10-Q 1 d98983e10vq.txt FORM 10-Q FOR QUARTER ENDED JUNE 30, 2002 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (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, 2002 ------------- OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ----------- ----------- Commission file number 1-4174 ------ THE WILLIAMS COMPANIES, INC. ------------------------------------------------------ (Exact name of registrant as specified in its charter) DELAWARE 73-0569878 ------------------------ ------------------------------------ (State of Incorporation) (IRS Employer Identification Number) ONE WILLIAMS CENTER TULSA, OKLAHOMA 74172 --------------------------------------- ---------- (Address of principal executive office) (Zip Code) Registrant's telephone number: (918) 573-2000 -------------- NO CHANGE --------------------------------------------------- Former name, former address and former fiscal year, if changed since last report. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date. Class Outstanding at July 31, 2002 -------------------------- ---------------------------- Common Stock, $1 par value 516,512,571 Shares The Williams Companies, Inc. Index
Page ---- Part I. Financial Information Item 1. Financial Statements Consolidated Statement of Operations--Three and Six Months Ended June 30, 2002 and 2001 2 Consolidated Balance Sheet--June 30, 2002 and December 31, 2001 3 Consolidated Statement of Cash Flows--Six Months Ended June 30, 2002 and 2001 4 Notes to Consolidated Financial Statements 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 30 Item 3. Quantitative and Qualitative Disclosures about Market Risk 52 Part II. Other Information 53 Item 1. Legal Proceedings Item 2. Changes in Securities and Use of Proceeds Item 4. Submission of Matters to a Vote of Security Holders Item 6. Exhibits and Reports on Form 8-K
Certain matters discussed in this report, excluding historical information, include forward-looking statements - statements that discuss Williams' expected future results based on current and pending business operations. Williams makes these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such as "anticipates," "believes," "expects," "planned," "scheduled" or similar expressions. Although Williams believes these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in this document. Additional information about issues that could lead to material changes in performance is contained in The Williams Companies, Inc.'s 2001 Form 10-K. 1 The Williams Companies, Inc. Consolidated Statement of Operations (Unaudited)
Three months Six months (Dollars in millions, except per-share amounts) ended June 30, ended June 30, -------------------------- -------------------------- 2002 2001* 2002 2001* ---------- ---------- --------- ----------- Revenues: Energy Marketing & Trading $ (195.6) $ 337.7 $ 145.3 $ 935.9 Gas Pipeline 381.7 368.7 805.5 790.7 Energy Services 2,003.6 2,225.1 3,743.7 4,469.4 Other 16.4 21.0 32.3 39.5 Intercompany eliminations (50.5) (31.2) (90.4) (104.8) ---------- ---------- ---------- ---------- Total revenues 2,155.6 2,921.3 4,636.4 6,130.7 ---------- ---------- ---------- ---------- Segment costs and expenses: Costs and operating expenses 1,866.1 2,119.8 3,467.3 4,309.2 Selling, general and administrative expenses 233.3 193.9 429.8 418.4 Other (income) expense - net 223.0 (89.8) 221.1 (79.7) ---------- ---------- ---------- ---------- Total segment costs and expenses 2,322.4 2,223.9 4,118.2 4,647.9 ---------- ---------- ---------- ---------- General corporate expenses 34.1 27.0 72.3 56.4 ---------- ---------- ---------- ---------- Operating income (loss): Energy Marketing & Trading (414.5) 263.1 (141.5) 750.0 Gas Pipeline 117.3 170.9 288.0 339.5 Energy Services 129.8 258.9 368.6 384.0 Other .6 4.5 3.1 9.3 General corporate expenses (34.1) (27.0) (72.3) (56.4) ---------- ---------- ---------- ---------- Total operating income (loss) (200.9) 670.4 445.9 1,426.4 Interest accrued (278.0) (161.1) (495.4) (341.1) Interest capitalized 6.7 11.1 12.4 20.8 Interest rate swap loss (83.2) -- (73.0) -- Investing income (loss): Estimated loss on realization of amounts due from Williams Communications Group, Inc. (15.0) -- (247.0) -- Other 54.8 35.0 70.9 69.0 Preferred returns and minority interest in income of consolidated subsidiaries (21.8) (21.7) (37.0) (47.0) Other income - net 23.7 6.0 19.8 11.4 ---------- ---------- ---------- ---------- Income (loss) from continuing operations before income taxes (513.7) 539.7 (303.4) 1,139.5 Provision (benefit) for income taxes (164.6) 210.9 (77.5) 443.8 ---------- ---------- ---------- ---------- Income (loss) from continuing operations (349.1) 328.8 (225.9) 695.7 Income (loss) from discontinued operations -- 10.7 (15.5) (157.0) ---------- ---------- ---------- ---------- Net income (loss) (349.1) 339.5 (241.4) 538.7 Preferred stock dividends (6.8) -- (76.5) -- ========== ========== ========== ========== Income (loss) applicable to common stock $ (355.9) $ 339.5 $ (317.9) $ 538.7 ========== ========== ========== ========== Basic earnings (loss) per common share: Income (loss) from continuing operations $ (.68) $ .68 $ (.58) $ 1.44 Income (loss) from discontinued operations -- .02 (.03) (.33) ---------- ---------- ---------- ---------- Net income (loss) $ (.68) $ .70 $ (.61) $ 1.11 ========== ========== ========== ========== Average shares (thousands) 520,427 487,211 519,829 483,173 Diluted earnings (loss) per common share: Income (loss) from continuing operations $ (.68) $ .67 $ (.58) $ 1.42 Income (loss) from discontinued operations -- .02 (.03) (.32) ---------- ---------- ---------- ---------- Net income (loss) $ (.68) $ .69 $ (.61) $ 1.10 ========== ========== ========== ========== Average shares (thousands) 520,427 491,698 519,829 487,527 Cash dividends per common share $ .20 $ .15 $ .40 $ .30
*Certain amounts have been restated or reclassified as described in Note 2 of Notes to Consolidated Financial Statements. See accompanying notes. 2 The Williams Companies, Inc. Consolidated Balance Sheet (Unaudited)
(Dollars in millions, except per-share amounts) June 30, December 31, 2002 2001* ----------- ------------ ASSETS Current assets: Cash and cash equivalents $ 773.3 $ 1,291.4 Restricted cash 169.5 -- Accounts and notes receivable less allowance of $201.3 ($255.0 in 2001) 3,679.0 3,118.6 Inventories 969.2 813.2 Energy risk management and trading assets 5,491.1 6,514.1 Margin deposits 369.6 213.8 Assets of discontinued operations -- 25.6 Deferred income taxes 479.8 440.6 Other 442.3 520.7 ----------- ----------- Total current assets 12,373.8 12,938.0 Restricted cash 101.1 -- Investments 1,750.5 1,563.1 Property, plant and equipment, at cost 22,868.2 22,138.4 Less accumulated depreciation and depletion (5,411.7) (5,199.6) ----------- ----------- 17,456.5 16,938.8 Energy risk management and trading assets 3,608.7 4,209.4 Goodwill, net 1,106.8 1,164.3 Assets of discontinued operations -- 935.9 Receivables from Williams Communications Group, Inc. less allowance of $2,084.9 ($103.2 in 2001) 287.4 137.2 Other assets and deferred charges 880.8 1,019.5 ----------- ----------- Total assets $ 37,565.6 $ 38,906.2 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Notes payable $ 711.2 $ 1,424.5 Accounts payable 3,423.6 2,885.9 Accrued liabilities 1,947.0 1,957.1 Liabilities of discontinued operations -- 40.9 Energy risk management and trading liabilities 4,723.5 5,525.7 Guarantees and payment obligations related to Williams Communications Group, Inc. 51.2 645.6 Long-term debt due within one year 1,636.3 1,014.8 ----------- ----------- Total current liabilities 12,492.8 13,494.5 Long-term debt 11,972.0 9,012.7 Deferred income taxes 3,420.9 3,689.9 Liabilities of discontinued operations -- 488.0 Energy risk management and trading liabilities 2,199.7 2,936.6 Guarantees and payment obligations related to Williams Communications Group, Inc. -- 1,120.0 Other liabilities and deferred income 989.2 943.1 Contingent liabilities and commitments (Note 12) Minority interests in consolidated subsidiaries 443.2 201.0 Preferred interests in consolidated subsidiaries 429.5 976.4 Stockholders' equity: Preferred stock, $1 per share par value, 30 million shares authorized, 1.5 million issued in 2002, none in 2001 272.3 -- Common stock, $1 per share par value, 960 million shares authorized, 519.6 million issued in 2002, 518.9 million issued in 2001 519.6 518.9 Capital in excess of par value 5,140.2 5,085.1 Retained earnings (deficit) (345.2) 199.6 Accumulated other comprehensive income 123.9 345.1 Other (53.9) (65.0) ----------- ----------- 5,656.9 6,083.7 Less treasury stock (at cost), 3.2 million shares of common stock in 2002 and 3.4 million in 2001 (38.6) (39.7) ----------- ----------- Total stockholders' equity 5,618.3 6,044.0 ----------- ----------- Total liabilities and stockholders' equity $ 37,565.6 $ 38,906.2 =========== ===========
* Certain amounts have been restated or reclassified as described in Note 2 of Notes to Consolidated Financial Statements. See accompanying notes. 3 The Williams Companies, Inc. Consolidated Statement of Cash Flows (Unaudited)
(Millions) Six months ended June 30, ------------------------ 2002 2001* ---------- ---------- OPERATING ACTIVITIES: Income (loss) from continuing operations $ (225.9) $ 695.7 Adjustments to reconcile to cash provided (used) by operations: Depreciation, depletion and amortization 439.6 349.6 Provision (benefit) for deferred income taxes (114.2) 215.7 Payments of guarantees and payment obligations related to Williams Communications Group, Inc. (753.9) -- Estimated loss on realization of amounts due from Williams Communications Group, Inc. 247.0 -- Provision for loss on property and other assets 154.1 25.1 Net gain on dispositions of assets (10.1) (101.5) Preferred returns and minority interest in income of consolidated subsidiaries 37.0 47.0 Tax benefit of stock-based awards 2.4 21.4 Cash provided (used) by changes in current assets and liabilities: Restricted cash (169.5) -- Accounts and notes receivable (567.0) (555.1) Inventories (159.7) 97.2 Margin deposits (155.8) 513.4 Other current assets (73.4) (104.8) Accounts payable 547.9 559.0 Accrued liabilities (69.4) (56.1) Changes in current energy risk management and trading assets and liabilities 220.8 (118.7) Changes in noncurrent energy risk management and trading assets and liabilities (136.1) (675.8) Changes in noncurrent deferred income (20.3) (12.8) Changes in noncurrent restricted cash (101.1) -- Other, including changes in noncurrent assets and liabilities 5.0 52.1 ---------- ---------- Net cash provided (used) by operating activities of continuing operations (902.6) 951.4 Net cash provided by operating activities of discontinued operations 30.2 79.6 ---------- ---------- Net cash provided (used) by operating activities (872.4) 1,031.0 ---------- ---------- FINANCING ACTIVITIES: Proceeds from notes payable 700.4 1,430.0 Payments of notes payable (2,003.1) (2,751.0) Proceeds from long-term debt 3,170.7 1,695.6 Payments of long-term debt (1,028.7) (705.9) Proceeds from issuance of common stock 24.5 1,380.8 Proceeds from issuance of preferred stock 272.3 -- Dividends paid (206.5) (145.3) Proceeds from sale of limited partner units of consolidated partnership 284.6 92.5 Payment of Williams obligated mandatorily redeemable preferred securities of Trust holding only Williams indentures -- (194.0) Payments of debt issuance costs (107.5) (24.5) Payments/dividends to preferred and minority interests (39.2) (25.9) Other--net (.5) -- ---------- ---------- Net cash provided by financing activities of continuing operations 1,067.0 752.3 Net cash provided (used) by financing activities of discontinued operations (5.6) 1,317.6 ---------- ---------- Net cash provided by financing activities 1,061.4 2,069.9 ---------- ---------- INVESTING ACTIVITIES: Property, plant and equipment: Capital expenditures (935.6) (708.4) Proceeds from dispositions 108.9 18.8 Changes in accounts payable and accrued liabilities (4.4) 27.1 Purchase of investment in Barrett -- (1,241.4) Purchases of investments/advances to affiliates (290.4) (232.0) Proceeds from sales of businesses 440.6 149.7 Proceeds from sales of investments and other assets .6 241.7 Other--net 12.1 32.2 ---------- ---------- Net cash used by investing activities of continuing operations (668.2) (1,712.3) Net cash used by investing activities of discontinued operations (48.6) (1,488.2) ---------- ---------- Net cash used by investing activities (716.8) (3,200.5) ---------- ---------- Cash of discontinued operations at spinoff -- (96.5) ---------- ---------- Decrease in cash and cash equivalents (527.8) (196.1) ---------- ---------- Cash and cash equivalents at beginning of period** 1,301.1 1,210.7 ---------- ---------- Cash and cash equivalents at end of period** $ 773.3 $ 1,014.6 ========== ==========
* Amounts have been restated or reclassified as described in Note 2 of Notes to Consolidated Financial Statements. ** Includes cash and cash equivalents of discontinued operations of $9.7 million, $23.7 million and $224.2 million at December 31, 2001, June 30, 2001 and December 31, 2000, respectively. See accompanying notes. 4 The Williams Companies, Inc. Notes to Consolidated Financial Statements (Unaudited) 1. General Recent Developments As a result of credit issues facing the company and the assumption of payment obligations and performance on guarantees associated with Williams Communications Group, Inc., (WCG), Williams announced plans during the first quarter of 2002 to strengthen its balance sheet. During the second quarter, the results of the energy marketing and trading business were not profitable reflecting market movements against its portfolio and an absence of origination activities. These unfavorable conditions were in large part a result of market concerns about Williams' credit and liquidity situation and limited this business' ability to manage market risk and exercise hedging strategies as market liquidity deteriorated. Subsequent to June 30, 2002, Williams' credit ratings were lowered below investment grade and it was unable to complete a renewal of its unsecured short-term bank credit facility. Following these events, Williams sold assets in July 2002 receiving net proceeds of approximately $1.5 billion, obtained secured credit facilities totaling $1.3 billion and amended its $700 million revolving credit facility to a secured basis. The effect of these transactions will be recorded in the third quarter of 2002. The Company has also reduced projected levels of capital expenditures and is considering selling other assets in the future to provide additional financial flexibility and liquidity. The board of directors reduced the quarterly dividend on common stock for the third quarter from the prior level of $.20 per share to $.01 per share. On August 1, 2002, Williams also announced its intentions to reduce its commitment to the energy marketing and trading business. This reduction could be realized by entering into a joint venture with a third party or sale of a portion or all of the marketing and trading portfolio. Additional information on these events is discussed in Note 18 and in Management's Discussion and Analysis included in this Form 10-Q. Other The accompanying interim consolidated financial statements of The Williams Companies, Inc. (Williams) do not include all notes in annual financial statements and therefore should be read in conjunction with the consolidated financial statements and notes thereto in Williams' Current Report on Form 8-K dated May 28, 2002. The accompanying financial statements have not been audited by independent auditors, but include all normal recurring adjustments and others, including asset impairments and loss accruals, which, in the opinion of Williams' management, are necessary to present fairly its financial position at June 30, 2002, its results of operations for the three and six months ended June 30, 2002 and 2001, and its cash flows for the six months ended June 30, 2002 and 2001. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. 2. Basis of presentation On March 27, 2002, Williams completed the sale of one of its Gas Pipeline segments, Kern River Gas Transmission (Kern River), to MidAmerican Energy Holdings Company (MEHC). Accordingly, the accompanying consolidated financial statements and notes reflect the results of operations, financial position and cash flows of Kern River as discontinued operations. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to the continuing operations of Williams (see Note 7). Certain other statement of operations, balance sheet and cash flow amounts have been reclassified to conform to the current classifications. Additionally, certain segment amounts have been reclassified as a result of transfers of management effective April 11, 2002 and July 1, 2002 (see Note 16). 3. Asset sales, impairments and other accruals Williams offered an enhanced-benefit early retirement option to certain employee groups. The deadline for electing the early retirement option was April 26, 2002. The three and six months ended June 30, 2002, reflects $30 million of expense associated with the early retirement, of which $24 million is recorded in selling, general and administrative expenses and the remaining in general corporate expenses. In a Form 8-K filed on May 28, 2002, Williams announced a plan that is designed to further improve the company's financial position and more narrowly focus its business strategy within its major business units. Part of this plan includes the generation of $1.5 billion to $3 billion of proceeds from the sale of assets or businesses. Williams is evaluating the assets and/or businesses that fit within its new, more narrowly focused business strategy, and has identified certain assets and/or businesses that are more-likely-than-not to be disposed of before the end of their previously estimated useful lives. These assets and/or businesses did not meet the criteria to be classified as held for sale at June 30, 2002, and were evaluated for recoverability on a held-for-use basis pursuant to Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." A probability-weighted approach was used to consider the likelihood of possible outcomes including sale in the near term and hold for the remaining estimated useful life. For those assets and/or businesses that were not recoverable based on undiscounted cash flows, an impairment loss was recognized in second-quarter 2002 based on management's estimate of fair value. In March 2002, Williams announced its intentions to sell its soda ash mining facility located in Colorado, which was previously written-down to estimated fair value at December 31, 2001, and in April 2002, Williams initiated a reserve-auction process. As this process and negotiations with interested parties progressed, new information regarding estimated fair value became available. As a result, an additional impairment loss of $44.1 million was recognized in second-quarter 2002 by the International segment. Management's estimate of fair value used to calculate the impairment loss was based on discounted cash flows assuming sale of the facility in 2002. During second-quarter 2002, Williams identified the travel centers as a business that does not fit within the new business strategy and began actively marketing that business for sale. Probability-weighted undiscounted cash flows for asset recoverability were estimated on a facility-by-facility basis. Fair value estimates for the travel centers with an indicated impairment were based on management's estimate of discounted cash flows using a probability-weighted approach which considered the likelihood of sale and related sale proceeds and the possibility of holding 5 Notes (Continued) the asset for its remaining estimated useful life. The $27 million loss recognized in second-quarter 2002 by Petroleum Services includes both impairment charges related to stores owned by Williams and liability accruals associated with a residual value guarantee of certain travel centers under an operating lease which, due to certain July 2002 amendments, will be accounted for as a capital lease beginning in July 2002. Additionally, as Williams has more narrowly focused its business strategy and reduced planned capital spending, certain projects will not be further developed. As a result, Williams has written-off capitalized costs and accrued for estimated costs associated with termination of these projects. The $83.7 million Energy Marketing & Trading charge includes write-offs associated with a terminated power plant project and accruals for commitments for certain assets that were previously planned to be used in power projects. Gas Pipelines' $7.5 million charge relates to the write-off of a cancelled pipeline construction project. In addition, Gas Pipeline also had an equity investment in another pipeline project which was cancelled resulting in a $12.3 million charge included in equity earnings (losses) (see Note 5). Energy Marketing & Trading recognized a $57.5 million goodwill impairment loss in second-quarter 2002 reflecting deteriorating market conditions in the merchant energy sector in which it operates and Energy Marketing & Trading's resulting announcement in June 2002 to scale back its own energy marketing and risk management business. The fair value of Energy Marketing & Trading used to calculate the goodwill impairment loss was based on the estimated fair value of the trading portfolio as reflected in the financial statements combined with the estimated fair value of contracts with affiliates that have not been marked to market. The fair value of these contracts was estimated using a discounted cash flow model with natural gas pricing assumptions based on current market information. Significant gains or losses from asset sales, impairments and other accruals included in other (income) expense - net within segment costs and expenses are included in the following table. With the exception of the $12.3 million charge at Gas Pipeline, the table includes those impairments and other accruals previously discussed.
Three months ended Six months ended June 30, June 30, ------------------ -------------------- (Millions) 2002 2001 2002 2001 ------ ------ ------ ------ ENERGY MARKETING & TRADING Net loss accruals and write-offs $ 83.7 $ -- $ 83.7 $ -- Impairment of goodwill 57.5 -- 57.5 -- GAS PIPELINE Gain on sale of limited partner units of Northern Border Partners, L.P. -- (27.5) - (27.5) Write-off of cancelled project 7.5 -- 7.5 -- ENERGY SERVICES: INTERNATIONAL Impairment of soda ash mining facility 44.1 -- 44.1 -- MIDSTREAM GAS & LIQUIDS Impairment of south Texas assets -- 10.9 - 10.9 PETROLEUM SERVICES Gain on sale of certain convenience stores -- (72.1) - (72.1) Impairment of end-to-end mobile computing systems business -- -- - 11.2 Impairment and other loss accruals for travel centers 27.0 -- 27.0 --
4. Receivables from Williams Communications Group, Inc. and other related information Background At December 31, 2001, Williams had financial exposure from WCG of $375 million of receivables and $2.21 billion of guarantees and payment obligations. Williams determined it was probable it would not fully realize the $375 million of receivables, and it would be required to perform under its $2.21 billion of guarantees and payment obligations. Williams developed an estimated range of loss related to its total WCG exposure and management believed that no loss within that range was more probable than another. For 2001, Williams recorded the $2.05 billion minimum amount of the range of loss from its financial exposure to WCG, which was reported in the Consolidated Statement of Operations as a $1.84 billion pre-tax charge to discontinued operations and a $213 million pre-tax charge to continuing operations. The charge to discontinued 6 Notes (Continued) operations of $1.84 billion included a $1.77 billion minimum amount of the estimated range of loss from performance on $2.21 billion of guarantees and payment obligations. The charge to continuing operations of $213 million included estimated losses from an assessment of the recoverability of the carrying amounts of the $375 million of receivables and a remaining $25 million investment in WCG common stock. Williams, prior to the spinoff of WCG, provided indirect credit support for $1.4 billion of WCG's Note Trust Notes. On March 5, 2002, Williams received the requisite approvals on its consent solicitation to amend the terms of the WCG Note Trust Notes. The amendment, among other things, eliminated acceleration of the WCG Note Trust Notes due to a WCG bankruptcy or from a Williams credit rating downgrade. The amendment also affirmed Williams' obligation for all payments due with respect to the WCG Note Trust Notes, which mature in March 2004, and allows Williams to fund such payments from any available sources. In July 2002, Williams acquired substantially all of the WCG Note Trust Notes by exchanging $1.4 billion of Williams Senior Unsecured 9.25 percent Notes due March 2004. With the exception of the March and September 2002 interest payments, totaling $115 million, WCG, through a subsidiary, remains obligated to reimburse Williams for any payments Williams makes in connection with the Notes. Williams also provided a guarantee of WCG's obligations under a 1998 transaction in which WCG entered into a lease agreement covering a portion of its fiber-optic network. WCG had an option to purchase the covered network assets during the lease term at an amount approximating the lessor's cost of $750 million. On March 8, 2002, WCG exercised its option to purchase the covered network assets. On March 29, 2002, Williams funded the purchase price of $754 million and became entitled to an unsecured note from WCG for the same amount. Pursuant to the terms of an agreement between Williams and WCG's revolving credit facility lenders, the liability of WCG to compensate Williams for funding the purchase is subordinated to the interests of WCG's revolving credit facility lenders and will not mature any earlier than one year after the maturity of WCG's revolving credit facility. Williams has also provided guarantees on certain other performance obligations of WCG totaling approximately $57 million. 2002 Evaluation At June 30, 2002, Williams has receivables and claims from WCG of $2.15 billion arising from Williams affirming its payment obligation on the $1.4 billion of WCG Note Trust Notes and Williams paying $754 million under the WCG lease agreement. At June 30, 2002, Williams also has $356 million of previously existing receivables. In second-quarter 2002, Williams recorded in continuing operations a pre-tax charge of $15 million related to WCG, including an assessment of the recoverability of its receivables and claims from WCG. For the six months ended June 30, 2002, Williams has recorded in continuing operations pre-tax charges of $247 million related to the recovery of these receivables and claims. At June 30, 2002, Williams estimates that approximately $2.2 billion of the $2.5 billion of receivables from WCG are not recoverable. On April 22, 2002, WCG filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Williams has filed proofs of claim in the bankruptcy proceedings for all amounts due Williams from WCG. On May 1, 2002 Williams was selected by the U.S. Trustee to serve on the Official Committee of Unsecured Creditors in the WCG bankruptcy. The committee formed a subcommittee, which excludes Williams, to investigate what rights and remedies, if any, the creditors may have against Williams relating to its dealings with WCG. Prior to the bankruptcy filing Williams entered into an agreement with WCG in which Williams agreed not to object to a plan of reorganization submitted by WCG in its bankruptcy if that plan provides for WCG to assume its obligations under certain service agreements and the sale-leaseback transaction involving the Williams Technology Center and aircraft with Williams and for Williams' other claims to be treated as general unsecured claims with treatment substantially identical to the treatment of claims by WCG's bondholders. On July 26, 2002, Williams executed a Settlement Agreement with WCG, the Official Committee of Unsecured Creditors and Leucadia National Corporation (Leucadia). On July 30, 2002, WCG filed with the bankruptcy court an Amended Plan of Reorganization and an Amended Disclosure Statement which, among other things, implement the provisions of the Settlement Agreement. The Settlement Agreement, amended on August 13, 2002, included agreements where Williams will sell $2.26 billion of its claims against WCG to Leucadia for $180 million and sell the Williams Technology Center and certain related assets to WCG for $145 million comprised of a $45 million 18-month note and a $100 million 7.5 year note. Both notes will be secured by a first lien on the assets sold to WCG. The Amended Disclosure Statement and Plan were filed by WCG with the bankruptcy court to reflect the August 13, 2002 amendment. The Settlement Agreement also provides for a release in favor of Williams of all claims by WCG and of certain claims that could be asserted by bondholders and other creditors. The Settlement Agreement satisfies the conditions of the pre-bankruptcy agreement with WCG. The transactions contemplated by the Settlement Agreement are subject to approval of the bankruptcy court and other parties and would close after such approval and after satisfaction of all conditions therein. Certain parties filed objections to portions of the Amended Disclosure Statement and certain parties may file objections to portions of the Amended Plan. On August 13, 2002, the bankruptcy court approved the Amended Disclosure Statement and Plan, set September 19, 2002 as the voting deadline for the Amended Plan, and set the confirmation hearing for September 25, 2002. The hearing before the bankruptcy court on the amended Settlement Agreement will be held on August 22, 2002. Competing reorganization alternatives may also impact the final outcome of the Settlement Agreement. At June 30, 2002, Williams estimated recoveries of its receivables and claims against WCG based on the agreements included in the Settlement Agreement. Williams believes the transactions contemplated by these agreements provide the most relevant information available to estimate the recovery of its receivables and claims from WCG, as they represent third party transactions that Williams management has accepted. 7 Notes (Continued) Prior to second-quarter 2002, Williams had estimated the recovery of its receivables from WCG by performing a financial analysis and utilizing the assistance of external legal counsel and an external financial and restructuring advisor. In preparing its financial analysis, Williams and its external financial and restructuring advisor considered the overall market condition of the telecommunications industry, financial projections provided by WCG, the potential impact of a bankruptcy on WCG's financial performance, the nature of the proposed restructuring as detailed in WCG's bankruptcy filing and various issues discussed in negotiations prior to WCG's bankruptcy filing. Actual recoveries may ultimately differ from currently estimated recoveries as the settlement agreements could be voided or amended as issues or challenges may be raised in the bankruptcy proceedings prior to finalization of the plan. If the settlement agreements were voided or amended, Williams' actual recoveries could differ from currently estimated recoveries as numerous factors will affect any recovery, including the form of consideration that Williams may receive from WCG's restructuring under bankruptcy, WCG's future performance, the length of time WCG remains in bankruptcy, customer reaction to WCG's bankruptcy filing, challenges to Williams' claims which may be raised in the bankruptcy proceedings, negotiations among WCG's secured creditors, its unsecured creditors and Williams, and the resolution of any related claims, issues or challenges that may be raised in the bankruptcy proceedings. 5. Investing income (loss) Estimated loss on realization of amounts due from Williams Communications Group, Inc. In second-quarter 2002, Williams recorded in continuing operations an additional pre-tax charge of $15 million related to WCG, including an assessment of the recoverability of certain receivables and claims from WCG. For the six months ended June 30, 2002, Williams has recorded in continuing operations pre-tax charges of $247 million related to the recoverability of these receivables and claims (see Note 4). Other Other investing income for the three and six months ended June 30, 2002 and 2001, is as follows:
Three months ended Six months ended June 30, June 30, ------------------ ---------------- (Millions) 2002 2001 2002 2001 ------ ------ ------ ------ Equity earnings* $ 40.8 $ 13.8 $ 48.3 $ 11.5 Interest income and other 14.0 21.2 22.6 57.5 ------ ------ ------ ------ Total other investing income $ 54.8 $ 35.0 $ 70.9 $ 69.0 ====== ====== ====== ======
* Item also included in segment profit (loss). Equity earnings (losses) for the three and six months ended June 30, 2002, include a benefit of $27.4 million, reflecting a contractual construction completion fee received by an equity affiliate of Williams whose operations are accounted for under the equity method of accounting. This equity affiliate served as the general contractor on the Gulfstream pipeline project for Gulfstream Pipeline Natural Gas System (Gulfstream), an interstate natural gas pipeline subject to Federal Energy Regulatory Commission (FERC) regulations and an equity affiliate of Williams. The fee paid by Gulfstream and associated with the early completion during second-quarter of the construction of Gulfstream's pipeline was capitalized by Gulfstream as property, plant and equipment and is included in Gulfstream's rate base to be recovered in future revenues. Also included in equity earnings (losses) for the three and six months ended June 30, 2002, is a $12.3 million write-down of Gas Pipeline's investment in a pipeline project which was cancelled in the second-quarter 2002. 8 Notes (Continued) 6. Provision (benefit) for income taxes The provision (benefit) for income taxes from continuing operations includes:
Three months ended Six months ended June 30, June 30, ------------------ ---------------- (Millions) 2002 2001 2002 2001 ------- ------- ------- ------ Current: Federal $ 29.1 $ 102.0 $ 36.7 $187.8 State (2.6) 20.3 -- 34.0 Foreign (3.6) -- -- 6.3 ------- ------- ------- ------ 22.9 122.3 36.7 228.1 Deferred: Federal (165.2) 81.7 (108.1) 198.0 State (15.7) 4.0 (6.2) 15.5 Foreign (6.6) 2.9 .1 2.2 ------- ------- ------- ------ (187.5) 88.6 (114.2) 215.7 ------- ------- ------- ------ Total provision (benefit) $(164.6) $ 210.9 $ (77.5) $443.8 ======= ======= ======= ======
The effective income tax rate for the three and six months ended June 30, 2002, is less than the federal statutory rate due primarily to the impairment of goodwill which is not deductible for income tax purposes and reduces the tax benefit of the pre-tax loss. The effective income tax rate for the three and six months ended June 30, 2001, is greater than the federal statutory rate due primarily to the effect of state income taxes. 7. Discontinued operations Kern River On March 27, 2002, Williams completed the sale of its Kern River pipeline for $450 million in cash and the assumption by the purchaser of $510 million in debt. As part of the agreement, $32.5 million of the purchase price was contingent upon Kern River receiving a certificate from the FERC to construct and operate a future expansion. This certificate was received in July 2002 and the contingent payment plus interest will be recognized as income from discontinued operations in third-quarter 2002. In accordance with the provisions related to discontinued operations within SFAS No. 144, the results of operations, financial position and cash flows for Kern River have been reflected in the accompanying consolidated financial statements and notes as discontinued operations. Williams Communications Group, Inc. On March 30, 2001, Williams' board of directors approved a tax-free spinoff of WCG to Williams' shareholders. Williams distributed 398.5 million shares, or approximately 95 percent of the WCG common stock held by Williams on April 23, 2001. In accordance with Accounting Principles Board Opinion (APB) No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual, and Infrequently Occurring Events and Transactions," the results of operations and cash flows for WCG have been reflected in the accompanying Consolidated Statement of Operations and Consolidated Statement of Cash Flows and notes as discontinued operations. See Note 4 for information regarding events in 2002 related to WCG. 9 Notes (Continued) Summarized results of discontinued operations for the three and six months ended June 30, 2002 and 2001, are as follows:
Three months ended Six months ended June 30, June 30, ------------------ ----------------- (Millions) 2002 2001 2002 2001 ------ ------ ------ ------- Kern River: Revenues $ -- $ 36.7 $ 40.3 $ 75.2 Income from operations before income taxes $ -- $ 16.8 $ 13.5 $ 34.9 Loss on sale of Kern River -- -- (38.1) -- (Provision) benefit for income taxes -- (6.1) 9.1 (12.8) ------ ------ ------ ------- Income (loss) from Kern River $ -- $ 10.7 $(15.5) $ 22.1 ------ ------ ------ ------- WCG: Revenues $ -- $ -- $ -- $ 329.5 Loss from operations before income taxes $ -- $ -- $ -- $(271.3) Benefit for income taxes -- -- -- 92.2 ------ ------ ------ ------- Loss from WCG $ -- $ -- $ -- $(179.1) ------ ------ ------ ------- Total income (loss) from discontinued operations $ -- $ 10.7 $(15.5) $(157.0) ====== ====== ====== =======
8. Earnings (loss) per share Basic and diluted earnings (loss) per common share are computed as follows:
(Dollars in millions, except per-share Three months ended Six months ended amounts; shares in thousands) June 30, June 30, ---------------------- ---------------------- 2002 2001 2002 2001 --------- --------- --------- --------- Income (loss) from continuing operations $ (349.1) $ 328.8 $ (225.9) $ 695.7 Preferred stock dividends (see Note 14) (6.8) -- (76.5) -- --------- --------- --------- --------- Income (loss) from continuing operations available to common stockholders for basic and diluted earnings per share $ (355.9) $ 328.8 $ (302.4) $ 695.7 --------- --------- --------- --------- Basic weighted-average shares 520,427 487,211 519,829 483,173 Effect of dilutive securities: Stock options -- 4,487 -- 4,354 --------- --------- --------- --------- Diluted weighted-average shares 520,427 491,698 519,829 487,527 --------- --------- --------- --------- Earnings (loss) per share from continuing operations: Basic $ (.68) $ .68 $ (.58) $ 1.44 Diluted $ (.68) $ .67 $ (.58) $ 1.42 ========= ========= ========= =========
For the three and six months ended June 30, 2002, diluted earnings (loss) per share is the same as the basic calculation. The inclusion of any stock options and convertible preferred stock would be antidilutive as Williams reported a loss from continuing operations for these periods. As a result, approximately .6 million and 1.3 million weighted-average stock options for the three and six months ended June 30, 2002, respectively, that otherwise would have been included, were excluded from the computation of diluted earnings per common share. Additionally, approximately 14.7 million and 7.8 million weighted-average shares for the three and six months ended June 30, 2002, respectively, related to the assumed conversion of 9 7/8 percent cumulative convertible preferred stock have been excluded from the computation of diluted earnings per common share. 10 Notes (Continued) 9. Restricted cash The current and noncurrent restricted cash is primarily invested in short-term money market accounts with financial institutions and an insurance company. Restricted cash within current assets is collateral in support of a financial guarantee and letters of credit. The contractual obligation requiring a significant portion of this collateral expires December 2002. The contractual obligations requiring the remaining collateral pertain to current operations. Restricted cash within noncurrent assets is collateral in support of surety bonds underwritten by an insurance company. Williams does not expect this cash to be released within the next twelve months. The classification of restricted cash is determined based on the expected term of the collateral requirement and not necessarily the maturity date of the underlying securities. 10. Inventories Inventories at June 30, 2002 and December 31, 2001 are as follows:
June 30, December 31, (Millions) 2002 2001 ------- ------------ Raw materials: Crude oil $ 194.1 $ 117.7 Other 1.3 1.3 ------ ------- 195.4 119.0 Finished goods: Refined products 306.8 265.0 Natural gas liquids 142.0 142.6 General merchandise 19.3 14.5 ------- ------- 468.1 422.1 ------- ------- Materials and supplies 146.2 134.0 Natural gas in underground storage 157.1 136.4 Other 2.4 1.7 ------- ------- $ 969.2 $ 813.2 ======= =======
11. Debt and banking arrangements The following discussions relate to Williams' debt and related facilities as of and for the six months ended June 30, 2002. See Note 18 for the significant changes to Williams' debt and related facilities, including certain operating leases, which occurred subsequent to June 30, 2002. Notes payable At June 30, 2002, Williams had a $2.2 billion commercial paper program which was backed by a short-term bank-credit facility with zero outstanding under this program. The commercial paper program and the short-term credit facility expired July 24, 2002. In addition, Williams has entered into various short-term credit agreements with amounts outstanding totaling $711 million at June 30, 2002. The weighted-average interest rate on these notes at June 30, 2002 was 3.7 percent. During July 2002, $300 million of the balance was repaid. The remaining $411 million matures in October 2002, and is payable by Williams Energy Partners L.P. 11 Notes (Continued) Debt Long-term debt at June 30, 2002 and December 31, 2001, is as follows:
Weighted- average interest June 30, December 31, (Millions) rate(1) 2002 2001 --------- --------- ------------ Revolving credit loans 3.3% $ 59.5 $ 53.7 Commercial paper -- -- 300.0 Debentures, 6.25% - 10.25%, payable 2003 - 2031 7.4 1,576.3 1,585.4 Notes, 5.1% - 9.45%, payable through 2032 (2) 7.4 10,467.7 6,835.3 Notes, adjustable rate, payable through 2004 3.0 1,377.5 1,192.9 Other, payable through 2016 7.7 127.3 60.2 ------ --------- --------- 13,608.3 10,027.5 Current portion of long-term debt (1,636.3) (1,014.8) --------- --------- $11,972.0 $ 9,012.7 ========= =========
(1) At June 30, 2002, including the effect of interest rate swaps. (2) $400 million of 6.75% notes, payable 2016, putable/callable in 2006 and $1.1 billion of 6.5% notes payable 2007, subject to remarketing in 2004. Williams' December 31, 2001, long-term debt included $300 million of commercial paper, $300 million of short-term debt obligations and $244 million of long-term debt obligations due within one year, which would have otherwise been classified as current, but were classified as noncurrent based on Williams' intent and ability to refinance on a long-term basis. At June 30, 2002, $275 million of current debt obligations of Transcontinental Gas Pipe Line have been classified as noncurrent based on Transcontinental Gas Pipe Line's July 2002 issuance of $325 million of 8.875 percent long-term debt obligations due 2012. Under the terms of Williams' $700 million revolving credit agreement, Northwest Pipeline, Transcontinental Gas Pipe Line and Texas Gas Transmission have access to various amounts of the facility, while Williams (Parent) has access to all unborrowed amounts. Interest rates vary with current market conditions. The provisions of this agreement relating to financial ratios and other covenants were modified subsequent to June 30, 2002. See Note 18 for changes to this facility, which is now a secured facility, subsequent to June 30, 2002. Additionally, certain Williams subsidiaries have revolving credit facilities with a total capacity of $116 million at June 30, 2002. One such facility, totalling $31 million, has subsequently been terminated. Pursuant to completion of a consent solicitation during first-quarter 2002 with WCG Note Trust holders, Williams recorded $1.4 billion of long-term debt obligations which mature in March 2004 and bear an interest rate of 8.25 percent (see Note 4). Subsequent to June 30, 2002, Williams completed an exchange of Williams 9.25 percent notes due March 2004 for substantially all of these securities. In March 2002, the terms of a Williams $560 million priority return structure, previously classified as preferred interest in consolidated subsidiaries, were amended. The amendment provided for the outside investor's preferred interest to be redeemed in equal quarterly installments through April 2003 (see Note 13). The interest rate varies based on LIBOR plus an applicable margin and was 2.57 percent at June 30, 2002. Based on the new payment terms, the preferred interest was reclassified to debt, of which $448 million is classified as long-term debt due within one year at June 30, 2002. In April 2002, $112 million was redeemed. In May 2002, Energy Marketing & Trading entered into an agreement which transferred the rights to certain receivables in exchange for cash. Due to the structure of the agreement, Energy Marketing & Trading accounted for this transaction as debt collateralized by the claims. The $78.7 million of debt is classified as current. 12 Notes (Continued) In addition to the items discussed above, significant long-term debt issuances and retirements, other than amounts under revolving credit agreements, for the six months ended June 30, 2002 are as follows:
Principal Issue/Terms Due Date Amount ----------- -------- --------- (Millions) Issuances of long-term debt in 2002: 6.5% notes (see Note 14) 2007 $1,100.0 8.125% notes 2012 650.0 8.75% notes 2032 850.0 Retirements/prepayments of long-term debt in 2002: 6.125% notes (1) 2012 $ 240.0 Various notes, 6.65%-9.45% 2002 134.0 Various notes, adjustable rate 2002 37.9
(1) Subject to redemption at par in 2002. Williams' ratio of net debt to consolidated net worth plus net debt, as defined in Williams' Current Report on Form 8-K dated May 28, 2002, was 63.5 percent at June 30, 2002, as compared to 61.5 percent at December 31, 2001. 12. Contingent liabilities and commitments Rate and regulatory matters and related litigation Williams' interstate pipeline subsidiaries have various regulatory proceedings pending. As a result of rulings in certain of these proceedings, a portion of the revenues of these subsidiaries has been collected subject to refund. The natural gas pipeline subsidiaries have accrued approximately $178 million for potential refund as of June 30, 2002. As a result of FERC Order 636 decisions in prior years, 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. Williams Energy Marketing & Trading Company (Energy Marketing & Trading) subsidiaries are engaged in power marketing in various geographic areas, including California. Prices charged for power by Williams and other traders and generators in California and other western states have been challenged in various proceedings including those before the FERC. In December 2000, the FERC issued an order which provided that, for the period between October 2, 2000 and December 31, 2002, it may order refunds from Williams and other similarly situated companies if the FERC finds that the wholesale markets in California are unable to produce competitive, just and reasonable prices or that market power or other individual seller conduct is exercised to produce an unjust and unreasonable rate. Beginning on March 9, 2001, the FERC issued a series of orders directing Williams and other similarly situated companies to provide refunds for any prices charged in excess of FERC-established proxy prices in January, February, March, April and May 2001, or to provide justification for the prices charged during those months. According to these orders, Williams' total potential refund liability for January through May 2001 is approximately $30 million. Williams has filed justification for its prices with the FERC and calculated its refund liability under the methodology used by the FERC to compute refund amounts at approximately $11 million. On July 25, 2001, the FERC issued an order establishing a hearing to establish the facts necessary to determine refunds under the approved methodology. On August 13, 2002, the FERC issued its preliminary findings as to its investigation into Western markets (discussed below), which call into question the gas price methodology established in the July 25, 2001 order. Any change from the July 25, 2001 methodology would likely result in increased refund liability for Energy Marketing & Trading. Refunds will cover the period of October 2, 2000 through June 20, 2001. They will be paid as offsets against outstanding bills and are inclusive of any amounts previously noticed for refund for that period. The judge presiding over the refund proceedings is expected to issue his findings in November 2002. The FERC will subsequently issue a refund order based on these findings. In an order issued June 19, 2001, the FERC implemented a revised price mitigation and market monitoring plan for wholesale power sales by all suppliers of electricity, including Williams, in spot markets for a region that includes California and ten other western states (the "Western Systems Coordinating Council," or "WSCC"). In general, the plan, which will be in effect from June 20, 2001 through September 30, 2002, establishes a market clearing price for spot sales in all hours of the day that is based on the bid of the highest-cost gas-fired California generating unit that is needed to serve the Independent System Operator's (ISO's) load. When generation operating reserves fall below seven percent in California (a "reserve deficiency period"), absent cost-based justification for a higher price, the maximum price that Williams may charge for wholesale spot sales in the WSCC is the market clearing price. When generation operating reserves rise to seven percent or above in California, absent cost-based 13 Notes (Continued) justification for a higher price, Williams' maximum price will be limited to 85 percent of the highest hourly price that was in effect during the most recent reserve deficiency period. This methodology initially resulted in a maximum price of $92 per megawatt hour during non-emergency periods and $108 per megawatt hour during emergency periods, and these maximum prices remained unchanged throughout summer and fall 2001. Revisions to the plan for the post-September 30, 2002, period were provided on July 17, 2002 as discussed below. On December 19, 2001, the FERC reaffirmed its June 19 and July 25 orders with certain clarifications and modifications. It also altered the price mitigation methodology for spot market transactions for the WSCC market for the winter 2001 season and set the period maximum price at $108 per megawatt hour through April 30, 2002. Under the order, this price would be subject to being recalculated when the average gas price rises by a minimum factor of ten percent effective for the following trading day, but in no event will the maximum price drop below $108 per megawatt hour. The FERC also upheld a ten percent addition to the price applicable to sales into California to reflect credit risk. On July 9, 2002 the ISO's operating reserve levels dropped below seven percent for a full operating hour, during which the ISO declared a Stage 1 System Emergency resulting in a new Market Clearing Price cap of $57.14/MWh under the FERC's rules. On July 11, 2002, the FERC issued an order that the existing price mitigation formula be replaced with a hard price cap of $91.87/MWh for spot markets operated in the West (which is the level of price mitigation that existed prior to the July 9, 2002, events that reduced the cap), to be effective July 12, 2002. The cap will expire when the currently effective West-wide mitigation plan expires on September 30, 2002. On July 17, 2002, the FERC issued its first order on the California ISO's proposed market redesign. Key elements of the order include (1) maintaining indefinitely the current must-offer obligation across the West; (2) the adoption of Automatic Mitigation Procedures (AMP) to identify and limit excessive bids and local market power within California, (bids less than $91.87/MWh will not be subject to AMP); (3) a West-wide spot market bid cap of $250/MWh, beginning October 1, 2002, and continuing indefinitely; (4) required the ISO to expedite the following market design elements and requiring them to be filed by October 21, 2002: (a) creation of an integrated day-ahead market; (b) ancillary services market reforms; and (c) hour-ahead and real-time market reforms; and (5) the development of locational marginal pricing (LMP). The California Public Utilities Commission (CPUC) filed a complaint with the FERC on February 25, 2002, seeking to void or, alternatively, reform a number of the long-term power purchase contracts entered into between the State of California and several suppliers in 2001, including Energy Marketing & Trading. The CPUC alleges that the contracts are tainted with the exercise of market power and significantly exceed "just and reasonable" prices. The Electricity Oversight Board made a similar filing on February 27, 2002. The FERC set the complaint for hearing on April 25, 2002, but held the hearing in abeyance pending settlement discussions before a FERC judge. The FERC also ordered that the higher public interest test will apply to the contracts. The FERC commented that the state has a very heavy burden to carry in proving its case. On July 17, 2002, the FERC denied rehearing of the April 25, 2002 order that set for hearing California's challenges to the long-term contracts entered into between the state and several suppliers, including Energy Marketing & Trading. Energy Marketing & Trading will appeal the order. The settlement discussions noted above have resulted in Williams reaching a settlement in principle with the State of California on a global settlement that includes a renegotiated long-term energy contract. The settlement will also resolve complaints brought by the California Attorney General against Williams that are discussed below and the State of California's refund claims that are discussed above. In addition, the settlement will resolve ongoing investigations by the States of California, Oregon and Washington. The settlement is subject to documentation and approval by various courts and agencies. On May 2, 2002, PacifiCorp filed a complaint against Energy Marketing & Trading seeking relief from rates contained in three separate confirmation agreements between PacifiCorp and Energy Marketing & Trading (known as the Summer 2002 90-Day Contracts). PacifiCorp filed similar complaints against three other suppliers. PacifiCorp alleges that the rates contained in the contracts are unjust and unreasonable. Energy Marking & Trading filed its answer on May 22, 2002, requesting that the FERC reject the complaint and deny the relief sought. On June 28, 2002, the FERC set PacifiCorp's complaints for hearing, but held the hearing in abeyance pending the outcome of settlement judge proceedings. If the case goes to hearing, the FERC stated that PacifiCorp will bear a heavy burden of proving that the extraordinary remedy of contract modification is justified. The FERC set a refund effective date of July 1, 2002. Should the matter go to hearing, a final decision should be issued by May 31, 2003. Certain entities have also asked the FERC to revoke Williams' authority to sell power from California-based generating units at market-based rates to limit Williams to cost-based rates for future sales from such units and to order refunds of excessive rates, with interest, retroactive to May 1, 2000, and possibly earlier. On March 14, 2001, the FERC issued a Show Cause Order directing Energy Marketing & Trading and AES Southland, Inc. to show cause why they should not be found to have engaged in violations of the Federal Power Act and various agreements, and they were directed to make refunds in the aggregate of approximately $10.8 million, and have certain conditions placed on Williams' market-based rate authority for sales from specific generating 14 Notes (Continued) facilities in California for a limited period. On April 30, 2001, the FERC issued an Order approving a settlement of this proceeding. The settlement terminated the proceeding without making any findings of wrongdoing by Williams. Pursuant to the settlement, Williams agreed to refund $8 million to the ISO by crediting such amount against outstanding invoices. Williams also agreed to prospective conditions on its authority to make bulk power sales at market-based rates for certain limited facilities under which it has call rights for a one-year period. Williams also has been informed that the facts underlying this proceeding are also under investigation by a California Grand Jury. On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking (NOPR) proposing to adopt uniform standards of conduct for transmission providers. The proposed rules define transmission providers as interstate natural gas pipelines and public utilities that own, operate or control electric transmission facilities. The proposed standards would regulate the conduct of transmission providers with their energy affiliates. The FERC proposes to define energy affiliates broadly to include any transmission provider affiliate that engages in or is involved in transmission (gas or electric) transactions, or manages or controls transmission capacity, or buys, sells, trades or administers natural gas or electric energy or engages in financial transactions relating to the sale or transmission of natural gas or electricity. Current rules affecting Williams regulate the conduct of Williams' natural gas pipelines and their natural gas marketing affiliates. The FERC invited interested parties to comment on the NOPR. On April 25, 2002, the FERC issued its staff analysis of the NOPR and the comments received. The staff analysis proposes redefining the definition of energy affiliates to exclude affiliated transmission providers. On May 21, 2002, the FERC held a public conference concerning the NOPR and the FERC invited the submission of additional comments. If adopted, these new standards would require the adoption of new compliance measures by certain Williams subsidiaries. On July 17, 2002, the FERC issued a Notice of Inquiry to seek comments on its negotiated rate policies and practices. The FERC states that it is undertaking a review of the recourse rate as a viable alternative and safeguard against the exercise of market power of interstate gas pipelines, as well as the entire spectrum of issues related to its negotiated rate program. The FERC has requested that interested parties respond to various questions related to the FERC's negotiated rate policies and practices. On August 1, 2002, the FERC issued a NOPR that proposes restrictions on the type of cash management program employed by Williams and its subsidiaries. In addition to stricter guidelines regarding the accounting for and documentation of cash management or cash pooling programs, the FERC proposal, if made final, would preclude public utilities, natural gas companies and oil pipeline companies from participating in such programs unless the parent company and its FERC-regulated affiliate maintain investment-grade credit ratings and that the FERC-regulated affiliate maintain stockholders equity of at least 30 percent of total capitalization. Williams' and its regulated gas pipelines' current credit ratings are not investment grade. The FERC is seeking public comments by August 22, 2002. On February 13, 2002, the FERC issued an Order Directing Staff Investigation commencing a proceeding titled Fact-Finding Investigation of Potential Manipulation of Electric and Natural Gas Prices. Through the investigation, the FERC intends to determine whether "any entity, including Enron Corporation (Enron) (through any of its affiliates or subsidiaries), manipulated short-term prices for electric energy or natural gas in the West or otherwise exercised undue influence over wholesale electric prices in the West, since January 1, 2000, resulting in potentially unjust and unreasonable rates in long-term power sales contracts subsequently entered into by sellers in the West." This investigation does not constitute a Federal Power Act complaint, rather, the results of the investigation will be used by the FERC in any existing or subsequent Federal Power Act or Natural Gas Act complaint. The FERC Staff is directed to complete the investigation as soon as "is practicable." Williams, through many of its subsidiaries, is a major supplier of natural gas and power in the West and, as such, anticipates being the subject of certain aspects of the investigation. Williams is cooperating with all data requests received in this proceeding. On May 8, 2002, Williams received an additional set of data requests from the FERC related to a recent disclosure by Enron of certain trading practices in which it may have been engaged in the California market. On May 21, and May 22, 2002, the FERC supplemented the request inquiring as to "wash" or "round trip" transactions. Williams responded on May 22, 2002, May 31, 2002, and June 5, 2002, to the data requests. On June 4, 2002, the FERC issued an order to Williams to show cause why its market-based rate authority should not be revoked as the FERC found that certain of Williams' responses related to the Enron trading practices constituted a failure to cooperate with the staff's investigation. Williams subsequently supplemented its responses to address the show cause order. On July 26, 2002, Williams received a letter from the FERC informing Williams that it had reviewed all of Williams' supplemental responses and concluded that they responded to the initial May 8, 2002 request. In response to an article appearing in the New York Times on June 2, 2002, containing allegations by a former Williams employee that it had attempted to "corner" the natural gas market in California, and at Williams' invitation, the FERC is conducting an investigation into these allegations. Also, the Commodity Futures Trading Commission (CFTC) is conducting an investigation regarding gas and power trading in Western markets and has requested information from Williams in connection with this investigation. On May 31, 2002, Williams received a request from the Securities and Exchange Commission (SEC) to 15 Notes (Continued) voluntarily produce documents and information regarding any prearranged or contemporaneous buy and sell ("round-trip") trades for gas or power from January 1, 2000, to the present in the United States. On June 24, 2002, the SEC made an additional request for information including a request that Williams address the amount of Williams' credit, prudency and/or other reserves associated with its energy trading activities and the methods used to determine or calculate these reserves. The June 24, 2002, request also requested Williams' volumes, revenues, and earnings from its energy trading activities in the Western U.S. market. Williams is in the process of responding to the SEC's requests. On March 20, 2002, the California Attorney General filed a complaint with the FERC alleging that Williams and all other sellers of power in California have failed to comply with federal law requiring the filing of rates and charges for power. While the FERC rejected the complaint that the market-based rate filing requirements violate the Federal Power Act, it directed the refiling of quarterly reports for periods after October 2000 to include transaction specific information. On July 3, 2002, the ISO announced fines against several energy producers including Williams, for failure to deliver electricity in 2001 as required. The ISO fined Williams $25.5 million, which will be offset against Williams' claims for payment from the ISO. Williams believes the vast majority of fines are not justified and has challenged the fines pursuant to the FERC-approved process contained in the ISO tariff. 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, 2002, these subsidiaries had accrued liabilities totaling approximately $32 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 Williams Gas Pipelines Central (Central) have identified polychlorinated biphenyl contamination in air compressor systems, soils and related properties at certain compressor station sites. Transcontinental Gas Pipe Line, Texas Gas and Central have also been involved in negotiations with the U.S. Environmental Protection Agency (EPA) and state agencies to develop screening, sampling and cleanup programs. In addition, negotiations with certain environmental authorities and other programs concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites have been commenced by Central, Texas Gas and Transcontinental Gas Pipe Line. As of June 30, 2002, Central had accrued a liability for approximately $8 million, representing the current estimate of future environmental cleanup costs to be incurred over the next six to ten years. Texas Gas and Transcontinental Gas Pipe Line likewise had accrued liabilities for these costs which are included in the $32 million liability 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. Williams Energy Services (WES) and its subsidiaries also accrue environmental remediation costs for its natural gas gathering and processing facilities, petroleum products pipelines, retail petroleum and refining operations and for certain facilities related to former propane marketing operations primarily related to soil and groundwater contamination. In addition, WES owns a discontinued petroleum refining facility that is being evaluated for potential remediation efforts. At June 30, 2002, WES and its subsidiaries had accrued liabilities totaling approximately $36 million for these costs. WES accrues receivables related to environmental remediation costs based upon an estimate of amounts that will be reimbursed from state funds for certain expenses associated with underground storage tank problems and repairs. At June 30, 2002, WES and its subsidiaries had accrued receivables totaling $1 million. In connection with the 1987 sale of the assets of Agrico Chemical Company, Williams agreed to indemnify the purchaser for environmental cleanup costs resulting from certain conditions at specified locations, to the extent such costs exceed a specified amount. At June 30, 2002, Williams had approximately $10 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. 16 Notes (Continued) On July 2, 2001, the EPA issued an information request asking for information on oil releases and discharges in any amount from Williams' pipelines, pipeline systems, and pipeline facilities used in the movement of oil or petroleum products, during the period July 1, 1998 through July 2, 2001. In November 2001, Williams furnished its response. Other legal matters In connection with agreements to resolve take-or-pay and other contract claims and to amend gas purchase contracts, Transcontinental Gas Pipe Line and Texas Gas each entered into certain settlements with producers which may require the indemnification of certain claims for additional royalties which the producers may be required to pay as a result of such settlements. As a result of such settlements, Transcontinental Gas Pipe Line is currently defending two lawsuits brought by producers. In another case, 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. In addition, through December 31, 2001, post-judgment interest was approximately $10.5 million. Transcontinental Gas Pipe Line's appeals were denied by the Texas Court of Appeals for the First District of Texas, and on April 2, 2001, the company filed an appeal to the Texas Supreme Court. On February 21, 2002, the Texas Supreme Court denied Transcontinental Gas Pipe Line's petition for review. As a result, Transcontinental Gas Pipe Line recorded a fourth-quarter 2001 pre-tax charge to income (loss) for the year ended December 31, 2001, in the amount of $37 million ($18 million was included in Gas Pipeline's segment profit and $19 million in interest accrued) representing management's estimate of the effect of this ruling. Transcontinental Gas Pipe Line filed a motion for rehearing which was denied, thereby concluding this matter. In May 2002, Transcontinental Gas Pipe Line paid Texaco the amount of the judgment plus accrued interest. In the other cases, producers have asserted damages, including interest calculated through December 31, 2001, of $16.3 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. On June 8, 2001, fourteen Williams entities were named as defendants in a nationwide class action lawsuit which has been pending against other defendants, generally pipeline and gathering companies, for more than one year. The plaintiffs allege that the defendants, including the Williams defendants, have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs. In September 2001, the plaintiffs voluntarily dismissed two of the fourteen Williams entities named as defendants in the lawsuit. In November 2001, Williams, along with other Coordinating Defendants, filed a motion to dismiss under Rules 9b and 12b of the Kansas Rules of Civil Procedure. In January 2002, most of the Williams defendants, along with a group of Coordinating Defendants, filed a motion to dismiss for lack of personal jurisdiction. The court has not yet ruled on these motions. In the next several months, the Williams entities will join with other defendants in contesting certification of the plaintiff class. In 1998, the United States Department of Justice (DOJ) 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. In connection with its sale of Kern River, the Company agreed to indemnify the purchaser for liability relating to this claim. 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 DOJ 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. On October 21, 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tam cases, including those filed against Williams, to the United States District Court for the District of Wyoming for pre-trial purposes. Motions to dismiss the complaints filed by various defendants, including Williams, were denied on May 18, 2001. On August 6, 2002, Jack J. Grynberg, and Celeste C. Grynberg, Trustee on Behalf of the Rachel Susan Grynberg Trust, and the Stephen Mark Grynberg Trust, served The Williams Companies and Williams Production RMT Company with a complaint in the District Court in and for the City of Denver, State of Colorado. The complaint alleges that the defendants have used mismeasurement techniques that distort the BTU heating content of natural gas, resulting in the alleged underpayment of royalties to Grynberg and other independent natural gas producers. The complaint also alleges that defendants inappropriately took deductions from the gross value of their natural gas and made other royalty valuation errors. Theories for relief include breach of contract, breach of implied covenant of good faith and fair dealing, anticipatory repudiation, declaratory relief, equitable accounting, civil theft, deceptive trade practices, negligent misrepresentation, deceit based on fraud, conversion, breach of fiduciary duty, and violations of the state racketeering statute. Plaintiff is seeking actual damages of between $2 million and 17 Notes (Continued) $20 million based on interest rate variations, and punitive damages in the amount of approximately $1.4 million dollars. Williams will vigorously defend against the claims and does not believe they have merit. Williams and certain of its subsidiaries are named as defendants in various putative, nationwide class actions brought on behalf of all landowners on whose property the plaintiffs have alleged WCG installed fiber-optic cable without the permission of the landowners. Williams and its subsidiaries were dismissed from all of the cases, except one. The parties in the only remaining case in which Williams or its subsidiaries are named as defendants have reached a settlement in principle and are in the process of drafting the settlement documents. The settlement does not obligate Williams or its subsidiaries to pay any monies to the remaining plaintiff. In November 2000, class actions were filed in San Diego, California Superior Court by Pamela Gordon and Ruth Hendricks on behalf of San Diego rate payers against California power generators and traders including Williams Energy Services Company and Energy Marketing & Trading, subsidiaries of Williams. Three municipal water districts also filed a similar action on their own behalf. Other class actions have been filed on behalf of the people of California and on behalf of commercial restaurants in San Francisco Superior Court. These lawsuits result from the increase in wholesale power prices in California that began in the summer of 2000. Williams is also a defendant in other litigation arising out of California energy issues. The suits claim that the defendants acted to manipulate prices in violation of the California antitrust and unfair business practices statutes and other state and federal laws. Plaintiffs are seeking injunctive relief as well as restitution, disgorgement, appointment of a receiver, and damages, including treble damages. These cases have all been coordinated in San Diego County Superior Court. On May 2, 2001, the Lieutenant Governor of the State of California and Assemblywoman Barbara Matthews, acting in their individual capacities as members of the general public, filed suit against five companies and fourteen executive officers, including Energy Marketing & Trading and Williams' then current officers Keith Bailey, Chairman and CEO of Williams, Steve Malcolm, President and CEO of Williams Energy Services and an Executive Vice President of Williams, and Bill Hobbs, Senior Vice President of Energy Marketing & Trading, in Los Angeles Superior State Court alleging State Antitrust and Fraudulent and Unfair Business Act Violations and seeking injunctive and declaratory relief, civil fines, treble damages and other relief, all in an unspecified amount. This case is being coordinated with the other class actions in San Diego Superior Court. On May 17, 2001, the DOJ advised Williams that it had commenced an antitrust investigation relating to an agreement between a subsidiary of Williams and AES Southland alleging that the agreement limits the expansion of electric generating capacity at or near the AES Southland plants that are subject to a long-term tolling agreement between Williams and AES Southland. In connection with that investigation, the DOJ has issued two Civil Investigative Demands to Williams requesting answers to certain interrogatories and the production of documents. Williams is cooperating with the investigation. On October 5, 2001, a suit was filed on behalf of California taxpayers and electric ratepayers in the Superior Court for the County of San Francisco against the Governor of California and 22 other defendants consisting of other state officials, utilities and generators, including Energy Marketing & Trading. The suit alleges that the long-term power contracts entered into by the state with generators are illegal and unenforceable on the basis of fraud, mistake, breach of duty, conflict of interest, failure to comply with law, commercial impossibility and change in circumstances. Remedies sought include rescission, reformation, injunction, and recovery of funds. Five similar cases have also been brought by private plaintiffs against Williams and others on similar grounds. These suits have all been removed to federal court, and plaintiffs are seeking to remand the cases to state court. On March 11, 2002, the California Attorney General filed a civil complaint in San Francisco Superior Court against Williams and three other sellers of electricity alleging unfair competition relating to sales of ancillary power services between 1998 and 2000. The complaint seeks restitution, disgorgement and civil penalties of approximately $150 million in total. This case has been removed to federal court. On April 9, 2002, the California Attorney General filed a civil complaint in San Francisco Superior Court against Williams and three other sellers of electricity alleging unfair and unlawful business practices related to charges for electricity during and after 2000. The maximum penalty for each violation is $2,500 and the complaint seeks a total fine in excess of $1 billion. 18 Notes (Continued) These cases have been removed to federal court. Motions to remand have been denied. Finally, the California Attorney General has indicated he may file a Clayton Act complaint against AES Southland and Williams relating to AES Southland's acquisition of Southern California generation facilities in 1998, tolled by Williams. Williams believes the complaints against it are without merit. Since January 29, 2002, Williams is aware of numerous shareholder class action suits that have been filed in the United States District Court for the Northern District of Oklahoma. The majority of the suits allege that Williams and co-defendants, WCG and certain corporate officers, have acted jointly and separately to inflate the stock price of both companies. Other suits allege similar causes of action related to a public offering in early January 2002, known as the FELINE PACS offering. These cases were filed against Williams, certain corporate officers, all members of the Williams board of directors and all of the offerings' underwriters. Williams does not anticipate any immediate action by the Court in these actions. These cases have all been consolidated and an order has been issued requiring separate amended consolidated complaints by Williams and Williams Communications equity holders. In addition, four class action complaints have been filed against Williams and the members of its board of directors under the Employee Retirement Income Security Act by participants in Williams' 401(k) plan. A motion to consolidate these suits has been approved. Derivative shareholder suits have been filed in state court in Oklahoma, all based on similar allegations. On August 1, 2002, a motion to consolidate and a motion to stay these suits pending action by the federal court in the shareholder suits was approved. Williams was selected by the U.S. Trustee to serve on the Official Committee of Unsecured Creditors in the WCG bankruptcy. At its initial meeting, the committee formed a subcommittee creditors committee, which excludes Williams, to investigate what rights and remedies, if any, the creditors may have against Williams relating to its dealings with WCG. Williams has entered into an agreement with WCG in which Williams agreed not to object to a plan of reorganization submitted by WCG in its bankruptcy if that plan provides (i) for WCG to assume its obligations under certain service agreements and the sale leaseback transaction with Williams and (ii) for Williams' other claims to be treated as general unsecured claims with treatment substantially identical to the treatment of claims by WCG's bondholders. This matter is discussed more fully in Note 4. On April 26, 2002, the Oklahoma Department of Securities issued an order initiating an investigation of Williams and WCG regarding issues associated with the spin-off of WCG and regarding the WCG bankruptcy. Williams has committed to cooperate fully in the investigation. On November 30, 2001, Shell Offshore, Inc. filed a complaint at the FERC against Williams Gas Processing - Gulf Coast Company, L.P. (WGP), Williams Field Services Company (WFS) and Transcontinental Gas Pipe Line Corporation (Transco), alleging concerted actions by the affiliates frustrating the FERC's regulation of Transco. The alleged actions are related to offers of gathering service by WFS and its subsidiaries on the recently spundown and deregulated offshore pipeline system, the North Padre Island gathering system. By order of the FERC the matter was heard before an administrative law judge in April 2002. On June 4, 2002, the administrative law judge issued an initial decision finding that the affiliates acted in concert to frustrate the FERC's regulation of Transco and recommending that the FERC reassert jurisdiction over the North Padre Island gathering system. Transco, WGP and WFS believe their actions were reasonable and lawful and submitted briefs taking exceptions to the initial decision. FERC has yet to act. In addition to the foregoing, various other proceedings are pending against Williams or its subsidiaries which are incidental to their operations. Enron and certain of its subsidiaries, with whom Energy Marketing & Trading and other Williams subsidiaries have had commercial relations, filed a voluntary petition for Chapter 11 reorganization under the U.S. Bankruptcy Code in the Federal District Court for the Southern District of New York on December 2, 2001. Additional Enron subsidiaries have subsequently filed for Chapter 11 protection. The court has not set a date within which claims may be filed. During fourth-quarter 2001, Energy Marketing & Trading recorded a total decrease to revenues of approximately $130 million as a part of its valuation of energy commodity and derivative trading contracts with Enron entities, approximately $91 million of which was recorded pursuant to events immediately preceding and following the announced bankruptcy of Enron. Other Williams subsidiaries recorded approximately $5 million of bad debt expense related to amounts receivable from Enron entities in fourth-quarter 2001, reflected in selling, general and administrative expenses. At December 31, 2001, Williams has reduced its recorded exposure to accounts receivable from Enron entities, net of margin deposits, to expected recoverable amounts. During first-quarter 2002, Energy Marketing & Trading sold rights to certain Enron receivables to a third party in exchange for $24.5 million in cash. The $24.5 million is recorded within the trading revenues in first-quarter 2002. 19 Notes (Continued) Summary While no assurances may be given, Williams, based on advice of counsel, 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. Commitments Energy Marketing & Trading has entered into certain contracts giving it the right to receive fuel conversion services as well as certain other services associated with electric generation facilities that are either currently in operation or are to be constructed at various locations throughout the continental United States. At June 30, 2002, annual estimated committed payments under these contracts range from approximately $53 million to $462 million, resulting in total committed payments over the next 20 years of approximately $8 billion. 13. Preferred interests in consolidated subsidiaries In December 2000, Williams formed two separate legal entities, Snow Goose Associates, L.L.C. (Snow Goose) and Arctic Fox Assets, L.L.C. (Arctic Fox) for the purpose of generating funds to invest in certain Canadian energy-related assets. An outside investor contributed $560 million in exchange for the non-controlling preferred interest in Snow Goose. The investor in Snow Goose is entitled to quarterly priority distributions. The initial priority return structure was originally scheduled to expire in December 2005. During first-quarter 2002, the terms of the priority return were amended. Significant terms of the amendment include elimination of covenants regarding Williams' credit ratings, modifications of certain Canadian interest coverage covenants and a requirement to amortize the outside investor's preferred interest with equal principal payments due each quarter and the final payment in April 2003. In addition, Williams provided a financial guarantee of the Arctic Fox note payable to Snow Goose which, in turn, is the source of the priority returns. Based on the terms of the amendment, the remaining balance due is classified as long-term debt due within one year on Williams' Consolidated Balance Sheet at June 30, 2002. Priority returns prior to this amendment are included in preferred returns and minority interest in income of consolidated subsidiaries on the Consolidated Statement of Income. Subsequent to June 30, 2002, the $135 million preferred interest in Williams Risk Holdings L.L.C. was redeemed following the downgrades in Williams' credit ratings in July 2002. Additionally, terms of the $200 million preferred interest in Castle Associates L.P. and the $100 million preferred interest in Piceance Production Holdings LLC were amended subsequent to June 30, 2002, and as a result the $200 million and $100 million, respectively, will be classified as debt beginning in July 2002. 14. Stockholders' equity Concurrent with the sale of Kern River to MEHC, Williams issued approximately 1.5 million shares of 9 7/8 percent cumulative convertible preferred stock to MEHC for $275 million. The terms of the preferred stock allow the holder to convert, at any time, one share of preferred stock into 10 shares of Williams common stock at $18.75 per share. Preferred shares have a liquidation preference equal to the stated value of $187.50 per share plus any dividends accumulated and unpaid. Dividends on the preferred stock are payable quarterly. Preferred dividends for the six months ended June 30, 2002, include $69.4 million associated with the accounting for a preferred security that contains a conversion option that is beneficial to the purchaser at the time the security was issued. This is accounted for as a noncash dividend (reduction to retained earnings) and results from the conversion price being less than the market price of Williams common stock on the date the preferred stock was issued. The reduction in retained earnings was offset by an increase in capital in excess of par value. In January 2002, Williams issued $1.1 billion of 6.5 percent notes payable 2007 which are subject to remarketing in 2004. Attached to these notes is an equity forward contract requiring the holder to purchase Williams common stock at the end of three years. The note and equity forward contract are bundled as units, called FELINE PACS, and were sold in a public offering for $25 per unit. At the end of three years, the holder is required to purchase for 20 Notes (Continued) $25, one share of Williams common stock provided the average price of Williams common stock does not exceed $41.25 per share for a 20 trading day period prior to settlement. If the average price over that period exceeds $41.25 per share, the number of shares issued in exchange for $25 will be equal to one share multiplied by the quotient of $41.25 divided by the average price over that period. 21 Notes (Continued) 15. Comprehensive income (loss) Comprehensive income (loss) is as follows:
Three months ended Six months ended June 30, June 30, (Millions) 2002 2001 2002 2001 ------ ------ ------ ------ Net income (loss) $(349.1) $339.5 $(241.4) $538.7 Other comprehensive income (loss): Unrealized gains (losses) on securities (.3) 33.5 .8 (53.2) Realized gains on securities reclassified to net income -- (.1) -- (20.7) Cumulative effect of a change in accounting for derivative instruments -- -- -- (153.4) Unrealized gains (losses) on derivative instruments 12.4 442.4 (188.9) 457.1 Net reclassification into earnings of derivative instrument (gains) losses (46.5) 36.5 (200.8) 45.7 Foreign currency translation adjustments 21.1 7.4 19.7 (24.4) ------ ------ ------ ------ Other comprehensive income (loss) before taxes and minority interest (13.3) 519.7 (369.2) 251.1 Income tax benefit (provision) on other comprehensive income (loss) 13.0 (191.4) 148.0 (100.1) Minority interest in other comprehensive income (loss) -- (2.5) -- 10.0 ------ ------ ------ ------ Other comprehensive income (loss) (.3) 325.8 (221.2) 161.0 ------ ------ ------ ------ Comprehensive income (loss) $(349.4) $665.3 $(462.6) $699.7 ====== ====== ====== ======
Components of other comprehensive income (loss) before minority interest and taxes related to discontinued operations are as follows:
Three months ended Six months ended June 30, June 30, (Millions) 2002 2001 2002 2001 ------ ------ ------ ------ Unrealized gains (losses) on securities $ -- $34.5 $ -- $(56.2) Realized gains on securities reclassified to net income -- (.1) -- (20.7) Foreign currency translation adjustments -- (2.7) -- (22.1) ------ ----- ------ ------ Other comprehensive income (loss) before minority interest and taxes related to discontinued operations $ -- $31.7 $ -- $(99.0) ====== ===== ====== ======
22 Notes (Continued) 16. Segment disclosures Segments and reclassification of operations 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 corporate operations. Effective July 1, 2002, management of certain operations previously conducted by Energy Marketing & Trading, International and Petroleum Services was transferred to Midstream Gas & Liquids. These operations included natural gas liquids trading, activities in Venezuela and a petrochemical plant, respectively. Segment amounts have been restated to reflect these changes. On April 11, 2002, Williams Energy Partners L.P., a partially owned and consolidated entity of Williams, acquired Williams Pipe Line, an operation within Petroleum Services. Accordingly, Williams Pipe Line's operations have been transferred from the Petroleum Services segment to the Williams Energy Partners segment for which segment information has been restated for all prior periods presented. Segments - Performance measurement Williams currently evaluates performance based upon segment profit (loss) from operations which includes revenues from external and internal customers, operating costs and expenses, depreciation, depletion and amortization, equity earnings (losses) and income (loss) from investments. Intersegment sales are generally accounted for as if the sales were to unaffiliated third parties, that is, at current market prices. In first-quarter 2002, Williams began managing its interest rate risk on an enterprise basis by the corporate parent. The more significant of these risks relate to its debt instruments and its energy risk management and trading portfolio. To facilitate the management of the risk, entities within Williams may enter into derivative instruments (usually swaps) with the corporate parent. The level, term and nature of derivative instruments entered into with external parties are determined by the corporate parent. Energy Marketing & Trading has entered into intercompany interest rate swaps with the corporate parent, the effect of which is included in Energy Marketing & Trading's segment revenues and segment profit (loss) as shown in the reconciliation below. The results of interest rate swaps with external counter parties are shown as interest rate swap loss in the Consolidated Statement of Operations below operating income (loss). The majority of energy commodity hedging by the Energy Services' business units is done through intercompany derivatives with Energy Marketing & Trading which, in turn, enters into offsetting derivative contracts with unrelated third parties. Energy Marketing & Trading bears the counterparty performance risks associated with unrelated parties. The decrease in Energy Marketing & Trading's total assets, as reflected on page 26, is due primarily to a decline in the fair value of the energy risk management and trading portfolio. The following tables reflect the reconciliation of revenues and operating income (loss) as reported in the Consolidated Statement of Operations to segment revenues and segment profit (loss). 23 Notes (Continued) 16. Segment disclosures (continued)
Three months ended June 30, 2002 Three months ended June 30, 2001 ---------------------------------- ---------------------------------- Intercompany Intercompany Interest Segment Interest Segment (Millions) Revenues Rate Swaps Revenues Revenues Rate Swaps Revenues -------- ------------ -------- -------- ------------ -------- Energy Marketing & Trading $ (195.6) $(83.0) $ (278.6) $ 337.7 $ -- $ 337.7 Gas Pipeline 381.7 -- 381.7 368.7 -- 368.7 Energy Services 2,003.6 -- 2,003.6 2,225.1 -- 2,225.1 Other 16.4 -- 16.4 21.0 -- 21.0 Intercompany eliminations (50.5) 83.0 32.5 (31.2) -- (31.2) -------- ------ -------- -------- ------ -------- Total segments $2,155.6 $ -- $2,155.6 $2,921.3 $ -- $2,921.3 -------- ------ -------- -------- ------ --------
Three months ended June 30, 2002 Three months ended June 30, 2001 --------------------------------------------- --------------------------------------------- Operating Equity Intercompany Segment Operating Equity Intercompany Segment Income Earnings Interest Profit Income Earnings Interest Profit (Millions) (Loss) (Losses) Rate Swaps (Loss) (Loss) (Losses) Rate Swaps (Loss) --------- -------- ------------ ------- --------- -------- ------------ ------- Energy Marketing & Trading $ (414.5) $ -- $ (83.0) $(497.5) $ 263.1 $ (.9) $ -- $ 262.2 Gas Pipeline 117.3 39.4 -- 156.7 170.9 10.1 -- 181.0 Energy Services 129.8 2.0 -- 131.8 258.9 5.0 -- 263.9 Other .6 (.6) -- -- 4.5 (.4) -- 4.1 --------- -------- ------- ------- --------- -------- ------- ------- Total segments (166.8) $ 40.8 $ (83.0) $(209.0) 697.4 $ 13.8 $ -- $ 711.2 --------- -------- ------- ------- --------- -------- ------- ------- General corporate expenses (34.1) (27.0) --------- --------- Total operating income (loss) $ (200.9) $ 670.4 ========= =========
Six months ended June 30, 2002 Six months ended June 30, 2001 ---------------------------------- ---------------------------------- Intercompany Intercompany Interest Segment Interest Segment (Millions) Revenues Rate Swaps Revenues Revenues Rate Swaps Revenues -------- ------------ -------- -------- ------------ -------- Energy Marketing & Trading $ 145.3 $(68.9) $ 76.4 $ 935.9 $ -- $ 935.9 Gas Pipeline 805.5 -- 805.5 790.7 -- 790.7 Energy Services 3,743.7 -- 3,743.7 4,469.4 -- 4,469.4 Other 32.3 -- 32.3 39.5 -- 39.5 Intercompany eliminations (90.4) 68.9 (21.5) (104.8) -- (104.8) -------- ------ -------- -------- ------ -------- Total segments $4,636.4 $ -- $4,636.4 $6,130.7 $ -- $6,130.7 -------- ------ -------- -------- ------ --------
Six months ended June 30, 2002 Six months ended June 30, 2001 --------------------------------------------- ---------------------------------------------- Operating Equity Intercompany Segment Operating Equity Intercompany Segment Income Earnings Interest Profit Income Earnings Interest Profit (Millions) (Loss) (Losses) Rate Swaps (Loss) (Loss) (Losses) Rate Swaps (Loss) --------- -------- ------------ ------- --------- -------- ------------ -------- Energy Marketing & Trading $ (141.5) $ (4.0) $ (68.9) $(214.4) $ 750.0 $ 1.7 $ -- $ 751.7 Gas Pipeline 288.0 58.9 -- 346.9 339.5 18.2 -- 357.7 Energy Services 368.6 (5.8) -- 362.8 384.0 (8.0) -- 376.0 Other 3.1 (.8) -- 2.3 9.3 (.4) -- 8.9 --------- -------- ------- ------- --------- -------- ------- -------- Total segments 518.2 $ 48.3 $ (68.9) $ 497.6 1,482.8 $ 11.5 $ -- $1,494.3 --------- -------- ------- ------- --------- -------- ------- -------- General corporate expenses (72.3) (56.4) --------- --------- Total operating income (loss) $ 445.9 $ 1,426.4 ========= =========
24 Notes (Continued) 16. Segment disclosures (continued)
Revenues --------------------------------- External Inter- Equity Earnings Segment (Millions) Customers segment Total (Losses) Profit (Loss) --------- -------- -------- --------------- ------------- FOR THE THREE MONTHS ENDED JUNE 30, 2002 ENERGY MARKETING & TRADING $ 38.3 $ (316.9)* $ (278.6) $ -- $ (497.5) GAS PIPELINE 364.5 17.2 381.7 39.4 156.7 ENERGY SERVICES: Exploration & Production 24.2 206.6 230.8 1.0 95.4 International 9.1 -- 9.1 (2.3) (57.0) Midstream Gas & Liquids 489.4 16.3 505.7 3.6 84.6 Petroleum Services 1,130.9 23.1 1,154.0 (.3) (20.7) Williams Energy Partners 92.8 11.2 104.0 -- 29.5 -------- -------- -------- -------- -------- TOTAL ENERGY SERVICES 1,746.4 257.2 2,003.6 2.0 131.8 -------- -------- -------- -------- -------- OTHER 6.4 10.0 16.4 (.6) -- ELIMINATIONS -- 32.5 32.5 -- -- -------- -------- -------- -------- -------- TOTAL $2,155.6 $ -- $2,155.6 $ 40.8 $ (209.0) ======== ======== ======== ======== ======== FOR THE THREE MONTHS ENDED JUNE 30, 2001 ENERGY MARKETING & TRADING $ 473.8 $ (136.1)* $ 337.7 $ (.9) $ 262.2 GAS PIPELINE 358.0 10.7 368.7 10.1 181.0 ENERGY SERVICES: Exploration & Production 20.7 86.5 107.2 8.9 45.2 International 8.4 -- 8.4 1.4 (9.5) Midstream Gas & Liquids 520.5 25.0 545.5 (5.5) 64.5 Petroleum Services 1,439.0 22.7 1,461.7 .2 130.1 Williams Energy Partners 90.1 12.2 102.3 -- 33.7 Merger-related costs -- -- -- -- (.1) -------- -------- -------- -------- -------- TOTAL ENERGY SERVICES 2,078.7 146.4 2,225.1 5.0 263.9 -------- -------- -------- -------- -------- OTHER 10.8 10.2 21.0 (.4) 4.1 ELIMINATIONS -- (31.2) (31.2) -- -- -------- -------- -------- -------- -------- TOTAL $2,921.3 $ -- $2,921.3 $ 13.8 $ 711.2 ======== ======== ======== ======== ========
* Energy Marketing & Trading intercompany cost of sales, which are netted in revenues consistent with fair-value accounting, exceed intercompany revenue. 25 Notes (Continued) 16. Segment disclosures (continued)
Revenues --------------------------------- External Inter- Equity Earnings Segment (Millions) Customers segment Total (Losses) Profit (Loss) --------- -------- -------- --------------- ------------- FOR THE SIX MONTHS ENDED JUNE 30, 2002 ENERGY MARKETING & TRADING $ 646.4 $(570.0)* $ 76.4 $ (4.0) $ (214.4) GAS PIPELINE 770.4 35.1 805.5 58.9 346.9 ENERGY SERVICES: Exploration & Production 41.9 416.6 458.5 .6 201.7 International 18.0 -- 18.0 (11.3) (77.5) Midstream Gas & Liquids 937.1 38.2 975.3 5.2 172.5 Petroleum Services 2,040.2 55.6 2,095.8 (.3) 9.7 Williams Energy Partners 169.9 26.2 196.1 -- 56.4 -------- ------- -------- -------- -------- TOTAL ENERGY SERVICES 3,207.1 536.6 3,743.7 (5.8) 362.8 -------- ------- -------- -------- -------- OTHER 12.5 19.8 32.3 (.8) 2.3 ELIMINATIONS -- (21.5) (21.5) -- -- -------- ------- -------- -------- -------- TOTAL $4,636.4 $ -- $4,636.4 $ 48.3 $ 497.6 ======== ======= ======== ======== ======== FOR THE SIX MONTHS ENDED JUNE 30, 2001 ENERGY MARKETING & TRADING $1,232.7 $(296.8)* $ 935.9 $ 1.7 $ 751.7 GAS PIPELINE 773.3 17.4 790.7 18.2 357.7 ENERGY SERVICES: Exploration & Production 37.8 211.8 249.6 10.9 100.4 International 12.7 -- 12.7 (6.2) (30.6) Midstream Gas & Liquids 1,170.6 40.9 1,211.5 (12.8) 104.1 Petroleum Services 2,708.9 86.8 2,795.7 .1 147.1 Williams Energy Partners 175.1 24.8 199.9 -- 56.5 Merger-related costs -- -- -- -- (1.5) -------- ------- -------- -------- -------- TOTAL ENERGY SERVICES 4,105.1 364.3 4,469.4 (8.0) 376.0 -------- ------- -------- -------- -------- OTHER 19.6 19.9 39.5 (.4) 8.9 ELIMINATIONS -- (104.8) (104.8) -- -- -------- ------- -------- -------- -------- TOTAL $6,130.7 $ -- $6,130.7 $ 11.5 $1,494.3 ======== ======= ======== ======== ========
TOTAL ASSETS ----------------------------------- (Millions) June 30, 2002 December 31, 2001 ------------- ----------------- ENERGY MARKETING & TRADING $13,521.3 $15,046.4 GAS PIPELINE 8,754.2 8,291.5 ENERGY SERVICES: Exploration & Production 4,682.6 5,045.6 International 1,049.2 1,284.9 Midstream Gas & Liquids 5,867.9 5,718.8 Petroleum Services 2,276.0 2,147.9 Williams Energy Partners 1,185.0 1,033.6 --------- --------- TOTAL ENERGY SERVICES 15,060.7 15,230.8 --------- --------- OTHER 7,953.5 7,331.3 ELIMINATIONS (7,724.1) (7,955.3) --------- --------- 37,565.6 37,944.7 DISCONTINUED OPERATIONS -- 961.5 --------- --------- TOTAL $37,565.6 $38,906.2 ========= =========
* Energy Marketing & Trading intercompany cost of sales, which are netted in revenues consistent with fair-value accounting, exceed intercompany revenue. 26 Notes (Continued) 17. Recent accounting standards In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 142, "Goodwill and Other Intangible Assets." Williams adopted this Statement effective January 1, 2002. This Statement addresses accounting and reporting standards for goodwill and other intangible assets. Under the provisions of this Statement, goodwill and intangible assets with indefinite useful lives are no longer amortized, but will be tested annually for impairment. Based on management's estimate of the fair value of the operating unit's goodwill there was no impairment upon adoption of this Standard at January 1, 2002. In second-quarter 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." The rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt," and SFAS No. 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements," requires that gains and losses from extinguishment of debt only be classified as extraordinary items in the event that they meet the criteria of APB Opinion No. 30. SFAS No. 44, "Accounting for Intangible Assets of Motor Carriers," established accounting requirements for the effects of transition to the Motor Carriers Act of 1980 and is no longer required now that the transitions have been completed. Finally, the amendments to SFAS No. 13 require certain lease modifications that have economic effects which are similar to sale-leaseback transactions be accounted for as sale-leaseback transactions. The provisions of this Statement related to the rescission of SFAS No. 4 are to be applied in fiscal years beginning after May 15, 2002, while the provisions related to SFAS No. 13 are effective for transactions occurring after May 15, 2002. All other provisions of the Statement are effective for financial statements issued on or after May 15, 2002. There was no initial impact of SFAS No. 145 on Williams' results of operations and financial position. However, in subsequent reporting periods, gains and losses from debt extinguishments will not be accounted for as extraordinary items. Also in second-quarter 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." This Statement requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value only when the liability is incurred. The provisions of the Statement are effective for exit or disposal activities that are initiated after December 31, 2002. The effect of this standard on Williams' results of operations and financial position is being evaluated. 18. Subsequent events Subsequent to June 30, 2002, Williams announced that it expected to report a substantial net loss for second-quarter 2002 which included a significant operating loss from Energy Marketing & Trading and asset impairment charges. In addition, the board of directors reduced the quarterly dividend on Williams' common stock from $.20 per share to $.01 per share. The major credit rating agencies followed these announcements by downgrading Williams' credit rating below investment grade levels. Concurrent with these events, Williams was unable to complete a renewal of its unsecured short-term bank credit facility. Williams responded to these events with a concentrated effort to complete certain asset sales and obtain secured credit facilities in order to raise funds to meet current debt obligations and provide for other liquidity requirements. The asset sales and secured credit facilities are discussed below. Asset Sales In August 2002, Williams announced the sale for cash of the following assets as part of its previously announced financial strengthening plan: o 98 percent of Mid-America Pipeline, a 7,226-mile natural gas liquids pipeline system o 98 percent of its 80 percent ownership interest in Seminole Pipeline, a 1,281-mile natural gas liquids pipeline system o Jonah field natural gas production properties in Wyoming, which represented approximately 11 percent of total reserves at December 31, 2001 o Natural gas production properties in the Anadarko Basin o Cove Point liquefied natural gas facility and 87-mile pipeline in Maryland o Hugoton natural gas gathering system in Kansas 27 Notes (Continued) Except for the sale of the Cove Point assets, which is expected to close September 2002, each of these sale transactions closed in July 2002. The major classes of assets and liabilities included in the Consolidated Balance Sheet as of June 30, 2002, for these asset groups are as follows:
June 30, (Millions) 2002 -------- Current assets $ 101.8 Property, plant and equipment 1,350.8 Other assets 8.7 -------- Total assets $1,461.3 ======== Current liabilities $ 114.1 Long-term debt 289.3 Other liabilities and deferred income 176.4 -------- Total liabilities $ 579.8 ========
Secured credit facilities Subsequent to June 30, 2002, Williams obtained a $400 million letter of credit facility, a $900 million short-term loan (discussed below) and amended its existing $700 million revolving credit facility. The $400 million letter of credit facility which expires July 2003 and the $700 million revolving credit facility, which expires July 2005, are secured by the bulk of Williams' Midstream Gas & Liquids assets and the equity of substantially all of the Midstream Gas & Liquids subsidiaries and the subsidiaries which own the refinery assets. These facilities also have the benefit of guarantees from most of Williams' subsidiaries, not including Transcontinental Gas Pipe Line, Texas Gas or Northwest Pipeline. Additionally, the company is no longer required to make a "no material adverse change" representation prior to borrowings under the $700 million revolving credit facility. An additional $159 million of public securities were also ratably secured with the same assets in accordance with the indentures covering those securities. Additionally, as Williams completes certain asset sales the $700 million commitment from participating banks in the revolving credit facility will ultimately be reduced to $400 million and various other preexisting debt will be paid down. Transcontinental Gas Pipe Line, Texas Gas and Northwest Pipeline continue as participating borrowers in this facility. Significant new covenants under these agreements include: (i) restrictions on the creation of new subsidiaries, (ii) broader restrictions on pledging assets to other creditors, (iii) a covenant that the ratio of interest expense plus cash flow to interest expense be greater than 1.5 to 1, (iv) a limit on dividends on common stock paid by Williams in any quarter of $6.25 million, (v) certain restrictions on declaration or payment of dividends on preferred stock issued after July 30, 2002, (vi) a limit on investments in others of $50 million annually and (vii) a $50 million limit on additional debt incurred by subsidiaries other than Transcontinental Gas Pipe Line, Texas Gas, Northwest Pipeline or Williams Energy Partners L.P. Williams Production RMT Company (RMT), a wholly owned subsidiary, entered into a $900 million Credit Agreement dated as of July 31, 2002 (the "closing date"), with certain lenders including a subsidiary of Lehman Brothers, Inc., a related party. The loan is guaranteed by Williams, Williams Production Holdings LLC (Holdings) and certain RMT subsidiaries. It is also secured by the capital stock and assets of Holdings and certain of RMT's subsidiaries. The loan matures on July 25, 2003, and bears interest payable quarterly at the Eurodollar rate plus 4 percent per annum (5.824 percent at closing), plus additional interest of 14 percent per annum, which is accrued and added to the principal balance. RMT must also pay a deferred set-up fee. The amount of the fee is dependant upon whether a majority of the fair market value of RMT's assets or a majority of its capital stock is sold (a "company sale") on or before the maturity date, regardless of whether the loan obligations have been repaid. If a company sale has occurred, the amount of such fee would be the greater of (x) 15 percent of the loan principal amount, and (y) 15 percent to 21 percent, depending on the timing of the company sale, of the difference between (A) the purchase price of such company sale, including the amount of any liabilities assumed by the purchaser, up to $2.5 billion, and (B) the sum of (1) the principal amount of the outstanding loans, plus (2) outstanding debt of RMT and its subsidiaries, plus (3) accrued and unpaid interest on the loans to the date of repayment. If a company sale has not occurred, the fee would be 15 percent of the term loans. However, if a company sale occurs within three months after the maturity date, then RMT must also pay the positive difference, if any, between the fee that would have been paid had such company sale occurred prior to the maturity date and the actual fee paid on the maturity date. Significant covenants on Holdings, RMT and certain RMT subsidiaries under the loan agreement include: (i) an interest coverage ratio of greater than 1.5 to 1, (ii) a fixed charge coverage ratio of greater than 1.15 to 1, (iii) a limitation on restricted payments, (iv) a limitation on capital expenditures in excess of $300 million, and (v) a limitation on intercompany indebtedness. RMT must be sold within 75 days of a parent liquidity event which requires that Williams maintain actual and projected liquidity (a) at any time from the closing date through the 180th day thereafter, of $600 million; (b) at any time thereafter through and including the maturity date, of $750 million; and (c) at any time after the maturity date, of $200 million. Liquidity projections must be provided weekly until the maturity date. Each projection covers a period extending 12 months from the report date. The loan is also required to be prepaid with the net cash proceeds of any sale of RMT's assets, and, in the event 28 Notes (Continued) of a company sale, the loan is required to be prepaid in full. Any prepayment or acceleration of the loan requires RMT to pay to lenders (i) a make-whole amount, and (ii) the deferred set up fee set forth above. Additionally, Williams amended certain other financing facilities and agreements totaling $1.9 billion which provided the lenders thereunder with guarantees from Williams Gas Pipeline Company, L.L.C. and Williams Production Holdings LLC and certain lenders with a ratable share of proceeds from future asset sales to reduce certain of these facilities. These facilities and agreements include the preferred interest in Castle Associates LP, $600 million of term loans, certain letters of credit, two operating lease agreements with special purpose entities, the preferred interest in Piceance Production Holdings LLC and the preferred interest in Snow Goose Associates, L.L.C. which is currently classified as debt. As a result of the changes to the two operating lease agreements, these leases will be reported as capitalized leases as of July 31, 2002. If these leases were treated as capitalized lease obligations at June 30, 2002, assets and long-term debt would increase by approximately $287 million. Additionally, the preferred interest in Castle Associates L.P. and Piceance Production Holdings LLC will be reported as debt as of July 31, 2002. 29 ITEM 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION RECENT EVENTS As a result of credit issues facing the Company and the assumption of payment obligations and performance on guarantees associated with WCG, Williams announced plans during first-quarter 2002 to strengthen its balance sheet and support retention of its investment grade ratings. The plan included reducing capital expenditures during the balance of 2002, future sales of assets to generate proceeds to be used to reduce outstanding debt and the lowering of expenses, in part through an enhanced-benefit early retirement program which concluded during the second quarter. In addition, "ratings triggers" exposure for potential acceleration of debt payment and redemption of preferred interests was substantially reduced to $182 million at March 31, 2002 ($135 million of which was redeemed subsequent to June 30, 2002). During the second quarter, Williams experienced liquidity issues, the effect of which limited Energy Marketing & Trading's ability to manage market risk and exercise hedging strategies as market liquidity deteriorated. During May 2002, major rating agencies lowered their credit ratings on Williams' unsecured long-term debt; however, the ratings still were maintained as investment grade for the balance of the quarter. In June, Williams announced a $500 million reduction in its working capital and liquidity commitments to its Energy Marketing & Trading business and reduced its work force accordingly. Later in June, Williams announced its intentions to offer for sale its two refineries and related assets, with the expectation of closing such sales by the end of 2002. Subsequent to the end of the second quarter, Williams announced that it would have a substantial net loss for the quarter. The loss primarily resulted from a decline in Energy Marketing & Trading's results and reflected a significant decline in the forward mark-to-market value of its portfolio, the costs associated with terminated power projects, and the partial impairment of goodwill from deteriorating energy trading market conditions in the second quarter. In addition, Williams announced asset impairments and cost write-offs, in part a result of asset sale considerations and terminated projects reflecting a reduced capital expenditure program. In addition, the board of directors reduced the common stock dividend for the third quarter from the prior level of 20 cents per share to 1 cent per share. The major rating agencies downgraded Williams credit rating to below investment grade reflecting the uncertainty associated with the trading business, short-term cash requirements facing the Company and the increased level of debt the company had incurred to meet the WCG payment obligations and guarantees. Concurrent with these events, Williams was unable to complete a renewal of its unsecured short-term bank facility which expired on July 24, 2002. Subsequently, Williams did obtain two secured facilities totaling $1.3 billion, including a letter of credit facility for $400 million, and amended its existing $700 million revolving credit facility to a secured basis which expires July 2005. These borrowing facilities include pledges of certain assets and contain financial ratios and other covenants that must be maintained (see Note 18). If such provisions of the agreements are not maintained, then amounts outstanding can become due immediately and payable. Williams believes that these financings and the proceeds received from recent asset sales have significantly improved the company's liquidity for the balance of the year. In addition, Williams is pursuing the sale of other assets to enhance liquidity. The sales are anticipated to close during the second half of 2002. Following the credit rating downgrade in July, Williams sold certain exploration and production properties and substantially all of its natural gas liquids pipeline systems, receiving net cash proceeds of approximately $1.5 billion. It also announced the sale of certain liquified natural gas assets for approximately $217 million. This transaction is expected to close in September. In addition to its refineries and related assets, Williams has also announced that it is considering selling its gas pipeline unit known as Central and its Western Canada gathering and natural gas extraction assets. During the second quarter, a review for impairment was performed on certain assets that were being considered for possible sale, including an assessment of the more likely than not probabilities of sale for each asset. Impairments were recorded in the second quarter totaling approximately $71 million reflecting management's estimate of the fair value of these assets based on information available at the time. Williams has numerous assets which could be sold that exceed the previously announced target of $1.5 billion to $3 billion range of proceeds to be generated from asset sales. The specific assets that will be sold and the timing of such sales are dependent on various factors, including negotiations with prospective buyers, regulatory approvals, industry conditions and the short-and long-term liquidity requirements of the Company. While management believes it has considered all relevant information in assessing for potential impairments, the ultimate sales price for assets which may be sold in the future may result in an additional impairment or a loss. 30 Management's Discussion & Analysis (Continued) The operating results of Energy Marketing & Trading are adversely affected by several factors, including Williams' overall liquidity and credit ratings which impact Energy Marketing & Trading's ability to enter into price risk management and hedging activities. The credit rating downgrades have also triggered certain Energy Marketing & Trading contractual provisions, including providing counterparties with adequate assurance, margin, credit enhancement, or credit replacement. Successful completion of the agreement in principle reached in July regarding the global settlement with the State of California and other parties would eliminate certain outstanding complaints and litigation and resolve claims for refunds to the FERC filed in connection with its power activities in California (see Note 12). As currently proposed, the settlement would also provide for a new long-term power sales contract with the state in addition to other settlement provisions. For further discussions regarding Energy Marketing & Trading's business and its fair value of energy contracts, see the Fair Value of Energy Risk Management and Trading activities on page 45. The energy trading sector has experienced deteriorating conditions because of credit and regulatory concerns, and these have significantly reduced Energy Marketing & Trading's ability to attract new business. These market conditions plus the unwillingness of counterparties to enter into new business with Energy Marketing & Trading will affect results in the future and could result in additional operating losses. On August 1, 2002, Williams announced its intention to further reduce its commitment and exposure to its energy marketing and risk management business. This reduction could be realized by entering into a joint venture arrangement with a third party or a sale of a portion or all of the marketing and trading portfolio. It is possible that Williams, in order to generate levels of liquidity it needs in the future, would be willing to accept amounts for a portion or its entire portfolio that are less than its carrying value at June 30, 2002. At June 30, 2002, Williams has maturing long-term debt totaling $920 million for the remainder of the current year and $1,148 million during 2003. The Company's available liquidity to meet these requirements and fund a reduced level of capital expenditures will be dependent on several items, including the cash flows of retained businesses, the amount of proceeds raised from the sale of assets and the price of natural gas. Future cash flows from operations may also be affected by the timing and nature of the sale of assets. Because of recent asset sales, anticipated asset sales in the future and recently negotiated secured credit facilities, Williams currently believes that it has the financial resources and liquidity to meet future cash requirements for the balance of the year. The new secured credit facilities require Williams to meet certain covenants and limitations as well as maintain certain financial ratios (see Note 18). Included in these covenants are provisions that limit the ability to incur future indebtedness, pledge assets and pay dividends on common stock. In addition, debt and related commitments must be reduced from the proceeds of asset sales and minimum levels of current and future liquidity have been established. GENERAL On March 27, 2002, Williams completed the sale of one of its Gas Pipeline segments, Kern River Gas Transmission (Kern River), to MidAmerican Energy Holdings Company (MEHC). Accordingly, the results of operations for Kern River have been reflected in the consolidated financial statements as discontinued operations. (see Note 7). Unless otherwise indicated, the following discussion and analysis of results of operations, financial condition and liquidity relates to the continuing operations of Williams and should be read in conjunction with the consolidated financial statements and notes thereto included in Item 1 of this document and Exhibit 99(b) of Williams' Current Report on Form 8-K dated May 28, 2002, which includes financial statements that reflect Kern River as discontinued operations. 31 Management's Discussion & Analysis (Continued) RESULTS OF OPERATIONS Consolidated Overview The following table and discussion is a summary of Williams' consolidated results of operations. The results of operations by segment are discussed in further detail beginning on page 34.
THREE SIX MONTHS ENDED MONTHS ENDED JUNE 30, JUNE 30, -------------------- -------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (MILLIONS) (MILLIONS) Revenues $2,155.6 $2,921.3 $4,636.4 $6,130.7 ======== ======== ======== ======== Operating income (loss) $ (200.9) $ 670.4 445.9 1,426.4 Interest accrued-net (271.3) (150.0) (483.0) (320.3) Interest rate swap loss (83.2) -- (73.0) -- Investing income (loss): Estimated loss on realization of amounts due from WCG (15.0) -- (247.0) -- Other 54.8 35.0 70.9 69.0 Preferred returns and minority interest in income of consolidated subsidiaries (21.8) (21.7) (37.0) (47.0) Other income - net 23.7 6.0 19.8 11.4 -------- -------- -------- -------- Income (loss) from continuing operations before income taxes (513.7) 539.7 (303.4) 1,139.5 Provision (benefit) for income taxes (164.6) 210.9 (77.5) 443.8 -------- -------- -------- -------- Income (loss) from continuing operations (349.1) 328.8 (225.9) 695.7 Income (loss) from discontinued operations -- 10.7 (15.5) (157.0) -------- -------- -------- -------- Net income (loss) (349.1) 339.5 (241.4) 538.7 Preferred stock dividends (6.8) -- (76.5) -- -------- -------- -------- -------- Income (loss) applicable to common stock $ (355.9) $ 339.5 $ (317.9) $ 538.7 ======== ======== ======== ========
Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001 Williams' revenue decreased $765.7 million, or 26 percent, due primarily to lower revenues associated with energy risk management and trading activities at Energy Marketing & Trading. Also contributing were lower refined product sales prices and volumes at the refineries, lower travel center and Alaska convenience stores sales and the absence of $77 million of revenue related to the 198 convenience stores sold in May 2001 within Petroleum Services and lower natural gas liquids sales prices and lower revenue from natural gas liquids trading operations within Midstream Gas & Liquids. Partially offsetting these decreases was an increase in revenues at Exploration & Production resulting from higher net production volumes. Segment costs and expenses, including selling, general and administrative expenses, increased $98.5 million, or 4 percent, due to impairment charges, loss accruals and write-offs of $141.2 million within Energy Marketing & Trading, $44.1 million related to Colorado soda ash mining operations within International, $27 million related to the travel centers within Petroleum Services and $7.5 million related to a cancelled project at Gas Pipeline, as well as the benefit in 2001 of a $72.1 million pre-tax gain on the sale of the convenience stores. Selling, general and administrative expenses increased $39.4 million due primarily to an additional $24 million of costs related to an enhanced-benefit early retirement option offered to certain employee groups and $11 million higher expenses at Exploration & Production. Partially offsetting these increases were lower petroleum products costs and the absence of $76 million in costs related to the 198 convenience stores sold at Petroleum Services and lower costs related to the natural gas liquids trading operations within Midstream Gas & Liquids. Operating income (loss) decreased $871.3 million, due primarily to lower net revenues associated with energy risk management and trading activities at Energy Marketing & Trading, the absence of the 2001 gain from the 198 convenience stores sold, decreased operating profit from refining and marketing operations within Petroleum Services and the 2002 32 Management's Discussion & Analysis (Continued) impairment charges noted above, partially offset by the contribution of increased production volumes at Exploration & Production. Included in operating income (loss) are general corporate expenses, which increased $7 million, or 26 percent, due primarily to costs related to the enhanced-benefit early retirement option. Interest accrued - net increased $121.3 million, or 81 percent due primarily to the $98 million effect of higher borrowing levels including the impact of the $1.4 billion of long-term obligations related to WCG (see Note 11), the $3 million effect of higher average interest rates and $15 million of higher debt amortization expense related to higher debt levels. In light of the recent credit ratings downgrades and the secured credit facilities obtained subsequent to June 30, 2002, interest expense in the near term is expected to increase at least $100 million per quarter until debt levels are reduced. In first-quarter 2002, Williams began managing its interest rate risk on an enterprise basis by the corporate parent. The results of interest rate swaps with external counter parties were losses of $83.2 million in second-quarter 2002 (see Note 16). Investing income (loss) increased $4.8 million due primarily to $27 million higher earnings on equity investments, largely offset by the $15 million estimated loss on realization of amounts due from WCG (see Note 4) and an $8 million decrease in interest income related to lower margin deposits. Other income - net increased $17.7 million due primarily to an $11 million gain at Gas Pipeline associated with the disposition of securities received through a mutual insurance company reorganization and a decrease in losses from the sales of receivables to special purpose entities. The provision (benefit) for income taxes decreased $375.5 million due primarily to lower pre-tax income. The effective income tax rate for the three months ended June 30, 2002, is less than the federal statutory rate due primarily to the impairment of goodwill which is not deductible for income tax purposes and which reduces the tax benefit of the pre-tax loss. The effective income tax rate for the three months ended June 30, 2001, is greater than the federal statutory rate due primarily to the effect of state income taxes. Income (loss) from discontinued operations for second-quarter 2001 of $10.7 million reflects the after-tax results of operations of Kern River. Six Months Ended June 30, 2002 vs. Six Months Ended June 30, 2001 Williams' revenue decreased $1,494.3 million, or 24 percent, due primarily to lower revenues associated with energy risk management and trading activities at Energy Marketing & Trading, lower refined product sales prices at the refineries, lower travel center and Alaska convenience store sales and the absence of $182 million of revenue related to the 198 convenience stores sold in May 2001 within Petroleum Services. Also contributing were lower natural gas liquids sales prices and lower natural gas liquids trading operations revenue within Midstream Gas & Liquids. Partially offsetting these decreases was an increase in revenues at Exploration & Production resulting from higher net production volumes. Segment costs and expenses, including selling, general and administrative expenses, decreased $529.7 million, or 11 percent, due to lower petroleum products costs, lower travel center/convenience store costs reflecting the absence of the 198 convenience stores sold in May 2001, lower shrinkage, fuel and replacement gas purchases related to processing activities within Midstream Gas & Liquids and lower costs related to the natural gas liquids trading operations within Midstream Gas & Liquids. Partially offsetting these decreases were impairment charges, loss accruals and write-offs of $141.2 million within Energy Marketing & Trading, $44.1 million related to Colorado soda ash mining operations within International, $27 million related to the travel centers within Petroleum Services and $7.5 million related to a canceled project at Gas Pipeline as well as the benefit in 2001 of a $72.1 million pre-tax gain on the sale of the convenience stores. Operating income (loss) decreased $980.5 million, or 69 percent, due primarily to lower net revenues associated with energy risk management and trading activities at Energy Marketing & Trading, the absence of the 2001 gain from the 198 convenience stores sold and decreased operating profit from refining and marketing operations within Petroleum Services and the 2002 impairment charges noted above partially offset by increased production volumes at Exploration & Production. Included in operating income (loss) are general corporate expenses, which increased $15.9 million, or 28 percent, due primarily to a $6 million increase in advertising costs and $6 million of expense related to the enhanced-benefit early retirement options offered to certain employee groups. 33 Management's Discussion & Analysis (Continued) Interest accrued - net increased $162.7 million, or 51 percent due primarily to the $149 million effect of higher borrowing levels and $18 million of higher debt amortization expense related to higher debt levels. The increases were slightly offset by the $12 million effect of lower average interest rates and by $9 million lower interest expense related to deposits received from customers relating to energy risk management and trading and hedging activities. In first-quarter 2002, Williams began managing its interest rate risk on an enterprise basis by the corporate parent. The results of interest rate swaps with external counter parties were losses of $73 million (see Note 16). Investing income (loss) decreased $245.1 million due substantially to the $247 million estimated loss on realization of amounts due from WCG (see Note 4), a $23 million decrease in interest income related to margin deposits and a $5 million decrease in dividend income due to the sale of Ferrellgas Partners L.P. senior common units in second-quarter 2001. Slightly offsetting these decreases are higher equity earnings of $36.8 million due primarily to the $27.4 million contractual construction completion fee received by a Gas Pipeline equity investment (see Note 5). Preferred returns and minority interest in income of consolidated subsidiaries decreased $10 million, or 21 percent, due primarily to a $15 million decrease in preferred returns of Snow Goose reflecting lower interest rates for the first-quarter 2002 and the fact that the preferred interest is now characterized as debt due to the first quarter amendment (see Note 11) and a $4 million decrease in preferred returns related to the second-quarter 2001 redemption of Williams obligated mandatory redeemable preferred securities of Trust. Partially offsetting these decreases was a $9 million increase related to minority interest associated with Williams Energy Partners. Other income - net increased $8.4 million due primarily to an $11 million gain in second-quarter 2002 at Gas Pipeline associated with the disposition of securities received through a mutual insurance company reorganization and a $7 million decrease in losses from the sales of receivables to special purpose entities. Partially offsetting these increases was an $8 million loss related to the early retirement of remarketable notes in first-quarter 2002. The provision (benefit) for income taxes decreased $521.3 million due primarily to lower pre-tax income. The effective income tax rate for the six months ended June 30, 2002, is less than the federal statutory rate due primarily to the impairment of goodwill which is not deductible for income tax purposes and which reduces the tax benefit of pre-tax loss. The effective income tax rate for the six months ended June 30, 2001, is greater than the federal statutory rate due primarily to the effect of state income taxes. Income (loss) from discontinued operations for 2002 of $15.5 million is the after-tax loss related to the sale of Kern River, partially offset by its results of operations for first-quarter 2002. The $157 million loss from discontinued operations for 2001 includes the after-tax loss from WCG operations of $179.1 million and after-tax income of $22.1 million from the operations of Kern River. Income (loss) applicable to common stock in 2002 reflects the impact of the $69.4 million associated with accounting for a preferred security that contains a conversion option that was beneficial to the purchaser at the time the security was issued. The average number of shares in 2002 for the diluted calculation (which is the same as the basic calculation due to Williams reporting a loss from continuing operations-see Note 8) increased by approximately 32 million from June 30, 2001. The increase is due primarily to the 29.6 million shares issued in the Barrett acquisition in August 2001. The increased shares had a dilutive effect on loss per share from continuing operations in 2002 of approximately $.04 per share. RESULTS OF OPERATIONS-SEGMENTS Williams is currently organized into three industry groups: Energy Marketing & Trading, Gas Pipeline and Energy Services (includes Exploration & Production, International, Midstream Gas & Liquids, Petroleum Services, and Williams Energy Partners). Williams currently evaluates performance based upon segment profit (loss) from operations (see Note 16). Segment profit of the operating companies may vary by quarter. Energy Marketing & Trading's results can vary quarter to quarter based on the timing of origination activities and market movements of commodity prices, interest rates and counterparty credit worthiness impacting the determination of fair value of contracts. Effective July 1, 2002, management of certain operations previously conducted by Energy Marketing & Trading, International and Petroleum Services was transferred to Midstream Gas & Liquids. These operations included natural gas liquids trading, activities in Venezuela and a petrochemical plant, respectively. The current and prior period amounts and the following discussions reflect these changes. 34 Management's Discussion & Analysis (Continued) On April 11, 2002, Williams Energy Partners L.P., a partially owned and consolidated entity of Williams, acquired Williams Pipe Line, an operation within the Petroleum Services segment. Accordingly, Williams Pipe Line's results of operations have been transferred from the Petroleum Services segment to the Williams Energy Partners segment. Also in the first quarter of 2002, management of APCO Argentina was transferred from the International segment to the Exploration & Production segment to align exploration and production activities. Prior period amounts have been restated to reflect these changes. The following discussions relate to the results of operations of Williams' segments. ENERGY MARKETING & TRADING
THREE SIX MONTHS ENDED MONTHS ENDED JUNE 30, JUNE 30, ---------------- ---------------- 2002 2001 2002 2001 ------- ------ ------- ------ (MILLIONS) (MILLIONS) Segment revenues $(278.6) $337.7 $ 76.4 $935.9 ======= ====== ======= ====== Segment profit (loss) $(497.5) $262.2 $(214.4) $751.7 ======= ====== ======= ======
Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001 ENERGY MARKETING & TRADING'S revenues decreased $616.3 million, or 182 percent, due primarily to a $616.5 million decrease in risk management and trading revenues. During second-quarter 2002, Energy Marketing & Trading's results were in general adversely affected by the impact of market movements against its portfolio and an absence of new origination activities. Energy Marketing & Trading's ability to manage or hedge its portfolio against adverse market movements was limited by a lack of market liquidity as well as market concerns regarding Williams' credit and liquidity and internal efforts to preserve liquidity. The $616.5 million decrease in risk management and trading revenues is due primarily to a decrease of $550.2 million in the natural gas and power portfolios and a $68.2 million decrease in the petroleum products portfolio. The $550.2 million decrease in the natural gas and power portfolio includes a $339.5 million decrease in new transaction origination compared to second-quarter 2001. This decline is reflective of the minimal amount of new transaction origination as a result of the deterioration of market liquidity and Williams' limited credit capacity. The decline in value of the natural gas and power portfolio is also a result of higher natural gas prices and lower power prices that led to significantly reduced spark spreads in the northeast and southeast regions. The $68.2 million decrease in the petroleum products portfolio was driven by a decline in market liquidity combined with a reduction in crude and unleaded prices. Additionally, the natural gas and power and the refined products portfolio were also impacted by the general market deterioration and credit degradation in the energy trading sector which had the effect of reducing contract valuations as market liquidity declined and corporate bond spreads deteriorated. Other (income) expense-net in 2002 includes $83.7 million of net loss accruals and write-offs primarily associated with commitments for certain terminated power projects. Of this amount, $50 million was associated with a reduction to fair value of certain power equipment for which management made the second-quarter decision to sell rather than utilize in power development projects. The balance primarily represents an accrual for costs associated with leased power generation equipment that management determined in the second quarter of 2002 will not be utilized. Also included in other (income) expense-net in 2002 is a $57.5 million partial goodwill impairment resulting from deteriorating market conditions during the second quarter (see Note 3). Segment profit decreased by $759.7 million due primarily to the $616.5 million reduction of trading revenues and the $141.2 million of items discussed above in other (income) expense-net. Energy Marketing & Trading's future results will be affected by the reduction in liquidity available to them from their parent, the willingness of counterparties to enter into transactions with Energy Marketing & Trading, the liquidity of the markets in which Energy Marketing & Trading transacts and the overall credit worthiness of other counterparties in the industry segment. Because credit rating agencies no longer consider Williams as an investment grade rated company, in some instances, Williams is required to provide additional adequate assurances in the form of cash or credit support to enter into price risk management transactions. With the decision to continue to reduce Williams' financial commitment and exposure to the trading business, it is likely that Energy Marketing & Trading's portfolio will have greater exposure to market movements which could result in 35 Management's Discussion & Analysis (Continued) additional operating losses. In addition, other companies in the energy trading and marketing sector are experiencing financial difficulties which will affect Energy Marketing & Trading's credit assessment related to the future value of its forward positions. The effects of these items on Energy Marketing & Trading's results will adversely affect results in the future. Williams will also continue to evaluate the carrying value of Energy Marketing & Trading's goodwill in light of recent developments. Williams announced on August 1, 2002, its intention to reduce its commitment to the energy marketing and trading business, which could be in several forms. Williams continues to pursue several opportunities to sell all or a portion of its portfolio. It also continues to discuss with certain parties joint venturing arrangements. It is not possible at this time to predict the ultimate outcome of these discussions or to estimate the sales proceeds that might be received if such transactions occur. It is possible that Williams, in order to generate levels of liquidity it needs in the future, would be willing to accept amounts for a portion or its entire portfolio that is lower than the carrying value at June 30, 2002. Issues in the Western Marketplace At June 30, 2002, Energy Marketing & Trading had net accounts receivable recorded of approximately $231 million for power sales to the California Independent System Operator and the California Power Exchange Corporation (CPEC). While the amount recorded reflects management's best estimate of collectibility, future events or circumstances could change those estimates. As discussed in Rate and Regulatory Matters and Related Litigation in Note 12 of the Notes to Consolidated Financial Statements, the FERC and the DOJ have issued orders or initiated actions which involve Energy Marketing & Trading related to California and the western states electric power industry. In addition to these federal agency actions, a number of federal and state initiatives addressing the issues of the California electric power industry are also ongoing and may result in restructuring of various markets in California and elsewhere. Discussions in California and other states have ranged from threats of re-regulation to suspension of plans to move forward with deregulation. Allegations have also been made that the wholesale price increases resulted from the exercise of market power and collusion of the power generators and sellers, such as Williams. These allegations have resulted in multiple state and federal investigations as well as the filing of class-action lawsuits in which Williams is a named defendant. Williams' long-term power contract with the State of California has also been challenged both at the FERC and in civil suits. Most of these initiatives, investigations and proceedings are in their preliminary stages and their likely outcome cannot be estimated. However, Williams is attempting to resolve many of these disputes through settlement and has reached a settlement in principle with the State of California on a global settlement that includes a renegotiated long-term energy contract. The settlement will also resolve complaints brought by the California Attorney General against Williams and the State of California's refund claims. In addition, the settlement will resolve ongoing investigations by the States of California, Oregon, and Washington. The settlement is subject to documentation and approval by various courts and agencies. (see Other Legal Matters in Note 12) There can be no assurance that these initiatives, investigations and proceedings will not have an adverse effect on Williams' results of operations or financial condition. Six Months Ended June 30, 2002 vs. June 30, 2001 ENERGY MARKETING & TRADING'S revenues decreased $859.5 million, or 92 percent, due primarily to an $861.2 million decrease in risk management and trading revenues. As noted previously, Energy Marketing & Trading's results were in general adversely affected by its limited ability to manage or hedge its portfolio against adverse market movements due to a lack of market liquidity, the market's concerns regarding Williams credit and liquidity, and internal efforts to preserve liquidity. The $861.2 million decrease in risk management and trading revenues is due primarily to a decrease of $961 million in the natural gas and power portfolios, partially offset by a $71.6 million increase in the petroleum products portfolio. The $961 million decrease in the natural gas and power portfolio includes a $218 million decrease due to the minimal amount of new transaction origination in second-quarter 2002. The decline in value of the natural gas and power portfolio is also a result of the impact of lower market volatility than was present during the first half of 2001 and to higher natural gas prices and lower power prices that led to reduced spark spreads in the northeast and southeast regions in the second quarter of 2002. The $71.6 million increase in the petroleum products portfolio was due primarily to $118.8 million resulting from origination of transactions during the first quarter of 2002 partially offset by a decrease in the value of the refined products storage and transportation portfolios during the second quarter of 2002. The natural gas and power portfolio and the refined products portfolio were also impacted in second-quarter 2002 by the general market deterioration and credit degradation in the energy trading sector had the effect of reducing structured contract valuations as market liquidity declined and corporate bond spreads deteriorated. Selling, general, and administrative expenses decreased by $42.4 million or 27 percent. This cost reduction is primarily due to lower variable compensation levels associated with reduced segment profit and the effect in 2002 of modifications to the variable compensation plan. Other (income) expense-net in 2002 includes the $83.7 million of net loss accruals and write-offs discussed above and the $57.5 million partial goodwill impairment also discussed above. Segment profit (loss) decreased by $966.1 million or 129 percent, due primarily to the $861.2 million reduction of trading revenues and the $141.2 million of non-recurring items discussed in other (income) expense - net above, partially offset by the decrease in selling, general and administrative expense. 36 Management's Discussion & Analysis (Continued) GAS PIPELINE
THREE SIX MONTHS ENDED MONTHS ENDED JUNE 30, JUNE 30, --------------- --------------- 2002 2001 2002 2001 ------ ------ ------ ------ (MILLIONS) (MILLIONS) Segment revenues $381.7 $368.7 $805.5 $790.7 ====== ====== ====== ====== Segment profit $156.7 $181.0 $346.9 $357.7 ====== ====== ====== ======
Three Months Ended June 30, 2002 vs. June 30, 2001 GAS PIPELINE'S revenues increased $13 million, or 4 percent, due primarily to $11 million higher demand revenues on the Transco system resulting from new expansion projects and new rates effective September 1, 2001, $8 million from environmental mitigation credit sales and services and $4 million higher transportation revenues on the Texas Gas system. Partially offsetting these increases were $8 million lower gas exchange imbalance settlements (offset in costs and operating expenses) and $3 million lower storage revenues. Costs and operating expenses increased $14.3 million, or 8 percent, due primarily to the $15 million effect in 2001 of a regulatory reserve reversal resulting from the FERC's approval for recovery of fuel costs incurred in prior periods by Transco, as well as $8 million of higher depreciation expense due to increased property, plant and equipment placed into service on the Transco system, partially offset by $8 million lower gas exchange imbalance settlements (offset in revenues). General and administrative costs increased $17 million, or 32 percent, due primarily to $11 million in early retirement pension costs and $2 million of increased long-term disability costs. Other (income) expense - net in 2002 includes a $7.5 million write-off of a cancelled pipeline project. Other (income) expense - net in 2001 includes a $27.5 million pre-tax gain from the sale of Williams' limited partnership interest in Northern Border Partners, L.P. Segment profit, which includes equity earnings, decreased $24.3 million, or 13 percent, due primarily to the $35 million unfavorable change in other (income) expense - net, as discussed above, and $17 million higher general and administrative costs discussed previously, partially offset by $29.3 million higher equity earnings. The $29.3 million increase in equity earnings includes a $27.4 million benefit in 2002 reflecting a contractual construction completion fee received by an equity affiliate. This equity affiliate served as the general contractor on the Gulfstream pipeline project for Gulfstream Natural Gas System (Gulfstream), an interstate natural gas pipeline subject to FERC regulation and also an equity affiliate. The fee, paid by Gulfstream and associated with the completion during the second quarter of 2002 of the construction of Gulfstream's pipeline, was capitalized by Gulfstream as property, plant and equipment and is included in Gulfstream's rate base to be recovered in future revenues. Additionally, the equity earnings increase reflects a $14 million increase from Gulfstream primarily related to interest capitalized on the Gulfstream pipeline project in accordance with FERC regulations. Partially offsetting these increases to equity earnings was a $12.3 million write-down of Gas Pipeline's investment in a pipeline project that has been cancelled. Subsequent to second-quarter 2002, Williams announced that it agreed to sell its Cove Point liquefied natural gas (LNG) facility and 87-mile pipeline for $217 million in cash to a subsidiary of Dominion Resources. The Cove Point LNG facility is currently used for storage and to serve customers during peak periods of demand, while the pipeline is used to serve customers year-round. The terminal is located on more than 1,000 acres of land on the western shore of the Chesapeake Bay. The sale is expected to close mid-September 2002. Revenues for the 37 Management's Discussion & Analysis (Continued) three and six months ended June 30, 2002 related to Cove Point were approximately $5.7 million and $8.6 million, respectively. In addition, Williams also announced it is considering the sale of the 6,000 mile natural gas pipeline system known as Central Gas Pipeline System. Revenues for the three and six months ended June 30, 2002, for the Central Gas Pipeline System were $41 million and $80 million, respectively. Transcontinental Gas Pipe Line and Texas Gas have various regulatory proceedings pending. As of June 30, 2002, approximately $178 million has been accrued for potential refund. As a result of rulings in certain of these proceedings, Williams anticipates recording revenues in third-quarter 2002 of approximately $39 million to $41 million. Six Months Ended June 30, 2002 vs. June 30, 2001 GAS PIPELINE'S revenues increased $14.8 million, or 2 percent, due primarily to $19 million higher demand revenues on the Transco system resulting from new expansion projects and new rates effective September 1, 2001 and $9 million from environmental mitigation credit sales and services. Partially offsetting these increases were $11 million lower recovery of tracked costs which are passed through to customers (offset in costs and operating expenses and general and administrative costs) and $3 million lower storage revenue. Costs and operating expenses increased $16 million, or 4 percent, due primarily to the $15 million effect in 2001 of a regulatory reserve reversal resulting from the FERC's approval for recovery of fuel costs incurred in prior periods by Transco, as well as $12 million higher depreciation expense due to increased property, plant and equipment placed into service, partially offset by $8 million lower tracked costs which are passed through to customers (offset in revenues). General and administrative costs increased $14 million, or 12 percent, due primarily to $11 million in early retirement pension costs and $2 million of increased long-term disability costs, partially offset by $3 million lower tracked costs (offset in revenues). Other (income) expense - net in 2002 includes a $7.5 million write-off of a cancelled pipeline project. Other (income) expense - net in 2001 includes a $27.5 million pre-tax gain from the sale of Williams' limited partnership interest in Northern Border Partners, L.P. Segment profit, which includes equity earnings, decreased $10.8 million, or 3 percent, due primarily to the $35 million unfavorable impact of the other (income) expense - net items discussed above and $14 million higher general and administrative costs discussed previously. These decreases in segment profit were partially offset by $40.6 million higher equity investment earnings. The $40.6 million increase in equity earnings includes the $27.4 million benefit in 2002 related to the contractual construction completion fee received by an equity affiliate discussed above. Additionally, the equity earnings increase reflects a $26 million increase from Gulfstream primarily related to interest capitalized on the Gulfstream pipeline project in accordance with FERC regulations. Partially offsetting these increases to equity earnings was a $12.3 million write-down of Gas Pipeline's investment in a pipeline project that has been cancelled. ENERGY SERVICES EXPLORATION & PRODUCTION
THREE SIX MONTHS ENDED MONTHS ENDED JUNE 30, JUNE 30, --------------- --------------- 2002 2001 2002 2001 ------ ------ ------ ------ (MILLIONS) (MILLIONS) Segment revenues $230.8 $107.2 $458.5 $249.6 ====== ====== ====== ====== Segment profit $ 95.4 $ 45.2 $201.7 $100.4 ====== ====== ====== ======
Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001 EXPLORATION & PRODUCTION'S revenues increased $123.6 million, or 115 percent, due primarily to $105 million higher production revenues. The $105 million increase in production revenues includes $114 million associated with an increase in net production volumes partially offset by $9 million from decreased net realized average prices for production (including the effect of hedge positions). The increase in net production volumes mainly results from the acquisition in third quarter 2001 of Barrett Resources Corporation (Barrett). Approximately 83 percent of production in the second quarter of 2002 was hedged. Exploration & Production has contracts that hedge approximately 80 percent of estimated production for the remainder of the year before consideration of the asset sales discussed below. These hedges are entered into with Energy Marketing & Trading which, in turn, enters into offsetting derivative contracts with unrelated third parties. Energy Marketing & Trading 38 Management's Discussion & Analysis (Continued) bears the counterparty performance risks associated with unrelated third parties. During 2001, a portion of the external derivative contracts was with Enron, which filed for bankruptcy in December 2001. As a result, the contracts were effectively liquidated due to contractual terms concerning bankruptcy and Energy Marketing & Trading recorded estimated charges for the credit exposure. Under accounting guidance, the other comprehensive income related to a terminated contract remains in accumulated other comprehensive income and is recognized as the underlying volumes are produced. During the second quarter of 2002, approximately $9 million related to the terminated contracts was recognized as revenues while $62 million remains in accumulated other comprehensive income at June 30, 2002. Segment costs and operating expenses increased $66 million, including an $11 million increase in selling, general and administrative expenses due primarily to the addition of Barrett operations. Segment costs and operating expenses increased due primarily to the addition of the former Barrett operations, comprised primarily of depletion, depreciation and amortization and lease operating expenses. Segment profit increased $50.2 million due primarily to increased production volumes. Subsequent to June 30, 2002, Exploration & Production initiated and completed the sale of Exploration & Production's Jonah Field natural gas production properties in Wyoming to EnCana Oil & Gas (USA) Inc. Exploration & Production also completed the sale of substantially all of its natural gas production properties in the Anadarko Basin to Chesapeake Exploration Limited Partnership . The sales generated approximately $308 million in net cash proceeds. The company expects to recognize a gain from these sales which will be recorded in the third quarter of 2002. Revenues for the three and six months ended June 30, 2002, related to these properties were approximately $22 million and $40 million, respectively. Six Months Ended June 30, 2002 vs. Six Months Ended June 30, 2001 EXPLORATION & PRODUCTION'S revenues increased $208.9 million, or 84 percent, due primarily to $210 million higher production revenues, $7 million in unrealized gains from the mark-to-market financial instruments related to basis differentials on natural gas production partially offset by $18 million lower gas management revenues. The $210 million increase in production revenues includes $270 million associated with an increase in net production volumes, partially offset by $60 million from decreased net realized average prices for production (including the effect of hedge positions). The increase in net production volumes mainly results from the acquisition in third quarter 2001 of Barrett. Approximately 82 percent of production through the second quarter of 2002 was hedged. Through the second quarter of 2002, approximately $18 million related to the Enron terminated contracts discussed above was recognized as revenues. At June 30, 2002, the contracted future hedge contracts are at prices that averaged above the spot market, resulting in an unrealized gain of $93 million (including $62 million related to the terminated contracts as discussed previously) reflected in accumulated other comprehensive income within stockholders' equity. This is a decrease from the unrealized gain at December 31, 2001, due to an increase in natural gas prices. Gas management revenues consist primarily of marketing activities within the Exploration & Production segment that are not a direct part of the results of operations for producing activities. These marketing activities include acquisition and disposition of other working interest and royalty interest gas and the movement of gas from the wellhead to the tailgate of the respective plants for sale to Energy Marketing & Trading or third parties. Segment costs and operating expenses increased $97 million, including a $20 million increase in selling, general and administrative expenses due primarily to the addition of Barrett operations. Segment costs and operating expenses increased due primarily to costs related to the former Barrett operations, comprised primarily of depletion, depreciation and amortization and lease operating expenses, and $5 million higher production-related taxes partially offset by $18 million lower gas management costs and $5 million lower costs from International activities. Segment profit increased $101.3 million due primarily to increased production volumes, partially offset by $10 million lower earnings from equity investments. 39 Management's Discussion & Analysis (Continued) INTERNATIONAL
THREE SIX MONTHS ENDED MONTHS ENDED JUNE 30, JUNE 30, ---------------- ---------------- 2002 2001 2002 2001 ------ ------ ------ ------ (MILLIONS) (MILLIONS) Segment revenues $ 9.1 $ 8.4 $ 18.0 $ 12.7 ====== ===== ====== ====== Segment loss $(57.0) $(9.5) $(77.5) $(30.6) ====== ===== ====== ======
Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001 INTERNATIONAL'S segment loss increased $47.5 million due primarily to a $44.1 million impairment charge related to the Colorado soda ash mining operations and a $4 million increase in equity losses from the Lithuania refinery, pipeline and terminal investment. The $44.1 million impairment charge, which is included in other (income) expense-net, is reflective of management's estimate of fair value which was based on discounted cash flows assuming sale of the facility in 2002 (see Note 3). This impairment is in addition to a $170 million impairment recorded in fourth-quarter 2001. During first-quarter 2002, Williams management announced plans to initiate a reserve-price auction of its interest in Colorado soda ash mining operations mentioned above, in an effort to monetize all or part of its investment. Williams expects to complete the reserve-price auction process during third-quarter 2002. On June 17, 2002 the Lithuania refinery completed an agreement with YUKOS Oil Company (YUKOS) and the Lithuanian government whereby a wholly owned subsidiary of YUKOS has become a shareholder in the Lithuania refinery. YUKOS contributed $75 million of equity and loaned another $75 million to the refinery in return for an approximate 27 percent ownership interest. The Lithuanian government provided a guaranty for the $75 million loan. In addition, YUKOS signed a 10-year crude oil supply agreement with the refinery. This transaction diluted Williams's ownership interest in the refinery from 33 percent to approximately 27 percent. Six Months Ended June 30, 2002 vs. Six Months Ended June 30, 2001 INTERNATIONAL'S segment loss increased $46.9 million due primarily to the $44.1 million impairment charge discussed above related to the Colorado soda ash mining operations and a $5 million increase in equity losses from the Lithuania refinery, pipeline and terminal investment. Slightly offsetting these losses was $5 million lower operating losses from soda ash mining operations. MIDSTREAM GAS & LIQUIDS
THREE SIX MONTHS ENDED MONTHS ENDED JUNE 30, JUNE 30, ---------------- ----------------- 2002 2001 2002 2001 ------ ------ ------ -------- (MILLIONS) (MILLIONS) Segment revenues $505.7 $545.5 $975.3 $1,211.5 ====== ====== ====== ======== Segment profit $ 84.6 $ 64.5 $172.5 $ 104.1 ====== ====== ====== ========
Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001 MIDSTREAM GAS & LIQUIDS' revenues decreased $39.8 million, or 7 percent, due primarily to $49 million lower revenues related to the natural gas liquids trading operations, $9 million lower natural gas liquids sales from processing activities and $8 million lower revenues from gathering activities, partially offset by a $19 million increase in revenue from a gas compression facility in Venezuela which began operations in August 2001 and $10 million higher natural gas liquids sales from fractionation activities. The $49 million decrease in natural gas liquids trading operations revenues reflects decreased natural gas liquids prices coupled with certain activities previously recorded on a gross basis which are now accounted for on a net basis. The $9 million lower natural gas liquids sales from processing activities reflects $45 million from a 21 percent decrease in natural gas liquid sales prices largely offset by $37 million from a 21 percent increase in natural gas liquids volumes. Costs and operating expenses decreased $51 million, or 12 percent, due primarily to lower expenses related to the natural gas liquids trading operations of $36 million, $12 million lower shrinkage, fuel and replacement gas purchases 40 Management's Discussion & Analysis (Continued) relating to processing activities and $6 million lower power costs from the natural gas liquids pipelines. The $36 million lower expense related to the natural gas liquids trading operations is due primarily to the reporting of certain costs net within revenue in 2002 as discussed above. Slightly offsetting these decreases were increased costs of $8 million associated with a gas compression facility in Venezuela which began operations in August 2001. Included in other (income) expense - net within segment costs and expenses for 2001 is a $10.9 million impairment loss related to management's second-quarter 2001 decision and commitment to sell certain south Texas non-regulated gathering and processing assets. The $10.9 million charge represented the impairment of the assets to fair value based on expected proceeds from the sale. In second-quarter 2002, a $4.8 million charge was recognized representing the impairment of assets to fair value associated with the sale of the Kansas-Hugoton natural gas gathering system. This sale closed during third quarter 2002. Segment profit increased $20.1 million, or 31 percent, due primarily to $11 million of segment profit from the gas compression facility in Venezuela, $10 million higher products margin from the fractionation activities, $9 million from higher average per-unit natural gas liquids margins and $7 million higher transportation revenues combined with decreased power costs from the natural gas liquids pipelines. Also contributing was $3.6 million in equity earnings in 2002 versus $5.6 million of equity losses in 2001 reflecting improved results from the Discovery pipeline project. These increases were partially offset by $12 million lower margins from natural gas liquids trading activity and $8 million lower gathering revenues. Subsequent to second quarter 2002, Williams announced the sale of 98 percent of Mapletree LLC and 98 percent of E-Oaktree, LLC to Enterprise Products Partners L.P. Mapletree owns all of Mid-America Pipeline, a 7,226-mile natural gas liquids pipeline system. E-Oaktree owns 80 percent of the Seminole Pipeline, a 1,281-mile natural gas liquids pipeline system. Revenues for the three and six months ended June 30, 2002 related to Mid-America Pipeline and Seminole were approximately $69 million and $141 million, respectively. The sale generated $1.1 billion in net cash proceeds. Williams expects to recognize a gain from the sale which will be recorded in the third quarter 2002. In addition, the Kansas Hugoton natural gas gathering system was sold to FrontStreet Hugoton LLC, an affiliate of FrontStreet Partners, LLC. Williams received approximately $80 million in cash. Six Months Ended June 30, 2002 vs. Six Months Ended June 30, 2001 MIDSTREAM GAS & LIQUIDS' revenues decreased $236.2 million, or 19 percent, due primarily to $113 million lower natural gas liquids sales from processing activities, $94 million lower revenues related to the natural gas liquids trading operations, $29 million lower revenues from processing activities due primarily to lower processing rates from Canadian activities, $29 million lower natural gas liquids sales from fractionation activities and $14 million lower gathering revenues due primarily to decreased volumes. These decreases were partially offset by $39 million increased revenues from the gas compression facility in Venezuela which began operations in August 2001 and $11 million higher transportation revenues associated with pipeline operations. The liquids sales decrease reflects $200 million from 39 percent lower average natural gas liquids sales prices, partially offset by $87 million from a 21 percent increase in volumes sold. The $94 million decrease in natural gas liquids trading operations reflects decreased natural gas liquids prices coupled with certain activities previously recorded on a gross basis which are now accounted for on a net basis. Costs and operating expenses decreased $295 million, or 29 percent, due primarily to $166 million lower shrinkage, fuel and replacement gas purchases relating to processing activities, $90 million lower expenses related to the natural gas liquids trading operations, $39 million lower liquid purchases related to fractionation activities and $13 million lower power expense related to natural gas liquids pipelines. The $90 million lower expense related to the natural gas liquids trading operations is due primarily to the reporting of certain costs net within revenue in 2002 and lower costs related to lower volumes sold. Slightly offsetting these decreases were $15 million of increased costs associated with the gas compression facility in Venezuela which began operations in August 2001. Included in other (income) expense - net within segment costs and expenses for 2001 is the $10.9 million impairment loss related to certain south Texas non-regulated gathering and processing assets. In second-quarter 2002, a $4.8 million charge was recognized representing the impairment of assets to fair value associated with the sale of the Kansas-Hugoton natural gas gathering system which closed in third-quarter 2002. 41 Management's Discussion & Analysis (Continued) Segment profit increased $68.4 million, or 66 percent, due primarily to $33 million from higher average per-unit natural gas liquids margins, $24 million of segment profit from the gas compression facility in Venezuela, $23 million from higher transportation revenues combined with decreased power costs from the natural gas liquids pipelines and $10 million higher products margins from fractionation activities. Also contributing to the increase in segment profit was $5.2 million in equity earnings in 2002 versus $12.8 million of equity losses in 2001. The improvement is primarily due to the Discovery pipeline project. These increases were partially offset by $14 million lower revenue from gathering activities, $13 million lower processing margins primarily due to lower processing rates and $9 million higher general and administrative expenses. PETROLEUM SERVICES
THREE SIX MONTHS ENDED MONTHS ENDED JUNE 30, JUNE 30, -------------------- ------------------- 2002 2001 2002 2001 -------- -------- -------- -------- (MILLIONS) (MILLIONS) Segment revenues $1,154.0 $1,461.7 $2,095.8 $2,795.7 ======== ======== ======== ======== Segment profit (loss) $ (20.7) $ 130.1 $ 9.7 $ 147.1 ======== ======== ======== ========
Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001 PETROLEUM SERVICES' revenues decreased $307.7 million, or 21 percent, due primarily to $138 million lower refining and marketing revenues, $155 million lower travel center/convenience store sales and $20 million lower bio-energy sales, slightly offset by $48 million lower intrasegment sales, which are eliminated and primarily relate to sales from refining and marketing to travel center/convenience stores. The $138 million decrease in refining and marketing revenues is due primarily to a 13 percent lower average refined product sales prices. The $155 million decrease in travel center/convenience store sales reflects a $78 million decrease in revenues related to travel centers and Alaska convenience stores and the absence of $77 million in revenues related to the 198 convenience stores sold in May 2001. The $78 million decrease in revenues of the travel centers and Alaska convenience stores primarily reflects $55 million from a 25 percent decrease in diesel sales volumes and $27 million from a 12 percent decrease in average diesel and gasoline sales prices, partially offset by a $6 million increase in gasoline sales volumes. The decrease in diesel sales volumes includes the impact of the discontinuance of a diesel volume incentive program. The $20 million decrease in bio-energy sales reflects a $28 million decrease from lower average ethanol sales prices partially offset by an $8 million increase from higher ethanol sales volumes. Costs and operating expenses decreased $254 million, or 18 percent, due primarily to $97 million lower refining and marketing costs and $157 million lower travel center/convenience store costs, partially offset by a $48 million increase in external costs due to decreased intrasegment purchases as discussed above, which are eliminated. The $97 million decrease in refining and marketing costs includes a $193 million decrease consisting primarily of lower crude supply costs and other per unit cost of sales from the refineries, partially offset by $101 million increase in the cost of refined product purchased for resale. The $157 million decrease in travel center and Alaska convenience store costs reflects the absence of $76 million in costs related to the 198 convenience stores sold in May 2001 and $82 million decrease in costs for the travel centers and Alaska convenience stores. The $82 million decrease reflects $53 million from decreased diesel sales volumes, $27 million from lower average gasoline and diesel purchase prices and $8 million lower store operating and merchandise costs, offset by a $5 million increase in gasoline purchase volumes. Other (income) expense - net in 2002 includes $27 million in loss accruals and impairment charges related to certain travel centers (see Note 3). Other (income) expense - net in 2001 includes a $72.1 million pre-tax gain from the sale of convenience stores in May 2001. Segment profit decreased $150.8 million to a $20.7 million segment loss due primarily to the net unfavorable effect of the items discussed above in other (income) expense - net and the $45 million lower operating profit from refining and marketing operations due primarily to narrowing crack spreads. As previously discussed, Williams has begun to more narrowly focus its business strategy within its major business units. The refining and marketing operations are businesses that have been announced as possible assets to be sold. In addition, the travel centers, Alaska convenience stores, and bio-energy operations are also businesses that may be sold in the future. 42 Management's Discussion & Analysis (Continued) Six Months Ended June 30, 2002 vs. Six Months Ended June 30, 2001 PETROLEUM SERVICES' revenues decreased $699.9 million, or 25 percent, due primarily to $444 million lower refining and marketing revenues, $335 million lower travel center/convenience store sales and $21 million lower bio-energy sales, slightly offset by $107 million lower intrasegment sales, which are eliminated and primarily relate to sales from refining and marketing to travel center/convenience stores. The $444 million decrease in refining and marketing revenues includes $412 million resulting from 21 percent lower average refined product sales prices and $32 million from a decrease in refined product volumes sold. The $335 million decrease in travel center/convenience store sales reflects a $153 million decrease in revenues related to travel centers and Alaska convenience stores and the absence of $182 million in revenues related to the 198 convenience stores sold in May 2001. The $153 million decrease in revenues of the travel centers and Alaska convenience stores primarily reflects $95 million from a 23 percent decrease in diesel sales volumes and $63 million from a 14 percent decrease in average diesel and gasoline sales prices, partially offset by an $8 million increase in gasoline sales volumes. The $21 million decrease in bio-energy sales reflects $45 million lower average ethanol sales prices, partially offset by $20 million higher ethanol sales volumes. Costs and operating expenses decreased $642.9 million, or 24 percent, due primarily to $396 million lower refining and marketing costs, $339 million lower travel center/convenience store costs and $8 million lower bio-energy product and operating costs, partially offset by $107 million increase in external costs due to decreased intrasegment purchases discussed above, which are eliminated. The $396 million decrease in refining and marketing costs includes a $342 million decrease from lower crude supply costs and other per unit cost of sales from the refineries and a $48 million decrease in the cost of refined product purchased for resale. The $339 million decrease in travel center and Alaska convenience store costs reflects the absence of $181 million in costs related to the 198 convenience stores sold in May 2001 and a $160 million decrease in costs for the travel centers and Alaska convenience stores. The $160 million decrease reflects $64 million from lower gasoline and diesel purchase prices and $91 million from decreased diesel purchase volumes and $12 million lower store operating and merchandise costs, partially offset by $7 million in increased gasoline purchase volumes. Other (income) expense - net in 2002 includes $27 million in loss accruals and impairment charges related to certain travel centers (see Note 3). Other (income) expense - net in 2001 includes a $72.1 million pre-tax gain from the sale of convenience stores in May 2001. Also included in other (income) expense - net in 2001 is an $11.2 million impairment charge related to an end-to-end mobile computing systems business. Segment profit decreased $137.4 million, or 93 percent, due primarily to the net unfavorable effect related to the items noted above in other (income) expense - net and the $54 million lower operating profit from refining and marketing operations due primarily to narrowing crack spreads. WILLIAMS ENERGY PARTNERS
THREE SIX MONTHS ENDED MONTHS ENDED JUNE 30, JUNE 30, ---------------- ---------------- 2002 2001 2002 2001 ------ ------ ------ ------ (MILLIONS) (MILLIONS) Segment revenues $104.0 $102.3 $196.1 $199.9 ====== ====== ====== ====== Segment profit $ 29.5 $ 33.7 $ 56.4 $ 56.5 ====== ====== ====== ======
Three Months Ended June 30, 2002 vs. Three Months Ended June 30, 2001 WILLIAMS ENERGY PARTNERS' revenue increased $1.7 million, or 2 percent, due primarily to $2 million higher revenues from transportation activities, a marine facility acquired in October 2001, and two inland terminals acquired in June 2001, partially offset by lower ammonia transportation revenues. Segment profit decreased $4.2 million, or 12 percent, due primarily to a $3 million increase in selling, general and administrative expenses incurred by the general partner. 43 Management's Discussion & Analysis (Continued) Six Months Ended June 30, 2002 vs. Six Months Ended June 30, 2001 WILLIAMS ENERGY PARTNERS' revenue decreased $3.8 million, or 2 percent, due primarily to $10 million lower commodity sales from transportation activities, partially offset by $4 million higher revenues from a marine facility acquired in October 2001 and two inland terminals acquired in June 2001. Costs and operating expenses decreased $11 million due primarily to $14 million lower costs from transportation activities consisting primarily of $10 million lower product costs. Segment profit for both periods was comparable despite the overall favorable impact of the revenue increase and the decrease in costs and operating expenses which were offset by higher selling, general and administrative expenses incurred by the general partner. 44 Management's Discussion & Analysis (Continued) FAIR VALUE OF ENERGY RISK MANAGEMENT AND TRADING ACTIVITIES The fair value of energy risk management and trading contracts for Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) decreased $343 million during second-quarter 2002 and $84 million year-to-date. The following table reflects the changes in fair value between December 31, 2001 and June 30, 2002.
(Millions) ---------- FAIR VALUE OF CONTRACTS OUTSTANDING AT DECEMBER 31, 2001 $2,261 Recognized losses included in the fair value of contracts outstanding at December 31, 2001 expected to be realized during the period 173 Initial recorded value of new contracts entered into during the period 181 Net options premiums received during the period (1) (271) Changes attributable to market movements of contracts outstanding at March 31, 2002 176 ------ FAIR VALUE OF CONTRACTS OUTSTANDING AT MARCH 31, 2002 $2,520 Recognized Gains included in the fair value of contracts outstanding at March 31, 2002 expected to be realized during the period (243) Initial recorded value of new contracts entered into during the period 22 Net options premiums paid during the period (1) 23 Changes attributable to market movements of contracts outstanding at June 30, 2002 (145) ------ FAIR VALUE OF CONTRACTS OUTSTANDING AT JUNE 30, 2002 $2,177
(1) Option Premiums paid and received are included in the fair value of contracts outstanding during any given period as they are a portion of the overall energy trading portfolio. Option premiums paid result in an initial increase the fair value of contracts outstanding and decrease in cash; premiums received result in an initial decrease in the fair value of contracts outstanding and an increase in cash. The underlying values of the options associated with the premium payments are also included in the fair value of contracts outstanding. 45 Management's Discussion & Analysis (Continued) The following tables reconcile the changes in fair value of energy risk management and trading contracts during first and second quarter 2002 to energy risk management trading revenues for those periods. Change in fair value during first-quarter 2002 $ 259 Net option premiums received 271 Recognized losses included in the fair value of contracts outstanding at December 31, 2001 expected to be realized during the period (173) Gains in interest rate hedges (1) 28 Other unrealized losses not included in the change in fair value (12) ------ Revenues recognized but not realized during first quarter 2002 $ 373 Revenues recognized and realized during first quarter 2002 (5) ------ ENERGY RISK MANAGEMENT AND TRADING REVENUES DURING FIRST QUARTER 2002 $ 368 Change in fair value during second quarter 2002 $ (343) Net option premiums paid (23) Recognized losses included in the fair value of contracts outstanding at March 31, 2002 expected to be realized during the period 243 Losses in interest rate hedges (1) (115) Other unrealized losses not included in the change in fair value (32) ------ Revenues recognized but not realized during second quarter 2002 $ (270) Revenues recognized and realized during second quarter 2002 (8) ------ ENERGY RISK MANAGEMENT AND TRADING REVENUES DURING SECOND QUARTER 2002 $ (278)
(1) Energy Marketing & Trading, through Williams, enters into interest rate derivatives to mitigate the associated interest rate risk from the fair value of the long-dated energy and energy-related contracts by fixing the interest rate inherent in the portfolio of contracts. 46 Management's Discussion & Analysis (Continued) The charts below reflect the fair value of energy risk management and trading contracts for Energy Marketing & Trading and the natural gas liquids trading operations now reported in the Midstream Gas & Liquids segment at December 31, 2001, March 31, 2002, and June 30, 2002 by valuation methodology and the year in which the recorded fair value is expected to be realized.
TO BE TO BE TO BE TO BE TO BE REALIZED IN REALIZED IN REALIZED IN REALIZED IN REALIZED IN 1-12 MONTHS 13-36 MONTHS 37-60 MONTHS 61-120 MONTHS 121+ MONTHS TOTAL FAIR VALUATION TECHNIQUE (YEAR 1) (YEARS 2-3) (YEARS 4-5) (YEARS 6-10) (YEARS 11+) VALUE ------------------- ----------- ------------ ------------ ------------- ------------ ---------- BASED UPON 12/31/2001 $ 757 $ 316 $ 345 $ 363 $ 18 $1,799 QUOTED PRICES IN ACTIVE MARKETS 3/31/2002 $ 875 $ 337 $ 379 $ 435 $ (5) $2,021 AND QUOTED PRICES & OTHER 6/30/2002 $ 625 $ 396 $ 383 $ 391 $ 4 $1,799 EXTERNAL FACTORS -------------------------------------------------------------------------------------------------- IN LESS LIQUID MARKETS (1) -------------------------------------------------------------------------------------------------------------------------- 12/31/2001 231 12 (19) 50 188 462 BASED UPON 3/31/2002 53 30 -- 125 291 499 MODELS & OTHER VALUATION 6/30/2002 143 (111) (33) 112 267 378 TECHNIQUES (2) -------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------- 12/31/2001 $ 988 $ 328 $ 326 $ 413 $ 206 $2,261 3/31/2002 $ 928 $ 367 $ 379 $ 560 $ 286 $2,520 TOTAL 6/30/2002 $ 768 $ 285 $ 350 $ 503 $ 271 $2,177 -------------------------------------------------------------------------------------------------- 1Q CHANGE $ (60) $ 39 $ 53 $ 147 $ 80 $ 259 2Q CHANGE $ (160) $ (82) $ (29) $ (57) $ (15) $ (343) --------------------------------------------------------------------------------------------------------------------------
(1) A significant portion of the value expected to be realized relates to a contract within the California power market. The terms of this agreement provide for the sale of power at prices ranging from $62.50 to $87.00 per megawatt hour over a ten-year period at variable volumes up to 1,400 megawatts per hour. On July 26, 2002 Williams announced that it had reached an agreement in principle with the State of California and other parties including the States of Washington and Oregon on a global settlement that is expected to result in a new long-term energy contract between Williams and the State of California. Further discussion of this settlement is included on page 14. (2) Quoted market prices of the underlying commodities are significant factors in estimating the fair value. Energy Marketing & Trading manages the risk assumed from providing energy risk management services to its customers. This risk results from exposure to energy commodity prices, volatility and correlation of commodity prices, the portfolio position of the contracts, liquidity of the market in which the contract is transacted, interest rates, and counterparty performance and credit. Energy Marketing & Trading seeks to diversify its portfolio in managing the commodity price risk in the transactions that it executes in various markets and regions by executing offsetting contracts to manage the commodity price risk in accordance with parameters established in its trading policy. However, as noted previously, during the second quarter of 2002, Energy Marketing & Trading was significantly constrained in its ability to manage or hedge its portfolio against adverse market movements according to the aforementioned methodology due to a lack of market liquidity, the market's concerns regarding Williams credit and liquidity, and internal efforts to preserve liquidity. Subsequent to June 30, 2002 and in response to factors such as recent downgrades to below-investment grade by the credit rating agencies and difficulties in obtaining financing facilities, the Company announced a significant reduction in its financial commitment to the Energy Marketing & Trading segment and is consequently evaluating opportunities to sell or liquidate Energy Marketing & Trading's trading portfolio or to form a joint venture around the Energy Marketing and Trading unit with another party. As a result of this decision, the ultimate realization of the estimated fair value of Energy Marketing & Trading's portfolio under this strategy may vary from the amount of the Company's estimate at June 30, 2002. 47 Management's Discussion & Analysis (Continued) FINANCIAL CONDITION AND LIQUIDITY LIQUIDITY Williams' liquidity comes from both internal and external sources. Certain of those sources are available to Williams (parent) and certain of its subsidiaries. Available cash equivalent investments at June 30, 2002, were $498 million, as compared to $1.1 billion at December 31, 2001. Subsequent to June 30, 2002, Williams' credit ratings were downgraded to levels considered below investment grade by the major rating agencies. Following these downgrades, Williams' liquidity became strained as Williams was unable to complete a renewal of its unsecured short-term bank credit facility which supported the $2.2 billion commercial paper program. Williams responded to these events with a concentrated effort to complete certain asset sales and obtain secured credit facilities in order to raise funds to meet maturing debt obligations and provide liquidity that should provide sufficient funding for at least the balance of the year. In addition, the board of directors reduced the quarterly dividend on common stock from $.20 per share to $.01 per share. After consideration of the asset sales and the secured credit facilities which closed subsequent to June 30, 2002, Williams' sources of liquidity consist primarily of the following: o $700 million available under Williams' $700 million unsecured bank credit facility at June 30, 2002, as compared to $700 million under an unsecured bank credit facility at December 31, 2001. This facility was amended to provide security interests to the participating banks and will reduce to $400 million as assets are sold (see Note 18). o A new $400 million secured short-term letter of credit agreement which expires July 29, 2003. o $900 million from a one-year borrowing arrangement secured by substantially all of the oil and gas interests of Williams Production RMT Company (see Note 18). o Approximately $1.5 billion of cash proceeds from the sale of substantially all of its natural gas liquids pipeline systems and certain exploration and production properties. o $325 million from the issuance of debt at Transcontinental Gas Pipe Line in July 2002. These funds will primarily be used to extinguish $150 million of variable interest rate debt, which was retired on July 31, 2002, and $125 million of fixed rate debt which matures in September 2002. o Cash generated from operations and the future sales of certain assets. The amounts above do not take into account the significant uses of cash or facilities that have occurred through August 9, 2002: o Retirement of $300 million in Notes Payable on July 30, 2002. o Retirement of $150 million of variable interest rate debt at Transcontinental Gas Pipe Line on July 31, 2002. o Retirement of $350 million of 6.2 percent notes on July 31, 2002. o Redemption of $135 million in preferred interest on August 8, 2002 which was accelerated due to the credit rating downgrade. o Planned utilization of a significant portion of $400 million letter of credit facility. o Funding of approximately $665 million of cash collateral and margin deposits (through August 12, 2002) which were required under certain contracts. In April 2002, Williams filed a shelf registration statement with the Securities and Exchange Commission to enable it to issue up to $3 billion of a variety of debt and equity securities. This registration statement was declared effective June 26, 2002. In addition, there are outstanding subsidiary registration statements filed with the Securities and Exchange Commission for Northwest Pipeline, Texas Gas Transmission and Transcontinental Gas Pipe Line (each a wholly owned subsidiary of Williams). As of August 9, 2002, approximately $450 million of shelf availability remains under these outstanding registration statements which may be used to issue a variety of debt or equity securities. Interest rates and market conditions will affect amounts borrowed, if any, under these arrangements. Capital and investment expenditures for 2002 are estimated to total approximately $2.2 billion. Williams expects to fund capital and investment expenditures, debt payments and working-capital requirements through (1) cash generated from operations, (2) the use of the available portion of Williams' $700 million bank-credit facility, and/or (3) the sale or disposal of existing assets. 48 Management's Discussion & Analysis (Continued) Credit Ratings At December 31, 2001, Williams maintained certain preferred interest and debt obligations that contained provisions requiring accelerated payment of the related obligation or liquidation of the related assets in the event of specified levels of decline in Williams' credit ratings given by Moody's Investor's Service, Standard & Poor's and Fitch Ratings (rating agencies). Performance by Williams under these terms included potential acceleration of debt payment and redemption of preferred interests totaling $816 million at December 31, 2001. During the first quarter of 2002, Williams negotiated changes to certain of the agreements which eliminated the exposure to the "ratings trigger" clauses incorporated in the agreements. Negotiations for one of the agreements resulted in Williams agreeing to redeem a $560 million preferred interest over the next year in equal quarterly installments (see Note 13). The amount related to potential acceleration of debt payment and redemption of preferred interests was reduced to $182 million at March 31, 2002. As a result of the credit rating downgrades in July 2002, Williams redeemed $135 million of preferred interests on August 1, 2002 and plans to repay a $47 million loan by the end of August. Williams' energy risk management and trading business also relied upon the investment-grade rating of Williams' senior unsecured long-term debt to satisfy credit support requirements of many counterparties. As a result of the credit rating downgrades to below investment grade, Energy Marketing & Trading's participation in energy risk management and trading activities will require alternate credit support under certain existing agreements. In addition, Williams will be required to fund margin requirements pursuant to industry standard derivative agreements with cash, letters of credit or other negotiable instruments. Subsequent to June 30, 2002, Williams and its subsidiaries have been notified that cash, letters of credit or other negotiable instruments would be required under terms of certain contracts. Through August 12, 2002, Williams has provided approximately $665 million in cash, including prepayments for crude oil for the refineries and margin requirements. Williams continues to negotiate on other notifications for significant levels. Off-Balance Sheet Financing Arrangements and Guarantees of Debt or Other Commitments to Third Parties As disclosed in Williams Current Report on Form 8-K dated May 28, 2002, Williams has operating lease agreements with two special purpose entities (SPE's). The operating lease agreements are with respect to certain Williams travel center stores, offshore oil and gas pipelines and an onshore gas processing plant. As a result of changes to these agreements in conjunction with the secured financing facilities completed in July 2002, these agreements no longer qualify for operating lease treatment and as such will be reflected as capital leases beginning in July 2002. If these agreements were treated as capital leases at June 30, 2002, assets and long-term debt would increase by $287 million. At June 30, 2002, Williams had agreements to sell, on an ongoing basis, certain of its accounts receivable to qualified special-purpose entities. On July 25, 2002, these agreements expired and were not renewed. WCG and significant events since December 31, 2001 regarding WCG At December 31, 2001, Williams had financial exposure from WCG of $375 million of receivables and $2.21 billion of guarantees and payment obligations. Williams determined it was probable it would not fully realize the $375 million of receivables and it would be required to perform under its $2.21 billion of guarantees and payment obligations. Williams developed an estimated range of loss related to its total WCG exposure and management believed that no loss within that range was more probable than another. For 2001, Williams recorded the $2.05 billion minimum amount of the range of loss from its financial exposure to WCG, which was reported in the Consolidated Statement of Operations as a $1.84 billion pre-tax charge to discontinued operations and a $213 million pre-tax charge to continuing operations. The charge to discontinued operations of $1.84 billion included a $1.77 billion minimum amount of the estimated range of loss from performance on $2.21 billion of guarantees and payment obligations. The charge to continuing operations of $213 million included estimated losses from an assessment of the recoverability of the carrying amounts of the $375 million of receivables and a $25 million investment in WCG common stock. Williams, prior to the spinoff of WCG, provided indirect credit support for $1.4 billion of WCG's Note Trust Notes. On March 5, 2002, Williams received the requisite approvals on its consent solicitation to amend the terms of the WCG Note Trust Notes. The amendment, among other things, eliminated acceleration of the WCG Note Trust Notes due to a WCG bankruptcy or from a Williams credit rating downgrade. The amendment also affirmed Williams' obligation for all payments due with respect to the WCG Note Trust Notes, which mature in March 2004, and allows Williams to fund such payments from any available sources. In July 2002, Williams acquired substantially all of the WCG Note Trust Notes by exchanging $1.4 billion of Williams Senior Unsecured 9.25 percent Notes due March 2004. With the exception of the March and September 2002 interest payments, totaling $115 million, WCG, through a subsidiary, remains obligated to reimburse Williams for any payments Williams makes in connection with the Notes. 49 Management's Discussion & Analysis (Continued) Williams also provided a guarantee of WCG's obligations under a 1998 transaction in which WCG entered into a lease agreement covering a portion of its fiber-optic network. WCG had an option to purchase the covered network assets during the lease term at an amount approximating the lessor's cost of $750 million. On March 8, 2002, WCG exercised its option to purchase the covered network assets. On March 29, 2002, Williams funded the purchase price of $754 million and became entitled to an unsecured note from WCG for the same amount. Pursuant to the terms of an agreement between Williams and WCG's revolving credit facility lenders, the liability of WCG to compensate Williams for funding the purchase is subordinated to the interests of WCG's revolving credit facility lenders and will not mature any earlier than one year after the maturity of WCG's revolving credit facility. Williams has also provided guarantees on certain other performance obligations of WCG totaling approximately $57 million. 2002 EVALUATION At June 30, 2002, Williams had receivables and claims from WCG of $2.15 billion arising from Williams affirming its payment obligation on the $1.4 billion of WCG Note Trust Notes and Williams paying $754 million under the WCG lease agreement. At June 30, 2002, Williams also has $356 million of previously existing receivables. In second-quarter 2002, Williams recorded in continuing operations a pre-tax charge of $15 million related to WCG, including an assessment of the recoverability of its receivables and claims from WCG. For the six months ended June 30, 2002, Williams has recorded in continuing operations pre-tax charges of $247 million related to recovery of these receivables and claims. At June 30, 2002, Williams estimates that approximately $2.2 billion of the $2.5 billion of receivables from WCG are not recoverable. See Note 4 for further discussion of Williams' estimate of recoverability including terms of the Settlement Agreement between Williams, WCG, the Official Committee of Unsecured Creditors and Leucadia National Corporation. OPERATING ACTIVITIES In March 2002, WCG exercised its option to purchase certain network assets under an operating lease agreement for which Williams provided a guarantee of WCG's obligations. On March 29, 2002, Williams, as guarantor under the agreement, paid $754 million related to WCG's purchase of these network assets. In return, Williams became entitled to receive an instrument of unsecured debt from WCG in the same amount. Williams recorded an additional pre-tax charge of $232 million and $15 million in first and second quarter 2002, respectively, related to its assessment of the recoverability of certain receivables from WCG (see Note 4). During 2002, Williams was required to establish surety bonds with various insurance companies and provide cash collateral in support of letters of credit due to downgrades by credit rating agencies. These bonds are reported as current and noncurrent restricted cash in the balance sheet and totalled approximately $271 million at June 30, 2002. During second-quarter 2002, Williams recorded approximately $154 million in provisions for losses on property and other assets. Those provisions consisted primarily of a partial impairment of goodwill at Energy Marketing & Trading and an impairment related to the soda ash mining operations. During second-quarter 2002, Williams made a $55 million contribution to its pension plan. Due to the decline of the stock market in recent months, the plan assets have decreased from the values at year end. If the recent stock market trend continues, it is likely that Williams would need to contribute additional cash to the pension plan. FINANCING ACTIVITIES On January 14, 2002, Williams completed the sale of 44 million publicly traded units, more commonly known as FELINE PACS, that include a senior debt security and an equity purchase contract. The $1.1 billion of debt has a term of five years, and the equity purchase contract will require the company to deliver Williams common stock to holders after three years based on a previously agreed rate. Net proceeds from this issuance were approximately $1.1 billion. The FELINE PACS were issued as part of Williams' plan to strengthen its balance sheet and maintain its investment-grade rating. On March 19, 2002, Williams issued $850 million of 30-year notes with an interest rate of 8.75 percent and $650 million of 10-year notes with an interest rate of 8.125 percent. The proceeds were used to repay outstanding commercial paper, provide working capital and for general corporate purposes. 50 Management's Discussion & Analysis (Continued) In April 2002, Williams Energy Partners L.P., a partially owned and consolidated entity of Williams, borrowed $700 million from a group of institutions. These proceeds were primarily used to acquire Williams Pipe Line, a wholly owned subsidiary of Williams. In May 2002, Williams Energy Partners L.P. issued approximately 8 million common units at $37.15 per unit resulting in approximately $283 million of net proceeds that were used to reduce the $700 million loan. Williams Energy Partners L.P. expects to refinance the June 30, 2002 balance of $411 million in short-term debt with long-term debt financing. In May 2002, Energy Marketing & Trading entered into an agreement which transferred the rights to certain receivables, along with risks associated with that collection, in exchange for cash. Due to the structure of the agreement, Energy Marketing & Trading accounted for this transaction as debt collateralized by the claims. The $79 million of debt is classified as current. On March 27, 2002, concurrent with its sale of Kern River to MEHC, Williams issued approximately 1.5 million shares of 9.875 percent cumulative convertible preferred stock for $275 million. Dividends on the preferred stock are payable quarterly (see Note 14). In July 2002, Williams reduced the quarterly dividend on common stock from $.20 per share to $.01 per share. Additionally, one of the new covenants within the credit agreements limits the common stock dividends paid by Williams in any quarter to not more than $6.25 million. For financing activities subsequent to June 30, 2002, see discussions in the Liquidity section on page 48 and Note 18 on page 27. Williams' long-term debt to debt-plus-equity ratio was 68.1 percent at June 30, 2002, compared to 59.9 percent at December 31, 2001 (excluding Kern River debt). If short-term notes payable and long-term debt due within one year are included in the calculations, these ratios would be 71.8 percent at June 30, 2002 and 65.5 percent at December 31, 2001. Additionally, the long-term debt to debt-plus-equity ratio as calculated for covenants under certain debt agreements was 63.5 percent at June 30, 2002 as compared to 61.5 percent at December 31, 2001. INVESTING ACTIVITIES Williams has contributed approximately $122 million and $81 million towards the development of the Gulfstream joint venture project, a Williams equity investment, during the first and second quarter, respectively, of 2002. Proceeds from the sales of businesses include $434.6 million related to the sale of Kern River on March 27, 2002. In July 2002, Williams received $32.5 million plus interest, related to the portion of the sales prices that was contingent upon Kern River receiving a certificate from the FERC. This certificate was received in July 2002. COMMITMENTS The table below summarizes the maturity or redemption by year of the notes payable, long-term debt and preferred interests in consolidated subsidiaries outstanding at June 30, 2002 by period. This table does not reflect the $900 million borrowing arrangement which matures July 2003.
July 1- December 31 2002(1) 2003 2004 2005 2006 Thereafter Total ------------ ------ ------ ---- ------ ---------- ------ Notes payable $711 $ -- $ -- $ -- $ -- $ -- $ 711 Long-term debt, including current portion(2) 920 1,148 3,006(3) 255 1,130(4) 7,149 13,608 Preferred interests in consolidated subsidiaries 335 -- -- -- 100 -- 435
---------- (1) As of August 9, 2002, $904 million has been paid on these obligations. (2) Subsequent to June 30, 2002, terms of certain operating leases were changed and as a result, will be considered capitalized leases. This amount was $287 million at June 30, 2002, and will be included in debt in third quarter 2002. (3) Includes $1.1 billion of 6.5% notes, payable 2007, subject to remarketing in 2004. (4) Includes $400 million of 6.75% notes, payable 2016, putable/callable in 2006. OTHER As disclosed in the March 31, 2002 Form 10-Q, if lump sum payments from the pension plan reaches settlement accounting threshold, Williams will need to recognize certain unrecognized net losses which could increase pension expense in third or fourth quarter of 2002 by $25 million to $35 million. This entire expense would be recognized at such time that the settlement accounting threshold is met. 51 Management's Discussion & Analysis (Continued) ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK INTEREST RATE RISK Williams' interest rate risk exposure associated with the debt portfolio was impacted by new debt issuances in first-quarter 2002. In January 2002, Williams issued $1.1 billion of 6.5 percent notes payable 2007 (see Note 11). In February 2002, $240 million of 6.125 percent notes were retired. In March 2002, Williams issued $850 million of 8.75 percent notes due 2032 and $650 million of 8.125 percent notes due 2012. Also in March 2002, the terms of a $560 million priority return structure classified as preferred interest in consolidated subsidiaries were amended. Based on the new payment terms of the amendment, the remaining balance due has been reclassified from preferred interests in consolidated subsidiaries to long-term debt due within one year (see Note 13). The interest rate varies based on LIBOR plus an applicable margin and was 2.57 percent at June 30, 2002. Pursuant to the completion of a consent solicitation during first-quarter 2002 with WCG Note Trust holders, Williams recorded $1.4 billion of long-term debt obligations which mature in March 2004 and bear an interest rate of 8.25 percent. Subsequent to June 30, 2002, Williams completed an exchange of Williams 9.25 percent notes due March 2004 for substantially all of these securities (see Note 4). In May 2002, Williams Energy Partners entered into a $700 million short-term debt obligation which matures in October 2002. The interest rate varies based on the Eurodollar rate plus 2.5 percent for the first 120 days of the short-term debt obligation and, thereafter, at the Eurodollar rate plus 4 percent. This rate was 4.3 percent at June 30, 2002. In July 2002, Transcontinental Gas Pipe Line issued $325 million of 8.875 percent long-term debt obligations due 2012. Subsequent to June 30, 2002, Williams obtained a $900 million secured short-term loan. The borrowing accrues interest at a 14 percent interest rate plus a variable rate which is currently 5.82 percent. COMMODITY PRICE RISK At June 30, 2002, the value at risk for the Energy Marketing & Trading operations and the natural gas liquids trading operations now reported in the Midstream Gas & Liquids segment was $74.5 million compared to $75.2 million at March 31, 2002. Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the trading portfolio. The value-at-risk model includes all financial instruments and physical positions and commitments in its trading portfolio and assumes that as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the trading portfolio will not exceed the value at risk. The value-at-risk model uses historical simulations to estimate hypothetical movements in future market prices assuming normal market conditions based upon historical market prices. Value at risk does not consider that changing the energy risk management and trading portfolio in response to market conditions could affect market prices and could take longer to execute than the one-day holding period assumed in the value-at-risk model. While a one-day holding period is the industry standard, a longer holding period could more accurately represent the true market risk in an environment where market illiquidity and credit and liquidity constraints of the company may result in further inability to mitigate risk in a timely manner in response to changes in market conditions. 52 PART II. OTHER INFORMATION Item 1. Legal Proceedings The information called for by this item is provided in Note 12 Contingent liabilities and commitments included in the Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item. Item 2. Changes in Securities and Use of Proceeds Pursuant to the terms of the new credit facilities entered into on July 31, 2002, Williams is restricted from declaring and paying dividends in any quarter the aggregate amount of which would be greater than $6.25 million. This restriction does not limit Williams' ability to declare and pay dividends on preferred stock issued prior to July 31, 2002, nor does it limit the ability of Williams Energy Partners, L.P. to make distributions to its unit holders pursuant to the terms of its partnership agreement. The terms of the 9.875 percent cumulative convertible preferred stock issued to MEHC (see Note 14) prohibit Williams from declaring and paying dividends on its common stock or any other parity preferred stock if dividends on the 9.875 percent cumulative convertible preferred stock are in arrears. Dividends on all parity preferred stock not paid in full must be paid pro rata. Item 4. Submission of Matters to a Vote of Security Holders The Annual Meeting of Stockholders of the Company was held on May 16, 2002. At the Annual Meeting, five individuals were elected as directors of the Company and eight individuals continue to serve as directors pursuant to their prior election. The Williams Companies, Inc. 2002 Incentive Plan was approved, and the appointment of Ernst & Young LLP as the independent auditor of the Company for 2002 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 Broker Non-votes ----------------- ----------- ----------- ---------------- Hugh M. Chapman 427,929,716 11,019,138 -- Ira D. Hall 427,799,045 11,149,809 -- Frank T. MacInnis 428,196,271 10,752,583 -- Steven J. Malcolm 430,096,135 8,852,719 -- Janice D. Stoney 427,466,977 11,481,877 --
Approval of The Williams Companies, Inc. 2002 Incentive Plan
For Against Abstain Broker Non-votes ----------- ---------- --------- ---------------- 368,839,919 65,857,217 4,251,718 --
Ratification of Appointment of Independent Auditors
For Against Abstain Broker Non-votes ----------- ---------- --------- ---------------- 416,876,138 19,280,711 2,792,005 --
Item 6. Exhibits and Reports on Form 8-K (a) The exhibits listed below are filed as part of this report: Exhibit 4.1--Indenture dated as of July 3, 2002 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A. as trustee, for the Series A and Series B 8-7/8% Notes due July 15, 2012 Exhibit 10.1--Purchase Agreement between E-Birchtree, LLC and Enterprise Products Operating L.P. dated as of July 31, 2002. Exhibit 10.2--Purchase Agreement between E-Birchtree, LLC and E-Cypress, LLC dated as of July 31, 2002. Exhibit 10.3--$900,000,000 Credit Agreement dated as of July 31, 2002, among The Williams Companies, Inc., Williams Production Holdings LLC, Williams Production RMT Company, as Borrower, the Several Lenders from time to time parties thereto, Lehman Brothers Inc., as Lead Arranger and Book Manager, and Lehman Commercial Paper Inc., as Syndication Agent and Administrative Agent. Exhibit 10.4--Guarantee and Collateral Agreement made by The Williams Companies, Inc., Williams Production Holdings LLC, Williams Production RMT Company and certain of its Subsidiaries in favor of Lehman Commercial Paper Inc., as Administrative Agent, dated as of July 31, 2002. Exhibit 10.5--Termination Agreement between The Williams Companies, Inc. and Keith E. Bailey dated May 1, 2002. Exhibit 10.6--Security Agreement dated as of July 31, 2002, among The Williams Companies, Inc. and each of the Subsidiaries which is a signatory hereto or which subsequently becomes a party hereto in favor of Citibank, N.A., as collateral trustee for the benefit of the holders of the Secured Obligations. Exhibit 10.7--Pledge Agreement dated as of July 31, 2002, among The Williams Companies, Inc. and each of the Subsidiaries which is a signatory hereto or which subsequently becomes a party hereto in favor of Citibank, N.A., as collateral trustee for the benefit of the holders of the Secured Obligations. Exhibit 10.8--Guaranty dated as of July 31, 2002 by Williams Gas Pipeline Company, L.L.C. in favor of the Financial Institutions. Exhibit 10.9--Collateral Trust Agreement among The Williams Companies, Inc., and certain of its Subsidiaries, as Debtors, and Citibank, N.A., as Collateral Trustee, dated as of July 31, 2002. Exhibit 10.10--Form of Guaranty dated as of July 31, 2002 by each of the entities named on the signature pages hereto in favor of Citibank, N.A., as surety administrative agent for the Financial Institutions. Exhibit 10.11--Form of Subordinated Guaranty dated as of July 31, 2002 by Williams Production Holdings LLC in favor of the Financial Institutions. Exhibit 10.12--Consent and Fourth Amendment to the Credit Agreement dated as of July 31, 2002 among the Borrowers party to the Credit Agreement, the Banks from time to time party to the Credit Agreement, the Co-Syndication Agents as named therein, the Documentation Agent as named therein and Citibank, N.A., as agent for the Banks. Exhibit 10.13--U.S. $400,000,000 Credit Agreement dated as of July 31, 2002 among The Williams Companies, Inc., as Borrower, Citicorp USA, Inc., as Agent and Collateral Agent, Bank of America N.A., as Syndication Agent, Citibank, N.A. and Bank of America N.A., as Issuing Banks, the Banks named herein, as Banks, and Salomon Smith Barney Inc., as Arranger. Exhibit 12--Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements Exhibit 99.1--Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 by Steven J. Malcolm, Chief Executive Officer of The Williams Companies, Inc. Exhibit 99.2--Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 by Jack D. McCarthy, Chief Financial Officer of The Williams Companies, Inc. (b) During second-quarter 2002, the Company filed a Form 8-K on April 1, 2002; April 15, 2002; April 25, 2002; April 26, 2002; May 3, 2002; May 22, 2002 (filed two Form 8-K's this date); May 28, 2002 (filed two Form 8-K's this date); June 6, 2002; June 12, 2002; June 24, 2002 (filed two Form 8-K's this date); and June 28, 2002, which reported significant events under Item 5 of the Form and included the Exhibits required by Item 7 of the Form. 53 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. THE WILLIAMS COMPANIES, INC. ----------------------------- (Registrant) /s/ Gary R. Belitz ----------------------------- Gary R. Belitz Controller (Duly Authorized Officer and Principal Accounting Officer) August 14, 2002 INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION ------- ----------- 4.1 Indenture dated as of July 3, 2002 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A. as trustee, for the Series A and Series B 8-7/8% Notes due July 15, 2012 10.1 Purchase Agreement between E-Birchtree, LLC and Enterprise Products Operating L.P. dated as of July 31, 2002. 10.2 Purchase Agreement between E-Birchtree, LLC and E-Cypress, LLC dated as of July 31, 2002. 10.3 $900,000,000 Credit Agreement dated as of July 31, 2002, among The Williams Companies, Inc., Williams Production Holdings LLC, Williams Production RMT Company, as Borrower, the Several Lenders from time to time parties thereto, Lehman Brothers Inc., as Lead Arranger and Book Manager, and Lehman Commercial Paper Inc., as Syndication Agent and Administrative Agent. 10.4 Guarantee and Collateral Agreement made by The Williams Companies, Inc., Williams Production Holdings LLC, Williams Production RMT Company and certain of its Subsidiaries in favor of Lehman Commercial Paper Inc., as Administrative Agent, dated as of July 31, 2002. 10.5 Termination Agreement between The Williams Companies, Inc. and Keith E. Bailey dated May 1, 2002. 10.6 Security Agreement dated as of July 31, 2002, among The Williams Companies, Inc. and each of the Subsidiaries which is a signatory hereto or which subsequently becomes a party hereto in favor of Citibank, N.A., as collateral trustee for the benefit of the holders of the Secured Obligations. 10.7 Pledge Agreement dated as of July 31, 2002, among The Williams Companies, Inc. and each of the Subsidiaries which is a signatory hereto or which subsequently becomes a party hereto in favor of Citibank, N.A., as collateral trustee for the benefit of the holders of the Secured Obligations. 10.8 Guaranty dated as of July 31, 2002 by Williams Gas Pipeline Company, L.L.C. in favor of the Financial Institutions. 10.9 Collateral Trust Agreement among The Williams Companies, Inc., and certain of its Subsidiaries, as Debtors, and Citibank, N.A., as Collateral Trustee, dated as of July 31, 2002. 10.10 Form of Guaranty dated as of July 31, 2002 by each of the entities named on the signature pages hereto in favor of Citibank, N.A., as surety administrative agent for the Financial Institutions. 10.11 Form of Subordinated Guaranty dated as of July 31, 2002 by Williams Production Holdings LLC in favor of the Financial Institutions. 10.12 Consent and Fourth Amendment to the Credit Agreement dated as of July 31, 2002 among the Borrowers party to the Credit Agreement, the Banks from time to time party to the Credit Agreement, the Co-Syndication Agents as named therein, the Documentation Agent as named therein and Citibank, N.A., as agent for the Banks. 10.13 U.S. $400,000,000 Credit Agreement dated as of July 31, 2002 among The Williams Companies, Inc., as Borrower, Citicorp USA, Inc., as Agent and Collateral Agent, Bank of America N.A., as Syndication Agent, Citibank, N.A. and Bank of America N.A., as Issuing Banks, the Banks named herein, as Banks, and Salomon Smith Barney Inc., as Arranger. 12 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements 99.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 by Steven J. Malcolm, Chief Executive Officer of The Williams Companies, Inc. 99.2 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 by Jack D. McCarthy, Chief Financial Officer of The Williams Companies, Inc.