 162.3 167.0 Williams Communications Group (Note 4) 3.3 1.1 1.3 3.9 Other 6.4 1.2 2.2 2.5 ------------ ------------ ------------ ------------ Total operating profit 214.7 205.4 478.0 461.5 General corporate expenses (11.6) (7.1) (19.7) (18.2) Interest accrued (101.1) (90.0) (198.2) (172.1) Interest capitalized 3.9 .6 6.1 2.4 Investing income 1.9 3.6 7.8 8.1 Gain on sale of interest in subsidiary (Note 4) 44.5 -- 44.5 -- Minority interest in income of consolidated subsidiaries (Note 4) (5.1) -- (5.1) -- Other expense--net (4.5) (3.0) (7.5) (6.3) ------------ ------------ ------------ ------------ Income before income taxes 142.7 109.5 305.9 275.4 Provision for income taxes (Notes 4 and 5) 34.9 29.1 92.2 90.1 ------------ ------------ ------------ ------------ Net income 107.8 80.4 213.7 185.3 Preferred stock dividends 2.6 2.6 5.2 5.2 ------------ ------------ ------------ ------------ Income applicable to common stock $ 105.2 $ 77.8 $ 208.5 $ 180.1 ============ ============ ============ ============ Earnings per common and common-equivalent share (Note 9): Primary $ .65 $ .48 $ 1.28 $ 1.11 Average shares (thousands) 162,711 162,372 162,380 162,006 Fully diluted $ .64 $ .47 $ 1.26 $ 1.10 Average shares (thousands) 168,569 168,231 168,491 168,049 Cash dividends per common share $ .26 $ .227 $ .52 $ .453 See accompanying notes. 2

4 The Williams Companies, Inc. Consolidated Balance Sheet (Unaudited) (Millions) ---------------------- June 30, December 31, 1997 1996 --------- --------- ASSETS Current assets: Cash and cash equivalents $ 143.6 $ 115.3 Receivables (Note 6) 741.8 952.9 Transportation and exchange gas receivable 109.1 117.7 Inventories 271.5 204.6 Commodity trading assets 133.0 147.2 Deferred income taxes 190.1 199.5 Other 115.0 152.9 --------- --------- Total current assets 1,704.1 1,890.1 Investments 261.2 190.6 Property, plant and equipment, at cost 11,626.6 11,212.3 Less accumulated depreciation and depletion (2,036.7) (1,826.0) --------- --------- 9,589.9 9,386.3 Goodwill and other intangible assets--net (Note 4) 440.5 198.1 Other assets and deferred charges 752.7 753.7 --------- --------- Total assets $12,748.4 $12,418.8 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Notes payable $ 44.1 $ 269.5 Accounts payable 475.8 683.3 Transportation and exchange gas payable 67.9 73.7 Accrued liabilities 949.6 975.3 Commodity trading liabilities 119.6 137.9 Long-term debt due within one year (Note 7) 263.3 59.6 --------- --------- Total current liabilities 1,920.3 2,199.3 Long-term debt (Note 7) 4,656.1 4,376.9 Deferred income taxes 1,650.6 1,626.6 Other liabilities 848.5 787.5 Minority interest in consolidated subsidiaries (Note 4) 85.6 7.5 Contingent liabilities and commitments (Note 8) Stockholders' equity: Preferred stock, $1 par value, 30,000,000 shares authorized, 3,240,984 shares issued in 1997 and 3,241,552 shares issued in 1996 161.0 161.0 Common stock, $1 par value, 480,000,000 shares authorized, 161,318,883 shares issued in 1997 and 160,214,163 shares issued in 1996 161.3 160.2 Capital in excess of par value 1,080.4 1,047.7 Retained earnings 2,245.7 2,119.5 Unamortized deferred compensation (2.5) (2.2) --------- --------- 3,645.9 3,486.2 Less treasury stock (at cost), 2,459,729 shares of common stock in 1997 and 2,737,337 shares of common stock in 1996 (58.6) (65.2) --------- --------- Total stockholders' equity 3,587.3 3,421.0 --------- --------- Total liabilities and stockholders' equity $12,748.4 $12,418.8 ========= ========= See accompanying notes. 3

5 The Williams Companies, Inc. Consolidated Statement of Cash Flows (Unaudited) (Millions) ------------------------- Six months ended June 30, ------------------------- 1997 1996 ---------- ------------ OPERATING ACTIVITIES: Net income $ 213.7 $ 185.3 Adjustments to reconcile to cash provided from operations: Depreciation, depletion and amortization 245.1 222.6 Provision for deferred income taxes 39.8 2.3 Minority interest in income of consolidated subsidiaries 5.1 -- Gain on sale of interest in subsidiary (44.5) -- Changes in receivables sold 143.8 (22.5) Changes in receivables 237.5 43.2 Changes in inventories (41.9) (12.2) Changes in other current assets 35.4 23.2 Changes in accounts payable (201.1) (11.9) Changes in accrued liabilities (124.4) (83.6) Changes in current commodity trading assets and liabilities (4.1) (19.1) Changes in non-current commodity trading assets and liabilities (10.2) (20.6) Other, including changes in non-current assets and liabilities 19.2 29.5 -------- -------- Net cash provided by operating activities 513.4 336.2 -------- -------- FINANCING ACTIVITIES: Proceeds from notes payable 45.6 304.8 Payments of notes payable (281.9) (221.1) Proceeds from long-term debt 513.7 1,271.9 Payments of long-term debt (177.6) (907.2) Proceeds from issuance of common stock 21.9 36.8 Dividends paid (87.5) (76.5) Other--net (1.0) (5.0) -------- -------- Net cash provided by financing activities 33.2 403.7 -------- -------- INVESTING ACTIVITIES: Property, plant and equipment: Capital expenditures (417.5) (273.8) Proceeds from dispositions 74.6 -- Changes in accounts payable and accrued liabilities (17.2) (11.5) Acquisition of businesses, net of cash acquired (79.1) (236.7) Income tax and other payments related to discontinued operations (6.9) (220.8) Purchase of investments/advance to affiliate (91.4) (27.9) Other--net 19.2 5.9 -------- -------- Net cash used by investing activities (518.3) (764.8) -------- -------- Increase (decrease) in cash and cash equivalents 28.3 (24.9) Cash and cash equivalents at beginning of period 115.3 90.4 -------- -------- Cash and cash equivalents at end of period $ 143.6 $ 65.5 ======== ======== 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 financial statements and notes thereto in Williams' 1996 Annual Report on Form 10-K. The accompanying financial statements have not been audited by independent auditors, but include all adjustments both normal recurring and others which, in the opinion of Williams' management, are necessary to present fairly its financial position at June 30, 1997, results of operations for the three and six months ended June 30, 1997 and 1996, and cash flows for the six months ended June 30, 1997 and 1996. 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 April 30, 1997, Williams and Northern Telecom (Nortel) combined their customer premise operations into a limited liability company, WilTel Communications, LLC (LLC) (see Note 4). Williams Communications Group's revenues and operating profit amounts for the three and six months ended June 30, 1997, include the operating results of the LLC beginning May 1, 1997. Williams Energy Group is comprised of four units. Field Services includes Williams' natural gas gathering and processing activities previously reported in Williams Field Services Group. Merchant Services includes Williams' energy commodity trading and price-risk management activities previously reported in Williams Energy Services. Certain natural gas and natural gas liquids marketing operations formerly reported in Williams Field Services Group are also included in Merchant Services. Petroleum Services includes Williams' interstate petroleum products pipeline, ethanol-producing facilities and petroleum terminals previously reported in Williams Pipe Line. Exploration & Production includes exploration for and production of hydrocarbons previously reported as a component of Williams Field Services Group. Williams Communications Group is a combination of WilTel and WilTech Group, previously reported separately. Certain revenues and operating profit amounts for the three and six months ended June 30, 1996, and cash flow amounts for the six months ended June 30, 1996, have been reclassified to conform to current-year classifications for these reorganizations and certain other matters. Revenues and operating profit amounts for the three and six months ended June 30, 1996, include the operating results of Kern River Gas Transmission Company since its January 16, 1996, acquisition by Williams of the remaining interest. 3. Revenues and operating profit Revenues and operating profit of Williams Interstate Natural Gas Systems and Williams Energy Group for the three and six months ended June 30, 1997 and 1996, are as follows: Three months ended June 30, ------------------------------------- (Millions) Revenues Operating Profit ------------------------------------- 1997 1996 1997 1996 ------- ------- ------- ------- Williams Interstate Natural Gas Systems: Northwest Pipeline $ 66.1 $ 68.9 $ 30.0 $ 34.8 Williams Natural Gas 40.9 45.2 11.6 9.6 Transcontinental Gas Pipe Line 188.1 188.8 50.2 40.3 Texas Gas Transmission 60.0 63.0 8.4 11.8 Kern River Gas Transmission 42.3 36.8 31.0 27.5 ------- ------- ------- ------- $ 397.4 $ 402.7 $ 131.2 $ 124.0 ======= ======= ======= ======= Williams Energy Group: Field Services $ 169.0 $ 148.9 $ 42.9 $ 38.8 Merchant Services 18.6 54.8 5.3 15.9 Petroleum Services 129.6 123.6 21.5 25.2 Exploration & Production 24.6 13.5 4.1 (.8) ------- ------- ------- ------- $ 341.8 $ 340.8 $ 73.8 $ 79.1 ======= ======= ======= ======= Six months ended June 30, ------------------------------------- (Millions) Revenues Operating Profit ------------------------------------- 1997 1996 1997 1996 ------- ------- ------- ------- Williams Interstate Natural Gas Systems: Northwest Pipeline $ 133.3 $ 136.5 $ 59.2 $ 67.0 Williams Natural Gas 87.8 88.4 32.3 22.0 Transcontinental Gas Pipe Line 378.8 392.2 108.9 93.1 Texas Gas Transmission 157.2 165.6 51.8 52.9 Kern River Gas Transmission 82.0 75.7 60.0 53.1 ------- ------- ------- ------- $ 839.1 $ 858.4 $ 312.2 $ 288.1 ======= ======= ======= ======= Williams Energy Group: Field Services $ 347.6 $ 308.0 $ 89.9 $ 86.5 Merchant Services 58.4 124.3 21.8 37.7 Petroleum Services 257.6 242.0 35.9 43.0 Exploration & Production 62.4 33.4 14.7 (.2) ------- ------- ------- ------- $ 726.0 $ 707.7 $ 162.3 $ 167.0 ======= ======= ======= ======= 4. Acquisition On April 30, 1997, Williams and Nortel combined their customer premise equipment sales and service operations into a limited liability company, WilTel Communications, LLC. In addition, Williams paid $68 million to Nortel. Williams has 5

7 Notes (continued) 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. Accordingly, the acquired assets and liabilities, including $150 million in long-term debt, have been recorded based on an allocation of the purchase price, with substantially all of the cost in excess of historical carrying values allocated to goodwill. The goodwill will be amortized using the straight line method over approximately 25 years. 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 affect the differences between the financial and tax bases of identifiable assets and liabilities. If the transaction occurred on January 1, 1996, Williams' unaudited pro forma revenues for the six months ended June 30, 1997 and 1996, would have been $2,270.1 million and $2,086.5 million, respectively. 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, 1996, or of future results of operations of the combined companies. 5. Provision for income taxes Three months ended Six months ended (Millions) June 30, June 30, - -------------------------------------------------------------------------------- 1997 1996 1997 1996 - -------------------------------------------------------------------------------- Current: Federal $ 18.4 $ 28.2 $ 44.1 $ 72.9 State 3.3 6.4 8.3 14.9 ------- ------- ------- ------- 21.7 34.6 52.4 87.8 Deferred: Federal 10.5 (5.4) 32.1 .8 State 2.7 (.1) 7.7 1.5 ------- ------- ------- ------- 13.2 (5.5) 39.8 2.3 ------- ------- ------- ------- Total provision $ 34.9 $ 29.1 $ 92.2 $ 90.1 ======= ======= ======= ======= 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 the second quarter (see Note 4) and income tax credits from coal-seam gas production, partially offset by the effects of state income taxes. The effective income tax rate in 1996 is less than the federal statutory rate due primarily to income tax credits from coal-seam gas production, partially offset by the effects of state income taxes. In addition, both 1996 periods include recognition of favorable adjustments totaling $10 million related to research credits and previously provided deferred income taxes on certain regulated capital projects. Cash payments, net of refunds, for income taxes for the six months ended June 30, 1997 and 1996, were $56 and $314 million, respectively. 6. Sale of receivables In January 1997, Williams expanded its revolving receivables facilities by $200 million. As of June 30, 1997, Williams has sold $159.8 million of receivables under this facility. The Financial Accounting Standards Board has issued a new accounting standard, FAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," effective for transactions occurring after December 31, 1996. The adoption of this standard has not had a material impact on Williams' consolidated results of operations, financial position or cash flows. 7. Long-term debt Weighted average interest June 30, December 31, (Millions) rate* 1997 1996 ---------- ---------- ---------- The Williams Companies, Inc. Revolving credit loans 8.5% $ 205.0 $ -- Debentures, 8.875% - 10.25%, payable 2012, 2020, 2021 and 2025 9.6 587.4 587.5 Notes, 7.5% - 9.625%, pay- able 1998 through 2001 8.8 815.5 817.5 Northwest Pipeline Debentures, 7.125% - 10.65%, payable through 2025 9.0 352.6 360.0 Adjustable rate notes, payable through 2002 9.0 8.3 10.0 Williams Natural Gas Variable rate notes, payable 1999 8.2 130.0 130.0 Transcontinental Gas Pipe Line Debentures, 7.25% and 9.125%, payable 1998 through 2026 8.1 352.3 352.4 Debentures, 7.08%, payable 2026 (subject to debt- holder redemption in 2001) 7.1 200.0 200.0 Note, 8.875%, payable 2002 8.9 128.4 227.7 Texas Gas Transmission Notes, 9.625% and 8.625%, payable 1997 and 2004 9.0 252.6 253.6 Kern River Gas Transmission Notes, 6.42% and 6.72%, payable through 2001 6.6 602.8 617.7 Williams Holdings of Delaware Revolving credit loans 6.1 575.0 500.0 Debentures, 6.25%, payable 2006 4.6 248.8 248.8 Notes, 6.4% - 6.91%, payable 1998 through 2002 6.8 205.6 -- Williams Pipe Line Notes, 8.95% and 9.78%, payable through 2001 9.4 100.0 100.0 Williams Energy Ventures Adjustable rate notes -- -- 25.6 WilTel Communications, LLC Note, 6.19%, payable 1997 6.2 150.0 -- Other, payable through 1999 8.0 5.1 5.7 ---------- ---------- ---------- 4,919.4 4,436.5 Current portion of long-term debt (263.3) (59.6) ---------- ---------- $ 4,656.1 $ 4,376.9 ========== ========== *At June 30, 1997, including the effects of interest-rate swaps. In June 1997, $205 million of notes payable were repaid with borrowings under the $1 billion bank-credit facility. Subsequent to June 30, 1997, Williams entered into a new $1 billion bank-credit agreement, replacing the previous 6

8 agreement. Under the new agreement, Northwest Pipeline, Transcontinental Pipe Line, Texas Gas Transmission, Williams Pipe Line, and WilTel Communications, LLC (see Note 4) will have access to varying amounts of the facility while Williams (parent) and Williams Holdings of Delaware, Inc. (Williams Holdings) have access to all unborrowed amounts. Interest rates vary with current market conditions. In July 1997, Williams Holdings finalized a commercial paper program backed by a new $500 million short-term bank-credit facility and issued $250 million under this program. Interest rates vary with current market conditions. For financial statement reporting purposes at June 30, 1997, $319 million in current debt obligations have been classified as non-current obligations based on Williams' intent and ability to refinance on a long-term basis. At June 30, 1997, the amount available on the $1 billion credit agreement of $220 million and Texas Gas Transmission's July 1997 issuance of $100 million in debentures, due 2027, are sufficient to complete these refinancings. Cash payments for interest (net of amounts capitalized) for the six months ended June 30, 1997 and 1996, are $195 million and $173 million, respectively. 8. 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. As to Williams Pipe Line, revenues collected subject to refund were $286 million at June 30, 1997; it is not expected that the amount of any refunds ordered would be significant. Accordingly, no portion of these revenues has been reserved for refund. As to the other pipelines, $243 million of revenues has been reserved for potential refund as of June 30, 1997. The Federal Energy Regulatory Commission (FERC) recently issued orders addressing, among other things, the authorized rates of return for three of 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 has challenged or will challenge their 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 1992, 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. Kern River Gas Transmission implemented its restructuring on August 1, 1993, Williams Natural Gas implemented its restructuring on October 1, 1993, and Northwest Pipeline, Texas Gas and Transcontinental Gas Pipe Line implemented their restructurings on November 1, 1993. Certain aspects of four pipeline companies' restructurings are under appeal. On July 16, 1996, the U.S. Court of Appeals for the D.C. Circuit issued an order which in part affirmed and in part remanded Order 636. However, the court stated that Order 636 would remain in effect until FERC issued a final order on remand after considering the remanded issues. With the issuance of this decision, the stay on the appeals of individual pipeline's restructuring cases will be lifted. The only appeal challenging Northwest Pipeline's restructuring has been dismissed. 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. Contract reformations and gas purchase deficiencies 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 Natural Gas (WNG) has made eight filings to direct bill take-or-pay and gas supply realignment costs. The first provided for the offset of certain amounts collected subject to refund against previous take-or-pay direct-billed amounts and, in addition, covered $24 million in new costs. This filing was approved, and the final direct-billed amount, taking into consideration the offset, was $15 million. The second filing covered $18 million in gas supply realignment costs, and provided for an offset of $3 million. The third filing covered $6.5 million in gas supply realignment costs. The remaining filings covered additional costs of approximately $18 million, which are similar in nature to the costs in the second filing. An intervenor has filed a protest seeking to have the Commission 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. As of June 30, 1997, this subsidiary had an accrual of $74 million for its then-estimated remaining contract-reformation and gas supply realignment costs. An intervenor has filed a protest seeking to have the FERC decide whether non-settlement costs covered by certain of WNG's recent filings were eligible for recovery pursuant to Order No. 636. In January 1997, the FERC held that 100 percent of such prudent non-settled costs would be recovered by WNG if such costs were eligible for recovery under Order No. 636. The FERC also held that none of the non-settled costs could be recovered by WNG if these costs were not eligible for recovery under Order No. 636. This Order was affirmed on rehearing in April 1997. WNG has appealed these FERC orders. WNG will make additional filings under the applicable FERC orders to recover such further costs as may be incurred in the future. WNG has recorded a regulatory asset of approximately $73 million for estimated future recovery of the foregoing costs. Because of the uncertainties related to the outcome of the FERC orders on appeal, WNG is actively pursuing settlement of the gas purchase contracts. While WNG believes that the accrued liability of $74 million is adequate through June 30, 1997, WNG has not been successful in negotiating a contract settlement for this amount. WNG cannot reasonably estimate what the financial impact would be if a settlement is not reached in the near term or if unfavorable rulings are received on the Order 636 eligibility case or the FERC orders on appeal. In September 1995, Texas Gas received FERC approval of a settlement regarding Texas Gas' recovery of gas supply realignment costs. The settlement provides that Texas Gas will recover 100 percent of such costs up to $50 million, will share in costs incurred between $50 million and $80 million, and will absorb any such costs above $80 million. Through June 30, 1997, Texas Gas has paid approximately $76 million and expects to pay no more than $80 million for gas supply 7

9 realignment costs, primarily as a result of contract terminations. Texas Gas has recovered approximately $66 million, plus interest, in gas supply realignment costs and has recorded a regulatory asset of approximately $1 million for the estimated future recovery of such costs, most of which will be collected from customers prior to December 31, 1997. Ninety percent of the cost recovery is collected through demand surcharges on Texas Gas' firm transportation rates; the remaining 10 percent should be recoverable from interruptible transportation service. 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, 1997, 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 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 Williams Natural Gas 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 Williams Natural Gas 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 Williams Natural Gas, Texas Gas and Transcontinental Gas Pipe Line. As of June 30, 1997, Williams Natural Gas 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 Field Services unit of Williams Energy Group has recorded an aggregate liability of approximately $14 million, representing the current estimate of their future environmental and remediation costs, including approximately $5 million relating to former Williams Natural Gas facilities. Texas Gas and Transcontinental Gas 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 Williams Natural Gas have deferred these costs pending recovery as incurred through future rates and other means. 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, 1997, Williams had approximately $11 million accrued for such excess costs. The actual costs incurred will depend on the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors. A lawsuit was filed in May 1993, in a state court in Colorado in which certain claims have been made against various defendants, including Northwest Pipeline, contending that gas exploration and development activities in portions of the San Juan Basin have caused air, water and other contamination. The plaintiffs in the case sought certification of a plaintiff class. In June 1994, the lawsuit was dismissed for failure to join an indispensable party over which the state court had no jurisdiction. The Colorado court of appeals 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. Northwest Pipeline is vigorously defending these lawsuits. Other legal matters 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. In addition, if the Tribe is successful in showing that Williams Production has no rights in the coal-seam gas, Williams Production has agreed to pay to the Trust for distribution to then-current unitholders, an amount representing a return of a portion of the 8

10 original purchase price paid for the units. While Williams believes that such a payment is not probable, it has reserved a portion of the proceeds from the sale of the units in the Trust. 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. Amoco Production Company, the class representative for the defendant class (of which Williams Production is a part), has indicated its intent to seek review of the Court of Appeals decision. In the event that further review is denied, the district court will be in the position to hear the defendants' affirmative defenses against the Tribe's claims. 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 and Texas Gas were named as defendants in, respectively, six and two lawsuits. Six of the eight lawsuits have been settled for cash payments aggregating approximately $9 million, all of which have previously been accrued, and of which approximately $3 million is recoverable as transition costs under Order 636. Damages, including interest calculated through December 31, 1996, of approximately $29 million, have been asserted in the remaining cases. 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 November 1994, Continental Energy Associates Limited Partnership (the Partnership) filed a voluntary petition under Chapter 11 of the Bankruptcy Code with the U.S. Bankruptcy Court, Middle District of Pennsylvania. The Partnership owns a cogeneration facility in Hazelton, Pennsylvania (the Facility). Hazelton Fuel Management Company (HFMC), a subsidiary of Transco Energy, formerly supplied natural gas and fuel oil to the Facility. As of June 30, 1997, HFMC had current outstanding receivables from the Partnership of approximately $20 million, all of which have been reserved. A Plan of Reorganization (the Plan) acceptable to most creditors and the debtor has been filed with the court. Under the Plan, all litigation involving HFMC will be fully settled, and a net payment in some amount to HFMC is possible. It is not possible to predict with certainty whether the Plan as filed will be approved or the amount of any such payment to HFMC. On July 18, 1996, an individual filed a lawsuit in the U.S. District Court for the District of Columbia against 70 natural gas pipelines and other gas purchasers or former gas purchasers. All of Williams' natural gas pipeline subsidiaries were named as defendants in the lawsuit. The plaintiff claimed, on behalf of the United States under the False Claims Act, that the pipelines had incorrectly measured the heating value or volume of gas purchased by the defendants. The plaintiff claimed that the United States had lost royalty payments as a result of these practices. The court recently dismissed the claims against Williams' natural gas pipelines and most of the other defendants. 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. 9. Adoption of accounting standards The Financial Accounting Standards Board has issued two new accounting standards, FAS No. 130, "Reporting Comprehensive Income," and FAS No. 131, "Disclosure about Segments of an Enterprise and Related Information," effective for fiscal years beginning after December 15, 1997. The disclosure requirements will not impact Williams' results of operations or financial position. Williams has not yet determined if it will adopt either standard early. The Financial Accounting Standards Board has issued FAS No. 128, "Earnings per Share," effective for fiscal years ending after December 15, 1997. Earnings per share calculated under this standard would not differ significantly from amounts reported in the Consolidated Statement of Income. 10. Subsequent event In August 1997, Williams called for the redemption in September 1997 of its 9.6 percent debentures and $2.21 cumulative preferred stock with a total carrying value of $91 million. 9

11 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Second Quarter 1997 vs. Second Quarter 1996 NORTHWEST PIPELINE'S revenues decreased $2.8 million, or 4 percent, due primarily to the net unfavorable effect of adjustments to rate refund accruals in both 1997 and 1996, partially offset by new transportation rates effective March 1, 1997. Total throughput decreased 28 TBtu, or 14 percent. Operating profit decreased $4.8 million, or 14 percent, due primarily to the net unfavorable effect of adjustments to rate refund accruals, partially offset by lower operating and maintenance expenses. WILLIAMS NATURAL GAS' revenues decreased $4.3 million, or 9 percent, and costs and operating expenses decreased $4 million, or 16 percent, due primarily to a lower level of gas supply realignment cost recovery. Total throughput decreased 6.3 TBtu, or 10 percent, due primarily to lower firm transportation volumes. Operating profit increased $2 million, or 22 percent, due primarily to lower operation and maintenance expenses, lower general and administrative expenses and an increase in firm reserved capacity. TRANSCONTINENTAL GAS PIPE LINE'S revenues decreased slightly as increased transportation revenues resulting from the effects of a mainline expansion placed in service in late 1996 and new rates effective May 1, 1997 which reflect other capital projects placed into service was more than offset by lower pass-through to customers of costs charged to Transco as provided in Transco's rates. Costs and operating expenses decreased $7.4 million, or 6 percent, due primarily to $5 million of lower costs charged to Transco by others and passed through to customers as provided in Transco's rates and lower operation and maintenance expenses. Total throughput increased 14 TBtu, or 4 percent, due primarily to higher firm long-haul transportation volumes. Operating profit increased $9.9 million, or 24 percent, due primarily to higher transportation revenues resulting from the effects of the mainline expansion and the new rates effective May 1, 1997, in addition to lower operation 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. TEXAS GAS TRANSMISSION'S revenues decreased $3 million, or 5 percent, due primarily to lower costs passed through to customers as provided in Texas Gas' rates, a change in mix of transportation volumes under different rate structures and lower other revenues. Total throughput increased 13.1 TBtu, or 8 percent. Operating profit decreased $3.4 million, or 29 percent, due primarily to a favorable adjustment to rate refund accruals in 1996, a change in mix of transportation volumes under different rate structures and lower other revenues. Texas Gas typically experiences lower operating profit in the second and third quarters as compared to the first and fourth quarters. KERN RIVER GAS TRANSMISSION'S (KERN RIVER) revenues increased $5.5 million, or 15 percent, due primarily to a 1996 adjustment (not impacting operating profit) related to first-quarter 1996 and higher interruptible transportation revenues. Total throughput increased slightly over 1996 levels. Operating profit increased $3.5 million, or 13 percent, due primarily to lower general and administrative expenses and higher interruptible transportation revenues. FIELD SERVICES' revenues increased $20.1 million, or 13 percent, due primarily to higher natural gas liquids sales of $11 million resulting from a 31 percent increase in volumes, the passthrough of $7 million higher operating costs to customers, and a 12 percent increase in processing volumes. Costs and operating expenses increased $15 million, or 15 percent, due primarily to increased fuel and replacement gas purchases and higher operating costs passed through to customers. Operating profit increased $4.1 million, or 11 percent, due primarily to a $2 million business interruption insurance estimate adjustment and increased processing volumes. MERCHANT SERVICES' revenues decreased $36.2 million, or 66 percent, and costs and operating expenses decreased $29 million, or 100 percent, due primarily to the 1997 reporting on a net margin basis of certain natural gas and gas liquids marketing operations previously reported in Field Services (see 10

12 Note 2). In addition, revenues decreased due to lower price-risk management revenues and physical trading margins as a result of decreased price volatility. Partially offsetting this decrease were increased natural gas and liquid petroleum physical trading volumes. Operating profit decreased $10.6 million, or 67 percent, due primarily to the decrease in net revenues and the expense of expansion of business growth platforms. PETROLEUM SERVICES' revenues increased $6 million, or 5 percent, due primarily to a $7 million increase in product sales associated with transportation activities. A 3 percent increase in shipments was more than offset by lower average transportation rates. Costs and operating expenses increased $7 million, or 8 percent, due primarily to the increase in product sales. Operating profit decreased $3.7 million, or 15 percent, due primarily to the impact of a $2 million favorable insurance settlement in 1996 and lower ethanol sales. Ethanol operations generated an operating loss of $200,000 in the second quarter of 1997 as compared to a $1.6 million operating profit in 1996. EXPLORATION & PRODUCTION'S revenues increased $11.1 million, or 83 percent, due primarily to higher average natural gas sales prices for company-owned production and from the marketing of Williams Coal Seam Gas Royalty Trust (Royalty Trust) natural gas, and a 28 percent increase in company-owned production volumes, slightly offset by a decrease in Royalty Trust marketing volumes. Costs and operating expenses increased $6 million, or 50 percent, due primarily to higher operating expenses associated with increased production activities and increased taxes other than income. Operating profit increased $4.9 million from a $800,000 loss in 1996 due primarily to the increase in average natural gas prices and company-owned production volumes sold, partially offset by higher operating expenses and dry hole costs. WILLIAMS COMMUNICATIONS GROUP'S revenues increased $197.6 million, or 122 percent, to $359.1 million due primarily to acquisitions which contributed revenues of approximately $160 million, including $125 million from the acquisition of the customer premise equipment sales and services operations of Northern Telecom (Nortel). Additionally, increased business activity in the customer premise equipment sales and service operations resulted in a $17 million revenue increase in new systems sales and a $13 million increase in existing system enhancement revenues. The number of ports in service at June 30, 1997, more than doubled as compared to June 30, 1996, due primarily to the acquisition of Nortel. Fiber billable minutes from occasional service increased 81 percent. Dedicated service voice-grade equivalent miles at June 30, 1997, increased 46 percent as compared with June 30, 1996. Costs and operating expenses increased $146 million, or 118 percent, and selling, general and administrative expenses increased $51 million, or 140 percent, due primarily to the acquired operations, the overall increase in business activity and higher expenses for developing advanced network applications. The increase in selling, general and administrative expenses also reflects the commitment by management to expand the infrastructure of this business for future growth. Operating profit increased $2.2 million from $1.1 million in 1996, due primarily to acquisition growth, partially offset by costs of expanding the infrastructure. GENERAL CORPORATE EXPENSES increased $4.5 million, or 62 percent, due primarily to higher professional fees and employee compensation expense, including amounts attributable to ongoing efforts to identify and implement "best practices" and optimize performance across the company. Interest accrued increased $11.1 million, or 12 percent, due primarily to higher borrowing levels under the $1 billion bank-credit facility. Interest capitalized increased $3.3 million, from $600,000 in 1996, due primarily to capital expenditures for Williams Communications Group's fiber-optic network. For information concerning the 1997 gain on sale of interest in subsidiary see Note 4. The minority interest in income of consolidated subsidiaries is related primarily to the 30 percent interest held by WilTel Communications, LLC's minority shareholders (see Note 4). 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 4) and income tax credits from coal- seam gas production, partially offset by the effects of state income taxes. The effective income tax rate in 1996 is less than the federal statutory rate due primarily to income tax credits from coal-seam gas production, partially offset by the effects of state income taxes. In addition, 1996 includes recognition of favorable adjustments totaling $10 million related to research credits and previously provided deferred income taxes on certain regulated capital projects. Six Months Ended June 30, 1997 vs. Six Months Ended June 30, 1996 NORTHWEST PIPELINE'S revenues decreased $3.2 million, or 2 percent, due primarily to net unfavorable effect of adjustments to rate refund accruals in both 1997 and 1996, partially offset by new transportation rates that became effective March 1, 1997. Total throughput decreased 64.9 TBtu, or 15 percent. Operating profit decreased $7.8 million, or 12 percent, due primarily to the net unfavorable effect of adjustments to rate refund accruals and the impact of the sale of the south-end facilities not reflected in rates until March 1, 1997, partially offset by lower operation and maintenance expenses. WILLIAMS NATURAL GAS' revenues decreased $600,000, or 1 percent. Total throughput decreased 14.4 TBtu, or 8 percent, due primarily to lower interruptible and firm transportation volumes. Other income includes a $7 million gain from the sale-in-place of natural gas from a decommissioned storage field. Operating profit increased $10.3 million, or 47 percent, due primarily to the gain on sale-in-place of natural gas, lower operation and maintenance expenses, lower general and administrative expenses and an increase in firm reserved capacity. TRANSCONTINENTAL GAS PIPE LINE'S revenues decreased $13.4 million, or 3 percent, due primarily to $19 million of lower costs charged to Transco by others and passed through to customers as provided in Transco's rates, partially offset by higher transportation revenues resulting from the effects of a mainline expansion placed into service in late 1996 and new rates effective May 1, 1997, reflecting other capital projects placed into service. Total throughput decreased 28.9 TBtu, or 4 percent, due primarily to lower firm long-haul transportation volumes. Costs and operating expenses decreased $23.1 million, or 10 percent, due primarily to $19 million of lower costs charged to Transco by others and passed through to 11

13 customers as provided in Transco's rates and lower operation and maintenance expenses. Operating profit increased $15.8 million, or 17 percent, due primarily to lower operation and maintenance expenses, the effects of the mainline expansion, the new rates effective May 1, 1997, and lower general and administrative 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. TEXAS GAS TRANSMISSION'S revenues decreased $8.4 million, or 5 percent, and costs and operating expenses decreased $5 million, or 6 percent, due primarily to lower costs passed through to customers as provided in Texas Gas' rates. Total throughput decreased 11.8 TBtu, or 3 percent. Operating profit decreased $1.1 million, or 2 percent, due primarily to favorable 1996 adjustments to rate refund accruals and a change in mix of transportation volumes under different rate structures, largely offset by 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. KERN RIVER'S revenues increased $6.3 million, or 8 percent, due primarily to a full six months of operations in 1997 compared to a partial six months in 1996 and increased interruptible sales during 1997. Results for 1996 reflect operations from January 16, 1996, when Williams acquired the remaining interest in Kern River. Total throughput increased 8.2 TBtu, or 6 percent, due primarily to the full six months of operations in 1997. Operating profit increased $6.9 million, or 13 percent, due primarily to the full six months of operations in 1997 and higher interruptible sales during 1997. FIELD SERVICES' revenues increased $39.6 million, or 13 percent, due primarily to higher natural gas liquids sales revenue of $31 million, the passthrough of $12 million higher operating costs to customers and higher condensate revenues of $8 million, partially offset by a lower average gathering rate in the Gulf-coast region and $7 million lower revenues associated with a 4 percent decrease in gathering volumes. Natural gas liquids sales revenues increased due to a 29 percent increase in volumes combined with an increase in average natural gas liquids prices. Costs and operating expenses increased $39 million, or 20 percent, due primarily to higher fuel and replacement gas purchases and higher operating costs passed through to customers. Other income--net in 1996 includes a $3 million environmental remediation accrual. Operating profit increased $3.4 million, or 4 percent, due primarily to increased natural gas liquids volumes, lower depreciation and amortization, $3 million higher processing revenue, the effect of the 1996 environmental remediation accrual and a $2 million business interruption insurance estimate adjustment in 1997. Substantially offsetting these were lower gathering volumes and average rates and higher gathering fuel and replacement gas purchase costs. MERCHANT SERVICES' revenues decreased $65.9 million, or 53 percent, and costs and operating expenses decreased $57 million, or 85 percent, due primarily to the 1997 reporting on a net margin basis of certain natural gas and gas liquids marketing operations previously reported in Field Services (see Note 2). In addition, revenues decreased due to lower physical trading margins as a result of decreased price volatility, slightly offset by higher price-risk management revenues and increased natural gas trading volumes. Operating profit decreased $15.9 million, or 42 percent, due primarily to the decrease in net revenues and the expense of expansion of business growth platforms. PETROLEUM SERVICES' revenues increased $15.6 million, or 6 percent, due primarily to a $19 million increase in product sales from transportation activities, partially offset by a decrease in average transportation rates. Costs and operating expenses increased $19 million, or 10 percent, due primarily to the increase in product sales. Operating profit decreased $7.1 million, or 16 percent, due primarily to lower average transportation rates, higher operating expenses within the products pipeline business and the impact of a $2 million favorable insurance settlement in 1996.

14 EXPLORATION & PRODUCTION'S revenues increased $29 million, or 87 percent, due primarily to higher average natural gas sales prices for company-owned production and from the marketing of Royalty Trust natural gas and a 14 percent increase in company-owned production volumes. Costs and operating expenses increased $16 million, or 53 percent, due primarily to increased Royalty Trust natural gas purchase prices, higher operating expenses associated with increased production activities and increased taxes other than income. Operating profit increased $14.9 million, from a $200,000 loss in 1996, due primarily to the increase in average natural gas prices and company-owned production volumes sold, partially offset by higher operating expenses and dry hole costs. WILLIAMS COMMUNICATIONS GROUP'S revenues increased $273.6 million, or 91 percent, to $575.7 million due primarily to acquisitions which contributed revenues of approximately $200 million, including $125 million from the acquisition of the customer premise equipment sales and service operations of Nortel. Additionally, increased business activity in the customer premise equipment sales and service operations resulted in a $38 million revenue increase in new systems sales and a $21 million increase in existing system enhancement revenues. The number of ports in service at June 30, 1997, more than doubled as compared to June 30, 1996, due primarily to the acquisition of Nortel. Fiber billable minutes from occasional service increased 81 percent. Dedicated service voice-grade equivalent miles at June 30, 1997, increased 46 percent as compared with June 30, 1996. Costs and operating expenses increased $202 million, or 88 percent, and selling, general and administrative expenses increased $75 million, or 110 percent, due primarily to the acquired operations, the overall increase in business activity and higher expenses for developing advanced network applications. The increase in selling, general and administrative expenses also reflects the commitment by management to expand the infrastructure of this business for future growth. Operating profit decreased $2.6 million, or 67 percent, to $1.3 million due primarily to the expense of developing the infrastructure and integrating the most recent acquisitions. INTEREST ACCRUED increased $26.1 million, or 15 percent, due primarily to higher borrowing levels under the $1 billion bank-credit facility, partially offset by lower average interest rates. Interest capitalized increased $3.7 million, or 155 percent, due primarily to capital expenditures for Williams Communications Group's fiber-optic network. For information concerning the 1997 gain on sale of interest in subsidiary see Note 4. The minority interest in income of consolidated subsidiaries is related primarily to the 30 percent interest held by WilTel Communications, LLC's minority shareholders (see 12

15 Note 4). 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 4) and income tax credits from coal-seam gas production, partially offset by the effects of state income taxes. The effective tax rate in 1996 is less than the federal statutory rate due primarily to income tax credits from coal-seam gas production, partially offset by the effects of state income taxes. In addition, 1996 includes recognition of favorable adjustments totaling $10 million related to research credits and previously provided deferred income taxes on certain regulated capital projects. 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, which can be utilized without limitation under existing loan covenants. At June 30, 1997, Williams had access to $261 million of liquidity representing the available portion of its $1 billion bank-credit facility plus cash-equivalent investments. This compares with liquidity of $550 million at December 31, 1996, and $334 million at June 30, 1996. The decrease in 1997 is due to additional borrowings under the bank-credit facility. At June 30, 1997, $219 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 with the remaining amount available under the $1 billion bank-credit facility. In July 1997, Williams Holdings of Delaware, Inc. (Williams Holdings), a wholly-owned subsidiary of Williams, finalized a commercial paper program backed by a new $500 million short-term bank-credit facility and issued $250 million of commercial paper under the program. The proceeds were used for working capital requirements and general corporate purposes. In 1997, capital expenditures are estimated to be approximately $1.5 billion. During 1997, Williams expects to finance capital expenditures, investments and working-capital requirements through cash generated from operations, the use of the available portion of its $1 billion bank-credit facility, commercial paper, short-term uncommitted bank lines and/or public debt/equity offerings. Financing Activities In January 1997, Williams expanded its revolving receivables facility and sold $200 million of receivables. The proceeds were used primarily for the repayment of long-term debt. In January 1997, Williams filed a $200 million shelf registration statement with the Securities and Exchange Commission to issue trust preferred securities. In May 1997, Transcontinental Gas Pipe Line Corporation, a wholly-owned subsidiary of Williams, filed a $300 million shelf registration statement with the Securities and Exchange Commission to issue debt securities. No securities have been issued under these two registration statements. In April 1997, Williams Holdings filed a $350 million shelf registration with the Securities and Exchange Commission to issue debt securities or preferred stock. In June 1997, $180 million of medium terms notes were issued under this registration statement. In May 1997, Texas Gas Transmission Corporation, a wholly-owned subsidiary of Williams, filed a $200 million shelf registration with the Securities and Exchange Commission to issue debt securities. In July 1997, $100 million of 7.25 percent debentures due 2027, were issued under this registration statement. The proceeds were used to repay $100 million of 9.625 percent notes which matured in July 1997. In June 1997, $205 million of short-term notes payable were repaid with borrowings under the $1 billion bank-credit facility. In July 1997, Transcontinental Gas Pipe Line entered into a $150 million five-year bank term loan agreement. The proceeds will be used for general corporate purposes. The consolidated long-term debt to debt-plus-equity ratio increased to 56.5 percent at June 30, 1997, from 56.1 percent at December 31, 1996. Investing Activities On April 30, 1997, Williams and Northern Telecom (Nortel) combined their customer premise equipment sales and service operations into a limited liability company, WilTel Communications, 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. Williams recorded the 30 percent reduction in its operations contributed to the LLC as a sale to the minority shareholders of the LLC. (See Note 4). During the second quarter of 1997, Williams sold interests in certain coal-seam natural gas properties for $56 million in cash. During the first quarter of 1997, Williams purchased a 20 percent interest in a foreign telecommunications business for $65 million in cash. Other The decrease in receivables from December 31, 1996, is due primarily to an increase in the level of receivables sold and lower natural gas sales prices, partially offset by receivables acquired in the Nortel business combination (see Note 4). The decrease in accounts payable is due primarily to lower natural gas purchase prices. Subsequent Events In August 1997, Williams called for the redemption in September 1997 of its 9.6 percent debentures and $2.21 cumulative preferred stock with a total carrying value of $91 million. 13

16 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 15, 1997. At the Annual Meeting, three individuals were elected as directors of the Company and one director retired from the Board. Nine individuals continue to serve as directors pursuant to their prior election. In addition, the amendment to the Company's Restated Certificate of Incorporation, as amended, was approved, and the appointment of Ernst & Young LLP as the independent auditor of the Company for 1997 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 - ---------------- ----------- --------- Keith E. Bailey 135,573,045 1,259,464 W. R. Howell 135,547,786 1,284,723 James C. Lewis 135,580,924 1,251,585 Approval of Amendment to Restated Certificate of Incorporation: For Against Abstain - ------------ ------- ------- 120,737,443 15,278,816 816,250 Ratification of Appointment of Independent Auditor: For Against Abstain - ------------ ------- ------- 135,424,468 560,722 847,319 Item 6. Exhibits and Reports on Form 8-K (a) The exhibits listed below are filed as part of this report: Exhibit 11--Computation of Earnings Per Common and Common- equivalent Share Exhibit 12--Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements Exhibit 27--Financial Data Schedule (b) During the second quarter of 1997, the Company did not file a Form 8-K. 14

17 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, 1997

18 INDEX TO EXHIBITS EXHIBIT NUMBER EXHIBIT - ------ ------- 11 Computation of Earnings Per Common and Common-equivalent Share 12 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements 27 Financial Data Schedule

1 Exhibit 11 The Williams Companies, Inc. Computation of Earnings Per Common and Common-Equivalent Share (Thousands, except per-share amounts) ----------------------------------------------- Three months ended Six months ended June 30, June 30, ----------------------------------------------- 1997 1996 1997 1996 ----------------------------------------------- Primary earnings: Net income $107,800 $ 80,400 $213,700 $185,300 Preferred stock dividends: $2.21 cumulative preferred stock 400 400 800 800 $3.50 cumulative convertible preferred stock 2,200 2,200 4,400 4,400 ----------------------------------------------- Income applicable to common stock $105,200 $ 77,800 $208,500 $180,100 =============================================== Primary shares: Average number of common shares outstanding during the period 158,630 157,290 158,269 156,901 Common-equivalent shares attributable to options and deferred stock 4,081 5,082 4,111 5,105 ----------------------------------------------- Total common and common-equivalent shares 162,711 162,372 162,380 162,006 =============================================== Primary earnings per common and common-equivalent share $ .65 $ .48 $ 1.28 $ 1.11 Fully diluted earnings: Net income $107,800 $ 80,400 $213,700 $185,300 $2.21 cumulative preferred stock dividends 400 400 800 800 ----------------------------------------------- Income applicable to common stock $107,400 $ 80,000 $212,900 $184,500 =============================================== Fully diluted shares: Average number of common shares outstanding during the period 158,630 157,290 158,269 156,901 Common-equivalent shares attributable to options and deferred stock 4,081 5,082 4,363 5,289 Dilutive preferred shares 5,858 5,859 5,859 5,859 ----------------------------------------------- Total common and common-equivalent shares 168,569 168,231 168,491 168,049 =============================================== Fully diluted earnings per common and common-equivalent share $ .64 $ .47 $ 1.26 $ 1.10

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, 1997 ------------------ Earnings: Income before income taxes ................................... $ 305.9 Add: Interest expense - net .................................... 192.1 Rental expense representative of interest factor .......... 15.7 Other ..................................................... 1.1 --------- Total earnings as adjusted plus fixed charges .......... $ 514.8 ========= Fixed charges and preferred stock dividend requirements: Interest expense - net ....................................... $ 192.1 Capitalized interest ......................................... 6.1 Rental expense representative of interest factor ............. 15.7 Pretax effect of dividends on preferred stock of the Company ............................................... 8.5 --------- Combined fixed charges and preferred stock dividend requirements ......................................... $ 222.4 ========= Ratio of earnings to combined fixed charges and preferred stock dividend requirements ........................ 2.31 =========

5 1,000 6-MOS DEC-31-1997 JAN-01-1997 JUN-30-1997 143,568 0 860,590 (9,708) 271,461 1,704,079 11,626,591 (2,036,681) 12,748,398 1,920,271 4,656,085 0 161,035 161,318 3,264,989 12,748,398 0 2,021,989 0 1,206,398 0 (2,230) 198,197 305,902 92,218 213,684 0 0 0 213,684 1.28 1.26