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 March 31, 1999 ------------------------------------------------- OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ---------------------- ------------------------- Commission file number 1-4174 ---------------------------------------------------------- THE WILLIAMS COMPANIES, INC. - -------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) DELAWARE 73-0569878 - ------------------------------- ------------------------------------- (State of Incorporation) (IRS Employer Identification Number) ONE WILLIAMS CENTER TULSA, OKLAHOMA 74172 - --------------------------------------- ------------------------------------- (Address of principal executive office) (Zip Code) Registrant's telephone number: (918) 573-2000 -------------------------------------------------- NO CHANGE - -------------------------------------------------------------------------------- Former name, former address and former fiscal year, if changed since last report. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date. Class Outstanding at April 30, 1999 - -------------------------- ----------------------------- Common Stock, $1 par value 432,385,894 Shares

2 The Williams Companies, Inc. Index Part I. Financial Information Page Item 1. Financial Statements Consolidated Statement of Income--Three Months Ended March 31, 1999 and 1998 2 Consolidated Balance Sheet--March 31, 1999 and December 31, 1998 3 Consolidated Statement of Cash Flows--Three Months Ended March 31, 1999 and 1998 4 Notes to Consolidated Financial Statements 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 14 Item 3. Quantitative and Qualitative Disclosures about Market Risk 20 Part II. Other Information 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 Certain matters discussed in this report, excluding historical information, include forward-looking statements. Although The Williams Companies, Inc. believes such forward-looking statements are based on reasonable assumptions, no assurance can be given that every objective will be achieved. Such statements are made in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. Additional information about issues that could lead to material changes in performance is contained in The Williams Companies, Inc.'s 1998 Form 10-K. 1

3 The Williams Companies, Inc. Consolidated Statement of Income (Unaudited) (Dollars in millions, except per-share amounts) Three months ended March 31, --------------------------------------------- --------------------------- 1999 1998* ----------- ----------- Revenues (Note 14): Gas Pipeline $ 466.9 $ 442.2 Energy Services (Note 2) 1,253.1 1,304.2 Communications 506.0 398.4 Other 6.2 13.7 Intercompany eliminations (248.2) (199.7) ----------- ----------- Total revenues 1,984.0 1,958.8 ----------- ----------- Segment costs and expenses: Costs and operating expenses 1,442.6 1,423.1 Selling, general and administrative expenses 304.7 235.6 Other (income) expense--net (Note 3) (2.5) 31.9 ----------- ----------- Total segment costs and expenses 1,744.8 1,690.6 ----------- ----------- General corporate expenses 16.9 40.8 ----------- ----------- Operating income (loss) (Note 14): Gas Pipeline 186.8 195.0 Energy Services (Note 3) 120.9 91.8 Communications (51.5) (21.6) Other (17.0) 3.0 General corporate expenses (Note 3) (16.9) (40.8) ----------- ----------- Total operating income 222.3 227.4 Interest accrued (143.3) (118.0) Interest capitalized 9.4 8.2 Investing income 6.7 3.7 Minority interest in income of consolidated subsidiaries (.6) (2.3) Other income (expense)--net 1.3 (.6) ----------- ----------- Income before income taxes, extraordinary loss and change in accounting principle 95.8 118.4 Provision for income taxes (Note 4) 39.9 45.5 ----------- ----------- Income before extraordinary loss and change in accounting principle 55.9 72.9 Extraordinary loss (Note 5) -- (4.8) ----------- ----------- Income before change in accounting principle 55.9 68.1 Change in accounting principle (Note 6) (5.6) -- ----------- ----------- Net income 50.3 68.1 Preferred stock dividends 1.6 2.2 ----------- ----------- Income applicable to common stock $ 48.7 $ 65.9 =========== =========== Basic and diluted earnings per common share (Note 7): Income before extraordinary loss and change in accounting principle $ .12 $ .17 Extraordinary loss (Note 5) -- (.01) ----------- ----------- Income before change in accounting principle .12 .16 Change in accounting principle (Note 6) (.01) -- ----------- ----------- Net income $ .11 $ .16 =========== =========== Basic average shares (thousands) 432,091 417,347 Diluted average shares (thousands) 437,000 439,031 Cash dividends per common share $ .15 $ .15 * Certain amounts have been reclassified as described in Note 2 of Notes to Consolidated Financial Statements. See accompanying notes. 2

4 The Williams Companies, Inc. Consolidated Balance Sheet (Unaudited) (Dollars in millions, except per-share amounts) March 31, December 31, --------------------------------------------- 1999 1998 ------------ ------------ ASSETS Current assets: Cash and cash equivalents $ 330.1 $ 503.3 Receivables 1,579.9 1,628.2 Transportation and exchange gas receivable 74.5 96.4 Inventories (Note 8) 533.9 497.5 Energy trading assets 323.6 354.5 Deferred income taxes 235.6 239.9 Other 228.2 212.3 ------------ ------------ Total current assets 3,305.8 3,532.1 Investments 1,284.2 866.1 Property, plant and equipment, at cost 16,614.7 16,225.6 Less accumulated depreciation and depletion (3,704.2) (3,621.0) ------------ ------------ 12,910.5 12,604.6 Goodwill and other intangible assets--net 635.0 583.6 Other assets and deferred charges 1,036.7 1,060.9 ------------ ------------ Total assets $ 19,172.2 $ 18,647.3 ============ ============ LIABILITIES AND STOCKHOLDERS EQUITY Current liabilities: Notes payable (Note 10) $ 1,683.8 $ 1,052.7 Accounts payable 978.3 1,158.2 Accrued liabilities 1,335.8 1,547.6 Energy trading liabilities 243.0 290.1 Long-term debt due within one year (Note 10) 691.8 390.6 ------------ ------------ Total current liabilities 4,932.7 4,439.2 Long-term debt (Note 10) 6,192.4 6,366.4 Deferred income taxes 2,132.1 2,060.8 Other liabilities and deferred income 1,080.0 1,015.2 Minority interest in consolidated subsidiaries 504.5 508.3 Contingent liabilities and commitments (Note 11) Stockholders' equity: Preferred stock, $1 par value, 30 million shares authorized, 1.4 million issued in 1999, 1.8 million in 1998 79.7 102.2 Common stock, $1 par value, 960 million shares authorized, 435.7 million issued in 1999, 432.3 million in 1998 435.7 432.3 Capital in excess of par value 1,037.8 982.4 Retained earnings 2,833.5 2,849.5 Accumulated other comprehensive income 68.4 16.7 Other (79.5) (78.5) ------------ ------------ 4,375.6 4,304.6 Less treasury stock (at cost), 3.8 million shares of common stock in 1999 and 4.0 million in 1998 (45.1) (47.2) ------------ ------------ Total stockholders' equity 4,330.5 4,257.4 ------------ ------------ Total liabilities and stockholders' equity $ 19,172.2 $ 18,647.3 ============ ============ See accompanying notes. 3

5 The Williams Companies, Inc. Consolidated Statement of Cash Flows (Unaudited) (Millions) Three months ended March 31, --------- ---------------------------- 1999 1998 ------------ ------------ OPERATING ACTIVITIES: Net income $ 50.3 $ 68.1 Adjustments to reconcile to cash provided from operations: Extraordinary loss -- 4.8 Change in accounting principle 5.6 -- Depreciation, depletion and amortization 172.9 155.3 Provision for deferred income taxes 27.9 37.8 Minority interest in income of consolidated subsidiaries .6 2.3 Cash provided (used) by changes in assets and liabilities: Receivables sold 16.0 (17.2) Receivables 16.0 280.8 Inventories (19.4) 12.6 Other current assets (29.6) 6.1 Accounts payable (104.8) (275.6) Accrued liabilities (226.5) (53.7) Changes in current energy trading assets and liabilities (16.0) (.4) Changes in non-current energy trading assets and liabilities 4.2 (2.4) Changes in non-current deferred income 116.5 5.2 Other, including changes in non-current assets and liabilities 22.9 (12.5) ------------ ------------ Net cash provided by operating activities 36.6 211.2 ------------ ------------ FINANCING ACTIVITIES: Proceeds from notes payable 681.6 354.7 Payments of notes payable (54.8) (646.2) Proceeds from long-term debt 727.8 1,450.1 Payments of long-term debt (598.9) (926.7) Proceeds from issuance of common stock 82.1 41.6 Dividends paid (66.3) (64.6) Other--net 4.8 20.0 ------------ ------------ Net cash provided by financing activities 776.3 228.9 ------------ ------------ INVESTING ACTIVITIES: Property, plant and equipment: Capital expenditures (376.5) (374.9) Changes in accounts payable and accrued liabilities (92.4) (7.0) Acquisition of business, net of cash acquired (162.9) -- Purchase of investments/advances to affiliates (353.2) (14.8) Other--net (1.1) 7.7 ------------ ------------ Net cash used by investing activities (986.1) (389.0) ------------ ------------ Increase (decrease) in cash and cash equivalents (173.2) 51.1 Cash and cash equivalents at beginning of period 503.3 122.1 ------------ ------------ Cash and cash equivalents at end of period $ 330.1 $ 173.2 ============ ============ See accompanying notes. 4

6 The Williams Companies, Inc. Notes to Consolidated Financial Statements (Unaudited) 1. General The accompanying interim consolidated financial statements of The Williams Companies, Inc. (Williams) do not include all notes in annual financial statements and therefore should be read in conjunction with the consolidated financial statements and notes thereto in Williams' Annual Report on Form 10-K. The accompanying financial statements have not been audited by independent auditors, but include all adjustments both normal recurring and others which, in the opinion of Williams' management, are necessary to present fairly its financial position at March 31, 1999, and its results of operations and cash flows for the three months ended March 31, 1999 and 1998. Segment profit of operating companies may vary by quarter. Based on current rate structures and/or historical maintenance schedules of certain of its pipelines, Gas Pipeline experiences higher segment profits in the first and fourth quarters as compared to the second and third quarters. 2. Basis of presentation In the fourth-quarter 1998, Williams adopted Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information." Beginning January 1, 1999, Communications' Network Applications 1998 segment results have been restated to include the results of investments in certain Brazilian and Australian telecommunications projects, which had previously been reported in Other segment revenues and profit(loss). These investments, along with businesses previously reported as Network Applications and certain cost-basis investments previously reported in Network Services, are now collectively managed and reported under the name of Strategic Investments. Effective April 1, 1998, certain marketing activities were transferred from other Energy Services segments to Energy Marketing & Trading and combined with its energy risk trading operations. As a result, revenues and segment profit amounts prior to April 1, 1998, have been reclassified and reported within Energy Marketing & Trading. The income statement presentation relating to certain of these operations was changed effective April 1, 1998, on a prospective basis, to reflect these revenues net of the related costs to purchase such items. Activity prior to this date is reflected on a "gross" basis in the Consolidated Statement of Income. Concurrent with completing the combination of such activities with the energy risk trading operations of Energy Marketing & Trading, the related contract rights and obligations of certain of these operations are recorded in the Consolidated Balance Sheet at fair value consistent with Energy Marketing & Trading's accounting policy. Certain other income statement and segment asset amounts have been reclassified to conform to the current classifications. 3. Merger-related costs In connection with the March 28, 1998, acquisition of MAPCO Inc., Williams recognized approximately $59 million in merger-related costs comprised primarily of outside professional fees and early retirement and severance costs in the first quarter of 1998. Approximately $36 million of these merger-related costs is included in other (income) expense-net within segment costs and expenses and as a component of Energy Services' segment profit, and $23 million, unrelated to the segments, is included in general corporate expenses. 4. Provision for income taxes The provision for income taxes includes: Three months ended (Millions) March 31, ----------------------------- 1999 1998 ------------ ------------ Current: Federal $ 7.8 $ 5.6 State 3.3 1.5 Foreign .9 .6 ------------ ------------ 12.0 7.7 Deferred: Federal 23.1 32.9 State 4.8 4.9 ------------ ------------ 27.9 37.8 ------------ ------------ Total provision $ 39.9 $ 45.5 ============ ============ The effective income tax rate for 1999 and 1998 is greater than the federal statutory rate due primarily to the effects of state income taxes. 5. Extraordinary loss In 1998, Williams paid $54.4 million to redeem higher interest rate debt for a $4.8 million net loss (net of a $2.6 million benefit for income taxes). 5

7 Notes (Continued) 6. Change in accounting principle Effective January 1, 1999, Williams adopted Statement of Position (SOP) 98-5, "Reporting on the Costs of Start-Up Activities." The SOP requires that all start-up costs be expensed as incurred and the expense related to the initial application of this SOP of $5.6 million (net of a $3.6 million benefit for income taxes) is reported as the cumulative effect of a change in accounting principle. Additionally, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" which was adopted first-quarter 1999. The effect of initially applying the consensus at January 1, 1999, is immaterial to Williams' results of operations and financial position. 7. Earnings per share Basic and diluted earnings per common share are computed for the three months ended March 31, 1999 and 1998, as follows: (Dollars in millions, except per-share Three months ended amounts; shares in thousands) March 31, ------------------------- 1999 1998 ----------- ----------- Income before extraordinary loss and change in accounting principle $ 55.9 $ 72.9 Preferred stock dividends 1.6 2.2 ----------- ----------- Income before extraordinary loss and change in accounting principle available to common stockholders for basic earnings per share 54.3 70.7 Effect of dilutive securities: Convertible preferred stock dividends -- 2.2 ----------- ----------- Income before extraordinary loss and change in accounting principle available to common stockholders for diluted earnings per share $ 54.3 $ 72.9 =========== =========== Basic weighted-average shares 432,091 417,347 Effect of dilutive securities: Convertible preferred stock -- 11,147 Stock options 4,909 10,537 ----------- ----------- 4,909 21,684 ----------- ----------- Diluted weighted-average shares 437,000 439,031 =========== =========== Earnings per common share before extraordinary loss and change in accounting principle: Basic and diluted $ .12 $ .17 ----------- ----------- For 1999, approximately 7.7 million shares related to the assumed conversion of $3.50 convertible preferred stock have been excluded from the computation of diluted earnings per common share. Inclusion of these shares would be antidilutive. 8. Inventories March 31, December 31, (Millions) 1999 1998 ------------ ------------ Raw materials: Crude oil $ 56.5 $ 43.2 Other 1.7 2.0 ------------ ------------ 58.2 45.2 Finished goods: Refined products 187.6 104.0 Natural gas liquids 17.5 58.6 General merchandise and communications equipment 99.1 92.8 ------------ ------------ 304.2 255.4 Materials and supplies 96.2 93.4 Natural gas in underground storage 65.1 95.7 Other 10.2 7.8 ------------ ------------ $ 533.9 $ 497.5 ============ ============ 9. Investments At December 31, 1998, Williams had investments in certain Brazilian telecommunication ventures totaling approximately $211 million of which approximately $150 million were preferred stock interests. Effective January 1, 1999, Williams adopted the provisions of the consensus of Emerging Issues Task Force (EITF) Issue No. 98-13, "Accounting by an Equity Method Investor for Investee Losses When the Investor has Loans to and Investments in Other Securities of the Investee." Williams currently applies the equity method to investments in common stock and certain other investments in which Williams exercises significant influence. Previously, Williams also applied the equity method to investments in certain other equity securities of the investee when Williams also had an investment in the common stock of the investee. The impact of the change for the three months ended March 31, 1999, was to increase both income before extraordinary loss and change in accounting principle and net income by approximately $26 million, or $.06 per share. 10. Debt and banking arrangements NOTES PAYABLE During 1999, Williams Holdings of Delaware, Inc. (Williams Holdings) increased its commercial paper program to $1.4 billion, backed by a short-term bank-credit facility. At March 31, 1999, $1.4 billion of commercial paper was outstanding under the program. Interest rates vary with current market conditions. DEBT Williams also has a $1 billion credit agreement under which Northwest Pipeline, Transcontinental Gas Pipe Line, Texas Gas Transmission, Williams Communications Solutions, LLC and Williams Communications Group, Inc. have access to varying amounts of the facility, while Williams and Williams Holdings have access to all unborrowed amounts. Interest rates vary with current market conditions. 6

8 NOTES (CONTINUED) Debt Weighted- average interest March 31, December 31, (Millions) rate* 1999 1998 ------------ ------------ ------------ Revolving credit loans 6.7% $ 645.0 $ 694.0 Debentures, 6.25% - 7.7%, payable 2001 - 2027 (1) 6.4 935.4 935.4 Debentures, 8.875% - 10.25%, payable 2003 - 2022 8.3 169.7 169.7 Notes, 5.1% - 7.6%, payable through 2012 (2) 6.3 3,850.1 3,871.6 Notes, 8.2% - 9.625%, payable through 2022 8.8 690.1 691.0 Notes, adjustable rate, payable through 2004 6.1 585.0 386.7 Other, payable through 2005 8.5 8.9 8.6 ------------ ------------ ------------ 6,884.2 6,757.0 Current portion of long-term debt (691.8) (390.6) ------------ ------------ $ 6,192.4 $ 6,366.4 ============ ============ * At March 31, 1999, including the effects of interest-rate swaps. (1) $200 million, 7.08% debentures, payable 2026, are subject to redemption at par at the option of the debtholder in 2001. (2) $300 million, 5.95% notes, payable 2010, and $240 million, 6.125% notes, payable 2012, are subject to redemption at par at the option of the debtholder in 2000 and 2002, respectively. In April 1999, Williams' communications business entered into a $1.4 billion temporary short-term bank-credit facility, guaranteed by Williams. Communications expects to replace this facility with a permanent bank-credit facility in the second quarter of 1999. 11. 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 $249 million for potential refund as of March 31, 1999. In 1997, the Federal Energy Regulatory Commission (FERC) issued orders addressing, among other things, the authorized rates of return for three of the Williams interstate natural gas pipeline subsidiaries. All of the orders involve rate cases that became effective between 1993 and 1995 and, in each instance, these cases have been superseded by more recently filed rate cases. In the three orders, the FERC continued its practice of utilizing a methodology for calculating rates of return that incorporates a long-term growth rate component. However, the long-term growth rate component used by the FERC is now a projection of U.S. gross domestic product growth rates. Generally, calculating rates of return utilizing a methodology which includes a long-term growth rate component results in rates of return that are lower than they would be if the long-term growth rate component were not included in the methodology. Each of the three pipeline subsidiaries challenged its respective FERC order in an effort to have the FERC change its rate of return methodology with respect to these and other rate cases. In October 1997, the FERC voted not to reconsider an order issued in the first of the three pipeline proceedings, and the pipeline appealed the FERC's decision. On January 30, 1998, the FERC convened a public conference to consider, on an industry-wide basis, issues with respect to pipeline rates of return. In July 1998, the FERC issued orders in 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. Certain parties are appealing the FERC's action, because the most recent formula modification results in somewhat higher rates of return compared to the rates of return calculated under the FERC's prior formula. In March 1999, the FERC was granted a remand to reconsider whether the new methodology should be applied in the first proceeding. None of the three pipelines has made any changes to its accounting reserves pending resolution of the issues discussed above. In 1992, the FERC issued Order 636, Order 636-A and Order 636-B. These orders, which were challenged in various respects by various parties in proceedings ruled on by the U.S. Court of Appeals for the D.C. Circuit, required interstate gas pipeline companies to change the manner in which they provide services. Williams' gas pipelines subsidiaries implemented restructurings in 1993. The only appeal challenging Northwest Pipeline's restructuring has been dismissed. On April 14, 1998, all appeals concerning Transcontinental Gas Pipe Line's restructuring were denied by the D.C. Circuit. Williams Gas Pipelines Central's restructuring appeal was remanded to the FERC. The appeal of Texas Gas' restructuring remains pending. On February 27, 1997, the FERC issued Order No. 636-C in response to the D.C. Circuit's partial remand of the three previous 636 orders. In that order, the FERC reaffirmed that pipelines should be exempt from sharing gas supply realignment costs. Rehearing of Order 636-C was denied in Order 636-D. Orders 636-C and 636-D have been appealed. Recently, the FERC issued a Notice of Proposed Rulemaking (NOPR) and a Notice of Inquiry (NOI), proposing revisions to regulatory policies for interstate natural gas transportation service. In the NOPR, the FERC proposes to eliminate the rate cap on short-term transportation services and implement regulatory policies that are intended to maximize competition in the short-term transportation market, mitigate the ability of firms to exercise residual monopoly power and provide opportunities for greater flexibility in the provision of pipeline services and to revise certain other rate and certificate policies. In the NOI, the FERC seeks comments on its pricing policies in the existing long-term market and pricing policies for new capacity. The deadline for comments on the NOPR and NOI has been extended until the second quarter of 1999. 7

9 Notes (Continued) As a result of the Order 636 decisions described, each of the natural gas pipeline subsidiaries has undertaken the reformation or termination of its respective gas supply contracts. None of the pipelines has any significant pending supplier take-or-pay, ratable take or minimum take claims. Central is continuing efforts to recover certain gas supply realignment costs which arose from supplier take-or-pay contracts. Current FERC policy associated with Orders 436 and 500 requires interstate gas pipelines to absorb some of the cost of reforming gas supply contracts before allowing any recovery through direct bill or surcharges to transportation as well as sales commodity rates. Under Orders 636, 636-A, 636-B, 636-C and 636-D, costs incurred to comply with these rules are permitted to be recovered in full, although a percentage of such costs must be allocated to interruptible transportation service. Pursuant to a stipulation and agreement approved by the FERC, Williams Gas Pipelines Central (Central) has made 17 filings to recover take-or-pay and gas supply realignment costs of $201.3 million from its customers. An intervenor filed a protest seeking to have the FERC review the prudence of certain of the costs covered by these filings. On July 31, 1996, the administrative law judge issued an initial decision rejecting the intervenor's prudency challenge. On September 30, 1997, the FERC, by a two-to-one vote, reversed the administrative law judge's decision and determined that three contracts were imprudently entered into in 1982. Central filed for rehearing, and management has vigorously defended the prudency of these contracts. An intervenor also filed a protest seeking to have the FERC decide whether non-settlement costs are eligible for recovery under Order No. 636. In January 1997, the FERC held that none of the non-settlement costs and only 75 percent of settlement costs could be recovered by Central if the costs were not eligible for recovery under Order No. 636. This order was affirmed on rehearing in April 1997. On June 16, 1998, a FERC administrative law judge issued an initial decision finding that Central had not met all the tests necessary to show that these costs were eligible for recovery under Order No. 636. On July 20, 1998, Central filed exceptions to the administrative law judge's decision. On May 29, 1998, the FERC approved an Order which permitted Central to conduct a reverse auction of the gas purchase contracts which are the subject of the prudence challenges outlined above. No party bid less than the fixed maximum price in the approved auction and, as a result, the contracts were not assigned. In accordance with the FERC's Orders, on September 30, 1998, Central filed a request for authority to conduct a second reverse auction of the contracts. Under the approved reverse auction, Central was granted authority to assign the contracts to bidders at or below an aggregate reserve price of $112.6 million. If no unaffiliated bidders were willing to accept assignment on those terms, Central was authorized to assign the contracts to an affiliate or a third party and recover $112.6 million from its customers subject to the outcome of the prudence and eligibility cases described above. The FERC also approved an extension of the recovery mechanism for non-settlement costs through February 1, 1999. On January 21, 1999, Central assigned its obligations under the largest of the three contracts to an unaffiliated third party and paid the third party $100 million. Central also agreed to pay the third party a total of $18 million in installments over the next five years. Central received indemnities from the third party and a release of its obligations under the contract. No parties submitted bids at the second reverse auction, and in accordance with the tariff provisions for the reverse auction, Central assigned the two smaller contracts to an affiliate effective February 1, 1999. As a result of these assignments, Central has no remaining above-market price gas contracts. Central has filed with the FERC to recover all costs related to the three contracts. Central has been negotiating with the FERC and state regulators to resolve the amount of costs which are recoverable from its customers. As a result of these negotiations, Central expensed $58 million of costs previously expected to be recovered and capitalized as a regulatory asset in 1998. At March 31, 1999, Central had a $57.7 million regulatory asset representing an estimate of costs to be recovered in the future. On April 21, 1999, Central reached an agreement in principle with the FERC staff, the state commissions, and its customers on all issues related to recovery of Central's remaining take-or-pay and gas supply realignment costs. The settlement resolves all prudence, eligibility and absorption issues at a level materially consistent with Central's established reserves at March 31, 1999, and provides that Central would be allowed to recover the costs allocated to its customers by means of a direct bill to be paid, in some instances, over time. The agreement in principle is subject to complete documentation and FERC approval. In September 1995, Texas Gas received FERC approval of a settlement regarding Texas Gas' recovery of gas supply realignment costs. Through March 31, 1999, Texas Gas has paid approximately $76 million and expects to pay no more than $80 million for gas supply realignment costs, primarily as a result of contract terminations. Texas Gas has recovered approximately $66 million, plus interest, in gas supply realignment costs. 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 8

10 Notes (Continued) the FERC policy. While Williams believes that these accruals are adequate and the associated regulatory assets are appropriate, costs actually incurred and amounts actually recovered from customers will depend upon the outcome of various court and FERC proceedings, the success of settlement negotiations and various other factors, not all of which are presently foreseeable. On July 15, 1998, Williams Pipe Line (WPL) received an Order from the FERC which affirmed an administrative law judge's 1996 initial decision regarding rate-making proceedings for the period September 15, 1990, through May 1, 1992. The FERC has ruled that WPL did not meet its burden of establishing that its transportation rates in its 12 noncompetitive markets were just and reasonable for the period and has ordered refunds. WPL continues to believe it should prevail upon appeal regarding collected rates for that period. However, due to this FERC decision, WPL accrued $15.5 million, including interest, in the second quarter of 1998, for potential refunds to customers for the issues described above. Since May 1, 1992, WPL has collected and recognized as revenues $160 million in noncompetitive markets that are in excess of tariff rates previously approved by the FERC and that are subject to refund with interest. WPL believes that the tariff rates collected in these markets during this period will be justified in accordance with the FERC's cost-basis guidelines and will be making the appropriate filings with the FERC to support this position. 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 March 31, 1999, 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 March 31, 1999, Central had recorded a liability for approximately $12 million, representing the current estimate of future environmental cleanup costs to be incurred over the next six to ten years. The Midstream Gas & Liquids unit of Energy Services (WES) has recorded an aggregate liability of approximately $10 million, representing the current estimate of its future environmental and remediation costs, including approximately $5 million relating to former Central facilities. Texas Gas and Transcontinental Gas Pipe Line likewise had recorded liabilities for these costs which are included in the $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 petroleum products pipelines, retail petroleum, refining and propane marketing operations primarily related to soil and groundwater contamination. At March 31, 1999, WES and its subsidiaries had reserves, in addition to the reserves listed above, totaling approximately $31 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 March 31, 1999, WES and its subsidiaries had receivables totaling $14 million. In connection with the 1987 sale of the assets of Agrico Chemical Company, Williams agreed to indemnify the purchaser for environmental cleanup costs resulting from certain conditions at specified locations, to the extent such costs exceed a specified amount. At March 31, 1999, 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 affirmed the 9

11 Notes (Continued) dismissal and remanded the case to Colorado district court for action consistent with the appeals court's decision. Since June 1994, eight individual lawsuits were filed against Northwest Pipeline and others in U.S. district court in Colorado, making essentially the same claims. The district court stayed all of the cases involving Northwest Pipeline until the plaintiffs exhausted their remedies before the Southern Ute Indian Tribal Court. Some plaintiffs filed cases in the Tribal Court, but none named Northwest Pipeline as a defendant. The parties have now executed a settlement agreement which settles all Federal and Tribal cases. Other legal matters On April 7, 1992, a liquefied petroleum gas explosion occurred near an underground salt dome storage facility located near Brenham, Texas and owned by an affiliate of MAPCO Inc., Seminole Pipeline Company ("Seminole"). MAPCO Inc., as well as Seminole, Mid-America Pipeline Company, MAPCO Natural Gas Liquids Inc., and other non-MAPCO entities were named as defendants in civil action lawsuits filed in state district courts located in four Texas counties. Seminole and the above-mentioned subsidiaries of MAPCO Inc. have settled in excess of 1,600 claims in these lawsuits. As of January 1999, the only lawsuit not fully resolved was the Dallmeyer case which was tried before a jury in Harris County. In Dallmeyer, the judgment rendered in March 1996 against defendants Seminole and MAPCO Inc. and its subsidiaries totaled approximately $72 million which included nearly $65 million of punitive damages awarded to the 21 plaintiffs. Both plaintiffs and defendants have appealed the Dallmeyer judgment to the Court of Appeals for the Fourteenth District of Texas in Harris County. In February and March 1998, the defendants entered into settlement agreements involving 17 of the 21 plaintiffs to finally resolve their claims against all defendants for an aggregate payment of approximately $10 million. These settlements have satisfied and reduced the judgment on appeal by approximately $42 million as to the remaining four plaintiffs. The Court of Appeals issued its decision on October 15, 1998, which, while denying all of the plaintiffs' cross-appeal issues, affirmed in part and reversed in part the trial court's judgment. The defendants had entered into settlement agreements with the remaining plaintiffs which, in light of the decisions, provided for aggregate payments of approximately $13.6 million, the full amount of which has been previously accrued. The releases from the last remaining plaintiffs were received in February 1999. In 1991, the Southern Ute Indian Tribe (the Tribe) filed a lawsuit against Williams Production Company (Williams Production), a wholly owned subsidiary of Williams, and other gas producers in the San Juan Basin area, alleging that certain coal strata were reserved by the United States for the benefit of the Tribe and that the extraction of coal-seam gas from the coal strata was wrongful. The Tribe seeks compensation for the value of the coal-seam gas. The Tribe also seeks an order transferring to the Tribe ownership of all of the defendants' equipment and facilities utilized in the extraction of the coal-seam gas. In September 1994, the court granted summary judgment in favor of the defendants, and the Tribe lodged an interlocutory appeal with the U.S. Court of Appeals for the Tenth Circuit. Williams Production agreed to indemnify the Williams Coal Seam Gas Royalty Trust (Trust) against any losses that may arise in respect of certain properties subject to the lawsuit. On July 16, 1997, the U.S. Court of Appeals for the Tenth Circuit reversed the decision of the district court, held that the Tribe owns the coal-seam gas produced from certain coal strata on fee lands within the exterior boundaries of the Tribe's reservation, and remanded the case to the district court for further proceedings. On September 16, 1997, Amoco Production Company, the class representative for the defendant class (of which Williams Production is a part), filed its motion for rehearing en banc before the Court of Appeals. On July 20, 1998, the Court of Appeals sitting en banc affirmed the panel's decision. The Supreme Court granted a writ of certiorari in respect of this decision and heard oral arguments on April 19, 1999. Williams Production has entered into an agreement in principle to settle the Tribe's claims against Williams Production. 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 10

12 Notes (Continued) currently defending two lawsuits brought by producers. In one of the cases, a jury verdict found that Transcontinental Gas Pipe Line was required to pay a producer damages of $23.3 million including $3.8 million in attorneys' fees. Transcontinental Gas Pipe Line is pursuing an appeal. In the other case, a producer has asserted damages, including interest calculated through December 31, 1997, of approximately $6 million. Producers have received and may receive other demands, which could result in additional claims. Indemnification for royalties will depend on, among other things, the specific lease provisions between the producer and the lessor and the terms of the settlement between the producer and either Transcontinental Gas Pipe Line or Texas Gas. Texas Gas may file to recover 75 percent of any such additional amounts it may be required to pay pursuant to indemnities for royalties under the provisions of Order 528. In connection with the sale of certain coal assets in 1996, MAPCO entered into a Letter Agreement with the buyer providing for indemnification by MAPCO for reductions in the price or tonnage of coal delivered under a certain pre-existing Coal Sales Agreement dated December 1, 1986. The Letter Agreement is effective for reductions during the period July 1, 1996, through December 31, 2002, and provides for indemnification for such reductions as incurred on a quarterly basis. The buyer has stated it is entitled to indemnification from MAPCO for amounts of $7.8 million through June 30, 1998, and may claim indemnification for additional amounts in the future. MAPCO has filed for declaratory relief as to certain aspects of the buyer's claims. MAPCO also believes it would be entitled to substantial set-offs and credits against any amounts determined to be due and has accrued a liability representing an estimate of amounts it expects to incur in satisfaction of this indemnity. The parties are currently pursuing settlement negotiations as a part of a mediation. In 1998, the United States Department of Justice informed Williams that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly owned subsidiaries including Williams Gas Pipelines Central, Kern River Gas Transmission, Northwest Pipeline, Williams Gas Pipeline Company, Transcontinental Gas Pipe Line Corporation, Texas Gas, Williams Field Services Company and Williams Production Company. Mr. Grynberg has also filed claims against approximately 300 other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys' fees, and costs. On April 9, 1999, the United States Department of Justice announced that it was declining to intervene in any of the Grynberg qui tam cases, including the action filed against the Williams entities in the United States District Court for the District of Colorado. 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 1998, Energy Marketing & Trading entered into a 15-year contract giving Williams the right to receive fuel conversion and certain other services for purposes of generating electricity. Annual committed payments under this contract range from $140 million to $165 million, resulting in total committed payments of approximately $2.3 billion. During the first quarter of 1999, Energy Marketing & Trading entered into a similar contract with a 20 year term. Annual committed payments under this contract, which is scheduled to commence in mid-2001, range from $39 million to $55 million resulting in additional committed payments of approximately $950 million. 12. Adoption of accounting standards The Financial Accounting Standards Board has issued Statement on Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." This standard, effective for fiscal years beginning after June 15, 1999, requires that all derivatives be recognized as assets or liabilities in the balance sheet and that those instruments be measured at fair value. The effect of this standard on Williams' results of operations and financial position is still being evaluated. 13. Comprehensive income Comprehensive income for the three months ended March 31 is as follows: Three months ended (Millions) March 31, 1999 1998 ------------ ------------ Net income $ 50.3 $ 68.1 Other comprehensive income (loss): Unrealized gains on securities 120.6 13.3 Foreign currency translation adjustments (22.0) (2.1) ------------ ------------ Other comprehensive income before taxes 98.6 11.2 Income taxes on other comprehensive income 46.9 5.2 ------------ ------------ Comprehensive income $ 102.0 $ 74.1 ============ ============ 11

13 Notes (Continued) 14. Segment disclosures Williams evaluates performance based upon segment profit or loss from operations which includes revenues from external and internal customers, equity earnings, operating costs and expenses, and depreciation, depletion and amortization. Intersegment sales are generally accounted for as if the sales were to unaffiliated third parties, that is, at current market prices. Williams' reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different technology, marketing strategies and industry knowledge. Other includes investments in international energy and communications-related ventures, as well as corporate operations. The following table reflects the reconciliation of segment profit, per the table on page 13, to operating income as reported in the Consolidated Statement of Income for the three months ended March 31: (Millions) 1999 1998 ---------- ---------- Segment profit $ 239.2 $ 268.2 General corporate expenses (16.9) (40.8) ---------- ---------- Operating income $ 222.3 $ 227.4 ========== ========== The increase in Strategic Investments' total assets, as noted on the following page, is due primarily to the additional investments in a Brazilian telecommunications project and the increase in the carrying value of a marketable equity security. 12

14 Notes (Continued) 14. Segment disclosures (continued) Revenues ------------------------------------------------------------- External Inter- Equity Earnings Segment (Millions) Customers segment (Losses) Total Profit (Loss) ------------ ------------ ------------ ------------ ------------ FOR THE THREE MONTHS ENDED MARCH 31, 1999 GAS PIPELINE $ 452.3 $ 14.5 $ .1 $ 466.9 $ 186.8 ENERGY SERVICES Energy Marketing & Trading 515.6 (43.5)* (.1) 472.0 40.7 Exploration & Production 1.2 26.3 -- 27.5 4.7 Midstream Gas & Liquids 193.1 26.9 (2.3) 217.7 46.6 Petroleum Services 334.4 201.3 .2 535.9 33.0 Merger-related costs and non-compete amortization -- -- -- -- (4.1) ------------ ------------ ------------ ------------ ------------ 1,044.3 211.0 (2.2) 1,253.1 120.9 ------------ ------------ ------------ ------------ ------------ COMMUNICATIONS Communications Solutions 337.3 -- -- 337.3 (8.8) Network Services 95.8 12.7 -- 108.5 (17.2) Strategic Investments 68.1 .2 (8.1) 60.2 (25.5) ------------ ------------ ------------ ------------ ------------ 501.2 12.9 (8.1) 506.0 (51.5) ------------ ------------ ------------ ------------ ------------ OTHER 12.8 9.8 (16.4) 6.2 (17.0) ELIMINATIONS -- (248.2) -- (248.2) -- ------------ ------------ ------------ ------------ ------------ TOTAL $ 2,010.6 $ -- $ (26.6) $ 1,984.0 $ 239.2 ============ ============ ============ ============ ============ FOR THE THREE MONTHS ENDED MARCH 31, 1998 GAS PIPELINE $ 430.3 $ 11.9 $ -- $ 442.2 $ 195.0 ENERGY SERVICES Energy Marketing & Trading 408.7 71.9 (1.1) 479.5 15.5 Exploration & Production 11.8 28.8 -- 40.6 12.3 Midstream Gas & Liquids 219.4 18.5 1.5 239.4 66.3 Petroleum Services 505.8 38.8 .1 544.7 33.6 Merger-related costs and non-compete amortization -- -- -- -- (35.9) ------------ ------------ ------------ ------------ ------------ 1,145.7 158.0 .5 1,304.2 91.8 ------------ ------------ ------------ ------------ ------------ COMMUNICATIONS Communications Solutions 327.4 -- -- 327.4 3.3 Network Services 9.1 12.1 -- 21.2 (7.9) Strategic Investments 50.2 1.1 (1.5) 49.8 (17.0) ------------ ------------ ------------ ------------ ------------ 386.7 13.2 (1.5) 398.4 (21.6) ------------ ------------ ------------ ------------ ------------ OTHER (4.4) 16.6 1.5 13.7 3.0 ELIMINATIONS -- (199.7) -- (199.7) -- ------------ ------------ ------------ ------------ ------------ TOTAL $ 1,958.3 $ -- $ .5 $ 1,958.8 $ 268.2 ============ ============ ============ ============ ============ TOTAL ASSETS ----------------------------------- (Millions) March 31, 1999 December 31, 1998 -------------- ----------------- GAS PIPELINE $ 8,261.8 $ 8,386.2 ENERGY SERVICES Energy Marketing & Trading 2,599.2 2,596.8 Exploration & Production 451.9 484.1 Midstream Gas & Liquids 3,343.6 3,201.8 Petroleum Services 2,511.6 2,525.2 -------------- -------------- 8,906.3 8,807.9 -------------- -------------- COMMUNICATIONS Communications Solutions 944.8 946.4 Network Services 780.8 712.9 Strategic Investments 1,102.8 638.4 -------------- -------------- 2,828.4 2,297.7 -------------- -------------- OTHER 5,393.3 4,782.4 ELIMINATIONS (6,217.6) (5,626.9) -------------- -------------- TOTAL $ 19,172.2 $ 18,647.3 ============== ============== * Energy Marketing & Trading intercompany cost of sales, which are netted in revenues consistent with fair-value accounting, exceed intercompany revenues. 13

15 15. Subsequent event On April 9, 1999, Williams' communications business filed a registration statement for an initial public equity offering which is expected to yield proceeds of $500 million to $750 million, representing a minority interest in its communications business. During the first quarter of 1999, Williams announced that simultaneously with the public equity offering, SBC Communications plans to acquire up to a 10 percent interest in Williams' communications business for an investment up to $500 million. In addition, Communications is expected to issue high-yield public debt of $1.3 billion in 1999. Proceeds will be reinvested in the continued construction of Williams' national fiber-optic network and other expansion opportunities. ITEM 2 Management's Discussion and Analysis of Financial Condition and Results of Operations Results of Operations First Quarter 1999 vs. First Quarter 1998 CONSOLIDATED OVERVIEW Williams' revenues increased $25 million, or 1 percent, due primarily to Communications' sales of excess fiber capacity and new business growth on the fiber-optic network, increased revenues from retail natural gas and electric activities following a late 1998 acquisition and higher power services revenues. Partially offsetting these increases were the $84 million effect in 1999 of reporting certain revenues net of costs within Energy Services (see Note 2 of the Notes to the Consolidated Financial Statements) and continued lower petroleum products and natural gas liquids sales prices. Segment costs and expenses increased $54 million, or 3 percent, due primarily to higher costs and expenses within Communications, higher costs from retail natural gas and electric activities following a late 1998 acquisition and higher power services costs. Partially offsetting these increases were the $84 million impact in 1999 of reporting certain costs net in revenues within Energy Services (see Note 2), lower purchase prices for petroleum products and the effect in 1998 of Mapco merger-related costs totaling $59 million (including $23 million within general corporate expenses). Operating income decreased $5 million, or 2 percent, comprised primarily of a $30 million decrease at Communications, reflecting losses from international ventures in initial operations and infrastructure growth and improvement, and a $21 million decrease from International activities, reflecting losses from start-up operations. Partially offsetting these decreases was the effect in 1998 of MAPCO merger-related costs totaling $59 million. Income before income taxes, extraordinary loss and change in accounting principle decreased $23 million due primarily to $24 million higher net interest expense reflecting continued expansion and new projects. GAS PIPELINES GAS PIPELINE'S revenues increased $24.7 million, or 6 percent, and costs and operating expenses increased $20 million, or 11 percent, due primarily to the settlement of an historical gas exchange imbalance. Segment profit decreased $8.2 million, or 4 percent, due primarily to the effect of a $3.4 million gain in 1998 from the sale-in-place of natural gas from a decommissioned storage field and $6 million higher general and administrative expenses in 1999, including expenses related to information system initiatives and a $2.3 million accrual for damages associated with two pipeline ruptures in the northwest. Based on current rate structures and/or historical maintenance schedules of certain of its pipelines, Gas Pipeline experiences higher segment profits in the first and fourth quarters as compared with the second and third quarters. During 1998, the Federal Energy Regulatory Commission (FERC) issued several rulings that could result in higher tariff rates in future periods for Gas Pipeline. These FERC rulings are subject to appeal (see Note 11). 14

16 ENERGY SERVICES ENERGY MARKETING & TRADING'S revenues decreased $7.5 million, or 2 percent, due primarily to the $84 million impact in 1999 of reporting revenues on a net basis for certain natural gas liquids trading operations previously reported on a "gross" basis (see Note 2). Excluding this decrease, revenues increased $77 million due primarily to $68 million higher revenues from retail natural gas and electric activities following the late 1998 acquisition of Volunteer Energy and $53 million higher electric power services revenues from new activity in southern California, partially offset by a $45 million decrease in revenues associated with crude and refined products marketing and trading. The $45 million decrease from crude and refined products activities reflects $79 million from lower average sales prices from crude and refined products marketing activities, partially offset by $19 million from increased volumes sold and $15 million higher net revenues associated with crude and refined products trading activities. Costs and operating expenses decreased $49 million, or 11 percent, due primarily to the $84 million impact in 1999 of reporting revenues on a net basis for certain natural gas liquids trading operations previously reported on a "gross" basis (see Note 2). In addition, costs associated with crude and refined products marketing activities decreased $59 million reflecting lower average product purchase prices, partially offset by increased volumes purchased. Partially offsetting these decreases were $62 million of higher costs following the late 1998 acquisition of Volunteer Energy and $40 million of costs related to new electric power activity in southern California. Selling, general and administrative expenses increased $16 million reflecting growth in electric power services operations, the Volunteer Energy acquisition and higher compensation levels associated with improved operating performance. Segment profit increased $25.2 million, to $40.7 million in 1999 from $15.5 million in 1998, due primarily to $8 million higher electric power marketing and trading profits and $12 million higher profits from crude and refined products marketing and trading. In addition, retail propane profits increased $7 million reflecting a 13 percent increase in propane volumes combined with improved per-unit propane margins resulting from favorable weather conditions. EXPLORATION & PRODUCTION'S revenues decreased $13.1 million, or 32 percent, due primarily to lower average natural gas sales prices for both company-owned production and sales of volumes from the Williams Coal Seam Gas Royalty Trust and royalty interest owners. In addition, revenues decreased due to a $4 million reduction in deferred income recognized from a 1997 transaction that transferred certain nonoperating economic benefits to a third party, partially offset by a $2 million increase resulting from 13 percent higher company-owned production volumes. Segment profit decreased $7.6 million, or 62 percent, due primarily to the $4 million reduction in deferred income recognition, a $5 million unfavorable effect of lower average natural gas sales prices for company-owned production and $2 million higher leasehold impairment expense, partially offset by $3 million lower dry hole costs and the 13 percent increase in company-owned production volumes. MIDSTREAM GAS & LIQUIDS' revenues decreased $21.7 million, or 9 percent, due primarily to $8 million lower natural gas liquids sales from processing activities, $3 million lower natural gas liquids pipeline transportation revenues resulting from decreased shipments, $4 million lower condensate revenues following processing plant shutdowns during 1999 and $4 million lower equity earnings primarily from the Discovery pipeline project. The $8 million lower natural gas liquids sales reflects $14 million from lower average liquids sales prices, partially offset by $6 million from a 14 percent increase in liquids volumes sold. Segment profit decreased $19.7 million, or 30 percent, due primarily to $9 million lower per-unit liquids margins, lower pipeline transportation revenues and equity earnings and increased costs and expenses, partially offset by the effect of a $3 million litigation accrual in 1998. PETROLEUM SERVICES' revenue decreased $8.8 million, or 2 percent, due primarily to $41 million lower revenues from refining operations and $8 million lower ethanol sales, largely offset by $18 million higher convenience store revenues, $12 million higher revenues from fleet management and mobile computer technology operations and $7 million higher transportation and terminalling revenues. The $41 million decline in refining revenues reflects $65 million from lower average sales prices because of lower crude costs, partially offset by $24 million from a 9 percent increase in refined product volumes sold. The $18 million increase in convenience store sales reflects $25 million from increased gasoline and diesel sales volumes and $11 million higher merchandise sales due to additional stores, partially offset by the $18 million effect of lower average retail gasoline and diesel sales prices. Costs and operating expenses decreased $9 million, or 2 percent, due primarily to $43 million lower refinery crude oil purchases, partially offset by $10 million higher costs from the fleet management and mobile computer technology operations, 15

17 $13 million higher convenience store cost of sales, $8 million higher convenience store operating costs and $4 million higher refinery operating costs. The $43 million lower crude oil purchase costs reflects $62 million from lower average crude oil prices, partially offset by $19 million related to an increase in processed barrels sold. The $13 million higher convenience store cost of sales reflects $23 million from increased gasoline and diesel sales volumes and $6 million of higher merchandise cost of sales, partially offset by $16 million from lower average gasoline and diesel prices. Segment profit decreased $.6 million, or 2 percent, due primarily to $5 million lower profits from the refining and retail operations and $6 million higher general and administrative expenses, substantially offset by $6 million higher profits from the transportation and terminalling operations and the recovery of $4 million of environmental expenses previously incurred. COMMUNICATIONS COMMUNICATIONS SOLUTIONS' revenues increased by $9.9 million, or 3 percent, due primarily to $14 million higher new system sales and upgrades, partially offset by $9 million lower customer service orders resulting, in part, from competitive pressures. Segment profit decreased $12.1 million, from a $3.3 million segment profit in 1998 to an $8.8 million segment loss in 1999, due primarily to $16 million higher selling, general and administrative expenses including $7 million increased provision for uncollectible trade receivables and higher costs necessary to improve managing and integrating complex business operations and systems. NETWORK SERVICES' revenues increased $87.3 million, from $21.2 million in 1998, due primarily to $51 million of revenue in 1999 from the sale of excess dark fiber capacity on the newly constructed digital fiber-optic network and $32 million from business growth. Costs and operating expenses increased $90 million, from $18 million in 1998, due primarily to $41 million of construction costs associated with the sale of dark fiber, $29 million higher leased capacity costs associated with providing customer services prior to completion of the new network and $6 million higher operations and maintenance expenses. Segment loss increased $9.3 million, from a $7.9 million loss in 1998 to a $17.2 million loss in 1999, due primarily to losses experienced from providing customer services prior to completion of the new network and the cost of expanding the infrastructure in support of the network expansion, partially offset by $10.5 million of profit from selling excess fiber capacity. As each phase of the on-going construction of the planned 32,000 mile full-services wholesale communications network goes into service, revenues and costs are expected to increase. During 1998, 9,000 miles of new network were added increasing the network to 19,000 cable miles at December 31, 1998. At March 31, 1999, the network had increased to 20,000 cable miles. The remaining 12,000 miles are planned to come online during the rest of 1999 and 2000. The February 8, 1999, announcement by Williams of a 20-year agreement with SBC Communications, under which Network Services will become the preferred provider of nationwide long-distance voice and data services for SBC Communications, will contribute to the expected network revenue increase in 2000. Additional sales of excess dark fiber capacity along the new network are expected to generate increasing revenues and serve as a funding source for continued infrastructure growth and construction. STRATEGIC INVESTMENTS' revenues increased $10.4 million, or 21 percent, due primarily to $15 million of revenue contributed by the August 1998 acquisition of an Australian telecommunications company, partially offset by equity investment losses of $8 million from ATL - Algar Telecom Leste S.A. (ATL), a Brazilian telecommunications business in initial operations. Costs and operating expenses increased $13 million, or 27 percent, and selling, general and administrative expenses increased $6 million, or 30 percent, due primarily to the Australian acquisition. Segment loss increased $8.5 million, or 50 percent, due primarily to start-up activities in the Australian and Brazilian telecommunications businesses, partially offset by a $6 million decrease in losses from video transmission services. Management is currently assessing some of its business activities within this segment which may ultimately result in the impairment of or the sale of some of these businesses. Preliminary estimates are that such impairment charges or losses for the activities under review approximate $30 million. No definitive agreements or formal plans have been reached relating to the businesses under review. OTHER OTHER segment loss of $17 million in 1999 compares to a segment profit of $3 million in 1998, due primarily to $18 million higher international equity investment losses, including $14 million from investing activities in another Brazilian communications company in which Williams has approximately a 5 percent common equity interest. The equity losses result primarily from start-up operations of certain communications ventures within this company. 16

18 CONSOLIDATED GENERAL CORPORATE EXPENSES decreased $23.9 million, or 59 percent, due primarily to $23 million of MAPCO merger-related costs included in first-quarter 1998 general corporate expenses. An additional $36 million of merger-related costs are included in 1998 as a component of Energy Services' segment profit (see Note 3). Interest accrued increased $25.3 million, or 21 percent, due primarily to higher borrowing levels including Williams Holdings' commercial paper program and the issuance of additional public debt. Investing income increased $3 million, to $6.7 million, due primarily to higher interest income on advances to affiliates. The $5.6 million, or 12 percent, decrease in the provision for income taxes is primarily a result of lower pre-tax income. The effective tax rate in 1999 and 1998 exceeds the federal statutory rate due primarily to the effects of state income taxes. The $4.8 million 1998 extraordinary loss results from the early extinguishment of debt (see Note 5). The $5.6 million 1999 change in accounting principle relates to the adoption of Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities" (see Note 6). 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 March 31, 1999, Williams had access to $512 million of liquidity including $355 million available under its $1 billion bank-credit facility and $149 million of cash-equivalent investments. This compares with liquidity of $738 million at December 31, 1998, and $1.2 billion at March 31, 1998. Registration statements have been filed with the Securities and Exchange Commission by Williams and Williams Holdings of Delaware, Northwest Pipeline, Texas Gas Transmission and Transcontinental Gas Pipeline (each a wholly owned subsidiary of Williams). Approximately $2.1 billion of shelf availability, including the registration of $975 million effective in April 1999, remains under these outstanding registration statements and may be used to issue a variety of debt or equity securities. Williams believes any additional financing arrangements can be obtained on reasonable terms if required. On April 9, 1999, Williams' communications business filed a registration statement for an initial public equity offering which is expected to yield proceeds of $500 million to $750 million, representing a minority interest in its communications business. During first-quarter 1999, Williams announced that simultaneously with the public equity offering, SBC Communications plans to acquire up to a 10 percent interest in Williams' communications business for an investment up to $500 million. In addition, Communications is expected to issue high-yield public debt of $1.3 billion in 1999 under a registration statement currently in process. Proceeds from these equity and debt transactions will be reinvested in the continued construction of Williams' national fiber-optic network and other expansion opportunities. Also in April, Williams' communications business entered into a $1.4 billion interim short-term bank-credit facility expected to be replaced with a permanent bank-credit facility in the second quarter of 1999. In addition, a total of $419 million remains available under Williams' securitized asset lease program designed to fund up to $750 million of capital expenditures for the fiber-optic network. In 1999, capital expenditures and investments are estimated to be approximately $5 billion. Williams expects to finance capital expenditures, investments and working-capital requirements through cash generated from operations, Communications' initial equity and high-yield debt offerings, and the use of the available portion of its $1 billion bank-credit facility and asset lease program, commercial paper, short-term uncommitted bank lines, private borrowings and debt or equity public offerings. Financing Activities In January 1999, Williams Holdings increased its commercial paper program to $1.4 billion from $1 billion. The commercial paper program is backed by a $1.4 billion short-term bank-credit facility. At March 31, 1999, $1.4 billion of commercial paper was outstanding under the program. Also in January 1999, Williams entered into a $200 million adjustable rate term loan due 2004. The proceeds were used for general corporate purposes, including the repayment of outstanding debt. The consolidated long-term debt to debt-plus-equity ratio was 58.8 percent at March 31, 1999, compared to 59.9 percent at December 31, 1998. If short-term notes payable and long-term debt due within one year are included in the calculations, these ratios would be 66.4 percent at March 31, 1999 and 64.7 percent at December 31, 1998. 17

19 Investing Activities During first-quarter 1999, Williams exercised an option to increase its investment in ATL, a Brazilian telecommunications business, by an additional 35 percent equity interest for $265 million. This investment was funded through borrowings under the $1 billion bank-credit facility. Also in first-quarter 1999, Williams purchased a company with an ethylene plant and natural gas liquids transportation, storage and other facilities for $163 million in cash. Operating Activities The decrease in accounts payable and accrued liabilities is due primarily to the payment in 1999 of $113 million of rate refunds to natural gas transportation customers, $100 million in connection with the assignment of Williams' obligations under a gas purchase contract to an unaffiliated third party (see Note 11), and $84 million pursuant to a wireless fiber capacity agreement. Year 2000 Compliance Williams initiated an enterprise-wide project in 1997 to address the year 2000 compliance issue for both traditional information technology areas and non-traditional areas, including embedded technology which is prevalent throughout the company. This project focuses on all technology hardware and software, external interfaces with customers and suppliers, operations process control, automation and instrumentation systems, and facility items. The phases of the project are awareness, inventory and assessment, renovation and replacement, testing and validation. The awareness and inventory/assessment phases of this project as they relate to both traditional and non-traditional information technology areas have been substantially completed. During the inventory and assessment phase, all systems with possible year 2000 implications were inventoried and classified into five categories: 1) highest, business critical, 2) high, compliance necessary within a short period of time following January 1, 2000, 3) medium, compliance necessary within 30 days from January 1, 2000, 4) low, compliance desirable but not required, and 5) unnecessary. Categories 1 through 3 were designated as critical and are the major focus of this project. Renovation/replacement and testing/validation of critical systems is expected to be completed by June 30, 1999, except for replacement of certain critical systems scheduled for completion later in 1999. Some non-critical systems may not be compliant by January 1, 2000. Testing and validation activities have begun and will continue throughout the process. Year 2000 test labs are in place and operational. As expected, few problems have been detected during testing for items believed to be compliant. The following table indicates the project status as of March 31, 1999, for traditional information technology and non-traditional areas by business unit. The tested category indicates the percentage that has been fully tested or otherwise validated as compliant. The untested category includes items that are believed to be compliant but which have not yet been validated. The not compliant category includes items which have been identified as not year 2000 compliant. Not Business Unit Tested Untested Compliant ------------- ---------- ---------- ---------- Traditional Information Technology: Gas Pipeline 80% 7% 13% Energy Services 74 23 3 Communications 58 24 18 Corporate/Other 86 11 3 Non-Traditional Information Technology: Gas Pipeline 79 10 11 Energy Services 68 28 4 Communications 74 20 6 Corporate/Other 93 7 0 Williams initiated a formal communications process with other companies in 1998 to determine the extent to which those companies are addressing year 2000 compliance. In connection with this process, Williams has sent approximately 15,600 letters and questionnaires to third parties including customers, vendors and service providers. Williams is evaluating responses as they are received or otherwise investigating the status of these companies' year 2000 compliance efforts. As of March 31, 1999, approximately 40 percent of the companies contacted have responded and virtually all of these have indicated that they are already compliant or will be compliant on a timely basis. Where necessary, Williams will be working with key business partners to reduce the risk of a break in service or supply and with non-compliant companies to mitigate any material adverse effect on Williams. Williams expects to utilize both internal resources and external contractors to complete the year 2000 compliance project. Williams has a core group of 279 people involved in this enterprise-wide project. This includes 16 individuals responsible for coordinating, organizing, managing, communicating, and monitoring the project and another 263 staff members responsible for completing the project. Depending on which phase the project is in and what area is being focused on at any given point in time, there can be an additional 500 to 1,200 employees who are also contributing a portion of their time to the completion of this project. The Communications business unit has contracted with an external contractor at a cost of approximately $3 million to assist in all phases and various areas of the project. Gas Pipeline has contracted with an external contractor for a cost of up to $6 million for the remediation of its customer service software. Within Energy Services, two external contractors are being utilized at a total cost of approximately $2 million. 18

20 Several previously planned system implementations are scheduled for completion during 1999, which will lessen possible year 2000 impacts. For example, a new year 2000 compliant payroll/human resources system was implemented January 1, 1999. It replaced multiple human resources administration and payroll processing systems previously in place. The Communications business unit has a major service information management system implementation and other system implementations currently in process necessary to integrate the operations of its many components acquired in past acquisitions. These systems are coming online in stages and will address the year 2000 compliance issues in certain areas. Within the Energy Services business unit, major applications had been replaced or were being replaced by MAPCO prior to its acquisition by Williams. Those applications have been incorporated into the enterprise-wide project and remaining system replacements are proceeding on schedule. In addition, the Petroleum Services business unit of Energy Services is replacing its ATLAS and revenue billing systems. The planned implementation date for this has been delayed from the summer of 1999, to October 1, 1999. Gas Pipeline completed implementation of a new telephone system in 1998, and a new common financial system is scheduled for completion July 1, 1999 at one of the pipelines. In situations where planned system implementations will not be in service timely or are delayed past an implementation date of September 1, 1999, alternative steps are being taken to make existing systems compliant. Although all critical systems over which Williams has control are planned to be compliant and tested before the year 2000, Williams has identified two areas that would equate to a most reasonably likely worst case scenario. First is the possibility of service interruptions due to non-compliance by third parties. For example, power failures along the communications network or transportation systems would cause service interruptions. This risk should be minimized by the enterprise-wide communications effort and evaluation of third-party compliance plans. Another area of risk for non-compliance is the delay of system replacements scheduled for completion during 1999. The status of these systems is being closely monitored to reduce the chance of delays in completion dates. It is not possible to quantify the possible financial impact if this most reasonably likely worst case scenario were to come to fruition. Initial contingency planning began during 1998. Significant focus on that phase of the project is taking place in 1999. Guidelines for that process were issued in January 1999. Contingency plans are being developed for critical business processes, critical business partners, suppliers and system replacements that experience significant delays. Communications has engaged an outside consultant to assist in this process. These plans are expected to be defined by August 31, 1999, and implemented where appropriate. Because of the delay in the implementation date of the new ATLAS and revenue billing systems at Petroleum Services to October 1, 1999, the contingency plan for those systems has been implemented. That plan includes the modification and testing of the existing ATLAS and revenue billing systems by September 1, 1999 to ensure that a compliant system is in place in case the new systems' implementation date is delayed further. Costs incurred for new software and hardware purchases are being capitalized and other costs are being expensed as incurred. Williams currently estimates the total cost of the enterprise-wide project, including any accelerated system replacements, to be approximately $50 million. This $50 million has been or is expected to be spent as follows: o Prior to 1998 and during the first quarter of 1998, Williams was conducting the project awareness and inventory/assessment phases of the project and incurred costs totaling $3 million. o During the second quarter of 1998, $2 million was spent on the renovation/replacement and testing/validation phases and completion of the inventory/assessment phase. o The third and fourth quarters of 1998 focused on the renovation/replacement and testing/validation phases, and $10 million was incurred. o During the first-quarter 1999, renovation/replacement and testing/validation continued, contingency planning began and $9 million was incurred. o During the second quarter of 1999, the primary focus is expected to shift to testing/validation and contingency planning, and $15 million is expected to be spent. o The third and fourth quarters of 1999 will focus mainly on contingency planning and final testing with $11 million expected to be spent. Of the $24 million incurred to date, approximately $21 million has been expensed, and approximately $3 million has been capitalized. Of the $26 million of future costs necessary to complete the project within the schedule described, approximately $23 million will be expensed and the remainder capitalized. This estimate does not include Williams' potential share of year 2000 costs that may be incurred by partnerships and joint ventures in which the company participates but is not the operator. The costs of previously planned system replacements are not considered to be year 2000 costs and are, therefore, excluded from the amounts discussed above. The preceding discussion contains forward-looking statements including, without limitation, 19

21 statements relating to the company's plans, strategies, objectives, expectations, intentions, and adequate resources, that are made pursuant to the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995. Readers are cautioned that such forward-looking statements contained in the year 2000 update are based on certain assumptions which may vary from actual results. Specifically, the dates on which the company believes the year 2000 project will be completed and computer systems will be implemented are based on management's best estimates, which were derived utilizing numerous assumptions of future events, including the continued availability of certain resources, third-party modification plans and other factors. However, there can be no guarantee that these estimates will be achieved, or that there will not be a delay in, or increased costs associated with, the implementation of the year 2000 project. Other specific factors that might cause differences between the estimates and actual results include, but are not limited to, the availability and cost of personnel trained in these areas, the ability to locate and correct all relevant computer code, timely responses to and corrections by third parties and suppliers, the ability to implement interfaces between the new systems and the systems not being replaced, and similar uncertainties. Due to the general uncertainty inherent in the year 2000 problem, resulting in large part from the uncertainty of the year 2000 readiness of third parties, the company cannot ensure its ability to timely and cost effectively resolve problems associated with the year 2000 issue that may affect its operations and business, or expose it to third-party liability. ITEM 3. Quantitative and Qualitative Disclosures About Market Risk During the first quarter of 1999, Williams issued $200 million in adjustable rate debt due in 2004 at an initial rate of approximately 5.3 percent. At March 31, 1999, Williams has preferred stock interests in certain South American ventures totaling $367 million for which the fair value of these investments is deemed to approximate the carrying value. Williams' financial results could be affected if these investments incur a permanent decline in value as a result of changes in foreign currency exchange rates and the local economic conditions. These ventures are in a country that has experienced significant devaluation and volatility. The ultimate duration and severity of the conditions in this country remain uncertain as does the long-term impact on Williams' interest in these ventures. 20

22 PART II. OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K (a) The exhibits listed below are filed as part of this report: Exhibit 12 -- Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements Exhibit 27 -- Financial Data Schedule (b) During the first quarter of 1999, the Company filed a Form 8-K on January 26, 1999; March 3, 1999; and March 24, 1999, which reported significant events under Item 5 of the Form and included the exhibits required by Item 7 of the Form. 21

23 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. THE WILLIAMS COMPANIES, INC. (Registrant) /s/ Gary R. Belitz -------------------------------- Gary R. Belitz Controller (Duly Authorized Officer and Principal Accounting Officer) May 14, 1999

24 INDEX TO EXHIBITS EXHIBIT NO. DESCRIPTION ------- ----------- Exhibit 12 -- Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements Exhibit 27 -- Financial Data Schedule

1 Exhibit 12 The Williams Companies, Inc. and Subsidiaries Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements (Dollars in millions) Three months ended March 31, 1999 --------------- Earnings: Income before income taxes, extraordinary loss and change in accounting principle $ 95.8 Add: Interest expense - net 133.9 Rental expense representative of interest factor 19.2 Minority interest in (income) loss of consolidated subsidiaries .6 Interest accrued - 50% owned company 1.8 Equity losses in less than 50% owned companies 20.3 Other 2.1 --------------- Total earnings as adjusted plus fixed charges $ 273.7 =============== Fixed charges and preferred stock dividend requirements: Interest expense - net $ 133.9 Capitalized interest 9.4 Rental expense representative of interest factor 19.2 Pretax effect of dividends on preferred stock of the Company 2.7 Interest accrued - 50% owned company 1.8 --------------- Combined fixed charges and preferred stock dividend requirements $ 167.0 =============== Ratio of earnings to combined fixed charges and preferred stock dividend requirements 1.64 ===============

5 1,000 3-MOS DEC-31-1999 JAN-01-1999 MAR-31-1999 330,077 0 1,694,303 39,865 533,883 3,305,839 16,614,721 3,704,236 19,172,166 4,932,718 6,192,394 0 79,710 435,663 3,815,101 19,172,166 0 1,984,011 0 1,744,796 0 9,587 143,336 95,837 39,945 55,892 0 0 (5,600) 50,292 .11 .11