10-K 1 d03793e10vk.txt FORM 10-K -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 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 or Other Jurisdiction of (IRS Employer Incorporation or Organization) Identification No.) ONE WILLIAMS CENTER, TULSA, OKLAHOMA 74172 (Address of Principal Executive Offices) (Zip Code)
918-573-2000 (Registrant's Telephone Number, Including Area Code) SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- --------------------- Common Stock, $1.00 par value New York Stock Exchange and Pacific Stock Exchange Preferred Stock Purchase Rights New York Stock Exchange and Pacific Stock Exchange Income PACS New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE 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 by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes [X] No [ ] The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant's most recently completed second quarter was approximately $3,099,735,940. The number of shares outstanding of the registrant's common stock held by non-affiliates outstanding at February 28, 2003 was 517,538,177. DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant's Proxy Statement being prepared for the solicitation of proxies in connection with the Annual Meeting of Stockholders of the registrant for 2003 are incorporated by reference in Part III of this Form 10-K. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- THE WILLIAMS COMPANIES, INC. FORM 10-K TABLE OF CONTENTS
PAGE ---- PART I Items 1 and 2. Business and Properties..................................... 1 Website Access to Reports................................... 1 General..................................................... 1 Recent Developments......................................... 4 Asset Sales and Cost Reductions........................... 4 Improving our Financial Position.......................... 6 Addressing Energy Marketing and Trading Issues............ 6 Resolution of Williams Communications Group Issues........ 6 Financial Information About Segments........................ 7 Business Segments........................................... 8 General................................................... 8 Gas Pipeline.............................................. 9 General................................................ 9 Regulatory Matters................................... 10 Competition.......................................... 10 Ownership of Property................................ 11 Environmental Matters................................ 11 Principal Companies in the Gas Pipeline Segment...... 12 Transcontinental Gas Pipe Line Corporation (Transco)........................................... 12 Northwest Pipeline Corporation....................... 14 Texas Gas Transmission Corporation................... 16 Exploration & Production.................................. 17 General................................................ 17 Oil and Gas Properties................................. 17 Rocky Mountain Properties............................ 17 Mid-Continent Properties............................. 18 Other Properties..................................... 19 Gas Reserves and Wells................................. 19 Operating Statistics................................... 19 Environmental and Other Regulatory Matters............. 20 Competition............................................ 21 Ownership of Property.................................. 21 Other Information...................................... 21 International Exploration and Production Interests..... 21
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PAGE ---- Midstream Gas & Liquids................................... 21 General................................................ 21 Domestic Gathering and Processing; Natural Gas Liquid Fractionator, Storage and Transportation............ 22 Gulf Coast Petrochemical and Olefins................. 22 Natural Gas Liquids Marketing and Risk Management.... 22 Canada............................................... 22 Venezuela............................................ 23 Expansion Projects................................... 23 Wyoming Expansion.................................... 23 Deepwater............................................ 23 Customers and Operations............................... 23 Operating Statistics................................... 24 Regulatory and Environmental Matters................... 24 Competition............................................ 25 Ownership of Property.................................. 25 Energy Marketing & Trading................................ 26 General................................................ 26 Operating Statistics................................... 27 Regulatory and Legal Matters........................... 27 Competition and Market Environment..................... 28 Ownership of Property.................................. 29 Environmental Matters.................................. 29 Williams Energy Partners L.P.............................. 29 General................................................ 29 Regulatory and Environmental Matters................... 30 Competition............................................ 30 Ownership of Property.................................. 30 Petroleum Services........................................ 30 General................................................ 30 Refining............................................... 31 Retail Petroleum....................................... 32 Regulatory Matters..................................... 32 Competition............................................ 32 Ownership of Property.................................. 33 Environmental Matters.................................. 33 Environmental Matters....................................... 33 Employees................................................... 33 Forward Looking Statements/Risk Factors and Cautionary Statement for Purposes of the "Safe Harbor" provisions of the Private Securities Litigation Reform Act of 1995...... 33 Risk Factors................................................ 34 Risks Affecting Our Strategy and Financing Needs.......... 34 Risks Related to Our Business............................. 35 Risks Related to Legal Proceedings and Governmental Investigations......................................... 37
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PAGE ---- Risks Related to the Regulations of Our Businesses........ 38 Risks Related to Environmental Matters.................... 40 Risks Relating to Accounting Policy....................... 41 Risks Relating to our Industry............................ 41 Other Risks............................................... 42 Financial Information About Geographic Areas................ 42 Item 3. Legal Proceedings........................................... 42 Environmental Matters....................................... 42 Other Legal Matters......................................... 44 Summary..................................................... 45 Item 4. Submission of Matters to a Vote of Security Holders......... 45 Item 4A. Executive Officers of the Registrant........................ 45 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters....................................... 47 Item 6. Selected Financial Data..................................... 49 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 50 Item 7A. Quantitative and Qualitative Disclosures About Market Risk...................................................... 90 Item 8. Financial Statements and Supplementary Data................. 94 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................. 182 PART III Item 10. Directors and Executive Officers of the Registrant.......... 183 Item 11. Executive Compensation...................................... 183 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters................ 183 Item 13. Certain Relationships and Related Transactions.............. 183 Item 14. Controls and Procedures..................................... 183 PART IV Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K....................................................... 184
iii PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES In this report, Williams (which includes The Williams Companies, Inc. and unless the context otherwise requires, all of our subsidiaries) is at times referred to in the first person as "we," "us" or "our". We also sometimes refer to Williams as the "Company." WEBSITE ACCESS TO REPORTS Our Internet address is www.williams.com. As required, as of November 15, 2002, we make available free of charge on or through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. GENERAL We are an energy company originally incorporated under the laws of the state of Nevada in 1949 and reincorporated under the laws of the state of Delaware in 1987. We were founded in 1908 when two Williams brothers began a construction company in Fort Smith, Arkansas. Today, we primarily find, produce, gather, process and transport natural gas. Our operations serve the Northwest, California, Rocky Mountains, Gulf Coast and Eastern Seaboard markets. In 2002, we faced many challenges including credit issues following the deterioration of our energy industry sector in the wake of the Enron bankruptcy and the assumption of payment obligations and performance on guarantees associated with our former telecommunications subsidiary, Williams Communications Group, Inc. (WCG). With the deterioration of the energy industry, the credit rating agencies' requirements for investment grade companies became more stringent. In response to those requirements, we announced plans on December 19, 2001, to strengthen our balance sheet in an effort to maintain our investment grade ratings. Those plans including revisions throughout the year due to changing market conditions included reducing capital expenditures, eliminating certain credit ratings triggers from our loan agreements, cost reductions including a reduction of quarterly dividends paid on our common stock, and asset sales to generate proceeds to be used to reduce outstanding debt. Despite our balance sheet strengthening efforts, we lost our investment grade ratings in July 2002. With the loss of our investment grade ratings our business changed significantly, especially our Energy Marketing & Trading business. Some counterparties were unwilling to extend credit and required cash, letters of credit, or other collateral. By mid-year we faced a liquidity crisis. Concurrently, our credit facility banks were unwilling to extend our $2.2 billion 364 day unsecured credit facility. We quickly worked with our banks and other parties to obtain secured credit facilities. In 2002, we also sold a significant amount of assets to meet our liquidity gap. Following this liquidity crisis, we continued to pursue cost reducing measures including a downsizing of our work force. We also settled substantially all issues between us and WCG through WCG's chapter 11 reorganization. To meet future debt obligations and liquidity needs and focus on creating future shareholder value, on February 20, 2003, we reiterated our strategy to become a smaller integrated natural gas company focusing on key growth markets within our Gas Pipeline, Exploration & Production, and Midstream Gas & Liquids segments. In conjunction with the strategy announcement and to help meet future debt obligations and future liquidity needs, we also announced plans to sell more assets including Texas Gas Transmission Corporation, our general and limited partner interest in Williams Energy Partners L.P., and certain assets within our Midstream Gas & Liquids and Exploration & Production business segments, and explained that we are attempting to further limit our exposure to losses in the Energy Marketing & Trading segment. We also expect further work force reductions in 2003. We will need to complete further cost reductions and asset sales and the realization of our strategy in order to meet our liquidity needs and to satisfy our loan covenants regarding minimum levels of liquidity. See 1 Managements' Discussion and Analysis of Financial Condition and Results of Operations -- Financial Condition and Liquidity for further details on liquidity issues we are facing. See also the Risk Factors page 34 for a discussion of factors that could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities. Our ongoing business segments include Gas Pipeline, Exploration & Production, Midstream Gas & Liquids, and Energy Marketing & Trading. At year-end 2002, our business segments also included Williams Energy Partners L.P. and Petroleum Services. Subject to completion of asset sales, those business segments will likely be eliminated in the future. See Part I -- Item 1. Business -- Business Segments for a detailed description of assets owned and services provided by each business segment. GAS PIPELINE - We own one of the nation's largest interstate natural gas pipeline systems with 20,200 miles of interstate natural gas pipelines for transportation of natural gas across the country to utilities and industrial customers. - Our pipelines include Transcontinental Gas Pipe Line Corporation, Texas Gas Transmission Corporation and Northwest Pipeline Corporation. We have announced our intention to sell Texas Gas Transmission Corporation. If this pipeline is sold, our network will cover 14,400 miles of natural gas pipelines. - We also own a 50 percent interest in the Gulfstream Pipeline. EXPLORATION & PRODUCTION - We had 2.8 trillion cubic feet of proved natural gas reserves as of December 31, 2002. - We produce, develop, explore for and manage natural gas reserves primarily located in the Rocky Mountain and Mid-Continent regions of the United States. - We produce natural gas predominately from tight-sand formations and coal bed methane reserves. MIDSTREAM GAS & LIQUIDS - We own and operate gas gathering and processing facilities within the western states of Wyoming, Colorado, and New Mexico and the onshore and offshore shelf and deepwater areas in and around the Gulf Coast states of Texas, Alabama, Mississippi, and Louisiana. - We own interests in and/or operate natural gas liquids fractionation and storage assets within central region of Kansas and southern Louisiana, and natural gas liquid transportation pipelines in the Gulf Coast. - We own and operate an ethylene production, storage and transportation complex (partially owned) and olefin extraction assets within Louisiana. - We own and/or operate natural gas processing, liquid extraction, fractionation and olefin extraction assets within Canada. - We provide natural gas liquid and petrochemical marketing and risk management services to customers from products produced from our processing and extraction facilities as well as from outside sources. - We have ownership interests in various Venezuelan energy assets. ENERGY MARKETING & TRADING - Our Energy Marketing & Trading segment is a national energy services provider that buys, sells and transports a full suite of energy and energy-related commodities, including power, natural gas, refined products, crude oil and emissions credits, primarily on a wholesale level. 2 - We have announced our intention to sell certain portions of the Energy Marketing & Trading portfolio, to liquidate of certain positions and negotiations with parties for a joint venture or sale of all or a portion of the trading portfolio. INVESTMENT IN WILLIAMS ENERGY PARTNERS L.P. - We have a 53 percent limited partnership interest and own 100 percent of the general partnership interest in Williams Energy Partners L.P. (Williams Energy Partners). In February 2003, we announced our intention to sell our ownership interests in Williams Energy Partners. - Williams Energy Partners owns a 6,700 mile refined petroleum products pipeline system (the Williams Pipe Line system acquired from Petroleum Services in 2002) that serves the mid-continent region of the United States with 39 system terminals and 26 million barrels of storage. - Williams Energy Partners has five petroleum products terminal facilities located along the Gulf Coast and near the New York harbor (marine terminals) with an aggregate storage capacity of approximately 18 million barrels. - Williams Energy Partners has 23 petroleum products terminals located principally in the southeastern United States (inland terminals) with an aggregate storage capacity of five million barrels. - Williams Energy Partners also has an 1,100-mile ammonia pipeline system that serves the mid-continent region of the United States. OTHER Our ongoing business segments are accounted for as continuing operations in the accompanying financial statements and notes to financial statements included in Part II. Assets announced to be sold are also included in continuing operations until such time that they qualify for treatment as "discontinued operations" under generally accepted accounting principles (GAAP). At year-end 2002, we also had a Petroleum Services business segment. Many of the assets within the Petroleum Services business segment have been sold or are being offered for sale and have been reclassified to "Discontinued Operations" in the accompanying financial statements and notes to financials in Part II. We intend to sell substantially all assets held in the Petroleum Services segment with the exception of our interest in Longhorn Partners Pipeline. The assets in the Petroleum Services segment are considered non-core and no longer fit into our overall strategy to focus our competencies in the natural gas market. Assets within the Petroleum Services segment currently include: - a petroleum products refinery and 29 convenience stores in Alaska; - a 3.0845 percent interest in the Trans-Alaska Pipeline System (TAPS) pipeline and the Valdez crude terminal in Alaska; and - a 32.1 percent interest in the Longhorn Partners pipeline in south and west Texas. Other assets sold in 2002 and early 2003 or subject to an approved sale have also been reclassified, in accordance with GAAP, from their traditional business segment to "Discontinued Operations" in the accompanying financial statements and notes to financial statements included in Part II. Our principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172. Our telephone number is 918-573-2000. 3 RECENT DEVELOPMENTS ASSET SALES AND COST REDUCTIONS Since December 2001, we have continued to work on strengthening our balance sheet through a number of efforts including asset sales and cost reductions. We have completed the sale or announced our intention to sell the following: GAS PIPELINE - March 27, 2002 -- We sold our Kern River interstate natural gas pipeline business to a unit of Mid-American Energy Holdings Company for $450 million in cash and the assumption of $510 million in debt. In conjunction with the sale, MEHC Investment, Inc., a wholly-owned subsidiary of Mid-American Energy Holdings Company, and a member of the Berkshire Hathaway family of companies, agreed to acquire 1,466,667 shares of our 9 7/8 percent cumulative convertible preferred stock at $187.50 per share for a total of $275 million. Each share of convertible preferred stock is convertible into ten shares of our common stock. - August 16, 2002 -- We completed the sale of our general partner interest in Northern Border Partners, L.P. for $12 million to a unit of Calgary-based TransCanada. - September 5, 2002 -- We sold our Cove Point liquefied natural gas facility and 87 mile pipeline for $217 million in cash before certain adjustments to a subsidiary of Dominion Resources. - October 29, 2002 -- We sold our ownership interest in the Canadian and United States segments of the Alliance pipeline to Enbridge Inc. and Fort Chicago Energy Partners L.P. for approximately $173 million cash. - November 15, 2002 -- We sold our Central interstate natural gas pipeline to Southern Star Central Corp for $380 million in cash and the assumption of $175 million in debt. - February 20, 2003 -- We announced our intention to sell Texas Gas Transmission Corporation. EXPLORATION & PRODUCTION - March 29, 2002 -- We completed a $73 million sale of selected exploration and production properties in the Wind River basin. - July 31, 2002 -- We sold our Jonah Field natural gas production properties in Wyoming for $350 million to EnCana Oil & Gas (USA) Inc. In addition, we completed the sale of the vast majority of our natural gas production properties in the Anadarko Basin to Chesapeake Exploration Limited Partnership for approximately $37.5 million. These sales of exploration and production properties generated $326 million in net cash proceeds. - February 20, 2003 -- We announced our intention to sell selected assets within the Exploration & Production segment. MIDSTREAM GAS & LIQUIDS - July 22, 2002 -- We announced our intention to sell our natural gas processing and liquids extraction operations in western Canada. - July 29, 2002 -- We sold our Kansas Hugoton natural gas gathering system to FrontStreet Hugoton LLC, an affiliate of FrontStreet Partners, LLC and GE Structured Finance Group for $77 million in cash. - August 1, 2002 -- We announced a series of transactions including the sale for approximately $1.2 billion of 98 percent of Mapletree LLC and 98 percent of E-Oaktree, LLC to Enterprise Products Partners, L.P. Mapletree owns the Mid-America Pipeline, a 7,226-mile natural gas liquids pipeline 4 system. E-Oaktree owns 80 percent of the Seminole Pipeline, a 1,281-mile natural gas liquids pipeline system. The sale generated $1.15 billion in net cash proceeds. - August 20, 2002 -- We announced our intention to sell our ownership interest in an olefins plant in Geismar, Louisiana and an associated ethylene pipeline system in Louisiana. - February 20, 2003 -- We announced our intention to sell selected assets within the Midstream Gas & Liquids segment. ENERGY MARKETING & TRADING - February 4, 2003 -- We announced the sale of our 170-megawatt power facility in Worthington, Indiana, to Hoosier Energy and terminated our power load serving full-requirements contract with Hoosier Energy for cash totaling $67 million. PETROLEUM SERVICES - April 11, 2002 -- We transferred the Williams Pipe Line System to Williams Energy Partners in exchange for $674 million cash and 7,830,924 Class B units of limited partnership interests in Williams Energy Partners. - June 18, 2002 -- We announced plans to sell our Memphis and Alaska refineries and related petroleum assets. On March 4, 2003, we sold our Memphis, Tennessee refinery and other related operations to Premcor Inc. for approximately $455 million in cash. - February 27, 2003 -- We sold our retail travel center operations for approximately $190 million in cash before debt repayments to Pilot Travel Centers LLC. - February 20, 2003 -- We announced a definitive agreement to sell our equity interest in Williams Bio-Energy L.L.C. for approximately $75 million to a new company formed by Morgan Stanley Capital Partners. Williams Bio-Energy owns and operates an ethanol production plant in Pekin, Illinois, holds 78.4 percent interest in another ethanol plant in Aurora, Nebraska, and has various agreements to market ethanol from third-party plants. WILLIAMS ENERGY PARTNERS - February 20, 2003 -- We announced our intention to sell our general partner and limited partner interest in Williams Energy Partners. OTHER - March 22, 2002 -- We announced our intention to sell our interest in a soda ash and sodium bicarbonate mining operation. - September 19, 2002 -- We sold our 26.85 percent equity interest in AB Mazeikiu Nafta, the Lithuania oil refining and transportation complex, to YUKOS Oil Company for $85 million. In an effort to further reduce costs, we have reduced the total number of employees from approximately 12,400 at the end of 2001 to approximately 9,800 at the end of 2002 and approximately 7,300 as of March 14, 2003. The reduction in work force was carried out in part through an enhanced-benefit early retirement program that concluded during the second quarter of 2002 and reductions associated with asset sales. Going forward, we intend to focus on our natural gas businesses including natural gas transportation through our interstate natural gas pipelines, natural gas exploration and production, and natural gas gathering and processing in key growth markets. 5 IMPROVING OUR FINANCIAL POSITION In addition to asset sales, we have taken other steps to improve our financial position. On January 14, 2002, we completed the sale of $1.1 billion of publicly traded units, known as FELINE PACS initially consisting of Income PACS, which include a senior debt security and an equity purchase contract. These units trade on the New York Stock Exchange under the ticker symbol WMB PrI. The net proceeds of the offering were used to fund our capital program, repay commercial paper and other short-term debt and for general corporate purposes. On March 19, 2002, we closed a two-part debt transaction totaling $1.5 billion that included $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. Proceeds were used to repay outstanding short-term debt, provide working capital and for general corporate purposes. On August 1, 2002, we announced a series of transactions that resolved then-current liquidity issues and strengthened our finances. We entered into agreements for $1.1 billion of credit through an amended $700 million secured revolving credit facility and a new $400 million secured letter of credit facility. We also entered into a $900 million senior secured credit agreement with a group of investors led by Lehman Brothers Inc. and a Berkshire Hathaway affiliate. The execution of these new credit facilities in conjunction with the asset sales announced on August 1, 2002, addressed our mid-year liquidity crisis. See Note 11 to our Notes to Consolidated Financial Statements for more information on the credit facilities. On March 4, 2003, Northwest Pipeline Corporation completed a $175 million debt offering of senior notes due 2010. Northwest Pipeline Corporation intends to use the proceeds for general corporate purposes, including the funding of capital expenditures. ADDRESSING ENERGY MARKETING AND TRADING ISSUES We have also spent considerable effort addressing concerns of the Federal Energy Regulatory Commission (FERC), the Commodity Futures Trading Commission (CFTC), the Securities and Exchange Commission (SEC), the Department of Justice (DOJ), and state regulatory bodies and attorneys general regarding energy trading practices. On July 26, 2002, we announced an agreement in principle with the state of California and other parties, including the states of Washington and Oregon, on a settlement regarding certain outstanding litigation and claims against us, including the state's claims for refunds at issue before the FERC. On November 11, 2002, we announced that we had agreed to restructure our long-term energy contracts with the state of California as part of the settlement. All necessary approvals were obtained, and the settlement was closed on December 31, 2002, although court approvals are still pending with respect to certain private plaintiffs. The settlement resolved most of the outstanding litigation and civil claims filed against us related to our participation in the natural gas and power markets during 2000 and 2001. Due to continuing market declines and the overall energy marketing and trading environment in the post-Enron world, we announced on June 10, 2002, that we were reducing our financial commitment to that part of our business as a realistic response to industry upheavals. Consistent with the effort in 2002, Energy Marketing & Trading reduced its number of employees from approximately 1,000 at December 31, 2001 to approximately 410 at December 31, 2002. As of February 25, 2003, the number of Energy Marketing & Trading employees was approximately 330. RESOLUTION OF WILLIAMS COMMUNICATIONS GROUP ISSUES In 2002, we settled substantially all claims and disputes between us and our former telecommunications subsidiary, WCG as part of WCG's chapter 11 reorganization. Prior to the commencement of WCG's chapter 11 on April 22, 2002, we held various claims against WCG and its subsidiaries in an aggregate amount of approximately $2.3 billion as a consequence of certain guarantees, services provided, and other financial accommodations, including the following: - Prior to the 2001 spinoff of WCG, we had provided various administrative services to WCG for which we were owed approximately $106 million. 6 - Prior to the 2001 spinoff of WCG, we also provided indirect credit support for $1.4 billion of WCG's structured notes through a commitment to make available proceeds of an equity issuance in the event any one of the following were to occur: (1) a WCG default; (2) downgrading of our senior unsecured debt by any of our credit rating agencies to below investment grade if our common stock closing price remained below $30.22 for ten consecutive trading days while such downgrade is in effect; or (3) proceeds from WCG's refinancing or remarketing of the structured notes prior to March 2004 produced proceeds of less than $1.4 billion. On March 5, 2002, we received the requisite approvals on our consent solicitation to amend the terms of the WCG structured notes. The amendment, among other things, eliminated acceleration of the notes due to a WCG bankruptcy or our credit rating downgrade. The amendment also affirmed our obligations for all payments related to the WCG structured notes, which are due March 2004, and allows us to fund such payments from any available sources. With the exception of the March and September 2002 interest payments, totaling $115 million, WCG remained indirectly obligated to reimburse us for any payments we are required to make in connection with the WCG structured notes. - In September 2001, we provided additional financing to WCG through a sale/leaseback transaction pursuant to which WCG sold to us the Williams Technology Center (Technology Center), related real estate and certain ancillary assets including corporate aircraft for $276 million in cash and WCG leased the foregoing property back from us for periods ranging from three to ten years. The Technology Center is a 15-story office building located in Tulsa, Oklahoma that WCG utilizes as its headquarters. - On March 8, 2002, we received a lease obligation notice letter from WCG relating to the asset defeasance program (ADP) that was entered into while WCG was still one of our subsidiaries. Under the ADP, we were obligated to pay $754 million related to WCG's purchase of certain telecommunications facilities that WCG had been leasing. We paid the $754 million on March 29, 2002, and in return received an unsecured claim against WCG for the amount paid. On April 22, 2002, WCG filed for chapter 11 bankruptcy protection. Through a negotiated settlement, we sold our claims against WCG including the $754 million claim associated with the ADP, the $1.4 billion claim associated with the WCG structured notes and a $106 million administrative services claim to Leucadia National Corporation (Leucadia) for $180 million in cash and received releases from WCG and its affiliates and insiders. In addition, the order confirming WCG's chapter 11 plan permanently enjoins all of WCG's creditors from asserting direct or derivative claims against us. As part of the settlement, we also sold the Technology Center to WCG in exchange for two promissory notes with face amounts totaling $174.4 million secured by a mortgage on the Technology Center. We no longer own any interest in WCG or its post-bankruptcy successor, WilTel Communications Group, Inc. (WilTel) and all prior WCG obligations to us have been extinguished as a result of the chapter 11 bankruptcy. We remain committed on certain pre-spinoff parental guarantees with a carrying value at December 31, 2002 of $48 million. Further, the September 2001 sale leaseback transaction involving the Technology Center was terminated as part of the bankruptcy process. The sale leaseback transaction involving WilTel's two corporate aircraft continues in effect until WilTel refinances that transaction. At that time, the proceeds of the refinancing are to be paid to us in partial satisfaction of one of the notes mentioned above. The settlement was closed into escrow on October 15, 2002, and finalized on December 2, 2002, and we received $180 million. See Note 2 of our Notes to Consolidated Financial Statements for more information on our settlement with WCG. FINANCIAL INFORMATION ABOUT SEGMENTS See Note 19 of our Notes to Consolidated Financial Statements for information with respect to each segment's revenues, profits or losses and total assets. 7 BUSINESS SEGMENTS GENERAL Substantially all of our operations are conducted through our subsidiaries. To achieve organizational and operating efficiencies, our interstate natural gas pipelines and pipeline joint venture investments are organized under our wholly-owned subsidiary, Williams Gas Pipeline Company, LLC; our Exploration & Production business is operated through several wholly-owned subsidiaries including Williams Production Company LLC and Williams Production RMT Company; our Midstream Gas & Liquids business is operated primarily through wholly-owned subsidiaries including Williams Field Services Group, Inc. and Williams Natural Gas Liquids, Inc.; our energy marketing and trading activities are primarily operated through our wholly-owned subsidiary, Williams Energy Marketing & Trading Company; our investment in a master limited partnership that focuses on the storage, transportation and distribution of refined petroleum products and ammonia is reported under Williams Energy Partners; and our Petroleum Services business is operated through various wholly-owned subsidiaries. Item 1 of this report is organized to reflect this structure. For organizational and reporting purposes, we classify our businesses into the following segments: GAS PIPELINE - Transportation and storage of natural gas and related activities through the operation and ownership of three wholly-owned interstate natural gas pipelines, one of which we have announced our intention to sell, and several pipeline joint ventures. EXPLORATION & PRODUCTION - Exploration, production and management of natural gas and oil through ownership of 2.8 trillion cubic feet equivalent of proved natural gas reserves primarily located in the Rocky Mountain and Mid-Continent regions of the United States, a portion of which we have announced our intention to sell. MIDSTREAM GAS & LIQUIDS - Natural gas gathering, treating and processing activities through ownership and operation of approximately 9,000 miles of gathering lines, eleven natural gas processing plants (two of which are partially owned), and nine natural gas treating plants within the United States. - Natural gas liquids fractionation, storage, and transportation activities through ownership interests in fractionation facilities, storage caverns and facilities within central Kansas and southern Louisiana, and liquids pipelines in the Gulf Coast. - Ethylene production and olefin extraction activities in Louisiana through an ownership interest in an ethylene production, storage and transportation complex (partially owned) and refinery off gas processing, and olefin extraction and fractionation facilities. - Natural gas processing, liquid extraction, fractionation, storage and olefin extraction activities within Alberta and British Columbia, Canada, through a natural gas field processing plant, five natural gas liquid extraction plants (two of which are partially-owned), a natural gas liquids gathering system and liquid storage facilities, a liquids fractionation facility and an olefins fractionation facility. - Natural gas liquid and petrochemical product marketing and risk management services within the United States and Canada. - Venezuelan gas compression, liquids extraction, fractionation and terminaling activities through various investments and contractual arrangements. - We have announced our intention to sell certain domestic and Canadian assets within the Midstream Gas & Liquids segment. 8 ENERGY MARKETING & TRADING - A national energy services provider that buys, sells and transports a full suite of energy and energy-related commodities, including power, natural gas refined products, crude oil and emissions credits primarily on a wholesale level, which we have announced our intention to sell in whole or in part. INVESTMENT IN WILLIAMS ENERGY PARTNERS - Transportation of petroleum products and related terminal services and ammonia transportation and terminal services. On February 20, 2003, we announced our intention to sell our interests in Williams Energy Partners. PETROLEUM SERVICES - Petroleum products refinery and 29 convenience stores in Alaska. - A 3.0845 percent interest in the TAPS pipeline and the Valdez crude terminal in Alaska. - A 32.1 percent interest in the Longhorn Partners pipeline in south and west Texas. We have announced our intention to sell substantially all assets within the Petroleum Services segment with the exception of our interest in Longhorn Partners Pipeline. We perform certain management, legal, financial, tax, consultative, administrative and other services for our subsidiaries and at March 14, 2003, employed approximately 1,925 employees at the corporate level to provide these services. Our principal sources of cash are from external financings, dividends and advances from our subsidiaries, investments, payments by subsidiaries for services rendered, interest payments from subsidiaries on cash advances and net proceeds from asset sales. The amount of dividends available to us from subsidiaries largely depends upon each subsidiary's earnings and operating capital requirements. The terms of many of our subsidiaries' borrowing arrangements limit the transfer of funds to us. The Federal Energy Regulatory Commission (FERC) has also proposed restrictions on various cash management programs employed by companies in the energy industry, including us. See Note 16 to our Notes to Consolidated Financial Statements for further information on the proposed cash management restrictions. We believe that we have adequate sources and availability of raw materials and commodities for existing and anticipated business needs. With the deterioration of our credit ratings, we now must pre-pay for crude supply for our Alaska refining operations and for gas supplies for our domestic and Canadian Midstream Gas & Liquids operations. Our pipeline systems are all regulated in various ways resulting in the financial return on the investments made in the systems being limited to standards permitted by the regulatory agencies. Each of the pipeline systems has ongoing capital requirements for efficiency and mandatory improvements, with expansion opportunities also necessitating periodic capital outlays. GAS PIPELINE GENERAL We own and operate, through Williams Gas Pipeline Company, LLC and its subsidiaries (Gas Pipeline), a combined total of approximately 20,200 miles of pipelines with a total annual throughput of approximately 3,200 trillion British Thermal Units of natural gas and peak-day delivery capacity of approximately 13 billion cubic feet of gas. Gas Pipeline consists of Transcontinental Gas Pipe Line Corporation (Transco), Northwest Pipeline Corporation (Northwest Pipeline), and Texas Gas Transmission Corporation (Texas Gas). Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent interest in the Gulfstream Natural Gas System, L.L.C. At December 31, 2002, Gas Pipeline employed approximately 2,300 employees. On February 20, 2003, we announced our intention to sell Texas Gas. In February 2001, subsidiaries of Duke Energy and the Company completed their joint acquisition of The Coastal Corporation's 100 percent ownership interest in Gulfstream Natural Gas System, L.L.C., and 9 announced that they were proceeding with the development of the Gulfstream gas pipeline project. In June, 2001 construction commenced on the project, which consists of a new natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida. On December 28, 2001, Gulfstream filed an application with the FERC to allow Gulfstream to phase the construction of its approved facilities. On May 28, 2002, the first phase of the project was placed into service at a cost of approximately $1.5 billion. The construction of the second phase of the project will be timed to match the anticipated in-service dates of the markets Gulfstream will serve. The total estimated capital cost of the project is approximately $1.7 billion, of which our portion is estimated to be approximately $850 million. At December 31, 2002, our investment in Gulfstream was $734 million. On April 24, 2001 the respective U.S. and Canadian general partners of the Georgia Strait Crossing Pipeline Project (GSX), a joint venture of the Company and BC Hydro, filed separate applications with the FERC and Canada's National Energy Board (NEB) to construct and operate a new pipeline that will provide 95,700 dekatherms ("Dth") per day of firm transportation capacity from Sumas, Washington to Vancouver Island, British Columbia. The installation of GSX will include approximately 85 miles of pipeline, a 10,302 horsepower compressor station and two meter stations. On September 20, 2002, the FERC issued an order approving the construction and operation of the U.S. portion of the project. GSX anticipates the NEB will issue a certificate approving the project by October 2003. Construction is expected to begin in the summer of 2004. The estimated cost of GSX is approximately $210 million, with Gas Pipeline's share being 50 percent of such amount. The targeted in-service date is October 2005. REGULATORY MATTERS Gas Pipeline's interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938 and under the Natural Gas Policy Act of 1978, and, as such, its rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. Each gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties considered jurisdictional for which certificates are required under the Natural Gas Act of 1938. Each gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. Cardinal Pipeline Company, LLC, a North Carolina natural gas pipeline company that is operated and 45 percent owned by Gas Pipeline, is subject to the jurisdiction of the North Carolina Utilities Commission. Each of our interstate natural gas pipeline companies establishes its rates primarily through the FERC's ratemaking process. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related income taxes and (3) volume throughput assumptions. The FERC determines the allowed rate of return in each rate case. Rate design and the allocation of costs between the demand and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund. See Note 16 of our Notes to Consolidated Financial Statements for the amounts accrued for potential refund at December 31, 2002. On March 13, 2003, we entered into a settlement with FERC regarding its investigation of the relationship between Transco and Energy Marketing & Trading whereby Transco will pay a civil penalty in the amount of $20 million payable over a five year period. In addition, we agreed to certain operational restrictions and agreed to implement a compliance program to ensure future compliance with the settlement agreement and FERC's marketing affiliate rules. See Note 16 of our Notes to Consolidated Financial Statements for further information on the settlement. COMPETITION The FERC has taken various actions to strengthen market forces in the natural gas pipeline industry which has led to increased competition throughout the industry. In a number of key markets, interstate 10 pipelines are now facing competitive pressures from other major pipeline systems, enabling local distribution companies and end users to choose a supplier or switch suppliers based on the short-term price of gas and the cost of transportation. We expect competition for natural gas transportation to continue to intensify in future years due to increased customer access to other pipelines, rate competitiveness among pipelines, customers' desire to have more than one transporter and regulatory developments. Future utilization of pipeline capacity will depend on competition from other pipelines, use of alternative fuels, the general level of natural gas demand and weather conditions. Electricity and distillate fuel oil are the primary competitive forms of energy for residential and commercial markets. Coal and residual fuel oil compete for industrial and electric generation markets. Nuclear and hydroelectric power and power purchased from electric transmission grid arrangements among electric utilities also compete with gas-fired electric generation in certain markets. Suppliers of natural gas are able to compete for any gas markets capable of being served by pipelines using nondiscriminatory transportation services provided by the pipeline companies. As the regulated environment has matured, many pipeline companies have faced reduced levels of subscribed capacity as contractual terms expire and customers opt to reduce firm capacity under contract in favor of alternative sources of transmission and related services. This situation, known in the industry as "capacity turnback," is forcing the pipeline companies to evaluate the consequences of major demand reductions in traditional long-term contracts. It could also result in significant shifts in system utilization, and possible realignment of cost structure for remaining customers since all interstate natural gas pipeline companies continue to be authorized to charge maximum rates approved by the FERC on a cost of service basis. Gas Pipeline does not anticipate any significant financial impact from "capacity turnback." We anticipate that we will be able to remarket most future capacity subject to capacity turnback, although competition may cause some of the remarketed capacity to be sold at lower rates or for shorter terms. Several state jurisdictions have been involved in implementing changes similar to the changes that have occurred at the federal level. The District of Columbia and states, including New York, New Jersey, Pennsylvania, Maryland, Georgia, Delaware, Virginia, California, Wyoming, Kentucky, Ohio, and Indiana, are currently at various points in the process of unbundling services at local distribution companies. Management expects the implementation of these changes to encourage greater competition in the natural gas marketplace. OWNERSHIP OF PROPERTY Each of our interstate natural gas pipeline companies generally owns its facilities, with certain portions, including some offshore facilities, being held jointly with third parties. However, a substantial portion of each pipeline company's facilities is constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned by others. Compressor stations, with appurtenant facilities, are located in whole or in part either on lands owned or on sites held under leases or permits issued or approved by public authorities. The storage facilities are either owned or held under long-term leases or easements. ENVIRONMENTAL MATTERS Each interstate natural gas pipeline is subject to the National Environmental Policy Act and federal, state and local laws and regulations relating to environmental quality control. We believe that, with respect to any capital expenditures and operation and maintenance expenses required to meet applicable environmental standards and regulations, the FERC would grant the requisite rate relief so that the pipeline companies could recover most of the cost of these expenditures in their rates. For this reason, we believe that compliance with applicable environmental requirements by the interstate pipeline companies is not likely to have a material adverse upon our earnings or competitive position. For a discussion of specific environmental issues involving the interstate pipelines, including estimated cleanup costs associated with certain pipeline activities, see "Environmental" under Management's Discussion and Analysis of Financial Condition and Results of Operations and "Environmental Matters" in Note 16 of Notes to Consolidated Financial Statements. 11 PRINCIPAL COMPANIES IN THE GAS PIPELINE SEGMENT A business description of the principal companies in the interstate natural gas pipeline group follows. Transcontinental Gas Pipe Line Corporation (Transco) Transco is an interstate natural gas transportation company that owns and operates a 10,400-mile natural gas pipeline system extending from Texas, Louisiana, Mississippi and the offshore Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Pennsylvania, and New Jersey to the New York City metropolitan area. The system serves customers in Texas and eleven southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, New York, New Jersey, and Pennsylvania. Effective May 1, 1995, Transco transferred the operation of certain production area facilities to Williams Field Services Group, Inc. (Williams Field Services), an affiliated company and part of the Midstream Gas & Liquids business. PIPELINE SYSTEM AND CUSTOMERS At December 31, 2002, Transco's system had a mainline delivery capacity of approximately 4.2 billion cubic feet of natural gas per day from its production areas to its primary markets. Using its Leidy Line and market-area storage capacity, Transco can deliver an additional 3.3 billion cubic feet of natural gas per day for a system-wide delivery capacity total of approximately 7.5 billion cubic feet of natural gas per day. Excluding the production area facilities operated by Williams Field Services, Transco's system is composed of approximately 7,600 miles of mainline and branch transmission pipelines, 44 transmission compressor stations and six storage locations. Transmission compression facilities at a sea level-rated capacity total approximately 1.4 million horsepower. Transco's major natural gas transportation customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on Transco's system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. No customer accounted for more than ten percent of Transco's total revenues in 2002. Transco's firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transco's business. Additionally, Transco offers storage services and interruptible transportation services under short-term agreements. Transco has natural gas storage capacity in five underground storage fields located on or near its pipeline system or market areas and operates three of these storage fields. Transco also has storage capacity in a liquefied natural gas (LNG) storage facility and operates the facility. The total top gas storage capacity available to Transco and its customers in such storage fields and LNG facility and through storage service contracts is approximately 216 billion cubic feet of gas. In addition, wholly-owned subsidiaries of Transco operate and hold a 35 percent ownership interest in Pine Needle LNG Company, an LNG storage facility with 4 billion cubic feet of storage capacity. Storage capacity permits Transco's customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods. EXPANSION PROJECTS In 2002, Transco completed construction of, and placed into service, three major projects, the Sundance Expansion Project, Phase 2 of the MarketLink Expansion Project, and the Leidy East Project. The Sundance Expansion Project was placed in service on May 1, 2002, adding approximately 228 million cubic feet per day (MMcf/d) of firm transportation capacity from Transco's Station 65 in Louisiana to delivery points in Georgia, South Carolina and North Carolina. Approximately 38 miles of new pipeline loop along the existing mainline system were installed along with approximately 41,225 horsepower of new compression and modifications to existing compressor stations in Georgia, South Carolina and North Carolina. The capital cost of the project was approximately $117 million. Phase 1 of the Market Link Expansion Project, which was placed in service on December 19, 2001, added approximately 160 MMcf/d of firm transportation capacity. Phase 2 of the MarketLink Expansion Project was 12 placed in service on November 1, 2002, adding approximately 126 MMcf/d of firm transportation capacity. Both phases of the MarketLink Project provide firm natural gas transportation service from Leidy, Pennsylvania to markets in the northeastern United States. The total capital cost of Phases 1 and 2 is estimated to be $243 million. The Leidy East Project was placed in service on November 1, 2002, adding approximately 126 MMcf/d of firm natural gas transportation service from Leidy, Pennsylvania to the northeastern United States. The project facilities included approximately 31 miles of pipeline looping and 3,400 horsepower of uprated compression. The capital cost of the project is estimated to be $98 million. On February 14, 2002, the FERC issued an order granting a certificate of public convenience and necessity to Transco to construct and operate the Momentum Expansion Project, an expansion of Transco's pipeline system from Station 65 in Louisiana to Station 165 in Virginia. On February 4, 2003, Transco filed an application with the FERC to amend the certificate to reduce the overall size of the expansion from approximately 347 MMcf/d to approximately 312 MMcf/d and to place the Momentum facilities into service in two phases, with the first phase, consisting of approximately 260 MMcf/d, to be placed into service on May 1, 2003 and the second phase, consisting of approximately 52 MMcf/d, to be placed into service on May 1, 2004. The reduction in the size of the expansion reflects the withdrawal of two shippers under the project and the partial replacement of those shippers with the two shippers who had subscribed to service under Transco's previously proposed Cornerstone Expansion Project. The revised project facilities include approximately 50 miles of pipeline looping and 45,000 horsepower of compression. The revised capital cost of the project is estimated to be approximately $189 million. On May 6, 2002, Transco filed an application for FERC approval of an expansion of Transco's Trenton-Woodbury Line, which runs from Transco's mainline at Station 200 in eastern Pennsylvania, around the metropolitan Philadelphia area and southern New Jersey area, to Transco's mainline near Station 205. Binding precedent agreements have been executed with two shippers for a total of 49 MMcf/d of incremental firm transportation capacity to the shippers' respective delivery points on the Trenton-Woodbury Line. On December 24, 2002, the FERC issued a final order authorizing Transco to construct and operate the project. The target in-service date for the project is November 1, 2003. The project will require approximately seven miles of pipeline looping at a capital cost of approximately $20 million. Pursuant to Transco's open season for the Cornerstone Expansion Project, Transco executed precedent agreements with two shippers for a total firm transportation quantity of approximately 52 MMcf/d. However, Transco and the shippers have agreed that Transco will provide such firm transportation service under the Momentum Expansion Project instead of under Cornerstone as noted in the above project description for the Momentum Expansion Project. Transco completed an open season on September 7, 2001, for the South Virginia Line Expansion project, a proposed expansion on Transco's pipeline system from Station 165 in Virginia to Hertford County, North Carolina. The proposed in-service date of May 1, 2005, has been postponed pending further development of the project. In March 1997, as amended in December 1997, Independence Pipeline Company, a general partnership owned equally by wholly-owned subsidiaries of Transco, ANR Pipeline Company and National Fuel Gas Company, filed an application with FERC for approval to construct and operate a new pipeline consisting of approximately 400 miles of 36-inch pipe from ANR Pipeline Company's existing compressor station at Defiance, Ohio to Transco's facilities at Leidy, Pennsylvania. On December 17, 1999, the FERC gave conditional approval for the Independence Pipeline project, subject to Independence filing long-term, executed contracts with nonaffiliated shippers for at least 35 percent of the capacity of the project. Independence filed for rehearing of the interim order. On April 26, 2000, the FERC issued an order denying rehearing and requiring that Independence submit by June 26, 2000, agreements with nonaffiliated shippers for at least 35 percent of the capacity of the project. Independence met this requirement, and on July 12, 2000, the FERC issued an order granting the necessary certificate authorizations for the Independence Pipeline project. Independence accepted the certificate authorization on August 11, 2000. On September 28, 2000, the FERC issued an order denying all requests for rehearing and requests for reconsideration of the Independence 13 certificate order filed by various parties. On November 1, 2001, Independence filed a letter with the FERC requesting an extension of the in service date for the project from November 2002 to November 2004. On June 24, 2002, Independence filed a request with the FERC to vacate its certificate because it has been unable to obtain sufficient contracts to proceed with the project to meet the November 2004 in service date. On July 19, 2002, FERC issued an order vacating Independence's certificate. As a result, Transco recorded a $12.3 million pre-tax charge to income in 2002 associated with the impairment of Transco's investment in Independence. OPERATING STATISTICS The following table summarizes transportation data for the Transco system for the periods indicated:
2002 2001 2000 ----- ----- ----- (IN TRILLION BRITISH THERMAL UNITS) Market-area deliveries: Long-haul transportation.................................. 824 766 787 Market-area transportation................................ 777 645 710 ----- ----- ----- Total market-area deliveries........................... 1,601 1,411 1,497 Production-area transportation.............................. 179 202 262 ----- ----- ----- Total system deliveries................................ 1,780 1,613 1,759 ===== ===== ===== Average Daily Transportation Volumes........................ 4.9 4.4 4.8 Average Daily Firm Reserved Capacity........................ 6.4 6.2 6.3
Transco's facilities are divided into eight rate zones. Five are located in the production area, and three are located in the market area. Long-haul transportation involves gas that Transco receives in one of the production-area zones and delivers to a market-area zone. Market-area transportation involves gas that Transco both receives and delivers within the market-area zones. Production-area transportation involves gas that Transco both receives and delivers within the production-area zones. Northwest Pipeline Corporation (Northwest Pipeline) Northwest Pipeline is an interstate natural gas transportation company that owns and operates a natural gas pipeline system extending from the San Juan Basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington. Northwest Pipeline provides services for markets in California, New Mexico, Colorado, Utah, Nevada, Wyoming, Idaho, Oregon and Washington directly or indirectly through interconnections with other pipelines. PIPELINE SYSTEM AND CUSTOMERS At December 31, 2002, Northwest Pipeline's system, having a mainline delivery capacity of approximately 2.9 billion cubic feet of natural gas per day, was composed of approximately 4,000 miles of mainline and lateral transmission pipelines and 43 compressor stations having sea level-rated capacity of approximately 348,000 horsepower. In 2002, Northwest Pipeline transported natural gas for a total of 166 customers. Transportation customers include distribution companies, municipalities, interstate and intrastate pipelines, gas marketers and direct industrial users. The two largest customers of Northwest Pipeline in 2002 accounted for approximately 14.2 percent and 12.7 percent, respectively, of its total operating revenues. No other customer accounted for more than 10 percent of Northwest Pipeline's total operating revenues in 2002. Northwest Pipeline's firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Northwest Pipeline's business. Additionally, Northwest Pipeline offers interruptible and short-term firm transportation service. 14 As a part of its transportation services, Northwest Pipeline utilizes underground storage facilities in Utah and Washington enabling it to balance daily receipts and deliveries. Northwest Pipeline also owns and operates a liquefied natural gas storage facility in Washington that provides a needle-peaking service for its system. These storage facilities have an aggregate firm delivery capacity of approximately 600 million cubic feet of gas per day. EXPANSION PROJECTS On August 29, 2001, Northwest Pipeline filed an application with the FERC to construct and operate an expansion of its pipeline system designed to provide an additional 175,000 Dth per day of capacity to its transmission system in Wyoming and Idaho in order to reduce reliance on displacement capacity. The Rockies Expansion Project includes the installation of 91 miles of pipeline loop and the upgrading or modification to six compressor stations for a total increase of 26,057 horsepower. Northwest Pipeline reached a settlement agreement with the majority of its firm shippers to support roll-in of the expansion costs into its existing rates. The FERC issued a certificate in September 2002 approving the project. Northwest Pipeline filed an application with the FERC in February 2003 to amend the certificate to reflect minor facility scope changes. Construction is scheduled to start by May 2003, with a targeted in-service date of November 1, 2003. The current estimated cost of the expansion project is approximately $140 million, of which approximately $16 million may be offset by settlement funds anticipated to be received from a former customer in connection with a contract restructuring. On October 31, 2001, Northwest Pipeline filed an application with the FERC to construct and operate an expansion of its pipeline system designed to provide 276,625 Dth per day of firm transportation service from Sumas, Washington to Chehalis, Washington to serve new power generation demand in western Washington. The Evergreen Expansion Project includes installing 28 miles of pipeline loop, upgrading, replacing or modifying five compressor stations and adding a net total of 64,160 horsepower of compression. The FERC issued a certificate on June 27, 2002, approving the expansion and the incremental rates to be charged to Northwest Pipeline's expansion customers. Northwest Pipeline started construction in October 2002 with completion targeted for October 1, 2003. Northwest Pipeline filed an application with the FERC in January 2003 to amend the certificate to reflect minor facility scope and schedule changes. The estimated cost of the expansion project is approximately $198 million. The Evergreen Expansion customers have agreed to pay for the cost of service of this expansion on an incremental basis. This expansion is based on 15 and 25-year contracts and is expected to provide approximately $42 million of operating revenues in its first 12 months of operation. Northwest Pipeline's October 3, 2001, application with respect to the Evergreen Expansion Project, which was approved by the FERC on June 27, 2002, also requested approvals to construct and operate an expansion of its pipeline system designed to replace 56,000 Dth per day of northflow design displacement capacity from Stanfield, Oregon to Washougal, Washington. The Columbia Gorge Project includes upgrading, replacing or modifying five existing compressor stations and adding a net total of 24,030 horsepower of compression. Northwest Pipeline reached a settlement with the majority of its firm shippers to support roll-in of 84 percent of the expansion costs into the existing rates with the remainder to be allocated to the incremental Evergreen Expansion customers. Northwest Pipeline's January 2003 application to amend the certificate also reflected minor facility scope changes for the Columbia Gorge Project. Northwest Pipeline plans to start construction of this expansion project by May 2003, with a targeted in-service date of November 1, 2003. The estimated cost of the expansion project is approximately $43 million. On November 1, 2002, Northwest Pipeline placed in service the Grays Harbor Lateral project. This lateral pipeline provides 161,500 Dth per day of firm transportation capacity to serve a new power generation plant in the state of Washington. The Grays Harbor Lateral project was requested by one of Northwest Pipeline's customers and included installation of 49 miles of 20-inch pipeline, the addition of 4,700 horsepower at an existing compressor station, and a new meter station. The cost of the lateral project is estimated to be approximately $92 million. The customer has suspended construction of the contemplated new power generation plant, but remains obligated to pay for the cost of service of the lateral pipeline on an incremental rate basis over the 30-year term of the contract. 15 OPERATING STATISTICS The following table summarizes transportation data for the Northwest Pipeline System for the periods indicated:
2002 2001 2000 ----- ----- ----- (IN TRILLION BRITISH THERMAL UNITS) Transportation Volumes...................................... 729 734 752 Average Daily Transportation Volumes........................ 2.0 2.0 2.1 Average Daily Firm Reserved Capacity........................ 2.9 2.7 2.7
Texas Gas Transmission Corporation On February 20, 2003, we announced our intention to sell Texas Gas. Texas Gas is an interstate natural gas transportation company that owns and operates a natural gas pipeline system extending from the Louisiana gulf coast area and east Texas and extending north and east through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana and into Ohio, with smaller diameter lines extending into Illinois. Texas Gas' direct market area encompasses eight states in the south and midwest, and includes the Memphis, Tennessee; Louisville, Kentucky; Cincinnati, Ohio; and Indianapolis, Indiana metropolitan areas. Texas Gas also has indirect market access to the northeast through interconnections with unaffiliated pipelines. PIPELINE SYSTEM AND CUSTOMERS At December 31, 2002, Texas Gas' system, with a peak-day delivery capacity of approximately 2.8 billion cubic feet of natural gas per day, was composed of approximately 5,800 miles of mainline, storage and branch transmission pipelines and 31 compressor stations having a sea level-rated capacity totaling approximately 556,000 horsepower. In 2002, Texas Gas transported natural gas to customers in Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana, Illinois and Ohio, and indirectly to customers in the northeast. At December 31, 2002, Texas Gas had transportation contracts with approximately 550 shippers. Transportation shippers include distribution companies, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Two customers accounted for approximately 18 percent and 12 percent, respectively, of Texas Gas' 2002 operating revenues. Texas Gas transported gas for 100 distribution companies and municipalities for resale to residential, commercial and industrial end users. Texas Gas provided transportation services to approximately 15 industrial customers located along its system. No other customer accounted for more than ten percent of total operating revenues in 2002. Texas Gas' firm transportation and storage agreements are generally long-term agreements with various expiration dates and account for the major portion of Texas Gas' business. Additionally, Texas Gas offers interruptible transportation, short-term firm transportation and storage services under agreements that are generally shorter term. Texas Gas owns and operates gas storage reservoirs in nine underground storage fields located in Indiana and Kentucky. The storage capacity of Texas Gas' certificated storage fields is approximately 178 billion cubic feet of natural gas, of which approximately 55 billion cubic feet is working gas. Texas Gas' storage gas is used in part to meet operational balancing needs on its system, in part to meet the requirements of Texas Gas' firm and interruptible storage customers, and in part to meet the requirements of Texas Gas' No-Notice transportation service, which allows Texas Gas' customers to temporarily draw from Texas Gas' storage gas to be repaid in-kind during the following summer season. A small amount of storage gas is also used to provide Summer No-Notice (SNS) transportation service, designed primarily to meet the needs of summer-season electrical power generation facilities. SNS customers may temporarily draw from Texas Gas' storage gas in the summer, to be repaid during the same summer season. A large portion of the natural gas delivered by Texas Gas to its market area is used for space heating, resulting in substantially higher daily requirements during winter months. 16 OPERATING STATISTICS The following table summarizes transportation data for the Texas Gas system for the periods indicated
2002 2001 2000 ----- ----- ----- (IN TRILLION BRITISH THERMAL UNITS) Transportation Volumes...................................... 670 710 738 Average Daily Transportation Volumes........................ 1.8 1.9 2.0 Average Daily Firm Reserved Capacity........................ 2.2 2.1 2.1
EXPLORATION & PRODUCTION GENERAL Our Exploration & Production segment, which is comprised of several wholly-owned subsidiaries including Williams Production Company LLC and Williams Production RMT Company, produces, develops, explores for and manages natural gas reserves primarily located in the Rocky Mountain and Mid-Continent regions of the United States. Exploration & Production specializes in natural gas production from tight-sands formations and coal bed methane reserves in the Piceance, San Juan, Powder River, Arkoma and Raton basins. Approximately 98.6 percent of Exploration & Production's domestic reserves are natural gas. Exploration & Production's primary strategy is to utilize existing expertise in the development of tight-sands and coalbed methane reserves. Exploration & Production's current multi-year drilling plan and probable reserves, provides us with a strong opportunity. Exploration & Production's goal is to drill existing proved undeveloped reserves, which comprise nearly 52 percent of proved reserves and to drill in areas of probable reserves. In addition, Exploration & Production provides a significant amount of equity production that is gathered and/or processed by our Midstream Gas & Liquids facilities. Substantially all of the assets of Williams Production RMT Company (formerly Barrett Resources Corporation) are pledged under the 360-day $900 million secured credit facility with Lehman Commercial Paper, Inc. and an affiliate of Berkshire Hathaway. See Note 11 of our Consolidated Financial Statements for further details on the secured credit facilities. In February 2003, we announced our intention to sell additional selected assets within the Exploration & Production segment. OIL AND GAS PROPERTIES Exploration & Production's properties are located primarily in the Rocky Mountain and Mid-Continent regions of the United States. Rocky Mountain properties are located in New Mexico, Wyoming, Colorado and Utah. Mid-Continent properties are located in Oklahoma and Kansas. Rocky Mountain Properties PICEANCE BASIN The Piceance Basin is located in northwestern Colorado, where Exploration & Production primarily targets the tight sands contained within the Williams Fork coalbed formation. The Piceance Basin is our largest area of concentrated development comprising approximately 48 percent of our proved reserves. With over 1.3 trillion cubic feet equivalent of proved reserves at year-end 2002, this area has approximately 900 undrilled proved locations in inventory. Probable reserves in this basin provide additional potential beyond our existing proved reserves. Within this basin, Exploration & Production has the ability to gather, process and deliver to four interstate and one intrastate pipelines. Exploration & Production is currently drilling wells in this basin on 20 acre well density. Exploration & Production successfully completed a 16 well pilot project on ten acre spacing in the Piceance Basin during 2002. This ten acre downspacing, currently pending Colorado Oil and Gas Conservation Commission approval, may enable us to increase our reserves by drilling at greater densities. In 2002, Exploration & Production drilled 129 gross wells and produced a net of approximately 17 60 billion cubic feet equivalent (Bcfe) of natural gas from the Piceance Basin. Exploration & Production's estimated proved reserves in the Piceance Basin at year-end 2002 were 1,372 Bcfe. SAN JUAN BASIN The San Juan Basin is a large gas producing area, located in northwest New Mexico and southwest Colorado. Exploration & Production produces natural gas primarily from the Fruitland Coal, Mesaverde and Dakota formations. Recently approved 80-acre spacing for Mesaverde development and 160-acre spacing for parts of the Fruitland Coal have resulted in the addition of new reserves. In 2002, Exploration & Production successfully introduced horizontal drilling to its Fruitland Coal development. In 2002, Exploration & Production participated in 119 gross wells (33 operated) and produced a net of approximately 52 Bcfe from the San Juan Basin. Exploration & Production's estimated proved reserves in the San Juan Basin at year-end 2002 were 710 Bcfe. POWDER RIVER BASIN Located in northeast Wyoming, the Powder River Basin includes large areas with multiple coal seam potential providing drilling opportunities, targeting thick coals at shallow depths. Exploration & Production is one of the largest natural gas producers in the Powder River Basin and operates the largest leasehold position in the basin. In 2002, Exploration & Production drilled 939 gross wells (576 operated) from this basin and produced a net of approximately 48 Bcfe of natural gas. Exploration & Production's estimated proved reserves in the Powder River Basin at year-end 2002 were 306 Bcfe. RATON BASIN Located in south central Colorado, the Raton Basin is known for quality coal bed methane production. Coal bed methane production is predominantly from two groups of coals in the Vermejo and Raton formations. In 2002, Exploration & Production drilled 38 gross wells in the Raton Basin and produced a net of approximately six Bcfe. Exploration & Production's estimated proved reserves in the Raton Basin at year-end 2002 were 134 Bcfe. UINTA BASIN The Brundage Canyon field, located in northeastern Utah, is Exploration & Production's principal property in the Uinta Basin. Production from this field is predominately oil, produced from the Lower Green River Formation. In 2002, Exploration & Production drilled 26 gross wells in the Uinta Basin and produced a net of approximately 462 thousand barrels of oil equivalent. Exploration & Production's estimated proved reserves at year-end 2002 were 9 million barrels of oil equivalent. Mid-Continent Properties ARKOMA BASIN Exploration & Production's Arkoma Basin properties are located in southeastern Oklahoma. Exploration & Production's production from the Arkoma Basin is primarily from the Hartshorne coal bed methane formation. Exploration & Production is utilizing horizontal drilling technology to develop the coal seams. In 2002, Exploration & Production drilled 51 gross wells (44 operated) in the Arkoma Basin and produced a net of approximately three Bcfe. Exploration & Production's estimated proved reserves in the Arkoma Basin at year-end 2002 were 83 Bcfe. HUGOTON AREA The Hugoton Embayment properties are located in southwest Kansas. Exploration & Production produced a net of approximately 10 Bcfe of natural gas from the Hugoton Area in 2002. Exploration & Production's estimated proved reserves in the Hugoton area at year-end 2002 were 102 Bcfe. 18 Other Properties Exploration & Production has operations in other areas, including the Green River Basin, located in southwest Wyoming, the Gulf Coast region and northeast Colorado. These properties contain approximately 2.5 percent of Exploration & Production's estimated proved reserves. GAS RESERVES AND WELLS At December 31, 2002, 2001 and 2000, Exploration & Production had proved developed natural gas reserves of 1,368 Bcfe, 1,599 Bcfe and 603 Bcfe, respectively, and proved undeveloped reserves of 1,466 Bcfe, 1,579 Bcfe and 599 Bcfe, respectively. At December 31, 2002, 48 percent of Exploration & Production's total proved reserves are located in the Piceance Basin in Colorado, 25 percent are located in the San Juan Basin of Colorado and New Mexico and 11 percent are located in the Powder River Basin in Wyoming. The remaining 16 percent of proved reserves are primarily in the Raton, Arkoma, Hugoton, and Green River basins, the Gulf Coast regions and northeast Colorado. No major discovery or other favorable or adverse event has caused a significant change in estimated gas reserves since year-end 2002. Exploration & Production has not filed on a recurring basis estimates of its total proved net oil and gas reserves with any U.S. regulatory authority or agency other than the Department of Energy (DOE) and the Securities and Exchange Commission (SEC). The estimates furnished to the DOE have been consistent with those furnished to the SEC, although Exploration & Production has not yet filed any information with respect to its estimated total reserves at December 31, 2002, with the DOE. Certain estimates filed with the DOE may not necessarily be directly comparable due to special DOE reporting requirements, such as requirements to report in some instances on a gross, net or total operator basis, and requirements to report in terms of smaller units. The underlying estimated reserves for the DOE did not differ by more than five percent from the underlying estimated reserves utilized in preparing the estimated reserves reported to the SEC. Approximately 95 percent of Exploration & Production's proved reserves estimates are either audited or prepared by Netherland, Sewell & Associates, Inc., Ryder Scott Company or Miller and Lents, LTD., depending on the basin. Approximately three percent of the 95 percent of Exploration & Production's proved reserves estimates that are audited or prepared externally are prepared by Miller and Lents, LTD. under an agreement with the Williams Coal Seam Gas Royalty Trust. At December 31, 2002, the gross and net developed acres leased by Exploration & Production totaled 1,129,044 and 605,450 respectively, and the gross and net undeveloped acres leased were 1,463,629 and 663,459, respectively. At December 31, 2002, Exploration & Production owned interests in 10,528 gross producing wells (4,697 net) on its leasehold lands. OPERATING STATISTICS Exploration & Production focuses on low-risk development drilling. The following tables summarize drilling activity by number and type of well for the periods indicated:
NUMBER OF GROSS NET 2002 WELLS WELLS WELLS ---------- ----- ----- Development: Drilled................................................... 1,347 723 Completed................................................. 1,332 713 Exploration: Drilled................................................... 6 3 Completed................................................. 2 1
19
NUMBER OF GROSS NET COMPLETED DURING WELLS WELLS ---------------- ----- ----- 2002........................................................ 1,334 714 2001........................................................ 776 352 2000........................................................ 246 62
The majority of Exploration & Production's natural gas production is currently being sold to Energy Marketing & Trading at prevailing market prices. Because Exploration & Production currently has a low-risk drilling program in proven basins, the main component of risk that it manages is price risk. Exploration & Production manages price risk as needed by hedging when market conditions warrant. Exploration & Production has entered into derivative contracts with Energy Marketing & Trading that hedge approximately 83 percent of projected 2003 domestic natural gas production before consideration of any potential property sales in 2003. Energy Marketing & Trading then enters into offsetting derivative contracts with unrelated third parties. Approximately 81 percent of Exploration and Production's natural gas production in 2002 was hedged. Exploration & Production's 2002 net production increased by nearly 62 percent over the previous year. The total net production sold during 2002, 2001 and 2000 was 211.5 Bcfe, 130.7 Bcfe and 65.6 Bcfe, respectively. The average production costs including production taxes per thousand cubic feet of gas equivalent (Mcfe) produced were $.58, $.61 and $.57, in 2002, 2001 and 2000, respectively. The average sales price per Mcfe was $2.11, $2.67 and $2.96, respectively, for the same periods. Additionally, Exploration & Production realized the impact of hedging contracts, which was a gain of $1.19 and $.46 per Mcfe for 2002 and 2001, respectively, and a loss of $.74 for 2000. Divestitures Effective July 1, 2002, Williams Production Company divested of its interest in the Jonah field located in the Green River Basin in southwest Wyoming. This divestiture comprised 365 Bcfe in year-end 2001 reserves and approximately 112 million cubic feet equivalent (MMcfe) per day in production. Effective March 1, 2002, Williams Production RMT Company divested of its non-core Wind River properties located in southwest Wyoming, which represented 60.2 Bcfe in year-end 2001 reserves and approximately 29 MMcfe per day in production. Effective July 1, 2002, Williams Production RMT Company divested of its non-core Anadarko properties located in western Oklahoma, which comprised 23 Bcfe in year-end 2001 reserves and approximately 10 MMcfe per day in production. Other smaller divestitures of non-core properties during the year consisted of 22 Bcfe in year-end 2001 reserves and approximately 15 MMcfe per day in production. ENVIRONMENTAL AND OTHER REGULATORY MATTERS Our Exploration and Production business is subject to various federal, state and local laws and regulations on taxation, the exploration for and development, production and marketing of oil and gas, and environmental and safety matters. Many laws and regulations require drilling permits and governs the spacing of wells, rates or production, prevention of waste and other matters. Such laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil and gas wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells which could limit our reserves. Our operations are subject to complex environmental laws and regulations adopted by the various jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil, or water, including responsibility for remedial costs. We could potentially discharge such materials into the environment in many ways including: - from a well or drilling equipment at a drill site; - leakage from gathering systems, pipelines, transportation facilities and storage tanks; 20 - damage to oil and gas wells resulting from accidents during normal operations; and - blowouts, cratering and explosions. Because the requirements imposed by such laws and regulations are frequently changed, we cannot assure you that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business. In addition, because we acquire properties that have been operated in the past by others, we may be liable for environmental damage caused by such former operators. COMPETITION The natural gas industry is highly competitive. We compete in the areas of property acquisitions and the development, production and marketing of, and exploration for, natural gas with major oil companies, other independent oil and natural gas concerns and individual producers and operators. We also compete with major and independent oil and gas concerns in recruiting and retaining qualified employees. Many of these competitors have substantially greater financial and other resources than us. OWNERSHIP OF PROPERTY The majority of Exploration & Production's ownership interest in exploration and production properties are held as working interests in oil and gas leaseholds. OTHER INFORMATION In 1993, Exploration & Production conveyed a net profits interest in certain of its properties to the Williams Coal Seam Gas Royalty Trust. Substantially all of the production attributable to the properties conveyed to the trust was from the Fruitland coal formation and constituted coal seam gas. Williams subsequently sold trust units to the public in an underwritten public offering and retained 3,568,791 trust units representing 36.8 percent of outstanding trust units. During 2000, Williams sold all of its trust units as part of a Section 29 tax credit transaction, in which Williams retained an option to repurchase the units. Williams registered the units with the Securities and Exchange Commission (SEC)and has been repurchasing the units and reselling the units on the open market from time to time. As of March 1, 2003, our option to repurchase trust units covered 2,608,791 trust units. INTERNATIONAL EXPLORATION AND PRODUCTION INTERESTS Exploration & Production also has investments in international oil and gas interests. Exploration & Production owns approximately a 69 percent interest in Apco Argentina Inc., an oil and gas exploration and production company with operations in Argentina, whose securities are traded on the NASDAQ stock market. Apco Argentina's principal business is its 51.7 percent interest in the Entre Lomas concession in southwest Argentina. It also owns a 45 percent interest in the Canadon Ramirez concession and a 1.5 percent interest in the Acambuco concession. In Venezuela, we own a 10 percent interest in the La Concepcion Area, a third round field development located in Western Venezuela, near Lake Maracaibo. Combined these interests make up 5.2 percent of Exploration & Production's total proved reserves. MIDSTREAM GAS & LIQUIDS GENERAL Our Midstream Gas & Liquids segment subsidiaries provide a suite of natural gas gathering, processing, treating and natural gas liquid and olefin fractionation, transportation, storage, risk management and marketing services throughout the United States, western Canada, and Venezuela. On February 20, 2003, we announced our intention to sell additional selected assets within the Midstream Gas & Liquids segment. Midstream Gas and Liquids' current suite of assets include the following operations: 21 Substantially all of our assets within the Midstream Gas & Liquids segment are pledged as collateral under our existing secured revolving credit facility and secured letter of credit facility. See Note 11 to our Notes to Consolidated Financial Statements for more information on the credit facilities. Domestic Gathering and Processing; Natural Gas Liquid Fractionation, Storage and Transportation Midstream Gas & Liquids owns and/or operates domestic gas gathering and processing assets primarily within the western states of Wyoming, Colorado, and New Mexico; and the onshore and offshore shelf and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama. These assets consist of approximately 9,000 miles of gathering pipelines with capacity in excess of eight billion cubic feet per day (including certain gathering lines owned by Transco but operated by Midstream Gas & Liquids), eleven processing plants (two partially owned) and nine natural gas treating plants with a combined daily inlet capacity in excess of 5.5 billion cubic feet per day. Midstream Gas & Liquids also owns interests in and/or operates natural gas liquid fractionation, storage and transportation assets that supplement the gathering and processing operations listed above. These assets include three partially owned natural gas liquid fractionation facilities (two of which are operated by Midstream Gas & Liquids) within central Kansas and southern Louisiana that have a combined production capacity in excess of 200,000 barrels per day. These assets also include ownership interests in approximately 25 million barrels of natural gas liquid storage capacity (wholly-owned) within central Kansas and approximately 3,500 miles of domestic natural gas liquids pipelines (partially owned) primarily located in the onshore and offshore Gulf Coast areas. Included in the assets listed above are the assets of Discovery Producer Services LLC and its subsidiary Discovery Transmission Services LLC (Discovery). Midstream Gas & Liquids owns a 50 percent interest in Discovery. During 2002, Midstream Gas & Liquids became the operator of Discovery. Discovery's assets include a cryogenic natural gas processing plant near Larose, Louisiana, a natural gas liquids fractionator plant near Paradis, Louisiana and an offshore natural gas gathering and transportation system. Gulf Coast Petrochemical and Olefins In southern Louisiana, Midstream Gas & Liquids provides customers in the petrochemical industry a full suite of products and services. These operations include a 42 percent interest in a 1.3 billion pound per year ethylene production, storage and transportation complex in Geismer, Louisiana and the ownership interest in Gulf Liquids New River LLC (Gulf Liquids). Gulf Liquids, a start up entity that began operations in late 2001, consists of two refinery off gas processing facilities, an olefinic fractionator and propylene splitter and connecting pipeline system. In September 2002, Midstream Gas & Liquids acquired the remaining interest in and became the operator of Gulf Liquids. Prior to 2002, the ownership interests in the Geismer ethylene production complex and Gulf Liquids were included as a component of the Petroleum Services and Energy Marketing & Trading business segments respectively. We have announced our intention to sell the petrochemical and olefins assets located in Geismar, Louisiana. Natural Gas Liquids Marketing and Risk Management Midstream Gas & Liquids marketing and risk management operations provide natural gas liquid and petrochemical product supply to third party end users. Supply for the third party end user is obtained from the equity production from Midstream Gas & Liquid's processing, fractionation and Gulf Coast olefins facilities as well as from outside sources. During 2002, natural gas liquid marketing and risk management operations were transferred from Energy Marketing & Trading to Midstream Gas & Liquids. Canada Midstream Gas & Liquids owns and operates natural gas treating and extraction facilities in Alberta and British Columbia, Canada. These operations include a natural gas processing plant, four natural gas liquid extraction plants (two of which are partially-owned), a natural gas liquids gathering system and natural gas liquid storage and fractionation facilities. 22 Canadian operations also include a newly constructed liquids extraction plant located near Ft. McMurray, Alberta and an olefin fractionation facility near Edmonton, Alberta. Operations of these facilities began in the first quarter of 2002. These new facilities extract olefin liquids from off-gas and then fractionate, store, treat and terminal propane and propylene. This project involves the recovery of hydrocarbon liquids, impurities and olefins from the off-gas produced from third party tar sands refining facilities near Ft. McMurray, Alberta. We have announced our intention to sell certain of our Canadian operations. Venezuela Midstream Gas & Liquids owns interests in one medium- and two high-pressure gas compression facilities, two natural gas liquids extraction units, one fractionation facility, and an operations contract on an oil and gas loading and storage facility located in Venezuela. During 2002, these operations were transferred to Midstream Gas & Liquids from the previously reported International business segment. Expansion Projects GATHERING AND PROCESSING -- WYOMING EXPANSION In January 2002, Midstream Gas & Liquids completed an expansion of our Echo Springs natural gas plant near Wamsutter, Wyoming. This expansion included the addition of a third cryogenic gas processing unit that boosted the inlet capacity of the plant from 250 to 390 million cubic feet per day and liquids extraction from 18,000 barrels to 28,000 barrels per day. This project also included the expansion of the gathering system that brings natural gas to the Echo Springs facility. GATHERING AND PROCESSING -- DEEPWATER PROJECTS In 2002, Midstream Gas & Liquids expanded its Gulf Coast gathering and processing operations with the completion of the 137-mile pipeline system to gather and transport oil and natural gas production from Kerr-McGee Corporation's deepwater developments in the Nansen and Boomvang areas in the western Gulf of Mexico. First production from Nansen and Boomvang occurred in late January 2002 and early July 2002, respectively. During 2002, Midstream Gas & Liquids also completed construction of Canyon Station, a state of the art production handling platform that treats and processes up to 500 million cubic feet gas per day from the Aconcagua Canden Hills and Kings Peak deepwater fields. First volumes began flowing through Canyon Station in September and are currently flowing in excess of 400 million cubic feet per day. Midstream Gas & Liquids also continues construction on the deepwater projects for the Devils Tower field (operated by Dominion Exploration and Production) in the eastern Gulf of Mexico. This project called for Midstream Gas & Liquids to construct and own a floating production facility, a 90-mile gas pipeline and a 120-mile oil pipeline to handle production from the Devils Tower field. First production is expected in late 2003. Midstream Gas & Liquids intends to use the facilities to provide production-handling services to surrounding fields. Midstream Gas & Liquids' Mobile Bay plant will process the gas and recover natural gas liquids, which will then be transported to the Baton Rouge Fractionator via the Tri-States and Wilprise pipelines, all owned in whole or in part by Midstream Gas & Liquids. Midstream Gas & Liquids also signed an agreement with Kerr-McGee to build a 100-mile oil pipeline to their Gunnison prospect. This pipeline will be connected to our Galveston Area Block A-244 platform for deliveries into a third party crude oil system. First oil production is expected by the second quarter 2004. Customers and Operations Midstream Gas & Liquids' domestic gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding Midstream Gas & Liquids' infrastructure. During 2002, these operations gathered gas for 244 customers and processed gas for 96 customers. The largest gathering customer accounted for approximately 15 percent of total gathered volumes, 23 and the two largest processing customers accounted for 24 percent and 15 percent, respectively, of processed volumes. Midstream Gas & Liquids' gathering and processing agreements are generally long-term agreements with various expiration dates. Midstream Gas & Liquids markets natural gas liquids and petrochemical products to a wide range of users in the energy and petrochemical industries. Midstream Gas & Liquids' marketing and risk management operations provide liquid and petrochemical product supply to third parties from the equity production from Midstream Gas & Liquids' domestic facilities as well as from outside sources. The majority of domestic sales are based on supply contracts of less than one-year in duration. Midstream Gas & Liquids' Canadian operations sold natural gas liquids produced from the Canadian facilities to third party end users. Canadian natural gas liquid sales contracts are typically long-term in nature. In order to meet the delivery requirements under various contracts Midstream Gas & Liquids maintains inventories of natural gas liquids at various locations throughout the United States and Canada. Midstream Gas & Liquids' Venezuelan assets were originally constructed and are currently operated for the exclusive benefit of Petroleos de Venezuela S.A. (PDVSA), the state owned Petroleum Corporation of Venezuela. The significant contracts are 20 years in duration with revenues based on a combination of fixed capital payments, throughput volumes, and in the case of one of the gas compression facilities, a minimum throughput guarantee. During December 2002 and early 2003, a countrywide strike took place within Venezuela that resulted in significant political instability and a volatile economic environment. Employees of PDVSA joined this strike, which had an impact on the operations of most of the Venezuelan facilities. All owned facilities are presently operating. However, an operating agreement for the PDVSA owned oil terminaling facility is the subject of a contract dispute with PDVSA. The ultimate impact the economic and political instability will have on Midstream Gas & Liquids' Venezuelan operations will depend upon the duration of the economic and political instability as well as the ability to enforce certain contract provisions with PDVSA. Operating Statistics The following table summarizes Midstream Gas & Liquids' significant operating statistics.
2002 2001 2000 ----- ----- ----- Volumes*: Domestic gathering (trillion British Thermal Units)......... 2,108 2,174 2,116 Domestic Natural Gas Liquid Production**.................... 135 122 132 Canadian Natural Gas Liquid Production**.................... 208 169 190 Domestic Natural Gas Liquids and Petrochemical Products Marketed**................................................ 391 326 281
--------------- * Excludes volumes associated with partially owned assets that are not consolidated for financial reporting purposes. ** Average thousand barrels per day. REGULATORY AND ENVIRONMENTAL MATTERS Under the Natural Gas Act (NGA), gathering and processing facilities and services are not subject to the regulatory authority of the FERC. Onshore gathering is reserved to the states and offshore gathering is subject to the Outer Continental Shelf Lands Act (OCSLA). Of the states where Midstream Gas & Liquids operates, currently only Kansas, Oklahoma and Texas actively regulate gathering activities. Those states regulate gathering through complaint mechanisms under which the state commission may resolve disputes involving an individual gathering arrangement. Although gathering facilities located offshore are not subject to the NGA, some controversy exists as to how the FERC should determine whether offshore facilities function as gathering. These issues are currently before the FERC and appellate courts. Most gathering facilities offshore are subject to the OCSLA, which provides in part that 24 outer continental shelf pipelines "must provide open and nondiscriminatory access to both owner and nonowner shippers." Midstream Gas & Liquids' business operations are subject to various federal, state, and local environmental and safety laws and regulations. The Discovery and other pipeline systems are subject to FERC regulation common to interstate gas transmission. Midstream Gas & Liquids' liquid pipeline operations are subject to the provisions of the Hazardous Liquid Pipeline Safety Act. In addition, the tariff rates, shipping regulations, and other practices of the Wilprise and Tri-States pipelines are regulated by the FERC pursuant to the provisions of the Interstate Commerce Act applicable to interstate common carrier petroleum and petroleum products pipelines. Both of these statutes require the filing of reasonable and nondiscriminatory tariff rates and subject Midstream Gas & Liquids to certain other regulations concerning its terms and conditions of service. Certain of our pipelines also file tariff rates covering intrastate movements with various state commissions. The United States Department of Transportation has prescribed safety regulations for common carrier pipelines. The pipeline systems are subject to various state laws and regulations concerning safety standards, exercise of eminent domain, and similar matters. The Kansas Department of Health and Environment (KDHE) has proposed new regulations to govern underground storage in Kansas, which may require additional equipment and testing for Midstream Gas & Liquids' storage operations in Kansas. The majority of our Midstream Gas & Liquids' Canadian assets, are regulated provincially. The Alberta-based assets are regulated by the Alberta Energy & Utilities Board (AEUB) and Alberta Environment, while the British Columbia-based assets are regulated by the British Columbia Oil and Gas Commission and the British Columbia Ministry of Environment, Lands and Parks. The regulatory system for Alberta oil and gas industry incorporates a large measure of self-regulation, providing that licensed operators are held responsible for ensuring that their operations are conducted in accordance with all provincial regulatory requirements. For situations in which non-compliance with the applicable regulations is at issue, the AEUB and Alberta Environment have implemented an enforcement process with escalating consequences. The British Columbia Oil and Gas Commission operates in a slightly different manner than the AEUB, with more emphasis placed on pre-construction criteria and the submission of post-construction documentation, as well as periodic inspections. Only one asset is subject to federal regulation, under the jurisdiction of Canada's National Energy Board (NEB). One pipeline system, which is Leg Number 2 of the natural gas liquids gathering system, is regulated by the NEB as a Group 2 inter-provincial pipeline between British Columbia and Alberta. While Group 2 regulated companies are required to post a toll and tariff for the facilities they operate, they are regulated on a "complaint only" basis and need only to employ standard uniform accounting procedures, rather than the more stringent Group 1 NEB-mandated accounting and reporting requirements. COMPETITION The gathering and processing business is a local business with varying competitive factors in each basin. Midstream Gas & Liquids' gathering and processing business competes with interstate and intrastate pipelines, producers and independent gatherers and processors. Numerous factors impact any given customer's choice of a gathering or processing services provider, including rate, location, term, timeliness of well connections, pressure obligations and the willingness of the provider to process for either a fee or for liquids taken in-kind. Midstream Gas & Liquids' gathering and processing services are generally covered under long-term contracts with applicable acreage or reserve dedications. Midstream Gas & Liquids' relatively large positions in the Western and Gulf Regions are indicators that demand for future gathering and processing infrastructure and services should continue. OWNERSHIP OF PROPERTY Midstream Gas & Liquids typically owns its gathering and processing facilities. Midstream Gas & Liquids constructs and maintains gathering and natural gas liquids pipeline systems pursuant to rights-of-way, easements, permits, licenses, and consents on and across properties owned by others. The compressor stations and gas processing and treating facilities are located in whole or in part on lands owned by subsidiaries of Midstream Gas & Liquids or on sites held under leases or permits issued or approved by public authorities. 25 ENERGY MARKETING & TRADING GENERAL Our Energy Marketing & Trading segment, is a national energy services provider that buys, sells and transports energy and energy-related commodities, including power, natural gas, refined products, crude oil, and emission credits, primarily on a wholesale level. In addition, Energy Marketing & Trading provides energy-related services through a variety of financial instruments and structured transactions including exchange-traded futures, as well as over-the-counter forwards, options, swaps, tolling, load serving, full requirements, storage, transportation, and transmission agreements and other derivatives related to various energy and energy-related commodities. As a result of current liquidity and credit constraints, in June 2002 we decided to limit our financial commitment and exposure to the Energy Marketing & Trading business. Energy Marketing & Trading initiated efforts in 2002 to sell all or portions of its portfolio and/or pursue potential joint venture or business combination opportunities. Energy Marketing & Trading's future results will likely be affected by the reduction in liquidity available from its parent, the unwillingness of counterparties to enter into transactions with Energy Marketing & Trading, the liquidity of markets in which Energy Marketing & Trading operates, and the creditworthiness of other counterparties in the industry and their ability to perform their contractual obligations. During 2002, 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 our credit and liquidity situation. See Note 15 of our Notes to Consolidated Financial Statements for information on financial instruments and energy trading activities. At December 31, 2002, Energy Marketing & Trading employed approximately 410 employees, compared with approximately 1,000 employees at the end of 2001. As of February 25, 2003, the number of Energy Marketing & Trading employees was approximately 330 and additional staffing reductions are expected during 2003. As discussed below and in Note 1 and 16 to our -- Notes to Consolidated Financial Statements, in 2002, the energy marketing and trading business sector, including Energy Marketing & Trading, experienced significant financial challenges, for example associated with credit downgrades and reduced liquidity, as well as significant legal and regulatory challenges, for example associated with federal and state investigations and numerous lawsuits, that adversely affected the energy marketing and trading business. These challenges are expected to continue in 2003. During 2002, Energy Marketing & Trading marketed over 404,711 physical gigawatt hours of power. As part of its approximately 11,000 megawatt power supply portfolio at year-end, Energy Marketing & Trading has a mix of owned generation, tolling agreements and supply resources through full requirements transactions in support of its load obligations. Energy Marketing & Trading had a number of long-term tolling agreements at December 31, 2002, to market capacity of electric generation facilities totaling approximately 7,500 megawatts (California -- 3,956 megawatts; Alabama -- 845 megawatts; Louisiana -- 765 megawatts; New Jersey -- 752 megawatts; Pennsylvania -- 655 megawatts; and Michigan -- 538 megawatts). Under these tolling arrangements, Energy Marketing & Trading has the right, but not the obligation, to supply fuel for conversion to electricity and then market capacity, energy and ancillary services related to the generating facilities owned and operated by various unrelated third parties. As of December 31, 2002, Energy Marketing & Trading also had entered into several agreements to provide full requirements services for a number of customers whose supply resources are being managed with approximately 2,520 megawatts of load in the United States, including transactions in Indiana, Pennsylvania and Georgia. Additionally, Energy Marketing & Trading has marketing rights for the energy and capacity from two natural gas-fired electric generating plants owned by affiliated companies and located near Bloomfield, New Mexico (60 megawatts); in Hazleton, Pennsylvania (147 megawatts); and near Worthington, Indiana (170 megawatts). Energy Marketing & Trading's subsidiary, Worthington Generation, L.L.C., which owns the Worthington facility, was sold in January of 2003 for $67 million, including a termination of an approximately 1,056 megawatt load serving transaction in Indiana. In connection with a global settlement of claims asserted by the state of California, and as more fully discussed in Note 16 of our Notes to Consolidated Financial Statements, Energy Marketing & Trading renegotiated long-term power agreements with the California Department of Water Resources. 26 Energy Marketing & Trading's primary power customers include utilities, municipalities, cooperatives, governmental agencies and other power marketers. In 2002, Energy Marketing & Trading marketed natural gas throughout North America with total physical volumes averaging 3.8 billion cubic feet per day. Beginning in 2000, Energy Marketing & Trading's natural gas marketing operations focused on activities that facilitate and/or complement the group's power portfolio. In addition to procuring supply for our Midstream Gas & Liquids operations, marketing equity gas for our Exploration & Production operations and managing firm service contracts for our Gas Pipeline operation, Energy Marketing & Trading's natural gas customers include local distribution companies, utilities, producers, industrials and other gas marketers. In 2002, Energy Marketing & Trading provided supply, distribution and related risk management services to petroleum producers, refiners and end-users in the United States and various international regions. During 2002, Energy Marketing & Trading marketed on average approximately 832,000 barrels per day of physical crude oil and petroleum products. In 2002, Energy Marketing & Trading curtailed its European trading activities conducted through its London office as part of our efforts to scale back our entire trading business in 2002. Included in the 2002 Energy Marketing & Trading staffing reductions noted above is a decrease in staffing of its London office from 32 at the end of 2001 to nine at the end of 2002. OPERATING STATISTICS The following table summarizes marketing and trading gross sales volumes for the periods indicated. Petroleum products volumes for 2001 and 2000 do not include volumes associated with the natural gas liquids business transferred to the Midstream Gas & Liquids segment during 2002. Energy Marketing & Trading
2002 2001 2000 ------- ------- ------- U.S. Operations Marketing and trading physical volumes: Power (thousand megawatt hours)....................... 404,711 293,808 141,311 Natural Gas (billion cubic feet per day).............. 3.8 3.4 3.3 Petroleum products (thousand barrels per day)......... 832 241 728
2002 ------ European Operations Marketing and trading physical volumes: Power (thousand megawatt hours)........................... 26,094 Natural Gas (billion cubic feet per day).................. 0.2 Petroleum products (thousand barrels per day)............. 83
As of December 31, 2002, Energy Marketing & Trading had approximately 287 customers compared with over 652 customers at the end of 2001. REGULATORY AND LEGAL MATTERS Energy Marketing & Trading's business is subject to a variety of laws and regulations at the local, state and federal levels in the United States and Europe (including the United Kingdom). In the U.S. Energy Marketing & Trading is regulated by the FERC and the Commodity Futures Trading Commission. Electricity and natural gas markets, in California and elsewhere, continue to be subject to numerous and wide-ranging federal and state regulatory proceedings and investigations, as well as civil actions, regarding among other things, market structure, behavior of market participants, market prices, and reporting to trade publications. Discussions in California and other states have ranged from threats of re-regulation to suspension of plans to 27 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 Energy Marketing & Trading. These allegations have resulted in multiple state and federal investigations as well as the filing of class-action lawsuits in which Energy Marketing & Trading is named a defendant. Energy Marketing & Trading's long-term power contract with the California Department of Water Resources has also been challenged both at the FERC and in civil suits. On November 11, 2002, Energy Marketing & Trading and Williams executed a settlement agreement that is intended to resolve many of these disputes with the State of California with respect to non-criminal matters and includes renegotiated long-term energy contracts. The settlement is also intended to resolve complaints brought by the California Attorney General against us and the State of California's refund claims. In addition, the settlement is intended to resolve ongoing investigations by the States of California, Oregon, and Washington. The settlement closed December 31, 2002, although certain court approvals are pending. Notwithstanding this settlement, numerous investigations and actions related to energy marketing and trading remain. Energy Marketing & Trading may be liable for refunds and other damages and penalties as a result of the above actions and investigations. Each of these matters as well as other regulatory and legal matters related to Energy Marketing & Trading are discussed in more detail in Note 16 to our Consolidated Financial Statements. The outcome of these matters could affect the creditworthiness and ability to perform contractual obligations of Energy Marketing & Trading as well as the creditworthiness and ability to perform contractual obligations of other market participants. On March 13, 2003, we entered into a settlement with FERC regarding its investigation of the relationship between Transco and Energy Marketing & Trading whereby Transco will pay a civil penalty in the amount of $20 million payable over a five year period. In addition, we agreed to certain operational restrictions and agreed to implement a compliance program to ensure future compliance with the settlement agreement and FERC's marketing affiliate rules. See Note 16 of our Notes to Consolidated Financial Statements for further information on the settlement. COMPETITION AND MARKET ENVIRONMENT Energy Marketing & Trading's operations compete directly with large independent energy marketers, marketing affiliates of regulated pipelines and utilities and natural gas producers. The financial trading business is highly competitive and Energy Marketing & Trading competes with other energy-based companies offering similar services as well as certain brokerage houses. This level of competition contributes to a business environment of constant pricing and margin pressure. In 2002, the energy marketing and trading industry, including Energy Marketing & Trading, experienced significant credit and liquidity constraints affecting the conduct of new business and performance on preexisting commitments. Energy Marketing & Trading's business also had relied upon our senior unsecured long-term debt investment-grade rating to satisfy credit support requirements of many counterparties. As a result of the credit rating downgrades to below investment grade levels, Energy Marketing & Trading's participation in energy risk management and trading activities requires adequate assurance or alternate credit support under certain existing agreements. In addition, we are required to fund margin requirements pursuant to industry standard derivative agreements with cash, letters of credit or other negotiable instruments. Certain of Energy Marketing & Trading's counterparties have experienced significant declines in their financial stability and creditworthiness which may adversely impact their ability to perform under contracts with Energy Marketing & Trading. Energy Marketing & Trading initiated efforts in 2002 to sell all or portions of its portfolio and/or pursue potential joint venture or business combination opportunities. During 2002, Energy Marketing & Trading closed out trading positions with a number of counterparties and has disputes associated with this liquidation. One counterparty has disputed a settlement amount related to the liquidation of a trading position with Energy Marketing & Trading and the amount of settlement is in excess of $100 million payable to Energy Marketing & Trading. The matter is being arbitrated. Credit constraints, declines in market liquidity, and financial instability of market participants, are expected to continue and potentially grow in 2003. Continued liquidity and credit constraints of Williams may also significantly impact Energy Marketing & Trading's ability to manage market risk and meet contractual obligations. These matters are further discussed in Management's Discussion & Analysis of Financial Conditions and Results of Operations. 28 OWNERSHIP OF PROPERTY The primary assets of Energy Marketing & Trading are its term contracts, related systems and technological support. In addition, Energy Marketing & Trading owned a gas-fired generating facility located near Worthington, Indiana with a capacity of approximately 170 megawatts. In January 2003, Energy Marketing & Trading sold Worthington Generation L.L.C., its subsidiary that owns the Worthington generation facility. As a result of our current liquidity constraints, Energy Marketing & Trading initiated efforts in 2002 to sell all or portions of its portfolio and/or pursue potential joint venture or business combination opportunities. No assurances can be made regarding the ultimate consummation of any sales or business combination activities currently being pursued. Energy Marketing & Trading is continuing to evaluate its potential alternatives. As discussed further in Note 1 to our Notes to Consolidated Financial Statements, portions of Energy Marketing & Trading's portfolio have been recognized at their estimated "fair value," which according to generally accepted accounting principles is the amount at which they could be exchanged in a current transaction between willing parties other than in a forced liquidation or sale. Given the financial condition and liquidity constraints and needs of the Company, however, amounts ultimately realized in any portfolio sales or business combination may be significantly different than fair value estimates presented in the financial statements, depending on the timing and terms of any such transactions. ENVIRONMENTAL MATTERS Power generation facilities are subject to various environmental laws and regulations, including laws and regulations regarding emissions. We do not believe compliance with various environmental laws and regulations would have a material adverse effect on capital expenditures, earnings and the competitive position of Energy Marketing & Trading. Facility availability may be affected by these laws and regulations. WILLIAMS ENERGY PARTNERS L.P. GENERAL We have announced our intention to sell our interests in Williams Energy Partners. In October 2000, we formed Williams Energy Partners, a wholly-owned master limited partnership through various wholly-owned subsidiaries, to acquire, own and operate a diversified portfolio of energy assets, concentrated around the storage, transportation and distribution of refined petroleum products and ammonia. In February 2001, 4,600,000 common units, representing approximately 40 percent of the total outstanding units of Williams Energy Partners, were sold to the public in an initial public offering. Williams Energy Partners' common units trade on the New York Stock Exchange under the symbol WEG. Following this transaction, we owned approximately 65 percent of Williams Energy Partners, including 100 percent of Williams Energy Partners' general partner interest. On April 11, 2002, Williams Energy Partners acquired all of the membership interests of Williams Pipe Line Company LLC from a wholly owned subsidiary of ours for approximately $1 billion. As consideration, Williams Energy Partners paid us $674.4 million in cash, after netting our $6 million required contribution to maintain our 2 percent general partner interest. We also received $304 million in the form of class B units representing limited partner interests in Williams Energy Partners. We currently own approximately a 53 percent limited partnership interest subject to certain limitations on voting rights and 100 percent of WEG GP LLC, Williams Energy Partners' sole general partner. Williams Energy Partners" current asset portfolio includes: - the Williams Pipe Line system, a 6,700 mile refined petroleum products pipeline system that serves the mid-continent region of the United States with 39 system terminals and 26 million barrels of storage; - five petroleum products terminal facilities located along the Gulf Coast and near the New York harbor (marine terminals) with an aggregate storage capacity of approximately 18 million barrels; 29 - 23 petroleum products terminals located principally in the southeastern United States (inland terminals) with an aggregate storage capacity of five million barrels; and - an 1,100-mile ammonia pipeline system that serves the mid-continent region of the United States. REGULATORY AND ENVIRONMENTAL MATTERS Williams Pipe Line, as an interstate common carrier pipeline, is subject to the provisions and regulations of the Interstate Commerce Act. Under this Act, Williams Pipe Line is required, among other things, to establish just, reasonable and nondiscriminatory rates, to file its tariffs with the FERC, to keep its records and accounts pursuant to the Uniform System of Accounts for Oil Pipeline Companies, to make annual reports to the FERC and to submit to examination of its records by the audit staff of the FERC. Authority to regulate rates, shipping rules and other practices and to prescribe depreciation rates for common carrier pipelines is exercised by the FERC. The Department of Transportation, as authorized by the 1995 Pipeline Safety Reauthorization Act, is the oversight authority for interstate liquids pipelines. Williams Pipe Line is also subject to the provisions of various state laws applicable to intrastate pipelines. The Surface Transportation Board, a part of the United States Department of Transportation, has jurisdiction over interstate pipeline transportation of ammonia. Ammonia transportation rates must be reasonable, and a pipeline carrier may not unreasonably discriminate among its shippers. If the Surface Transportation Board finds that a carrier's rates violate these statutory commands, it may prescribe a reasonable rate. In determining a reasonable rate, the Surface Transportation Board will consider, among other factors, the effect of the rate on the volumes transported by that carrier, the carrier's revenue needs and the availability of other economic transportation alternatives. COMPETITION In certain markets, barges provide an alternative source for transporting refined products; however, pipelines are generally the lowest-cost alternative for refined product movements between different markets. As a result, the Williams Pipe Line system's most significant competitors are other pipelines that serve the same markets. Williams Energy Partners experiences the greatest demand at its marine terminals when customers tend to store more product to take advantage of favorable pricing expected in the future. When the opposite market condition exists some companies choose not to store product or are less willing to enter into long-term storage contracts. The additional heating and blending services that Williams Energy Partners provides at its marine terminals attract additional demand for our storage services and result in increased revenue opportunities. Several major and integrated oil companies have their own proprietary storage terminals along the Gulf Coast that are currently being used in their refining operations. If these companies choose to shut down their refining operations and elect to store and distribute refined petroleum products through their proprietary terminals, Williams Energy Partners would experience increased competition for the services that it provides. In addition, several companies have facilities in the Gulf Coast region and offer competing storage and distribution services. OWNERSHIP OF PROPERTY Williams Energy Partners owns its pipeline and terminalling assets. Its facilities are located on property owned, leased, licensed, or subject to right-of-way agreements. PETROLEUM SERVICES GENERAL We completed a number of asset sales in the Petroleum Services segment during 2002 and early 2003. We regard the remaining assets within the Petroleum Services segment as non-strategic and substantially all of the remaining assets with the exception of our interest in Longhorn Partners pipeline will be sold in the near 30 future. Certain assets within the Petroleum Services segment, including the Alaska refinery and convenience stores, are pledged under our secured credit facilities. The Petroleum Services segment currently owns and operates a petroleum products refinery and 29 convenience stores in Alaska and markets products related thereto. We have announced our intention to sell the Alaska refinery and related operations. In 2002, no one customer accounted for ten percent of Petroleum Services' total revenues. We and our subsidiary, Longhorn Enterprises of Texas, Inc. (LETI), own a total 32.1 percent interest in Longhorn Partners Pipeline, LP, a joint venture formed to construct and operate a refined products pipeline from Houston, Texas, to El Paso, Texas. Pipeline construction is substantially complete and all regulatory and environmental approvals have been received. Operations are expected to commence by year-end 2003, once start-up financing is obtained. we have contributed a total of approximately $96 million and loaned approximately $139 million (including accrued interest of $21.5 million) to the joint venture. Williams Pipe Line Company, a subsidiary of Williams Energy Partners LP, has designed and constructed and will operate the pipeline. On June 30, 2000, we purchased a 3.08 percent interest in TAPS and the Valdez Crude terminal in Alaska from Mobil Alaska Pipeline Company for $32.5 million. Petroleum Services' share of the crude oil deliveries for 2002 and 2001 was approximately 14.4 million barrels and 14.0 million barrels, respectively. We also own Williams Bio-Energy L.L.C. that owns and operates an ethanol production plant in Pekin, Illinois, a 78.4 percent interest in another ethanol plant in Aurora, Nebraska, and have various agreements to market ethanol from third-party plants. On February 20, 2003, we announced a definitive agreement to sell our equity interest in Williams Bio-Energy L.L.C. REFINING Petroleum Services, through a subsidiary, owns and operates the North Pole, Alaska petroleum products refinery. The financial results of the North Pole refinery may be significantly impacted by changes in market prices for crude oil and refined products. Petroleum Services cannot predict the future of crude oil and product prices or their impact on its financial results. Due to our current credit situation, we must pre-pay for crude oil supply for our refinery operations. On June 18, 2002, we announced our intention to sell the Alaska refinery and related petroleum assets. The North Pole Refinery includes the refinery located at North Pole, Alaska and a terminal facility at Anchorage, Alaska. The refinery, the largest in the state, is located approximately two miles from the TAPS, its supply point for crude oil. The refinery's processing capability is approximately 215,000 barrels per day. At maximum crude throughput, the refinery can produce up to 70,000 barrels per day of retained refined products. The refinery producers jet fuel, gasoline, diesel fuel, heating oil, fuel oil, naphtha and asphalt. These products are marketed in Alaska, western Canada and the Pacific Rim principally to wholesale, commercial, industrial and government customers and to Petroleum Services' retail petroleum group. The North Pole Refinery processed and sold the following volumes per day:
2002 2001 2000 ------ ------ ------ Barrels Processed and Sold (barrels)....................... 63,400 61,705 58,109
The North Pole Refinery's crude oil is purchased from the state of Alaska or is purchased or received on exchanges from crude oil producers. The refinery has two long-term agreements with the state of Alaska for the purchase of royalty oil, both of which are scheduled to expire on December 31, 2003. The agreements permit the North Pole Refinery to purchase up to 56,000 barrels per day (approximately 80 percent of the refinery's supply needs for retained production) of the state's royalty share of crude oil produced from Prudhoe Bay, Alaska. These volumes, along with crude oil either purchased or received under exchange agreements from crude oil producers or other short-term supply agreements with the state of Alaska, are utilized as throughput for the refinery. Approximately 30 percent of the throughput is refined, retained and sold as 31 finished product and the remainder of the throughput is returned to the TAPS and either delivered to repay exchange obligations or sold. RETAIL PETROLEUM Petroleum Services, under the brand name "Williams Express," is engaged in the retail marketing of gasoline, diesel fuel, other petroleum products, convenience merchandise and fast food items. At December 31, 2002, the retail petroleum group operated 29 Williams Express convenience stores in Alaska. The convenience store sites are primarily concentrated in the vicinities of Anchorage and Fairbanks, Alaska. All of the motor fuel sold by Williams Express convenience stores is supplied either by exchanges or directly from the North Pole Refinery. Convenience merchandise and fast food accounted for approximately 57 percent of the retail petroleum group's gross margins in 2002. Gasoline and diesel sales volumes for the periods indicated are noted below:
2002 2001 2000 ------ ------ ------ Gasoline (thousands of gallons)............................ 40,049 44,248 45,917 Diesel (thousands of gallons).............................. 3,764 3,425 3,555
REGULATORY MATTERS Environmental regulations and changing crude oil supply patterns continue to affect the refining industry. Environmental Protection Agency regulations, adopted pursuant to the Clean Air Act, require refiners to change the composition of fuel manufactured. A refiner's ability to respond to the effects of regulation and changing supply patterns will determine its ability to maintain and capture new market shares. We will continue to attempt to position ourself to respond to changing regulations and supply patterns but cannot predict how future changes in the marketplace will affect our market areas. Williams Alaska Petroleum (WAPI) is actively engaged in administrative litigation being conducted jointly by the FERC and the Regulatory Commission of Alaska concerning the TAPS Quality Bank. Primary issues being litigated include the appropriate valuation of the naphtha and residual product cuts within the TAPS crude stream as well as the appropriate retroactive effect of the determinations. WAPI's interest in these proceedings is material, but the outcome cannot be predicted with certainty nor can the likely result be quantified. See Note 16 to our Notes to Consolidated Financial Statements for further detail on the Quality Bank matter. COMPETITION Competition exists from other refineries, cargo shipments, railroads and tank trucks. Competition is affected by trades of products or crude oil production from other refineries that have access to the Alaska market and by trades among brokers, traders and others who control products. These trades can result in the diversion of volumes from the North Pole refinery that might otherwise be refined. The possible changes in refining capacity, refinery closings, changes in the availability of crude oil to refineries located in its marketing area or conservation and conversion efforts by fuel consumers may adversely affect refinery throughput. The principal competitive forces affecting Petroleum Services' refining business are feedstock costs, refinery efficiency, refinery product mix and product distribution. Petroleum Services has no crude oil reserves and does not engage in crude oil exploration, and it must therefore obtain its crude oil requirements from unaffiliated sources. Petroleum Services believes that it will be able to obtain adequate crude oil and other feedstocks at generally competitive prices for the foreseeable future. The principal competitive factors affecting Petroleum Services' retail petroleum business are location, product price and quality, appearance and cleanliness of stores and brand-name identification. Competition in the convenience store industry is intense. 32 OWNERSHIP OF PROPERTY The North Pole refinery is located on land leased from the state of Alaska under a long-term lease scheduled to expire in 2005 and renewable at that time by us. The Anchorage, Alaska terminal is located on land leased from the Alaska Railroad Corporation under two long-term leases. Petroleum Services' management believes the condition and maintenance of its assets are adequate and sufficient for the conduct of its business. ENVIRONMENTAL MATTERS Groundwater monitoring and remediation are ongoing at the North Pole refinery and air and water pollution control equipment is operating to comply with applicable regulations. The Clean Air Act Amendments of 1990 continue to impact Petroleum Services' refining business through a number of programs and provisions. The provisions include Maximum Achievable Control Technology rules, which are being developed for the refining industry, controls on individual chemical substances, new operating permit rules and new fuel specifications to reduce vehicle emissions. The provisions impact other companies in the industry in similar ways and are not expected to adversely impact Petroleum Services' competitive position. Petroleum Services and its subsidiaries also accrue environmental remediation costs for its refining and former retail petroleum operation primarily related to soil and groundwater contamination. In addition, Petroleum Services owns a discontinued petroleum refining facility that is being evaluated for potential remediation efforts. At December 31, 2002, Petroleum Services and its subsidiaries had accrued liabilities totaling approximately $9.6 million. We have indemnified the purchaser of the Memphis refinery for certain environmental matters. Petroleum Services is subject to various federal, state and local laws and regulations relating to environmental quality control. Management believes that Petroleum Services' operations are in substantial compliance with existing environmental legal requirements. Management expects that compliance with existing environmental legal requirements will not have a material adverse effect on the capital expenditures, earnings and competitive position of Petroleum Services. See Note 16 of our Notes to Consolidated Financial Statements for further details on legal and environmental matters. ENVIRONMENTAL MATTERS In addition to the environmental matters included in the business segment discussions above, a description of environmental claims is included in Note 16 of our Notes to Consolidated Financial Statements and is incorporated herein by reference. EMPLOYEES At March 14, 2003, we and our subsidiaries had approximately 7,300 full-time employees, of whom approximately 490 were represented by unions and covered by collective bargaining agreements. We expect further workforce reductions in 2003. Our employees are jointly employed by us and one of our subsidiaries. With the exception of the countrywide strike in Venezuela, we consider our relations with our employees to be generally good. FORWARD LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 Certain matters discussed in this annual report, excluding historical information, include forward-looking statements -- statements that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. 33 Forward-looking statements can be identified by words such as "anticipates," "believes," "could," "continues," "estimates," "expects," "forecasts," "might," "planned," "potential," "projects," "scheduled" or similar expressions. Although we believe 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 could cause future results to be materially different from the results stated or implied in this document. Events in 2002 significantly impacted the risk environment all businesses face and raised a level of uncertainty in the capital markets that has approached that which lead to the general market collapse of 1929. Beliefs and assumptions as to what constitutes appropriate levels of capitalization and fundamental value have changed abruptly. The collapse of Enron and the energy industry generally combined with the meltdown of the telecommunications industry are both new realities that have had and will likely continue to have specific impacts on all companies, including us. RISK FACTORS You should carefully consider the following risk factors in addition to the other information in this annual report. Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities. RISKS AFFECTING OUR STRATEGY AND FINANCING NEEDS OUR STRATEGY TO STRENGTHEN OUR BALANCE SHEET AND IMPROVE LIQUIDITY DEPENDS ON OUR ABILITY TO DIVEST SUCCESSFULLY CERTAIN ASSETS. On February 20, 2003, we announced our intention to sell an additional $2.25 billion in assets, properties and investments. At December 31, 2002, we had debt obligations of $3.8 billion (including certain contractual fees and deferred interest related to underlying debt) that will mature between now and March 2004. Because our cash flow from operations will be insufficient alone to repay all such debt and our access to capital markets is limited, in part as a result of the loss of our investment grade ratings, we will depend on our sales of assets to generate sufficient net cash proceeds to enable the payment of our maturing obligations. Our secured credit facilities limit our ability to sell certain assets and require generally that one-half of all net proceeds from asset sales be applied (a) to repayment of certain long-term debt, (b) to cash collateralization of designated letters of credit, and (c) to reduction of the lender commitments under the secured facilities. The timing of and the net cash proceeds realized from such sales are dependent on locating and successfully negotiating sales with prospective buyers, regulatory approvals, industry conditions, and lender consents. If the realized cash proceeds are insufficient or are materially delayed, we might not have sufficient funds on hand to pay maturing indebtedness or to implement our strategy. RECENT DEVELOPMENTS AFFECTING THE WHOLESALE POWER AND ENERGY TRADING INDUSTRY SECTOR HAVE REDUCED MARKET ACTIVITY AND LIQUIDITY AND MIGHT CONTINUE TO ADVERSELY AFFECT OUR RESULTS OF OPERATIONS. As a result of the 2000-2001 energy crisis in California, the resulting collapse in energy merchant credit, the recent volatility in natural gas prices, the Enron Corporation bankruptcy filing, and investigations by governmental authorities into energy trading activities and increased litigation related to such inquiries, companies generally in the regulated and so-called unregulated utility businesses have been adversely affected. These market factors have led to industry-wide downturns that have resulted in some companies being forced to exit from the energy trading markets, leading to a reduction in the number of trading partners and in market liquidity and announcements by us, other energy suppliers and gas pipeline companies of plans to sell large numbers of assets in order to boost liquidity and strengthen their balance sheets. Proposed and completed sales by other energy suppliers and gas pipeline companies could increase the supply of the type of assets we are attempting to sell and potentially lead either to our failing to execute such asset sales or our obtaining lower prices on completed asset sales. If either of these developments were to occur, our ability to realize our strategy of improving our liquidity and reducing our indebtedness through asset sales could be significantly hampered. 34 BECAUSE WE NO LONGER MAINTAIN INVESTMENT GRADE CREDIT RATINGS, OUR COUNTERPARTIES MIGHT REQUIRE US TO PROVIDE INCREASING AMOUNTS OF CREDIT SUPPORT WHICH WOULD RAISE OUR COST OF DOING BUSINESS. Our transactions in each of our businesses, especially in our Energy Marketing & Trading business, will require greater credit assurances, both to be given from, and received by, us to satisfy credit support requirements. Additionally, certain market disruptions or a further downgrade of our credit rating might further increase our cost of borrowing or further impair our ability to access one or any of the capital markets. Such disruptions could include: - further economic downturns; - capital market conditions generally; - market prices for electricity and natural gas; - terrorist attacks or threatened attacks on our facilities or those of other energy companies; or - the overall health of the energy industry, including the bankruptcy of energy companies. RISKS RELATED TO OUR BUSINESS ELECTRICITY, NATURAL GAS LIQUIDS AND GAS PRICES ARE VOLATILE AND THIS VOLATILITY COULD ADVERSELY AFFECT OUR FINANCIAL RESULTS, CASH FLOWS, ACCESS TO CAPITAL AND ABILITY TO MAINTAIN EXISTING BUSINESSES. Our revenues, operating results, profitability, future rate of growth and the carrying value of our electricity and gas businesses depend primarily upon the prices we receive for natural gas and other commodities. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Historically, the markets for these commodities have been volatile and they are likely to continue to be volatile. Wide fluctuations in prices might result from relatively minor changes in the supply of and demand for these commodities, market uncertainty and other factors that are beyond our control, including: - worldwide and domestic supplies of electricity natural gas petroleum, and relate commodities; - weather conditions; - the level of consumer demand; - the price and availability of alternative fuels; - the availability of pipeline capacity; - the price and level of foreign imports; - domestic and foreign governmental regulations and taxes; - the overall economic environment; and - the credit in the markets where products are bought and sold. These factors and the volatility of the energy markets make it extremely difficult to predict future electricity and gas price movements with any certainty. Further, electricity and gas prices do not necessarily move in tandem. WE MIGHT NOT BE ABLE TO SUCCESSFULLY MANAGE THE RISKS ASSOCIATED WITH SELLING AND MARKETING PRODUCTS IN THE WHOLESALE ENERGY MARKETS. Our trading portfolios consist of wholesale contracts to buy and sell commodities, including contracts for electricity, natural gas, natural gas liquids and other commodities that are settled by the delivery of the commodity or cash throughout the United States. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, we could realize material losses from our trading activities. In the past, certain marketing and trading companies have experienced severe financial problems 35 due to price volatility in the energy commodity markets. In certain instances this volatility has caused companies to be unable to deliver energy commodities that they had guaranteed under contract. In such event, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties. In addition, in our businesses, we often extend credit to our counterparties. Despite performing credit analysis prior to extending credit, we are exposed to the risk that we might not be able to collect amounts owed to us. If the counterparty to such a financing transaction fails to perform and any collateral we have secured is inadequate, we will lose money. If we are unable to perform under our energy agreements, we could be required to pay damages. These damages generally would be based on the difference between the market price to acquire replacement energy or energy services and the relevant contract price. Depending on price volatility in the wholesale energy markets, such damages could be significant. OUR RISK MEASUREMENT AND HEDGING ACTIVITIES MIGHT NOT PREVENT LOSSES. Although we have risk management systems in place that use various methodologies to quantify risk, these systems might not always be followed or might not always work as planned. Further, such risk measurement systems do not in themselves manage risk, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, and changes in interest rates might still adversely affect our earnings and cash flows and our balance sheet under applicable accounting rules, even if risks have been identified. To lower our financial exposure related to commodity price and market fluctuations, we have entered into contracts to hedge certain risks associated with our assets and operations, including our long-term tolling agreements. In these hedging activities, we have used fixed-price, forward, physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges, as well as long-term structured transactions when feasible. Substantial declines in market liquidity, however, as well as deterioration, of our credit, and termination of existing positions (due for example to credit concerns) have greatly limited our ability to hedge risks identified and have caused previously hedged positions to become unhedged. To the extent we have unhedged positions, fluctuating commodity prices could cause our net revenues and net income to be volatile. OUR OPERATING RESULTS MIGHT FLUCTUATE ON A SEASONAL AND QUARTERLY BASIS. Revenues from our businesses, including gas transmission and the sale of electric power, can have seasonal characteristics. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, demand for power peaks during the winter. In addition, demand for gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. The pattern of this fluctuation might change depending on the nature and location of our facilities and pipeline systems and the terms of our power sale agreements and gas transmission arrangements. OUR INVESTMENTS AND PROJECTS LOCATED OUTSIDE OF THE UNITED STATES EXPOSE US TO RISKS RELATED TO LAWS OF OTHER COUNTRIES, TAXES, ECONOMIC CONDITIONS, FLUCTUATIONS IN CURRENCY RATES, POLITICAL CONDITIONS AND POLICIES OF FOREIGN GOVERNMENTS. THESE RISKS MIGHT DELAY OR REDUCE OUR REALIZATION OF VALUE FROM OUR INTERNATIONAL PROJECTS. We currently own and might acquire and/or dispose of material energy-related investments and projects outside the United States. The economic and political conditions in certain countries where we have interests or in which we might explore development, acquisition or investment opportunities present risks of delays in construction and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States. The uncertainty of the legal environment in certain foreign countries in which we develop or acquire projects or make investments could make it more difficult to obtain non-recourse project or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations 36 with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments. Operations in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain conditions under which we develop or acquire projects, or make investments, economic and monetary conditions and other factors could affect our ability to convert our earnings denominated in foreign currencies. In addition, risk from fluctuations in currency exchange rates can arise when our foreign subsidiaries expend or borrow funds in one type of currency but receive revenue in another. In such cases, an adverse change in exchange rates can reduce our ability to meet expenses, including debt service obligations. Foreign currency risk can also arise when the revenues received by our foreign subsidiaries are not in U.S. dollars. In such cases, a strengthening of the U.S. dollar could reduce the amount of cash and income we receive from these foreign subsidiaries. While we believe we have hedges and contracts in place to mitigate our most significant foreign currency exchange risks, our hedges might not be sufficient or we might have some exposures that are not hedged which could result in losses or volatility in our revenues. RISKS RELATED TO LEGAL PROCEEDINGS AND GOVERNMENTAL INVESTIGATIONS WE MIGHT BE ADVERSELY AFFECTED BY GOVERNMENTAL INVESTIGATIONS AND ANY RELATED LEGAL PROCEEDINGS RELATED TO THE ALLEGED CONDUCTING OF "ROUNDTRIP" TRADES BY OUR ENERGY TRADING BUSINESS. Public and regulatory scrutiny of the energy industry and of the capital markets has resulted in increased regulation being either proposed or implemented. In particular, the activities of Enron Corporation and other energy traders in allegedly using "roundtrip" trades which involve the prearrangement of simultaneously executed and offsetting buy and sell trades for the purpose of increasing reported revenues or trading volumes, or influencing prices and which lack a legitimate business purpose, have resulted in increased public and regulatory scrutiny. To date, we have responded to requests for information from the FERC and the SEC, related to an investigation of "roundtrip" energy transactions from January 2000 to the present. We also have received and are responding to subpoenas and supplemental requests for information regarding gas and power trading activities from the Houston office of the U.S. Attorney relating to a Houston grand jury inquiry, which involve the same issues and time period covered by the SEC requests, and from the Commodity Futures Trading Commission (CFTC). Such inquiries are ongoing and continue to adversely affect the energy trading business as a whole. We might see these adverse effects continue as a result of the uncertainty of these ongoing inquiries or additional inquiries by other federal or state regulatory agencies. In addition, we cannot predict the outcome of any of these inquiries, including the grand jury inquiry, or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our trading business and our trading revenues and net income or increase our operating costs in other ways. WE MIGHT BE ADVERSELY AFFECTED BY GOVERNMENTAL INVESTIGATIONS RELATED TO PRICING INFORMATION THAT WE PROVIDED TO MARKET PUBLICATIONS. On October 25, 2002, we disclosed that inaccurate pricing information had been provided to energy industry trade publications. This disclosure came as a result of an internal review conducted in conjunction with requests for information made by the FERC and the CFTC on energy trading practices. We had separately commenced a review of our historical survey publication data after another market participant announced in September 2002 that certain of its employees had provided inaccurate pricing data to publications. Later we received a subpoena from a federal grand jury regarding the same matters. We cannot predict the outcome of this investigation or whether this investigation will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which MIGHT be materially adverse to the operation of our trading business and our trading revenues and net income or increase our operating costs in other ways. 37 WE MIGHT BE ADVERSELY AFFECTED BY OTHER LEGAL PROCEEDINGS AND GOVERNMENTAL INVESTIGATIONS RELATED TO THE ENERGY MARKETING AND TRADING BUSINESS. Electricity and natural gas markets in California and elsewhere will continue to be subject to numerous and far-reaching federal and state proceedings and investigations because of allegations that wholesale price increases resulted from the exercise of market power and collusion of the power generators and sellers such as Energy Marketing & Trading. Discussions by governmental authorities and representatives in California and other states have ranged from threats of re-regulation to suspension of plans to move forward towards deregulation. The outcomes of these proceedings and investigations might directly or indirectly affect our creditworthiness and ability to perform our contractual obligations as well as other market participants' creditworthiness and their ability to perform of their contractual obligations. RISKS RELATED TO THE REGULATION OF OUR BUSINESSES OUR BUSINESSES ARE SUBJECT TO COMPLEX GOVERNMENT REGULATIONS. THE OPERATION OF OUR BUSINESSES MIGHT BE ADVERSELY AFFECTED BY CHANGES IN THESE REGULATIONS OR IN THEIR INTERPRETATION OR IMPLEMENTATION. Existing regulations might be revised or reinterpreted, new laws and regulations might be adopted or become applicable to us or our facilities, and future changes in laws and regulations might have a detrimental effect on our business. Certain restructured markets have recently experienced supply problems and price volatility. These supply problems and volatility have been the subject of a significant amount of press coverage, much of which has been critical of the restructuring initiatives. In some of these markets, including California, proposals have been made by governmental agencies and other interested parties to re-regulate areas of these markets which have previously been deregulated. We cannot assure you that other proposals to re-regulate will not be made or that legislative or other attention to the electric power restructuring process will not cause the deregulation process to be delayed or reversed. If the current trend towards competitive restructuring of the wholesale and retail power markets is reversed, discontinued or delayed, our business models might be inaccurate and we might face difficulty in accessing capital to refinance our debt and funding for operating and generating revenues in accordance with our current business plans. For example, in 2000, the FERC issued Order 637, which sets forth revisions to its policies governing the regulation of interstate natural gas pipelines that it finds necessary to adjust its current regulatory model to the needs of evolving markets. The FERC, however, determined that any fundamental changes to its regulatory policy will be considered after further study and evaluation of the evolving marketplace. Order 637 revised the FERC's pricing policy to waive through September 30, 2002 the maximum price ceilings for short-term releases of capacity of less than one year and to permit pipelines to file proposals to implement seasonal rates for short-term services and term-differentiated rates. Certain parties requested rehearing of Order 637 and eventually appealed certain issues to the District of Columbia Circuit Court of Appeals. The D.C. Circuit remanded as to certain issues, and on October 31, 2002, the FERC issued its order on remand. Rehearing requests for that order are now pending with the FERC. Given the extent of the FERC's regulatory power, we cannot give any assurance regarding the likely regulations under which we will operate our natural gas transmission and storage business in the future or the effect of regulation on our financial position and results of operations. The FERC has proposed to broaden its regulations that restrict relations between our jurisdictional natural gas companies, or "jurisdictional companies," and our marketing affiliates. In addition, the proposed rules would limit communications between each of our jurisdictional companies and all of our other companies engaged in energy activities. The rulemaking is pending at the FERC and the precise scope and effect of the rule is unclear. If adopted as proposed, the rule could adversely affect our ability to coordinate and manage our energy activities. 38 OUR REVENUES MIGHT DECREASE IF WE ARE UNABLE TO GAIN ADEQUATE, RELIABLE AND AFFORDABLE ACCESS TO TRANSMISSION AND DISTRIBUTION ASSETS DUE TO THE FERC AND REGIONAL REGULATION OF WHOLESALE MARKET TRANSACTIONS FOR ELECTRICITY AND GAS. We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity and natural gas we buy and sell in the wholesale market. If transmission is disrupted, if capacity is inadequate, or if credit requirements or rates of such utilities or energy companies are increased, our ability to sell and deliver products might be hindered. The FERC has issued power transmission regulations that require wholesale electric transmission services to be offered on an open-access, non- discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, some companies have failed to provide fair and equal access to their transmission systems or have not provided sufficient transmission capacity to enable other companies to transmit electric power. We cannot predict whether and to what extent the industry will comply with these initiatives, or whether the regulations will fully accomplish the FERC'S objectives. In addition, the independent system operators who oversee the transmission systems in regional power markets, such as California, have in the past been authorized to impose, and might continue to impose, price limitations and other mechanisms to address volatility in the power markets. These types of price limitations and other mechanisms might adversely impact the profitability of our wholesale power marketing and trading. Given the extreme volatility and lack of meaningful long-term price history in many of these markets and the imposition of price limitations by regulators, independent system operators or other marker operators, we can offer no assurance that we will be able to operate profitably in all wholesale power markets. THE DIFFERENT REGIONAL POWER MARKETS IN WHICH WE COMPETE OR WILL COMPETE IN THE FUTURE HAVE CHANGING REGULATORY STRUCTURES, WHICH COULD AFFECT OUR GROWTH AND PERFORMANCE IN THESE REGIONS. Our results are likely to be affected by differences in the market and transmission regulatory structures in various regional power markets. Problems or delays that might arise in the formation and operation of new regional transmission organizations (RTOs) might restrict our ability to sell power produced by our generating capacity to certain markets if there is insufficient transmission capacity otherwise available. The rules governing the various regional power markets might also change from time to time which could affect our costs or revenues. Because it remains unclear which Companies will be participating in the various regional power markets, or how RTOs will develop or what regions they will cover, we are unable to assess fully the impact that these power markets might have on our business. Problems that might arise in the formation and operation of new RTOs might result in delayed or disputed collection of revenues. The rules governing the various regional power markets might also change from time to time which could affect our costs or revenues. Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will develop or what regions they will cover, we are unable to assess fully the impact that these power markets might have on our business. OUR GAS SALES, TRANSMISSION, AND STORAGE OPERATIONS ARE SUBJECT TO GOVERNMENT REGULATIONS AND RATE PROCEEDINGS THAT COULD HAVE AN ADVERSE IMPACT ON OUR ABILITY TO RECOVER THE COSTS OF OPERATING OUR PIPELINE FACILITIES. Our interstate gas sales, transmission, and storage operations conducted through our Gas Pipelines business are subject to the FERC's rules and regulations in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The FERC's regulatory authority extends to: - transportation and sale for resale of natural gas in interstate commerce; - rates and charges; - construction; - acquisition, extension or abandonment of services or facilities; - accounts and records; 39 - depreciation and amortization policies; and - operating terms and conditions of service. The FERC has taken certain actions to strengthen market forces in the natural gas pipeline industry that has led to increased competition throughout the industry. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on economic and other considerations. RISKS RELATED TO ENVIRONMENTAL MATTERS WE COULD INCUR MATERIAL LOSSES IF WE ARE HELD LIABLE FOR THE ENVIRONMENTAL CONDITION OF ANY OF OUR ASSETS. We are generally responsible for all on-site liabilities associated with the environmental condition of our facilities and assets, which we have acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In addition, in connection with certain acquisitions and sales of assets, we might obtain, or be required to provide, indemnification against certain environmental liabilities. If we incur a material liability, or the other party to a transaction fails to meet its indemnification obligations to us, we could suffer material losses. ENVIRONMENTAL REGULATION AND LIABILITY RELATING TO OUR BUSINESS WILL BE SUBJECT TO ENVIRONMENTAL LEGISLATION IN ALL JURISDICTIONS IN, WHICH IT OPERATES, AND ANY CHANGES IN SUCH LEGISLATION COULD NEGATIVELY AFFECT OUR RESULTS OF OPERATIONS. Our operations are subject to extensive environmental regulation pursuant to a variety of federal, provincial, state and municipal laws and regulations. Such environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Existing environmental regulations could also be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur. The federal government and several states recently have proposed increased environmental regulation of many industrial activities, including increased regulation of air quality, water quality and solid waste management. Compliance with environmental legislation will require significant expenditures, including expenditures for compliance with the Clean Air Act and similar legislation, for clean up costs and damages arising out of contaminated properties, and for failure to comply with environmental legislation and regulations which might result in the imposition of fines and penalties. The steps we take to bring certain of our facilities into compliance could be prohibitively expensive, and we might be required to shut down or alter the operation of those facilities, which might cause us to incur losses. Further, our regulatory rate structure and our contracts with clients might not necessarily allow us to recover capital costs we incur to comply with new environmental regulations. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for certain development projects. If there is a delay in obtaining any required environmental regulatory approvals or if we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs. Should we fail to comply with all applicable environmental laws, we might be subject to penalties and fines imposed against us by regulatory authorities. Although we do not expect that the costs of complying with current environmental legislation will have a material adverse effect on our financial condition or results of operations, no assurance can be made that the costs of complying with environmental legislation in the future will not have such an effect. 40 RISKS RELATING TO ACCOUNTING POLICY POTENTIAL CHANGES IN ACCOUNTING STANDARDS MIGHT CAUSE US TO REVISE OUR FINANCIAL DISCLOSURE IN THE FUTURE, WHICH MIGHT CHANGE THE WAY ANALYSTS MEASURE OUR BUSINESS OR FINANCIAL PERFORMANCE. Recently discovered accounting irregularities in various industries have forced regulators and legislators to take a renewed look at accounting practices, financial disclosures, companies' relationships with their independent auditors and retirement plan practices. Because it is still unclear what laws or regulations will develop, we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition, the Financial Accounting Standards Board (FASB) or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets and liabilities. For instance, Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations," which we will implement effective on January 1, 2003, requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate can be made. See Note 1 to our Consolidated Financial Statements for further details. In October 2002, the FASBs Emerging Issues Task Force (EITF) reached consensus on Issue No. 02-03 deliberations and rescinded Issue No. 98-10. As a result, all energy trading contracts that do not meet the definition of a derivative under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," will be reported on an accrual basis. We will initially apply the consensus effective January 1, 2003, and expect to record a reduction to net income of approximately $750 million to $800 million on an after-tax basis which will be reported as a cumulative effect of a change in accounting principle. The accounting for Energy Marketing & Trading's energy-related contracts, which include contracts such as transportation, storage, load serving and tolling agreements, requires us to assess whether certain of these contracts are executory service arrangements or leases pursuant to SFAS No. 13, "Accounting for Leases." On January 23, 2003, the EITF reached a tentative consensus on Issue No. 01-8, "Determining Whether an Arrangement Contains a Lease," and directed the Working Group consider this Issue to further address certain matters, including transition. The March 14, 2003 report of the Working Group indicates the Working Group will support a prospective transition of this Issue, where the consensus could be applied to our arrangements consummated or substantively modified after the date of the final consensus. Our preliminary review indicates that certain of our tolling agreements could be considered to be leases under the tentative consensus. Accordingly, if the EITF did not adopt a prospective transition and applied the consensus to existing arrangements there would be a significant negative impact to Williams' financial position and results of operations. Other future changes in accounting standards could lead to negative impacts on reported earnings or increases in liabilities, which in turn could affect our reported results of operations. RISKS RELATING TO OUR INDUSTRY THE LONG-TERM FINANCIAL CONDITION OF OUR U.S. AND CANADIAN NATURAL GAS TRANSMISSION AND MIDSTREAM BUSINESSES ARE DEPENDENT ON THE CONTINUED AVAILABILITY OF NATURAL GAS RESERVES. The development of additional natural gas reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline systems. Low prices for natural gas, regulatory limitations, or the lack of available capital for these projects could adversely affect the development of additional reserves and production, gathering, storage and pipeline transmission and import and export of natural gas supplies. Additional natural gas reserves might not be developed in commercial quantities and in sufficient amounts to fill the capacities of our gathering and processing pipeline facilities. 41 OUR GATHERING, PROCESSING AND TRANSPORTING ACTIVITIES INVOLVE NUMEROUS RISKS THAT MIGHT RESULT IN ACCIDENTS AND OTHER OPERATING RISKS AND COSTS. There are inherent in our gas gathering, processing and transporting properties a variety of hazards and operating risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. OTHER RISKS RECENT TERRORIST ACTIVITIES AND THE POTENTIAL FOR MILITARY AND OTHER ACTIONS COULD ADVERSELY AFFECT OUR BUSINESS. The continued threat of terrorism and the impact of retaliatory military and other action by the United States and its allies might lead to increased political, economic and financial market instability and volatility in prices for natural gas, which could affect the market for our gas operations. In addition, future acts of terrorism could be directed against companies operating in the United States, and it has been reported that terrorists might be targeting domestic energy facilities. While we are taking steps that we believe are appropriate to increase the security of our energy assets, there is no assurance that we can completely secure our assets or to completely protect them against a terrorist attack. These developments have subjected our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business. In particular, we might experience increased capital or operating costs to implement increased security for our energy assets. The insurance industry has also been disrupted by these events. As a result, the availability of insurance covering risks that we and our competitors typically insure against might decrease. In addition, the insurance that we are able to obtain might have higher deductibles, higher premiums and more restrictive policy terms. FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS See Note 19 of our Notes to Consolidated Financial Statements for amounts of revenues during the last two fiscal years from external customers attributable to the United States and all foreign countries. See Note 19 of our Notes to Consolidated Financial Statements for information relating to long-lived assets during the last three fiscal years, other than financial instruments, long-term customer relationships of a financial institution, mortgage and other servicing rights and deferred policy acquisition costs, located in the United States and all foreign countries. See Item 1 -- Forward Looking Statements/Risk Factors and Cautionary Statement for a description of the risks attendant to our foreign operations and any dependence on one or more of our segments upon such foreign operations. ITEM 3. LEGAL PROCEEDINGS For information regarding certain proceedings pending before federal regulatory agencies, see Note 16 of our Notes to Consolidated Financial Statements. We are also subject to other ordinary routine litigation incidental to our businesses. ENVIRONMENTAL MATTERS Since 1989, Texas Gas and Transco 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. Transco has responded to data requests regarding such potential contamination of certain of its sites. The costs 42 of any such remediation will depend upon the scope of the remediation. At December 31, 2002, these subsidiaries had accrued liabilities totaling approximately $31 million for these costs related to these sites. Certain of our subsidiaries, including Texas Gas and Transco 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, we do 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. Transco and Texas Gas have identified polychlorinated biphenyl contamination in compressor systems, soils and related properties at certain compressor station sites. Transco and Texas Gas have entered into consent orders with the EPA and state agencies to develop screening, sampling and cleanup programs. As of December 31, 2002, much of the work required by such consent orders had been completed. 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 Texas Gas and Transco. 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. In addition to our gas pipelines, we have also accrued environmental remediation costs for our 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 2002, an arbitrator determined that our subsidiary must pay $2.8 million in damages to the purchaser of certain marketing facilities. Settlement discussions with that purchaser have commenced. In addition, we own a discontinued petroleum refining facility that is being evaluated for potential remediation efforts. At December 31, 2002, Midstream Gas & Liquids and Petroleum Services had accrued liabilities totaling approximately $51 million for these cost. We accrue 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 December 31, 2002, we have accrued receivables totaling $1 million. In connection with the 1987 sale of the assets of Agrico Chemical Company, we 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 December 31, 2002, we had approximately $9 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. On July 2, 2001, the EPA issued an information request asking for information on oil releases and discharges in any amount from our 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, we furnished our response. In 2002, Williams Refining & Marketing, LLC (Williams Refining) submitted to the EPA a self-disclosure letter indicating noncompliance with the EPA's benzene waste "NESHAP" regulations. This unintentional noncompliance had occurred due to a regulatory interpretation that resulted in under-counting the total annual benzene level at the Memphis refinery. Also in 2002, the EPA conducted an all-media audit of the Memphis refinery. The EPA anticipates releasing a report of its audit findings in mid-2003. The EPA will likely assess a penalty on Williams Refining due to the benzene waste NESHAP issue, but the amount of any such penalty is not known. On March 4, 2003, we completed the sale of the Memphis refinery. We are obligated to indemnify the purchaser for any such penalty. In 2002, the Memphis/Selby County Health Department (MSCHD) assessed a $100,000 penalty on Williams Refining due to a four-day period in 2001 within which Williams Refining allegedly released excess emissions of sulfur dioxide. Negotiations with the MSCHD are ongoing. 43 In 2002, Williams Field Services Company (WFSC) submitted to the Oklahoma Department of Environmental Quality (ODEQ) with a WFSC gas processing facility's air permit. This unintentional noncompliance had occurred due to operational difficulties with the facility's flare. WFSC is in negotiations with ODEQ, and the amount of any penalty that ODEQ may assess to WFSC is not known. OTHER LEGAL MATTERS In connection with agreements to resolve take-or-pay and other contract claims and to amend gas purchase contracts, our subsidiaries Transco 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, Transco has been sued by certain producers seeking indemnification from Transco. Transco is currently defending two lawsuits in which producers have asserted damages, including interest calculated through December 31, 2002, of approximately $18 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 Transco 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 FERC Order 528. On June 8, 2001, 14 of our 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 14 Williams entities named as defendants. 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. On August 19, 2002, the defendants' motion to dismiss on non-jurisdictional grounds was denied. In the fourth quarter 2002, the plaintiffs moved for certification of a plaintiffs' class. The Williams entities joined with other defendants in contesting certification of the class. In 1998, the DOJ informed us 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 us and certain of our wholly-owned subsidiaries including Central, Kern River, Northwest Pipeline, WGP, Transco, Texas Gas, WFS and Williams Production Company. Mr. Grynberg has also filed claims against approximately 300 other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys' fees, and costs. On April 9, 1999, the DOJ announced that it was declining to intervene in any of the Grynberg qui tam cases, including the action filed against our 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 us, to the United States District Court for the District of Wyoming for pre-trial purposes. In October 2002, the court granted the United States' motion to dismiss Grynberg's royalty valuation claims. Grynberg's measurement claims are not affected by the dismissal. Between November 2000 and May 2001, class actions were filed on behalf of California electric ratepayers against California power generators and traders including Energy Marketing & Trading. These lawsuits concern the increase in power prices in California during the summer of 2000 through the winter of 2000-01. The suits claim that the defendants acted to manipulate prices in violation of the California antitrust and business practice 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 been consolidated before the San Diego County Superior Court. As part of a comprehensive settlement with the state of California and other parties, we and the plaintiffs in these suits have resolved these claims. While the settlement is final as to the state of California, it must still be approved by the San Diego Superior Court 44 as to the ratepayer plaintiffs. Numerous other federal investigations regarding California power prices are also underway that involve Energy Marketing & Trading. Since January 29, 2002, numerous shareholder class action suits have been filed in the United States District Court for the Northern District of Oklahoma. The majority of the suits allege that we and our co-defendants, Williams Communications and certain corporate officers and directors, 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. This case was filed against us, certain of our corporate officers, all members of our board of directors and all of the offerings' underwriters. In addition, in 2002 class action complaints were filed in the United States District Court for the Northern District of Oklahoma against us and the members of our board of directors under the Employee Retirement Income Security Act by participants in our 401(k) plan based on similar allegations. We and other defendants have filed motions to dismiss each of these suits. Oral argument on the motions will be held in April 2003. Our subsidiary Williams Alaska Petroleum (WAPI) is actively engaged in administrative litigation being conducted jointly by the FERC and the Regulatory Commission of Alaska concerning the Trans-Alaska Pipeline System (TAPS) Quality Bank. Primary issues being litigated include the appropriate valuation of the naphtha, heavy distillate, vacuum gas oil and residual product cuts within the TAPS Quality Bank as well as the appropriate retroactive effects of the determinations. WAPI's interest in these proceedings is material as the matter involves claims by crude producers and the State of Alaska for retroactive payments plus interest from WAPI in the range of $150 million to $200 million in aggregate. Because of the complexity of the issues involved, however, the outcome cannot be predicted within certainty nor can the likely result be quantified. SUMMARY While no assurances may be given, we, based on advice of counsel, do 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 our future financial position, results of operations or cash flow requirements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT The name, age, period of service, and title of each of the executive officers of Williams as of February 28, 2003, are listed below. ALAN S. ARMSTRONG.............. Senior Vice President, Midstream Gas & Liquids Age: 40 Position held since February 2002 From 1999 to February 2002, Mr. Armstrong was Vice President, Gathering and Processing for Midstream. From 1998 to 1999 he was Vice President, Commercial Development for Midstream Gas & Liquids. JAMES J. BENDER................ Senior Vice President and General Counsel Age 46 Position held since December 16, 2002 Prior to joining Williams, Mr. Bender was Senior Vice President and General Counsel with NRG Energy, Inc., a position held since June 2000, prior to which he had been Vice President, General Counsel and Secretary of NRG Energy Inc. since June 1997.
45 GARY R. BELITZ................. Acting Chief Financial Officer, Controller and Chief Accounting Officer Age: 53 Position Held since December 2002 Mr. Belitz was named Acting Chief Financial Officer on December 31, 2002. Prior to that, he has been Controller of the Company since January 1, 1992 and Chief Accounting Officer since May 1994. RALPH A. HILL.................. Senior Vice President, Exploration and Production Age: 43 Position held since December 1998 Mr. Hill was vice president of the exploration and productions unit from 1993 to 1998. WILLIAM E. HOBBS............... Senior Vice President, Energy Marketing & Trading Age: 43 Position held since October 2002 From February 2000 to October 2002, Mr. Hobbs was President and Chief Executive Officer of Williams Energy Marketing & Trading. From 1997 to February 2000, he served as a Vice President of various Williams subsidiaries. MICHAEL P. JOHNSON, SR......... Senior Vice President, Strategic Services and Administration Age: 55 Position held since April 1999 Mr. Johnson was named Senior Vice President of Human Resources and Administration for Williams in April 1999. Prior to joining Williams in December 1998, he held officer level positions, such as Vice President of Human Resources, Vice President for Corporate People Strategies, and Vice President Human Resource Services, for Amoco Corporation from 1991-1998. STEVEN J. MALCOLM.............. Chief Executive Officer and President of Williams Age: 54 Position held since September 21, 2001 Mr. Malcolm was elected Chief Executive Officer of Williams in January 2002 and Chairman of the Board in May 2002. He was elected President and Chief Operating Officer of Williams in September 2001. Prior to that, he was an Executive Vice President of Williams since May 2001, President and Chief Executive Officer of Williams Energy Services, LLC, a subsidiary of Williams, since December 1998 and the Senior Vice President and General Manager of Williams Field Services Company, a subsidiary of Williams, since November 1994. J. DOUGLAS WHISENANT........... Senior Vice President, Gas Pipeline Age: 56 Position held since October 2002 From December 2001 to October 2002, Mr. Whisenant was President of Williams Gas Pipeline, a subsidiary of the Company. Prior to that, he served as Senior Vice President and General Manager of Williams Gas Pipeline -- West from 1997 to December 2001. MARK D. WILSON................. Senior Vice President, Corporate Development & Planning Age: 36 Position held since October 2002 Mr. Wilson was Vice President of Corporate Development for Williams from December 2000 to October 2002. Prior to joining Williams, Mr. Wilson served as Senior Vice President -- Corporate Development for Koch Petroleum Group at Koch Industries from 1997 to 2000. From 1992 to 1997, he served as a management consultant to the energy industry at Arthur D. Little, Inc. and Booz-Allen & Hamilton, Inc. where he led teams in mergers and acquisitions, strategy development, change management and process improvement.
46 PHILLIP D. WRIGHT.............. Senior Vice President and Chief Restructuring Officer Age: 47 Position held since October 2002 From September 2001 to October 2002, Mr. Wright served as President and Chief Executive Officer of Williams Energy Services. From 1996 until September 2001, he was Senior Vice President, Enterprise Development and Planning for Williams' energy services group. Mr. Wright has held various positions within Williams since 1989.
PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Our common stock is listed on the New York Stock Exchange and Pacific Stock Exchanges under the symbol "WMB." At the close of business on March 14, 2003, we had approximately 14,590 holders of record of our common stock and approximately 175,000 beneficial owners that hold in street name. The high and low closing sales price ranges (composite transactions) and dividends declared by quarter for each of the past two years are as follows:
2002 2001 -------------------------- -------------------------- QUARTER HIGH LOW DIVIDEND HIGH LOW DIVIDEND ------- ------ ------ -------- ------ ------ -------- 1st.............................. $25.97 $14.53 $.20 $45.90 $34.56 $.15 2nd.............................. $24.17 $ 5.47 $.20 $43.55 $32.40 $.15 3rd.............................. $ 6.32 $ 0.88 $.01 $33.97 $24.99 $.18 4th.............................. $ 3.06 $ 1.35 $.01 $30.43 $22.10 $.20
Some of our subsidiaries' borrowing arrangements limit transfer of funds to us. These terms have not impeded, nor are they expected to impede, our ability to pay dividends. However, our secured credit facility currently prohibits us from paying cash dividends on common stock in excess of $6,250,000 per fiscal quarter. Preferred Stock Issuance: Securities: On March 7, 2002, we sold 1,466,667 shares of 9 7/8% Cumulative Convertible Preferred Stock (9 7/8% Preferred Stock), par value $1.00 per share. Purchaser: MEHC Investment, Inc. Consideration: $187.50 per share less fees of $2,750,000. Terms of conversion: Each share of 9 7/8% Preferred Stock may be converted at any time, at the option of the holder into the number of fully-paid and non- assessable shares of common stock obtained by dividing the Stated Value (originally $187.50 per share) by the Conversion Price then in effect (originally $18.75 per share). On or after March 27, 2017, we may, by giving notice to the holders of the 9 7/8% Preferred Stock, convert each share of 9 7/8% Preferred Stock held by such holder into the number of shares of common stock equal to the Stated Value plus all accrued and unpaid dividends to the date of conversion divided by the Conversion Price then in effect; provided that in order to be allowed to exercise this right to compel mandatory conversion, the average of the last reported closing prices for the common stock for the 20 day period ending not more than 10 days prior to the date of 47 the giving of the mandatory notice must be greater than 128% of the Conversion Price then in effect. Exemption from Registration Claimed: We claim exemption from registration under Section 4(2) of the Securities Act of 1933 as a private placement. 48 ITEM 6. SELECTED FINANCIAL DATA The following financial data as of December 31, 2002 and 2001 and for the three years ended December 31, 2002 are an integral part of, and should be read in conjunction with, the consolidated financial statements and notes thereto. All other amounts have been prepared from the Company's financial records. Certain amounts below have been restated or reclassified (see Note 1 of Notes to Consolidated Financial Statements in Item 8). Information concerning significant trends in the financial condition and results of operations is contained in Management's Discussion & Analysis of Financial Condition and Results of Operations of this report.
2002 2001 2000 1999 1998 --------- --------- --------- --------- --------- (MILLIONS, EXCEPT PER-SHARE AMOUNTS) Revenues.............................. $ 5,608.4 $ 7,065.5 $ 6,559.3 $ 4,811.7 $ 4,232.2 Income (loss) from continuing operations(1)....................... (501.5) 802.7 820.4 233.1 125.8 Income (loss) from discontinued operations(2)....................... (253.2) (1,280.4) (296.1) (76.9) 1.3 Extraordinary gain (loss)(3).......... -- -- -- 65.2 (4.8) Diluted earnings (loss) per common share: Income (loss) from continuing operations....................... (1.14) 1.61 1.83 .52 .28 Loss from discontinued operations... (.49) (2.56) (.66) (.17) -- Extraordinary gain (loss)........... -- -- -- .15 (.01) Total assets at December 31........... 34,988.5 38,614.2 34,776.6 21,682.1 17,900.2 Short-term notes payable and long-term debt due within one year............ 2,017.6 2,423.9 3,195.2 1,525.1 1,270.7 Long-term debt at December 31......... 11,896.4 8,692.7 6,504.3 6,438.5 5,690.2 Preferred interests in consolidated subsidiaries at December 31......... -- 976.4 877.9 335.1 335.1 Williams obligated mandatorily redeemable preferred securities of Trust at December 31................ -- -- 189.9 175.5 -- Stockholders' equity at December 31(4)............................... 5,049.0 6,044.0 5,892.0 5,585.2 4,257.4 Cash dividends per common share....... .42 .68 .60 .60 .60
--------------- (1) See Note 3 of Notes to Consolidated Financial Statements for discussion of write-downs of certain assets related to Williams Communications Group, Inc. (WCG) in 2002 and 2001 and see Note 4 of Notes to Consolidated Financial Statements for discussion of asset sales, impairments and other accruals in 2002, 2001 and 2000. (2) See Note 2 of Notes to Consolidated Financial Statements for the discussion of the 2002, 2001 and 2000 losses from discontinued operations. The income (loss) from discontinued operations for 1999 and 1998 relates to the operations of WCG, Kern River Gas Transmission, Williams Gas Pipelines Central, the Colorado soda ash mining operations, Mid-America and Seminole pipelines, retail travel centers, bio-energy operations and Midsouth refinery. (3) The extraordinary gain for 1999 relates to the sale of Williams' retail propane business, Thermogas L.L.C. The extraordinary loss for 1998 relates to redemption of higher interest rate debt. (4) Stockholders' equity for 2001 includes the January 2001 common stock issuance (see Note 13), the issuance of common stock for the Barrett acquisition and the impact to Williams of the WCG spinoff (see Note 2). Stockholders' equity for 1999 includes the issuance of WCG's common stock. 49 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW OF THE YEAR 2002 In 2002, Williams faced many challenges including credit and liquidity constraints following the deterioration of our energy industry sector in the wake of the Enron collapse and the assumption of payment obligations and performance on guarantees associated with its former telecommunications subsidiary, Williams Communications Group, Inc. (WCG). With the deterioration of the energy industry, the credit rating agencies' requirements for investment grade companies became more stringent. Williams' credit rating was lowered below an investment grade rating in the middle of 2002. During 2002 and more recently, Williams has sold a significant amount of assets and/or businesses and outlined plans to sell more assets to satisfy maturing debt obligations and strengthen its short-term liquidity position. In regards to the short-term, Williams, at December 31, 2002, has maturing notes payable and long-term debt totaling approximately $3.8 billion (which includes certain contractual fees and deferred interest associated with an underlying debt) through the first quarter of 2004. The following discussion outlines in more detail the events of 2002 through the filing of this Form 10-K and the challenges facing the company. During December 2001 and first-quarter 2002, Williams announced plans to strengthen its balance sheet and support retention of its investment grade ratings. The plans 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. Towards these plans and in satisfaction of continued liquidity demands, Williams completed debt issuances and sold one of its regulated interstate pipelines. In addition, the company completed a consent agreement on behalf of the WCG obligations that precluded immediate performance by Williams in the event of a bankruptcy filing by WCG. In addition, the plan included the elimination of certain "ratings triggers" that would give rise to options to put or accelerate debt or cause redemption of preferred interests. Exposure to these ratings triggers was removed by the third quarter of 2002. Williams also had exposure to ratings triggers through certain contracts of Energy Marketing & Trading which are discussed under Credit Ratings within Financial Condition and Liquidity. During the second quarter of 2002, Williams experienced liquidity constraints, 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 remained investment grade for the balance of the second quarter. Williams announced it was expanding the scope of its plan to preserve its investment grade ratings, which included its intentions to offer for sale its two refineries and related assets, further reduce capital expenditures, scale back the operations of its Energy Marketing & Trading business and reduce its work force accordingly. Williams experienced a substantial net loss for the second quarter of 2002. 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 reflecting a decline in fair value from the deteriorating energy merchant market conditions. Williams also recognized asset impairments and cost write-offs of certain of its assets, in large 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 per share to $.01 per share. In July 2002, the major rating agencies downgraded Williams' unsecured long-term debt credit ratings to below investment grade, reflecting the uncertainty associated with the trading business, short-term cash requirements facing Williams 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 and a subsidiary obtained two secured facilities totaling $1.3 billion, including a letter of credit facility for $400 million and a $900 million short-term loan (RMT note payable), and amended its existing revolving credit facility, which expires July 2005, to make it secured. These facilities include pledges of certain assets and contain financial ratios and other covenants that must be maintained (see 50 Note 11 of Notes to Consolidated Financial Statements). 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 from banks must be reduced based on proceeds of asset sales and minimum levels of required current and future liquidity were established. If such provisions of these facilities are not adhered to, then Williams' lenders can declare all amounts outstanding to be immediately due and payable. Also following the credit rating downgrade and in response to a potential liquidity shortfall, 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 and resulting in gains on sales of $443 million ($302 million of which is reflected in discontinued operations). These actions, combined with the RMT note payable noted previously, provided proceeds to meet notes payable maturities. Williams also sold certain liquified natural gas assets for approximately $229 million, its 27 percent ownership interest in a Lithuanian refinery, pipeline and terminal investment for $85 million and its $75 million note receivable from the Lithuanian investment for face value. These transactions closed in September. Additionally in 2002, Williams' board of directors had approved for sale the Central natural gas pipeline unit, the soda ash mining operations, the Memphis refinery, bio-energy operations and the travel centers. The sale of Central closed in November 2002. The sales of the travel centers for $190 million before debt repayments and the Memphis refinery for $455 million were completed in February and March 2003, respectively. The remaining assets are expected to be sold in the first half of 2003. Concurrent with Williams' strategy of selling assets to reduce debt, reviews for impairment were performed on assets that were being considered for possible sale, including an assessment of the more likely than not probabilities of sale for each asset. The impairment reviews are updated to incorporate new information obtained through the maturation of the assets sales process or closing of a sale. Impairments and losses totaling $814 million on completed transactions and certain assets held for sale, are reported in discontinued operations for 2002 and an additional $378 million of impairments or guarantee loss accruals are reported in continuing operations for 2002. These impairments reflected management's estimate of the fair value of these assets based on information available at the time of the respective reviews. OUTLOOK FOR 2003 On February 20, 2003, Williams outlined its planned business strategy for the next several years and believes it to be a comprehensive response to the events which have impacted the energy sector and Williams during 2002. The plan focuses on retaining a strong, but smaller, portfolio of natural-gas businesses and bolstering Williams' liquidity through more asset sales, limited levels of financing at the subsidiary level and additional reductions in its operating costs. The plan is designed to provide Williams with a clear strategy to address near-term and medium-term liquidity issues and further de-leverage the company with the objective of returning to investment grade status by 2005, while retaining businesses with favorable returns and opportunities for growth in the future. As part of this plan, Williams expects to generate proceeds, net of related debt, of nearly $4 billion from asset sales during 2003, including approximately $2.25 billion in newly announced offerings combined with those assets already under contract or in negotiations for sale. Newly announced offerings include the Texas Gas pipeline system, Williams' investment in Williams Energy Partners, and certain properties and assets within Exploration & Production and Midstream Gas & Liquids. The specific assets and the timing of such sales are dependent on various factors, including negotiations with prospective buyers, regulatory approvals, industry conditions, lender consents to sales of collateral and the short- and long-term liquidity requirements of Williams. While management believes it has considered all relevant information in assessing for potential impairments, the ultimate sales price for assets that may be sold and the final decisions in the future may result in additional impairments or losses and/or gains. FACTORS AFFECTING WILLIAMS' BUSINESS During 2002, the operating results of Energy Marketing & Trading were adversely affected by several factors, including Williams' overall liquidity and credit ratings which impacted Energy Marketing & Trading's ability to enter into price risk management and hedging activities. The credit rating downgrades in 2002 also triggered certain Energy Marketing & Trading contractual provisions that require Williams to provide counterparties with adequate assurance, margin, credit enhancement, or credit replacement. See the Liquidity 51 section for further discussion of what amounts Williams and Energy Marketing & Trading have provided. During the later half of 2002, several companies in the energy trading sector announced that they are either reducing commitments to, or exiting altogether, the energy trading business. These market conditions plus the unwillingness of existing counterparties and new entrants to the sector to enter into new business with Energy Marketing & Trading will continue to affect results in the future and could result in additional operating losses. Additionally, on October 25, 2002, the Emerging Issues Task Force (EITF) concluded in Issue No. 02-3, "Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities," to rescind Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," under which non-derivative energy trading contracts were previously marked-to-market. As a result, a substantial portion of the Energy Marketing & Trading activities previously required to be reported on a fair value basis must now be reflected under the accrual method of accounting beginning January 1, 2003 (see Note 1). Williams continues its efforts to reduce the risk and liquidity impact of Energy Marketing & Trading on Williams. Part of these efforts includes the announced sale of certain portions of its trading portfolio, liquidation of certain trading positions and negotiations with parties for a joint venture or sale of all or a large portion of the trading portfolio. It is possible that Williams, in order to generate levels of liquidity that are needed in the future, would be willing to accept amounts for all or a portion or its entire portfolio that are less than its carrying value at December 31, 2002. Although the results of these negotiations could reduce the presence of the trading business, Energy Marketing & Trading will continue to be operated to meet the commitments of its remaining short- and long-term contracts. At December 31, 2002, Williams has maturing notes payable and long-term debt totaling approximately $3.8 billion (which includes certain contractual fees and deferred interest associated with an underlying debt) through the first quarter of 2004. The Company's available liquidity to meet these requirements and fund a reduced level of capital expenditures will be dependent on several factors, including the cash flows of retained businesses, the amount of proceeds raised from the sale of assets previously mentioned 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 and available secured credit facilities, Williams currently believes that it has the financial resources and liquidity to meet future cash requirements through the first quarter of 2004. In the event that Williams' financial condition does not improve or becomes worse, or if it fails to complete asset sales and reduce its commitment to its Energy Marketing & Trading business, Williams may have to consider other options including the possibility of seeking protection in a bankruptcy proceeding. GENERAL As a result of assets sales approved or closed during 2002 and in accordance with the provisions related to discontinued operations within Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the following components have been reported as discontinued operations (see Note 2): - Kern River Gas Transmission (Kern River), previously one of Gas Pipeline's segments - Central natural gas pipeline, previously one of Gas Pipeline's segments - Colorado soda ash mining operations, part of the previously reported International segment - Two natural gas liquids pipeline systems, Mid-American Pipeline and Seminole Pipeline, previously part of the Midstream Gas & Liquids segment - Refining and marketing operations in the Midsouth, including the Midsouth refinery, previously part of the Petroleum Services segment - Retail travel centers concentrated in the Midsouth, previously part of the Petroleum Services segment - Bio-energy operations, previously part of the Petroleum Services segment 52 On March 30, 2001, the board of directors of Williams approved a tax-free spinoff of Williams' communications business, WCG, to Williams' shareholders. On April 23, 2001, Williams distributed 398.5 million shares, or approximately 95 percent of the WCG common stock held by Williams, to holders of record of Williams common stock. As a result, the consolidated financial statements reflect WCG as discontinued operations. 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 within Item 8. All prior period information has been restated to reflect these changes. CRITICAL ACCOUNTING POLICIES & ESTIMATES Our financial statements reflect the selection and application of accounting policies which require management to make significant estimates and assumptions. The selection of these has been discussed with the company's Audit Committee and the Audit Committee has reviewed the disclosures that follow. We believe that the following are some of the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations. Revenue Recognition -- Gas Pipeline Most of Gas Pipeline's businesses are regulated by the Federal Energy Regulatory Commission (FERC). The FERC regulatory processes and procedures govern the tariff rates that the Gas Pipeline subsidiaries are permitted to charge customers for natural gas sales and services, including the interstate transportation and storage of natural gas. Accordingly, certain revenues are collected by Gas Pipeline which may be subject to refunds upon final orders in rate cases with the FERC. In recording estimates of refund obligations, Gas Pipeline takes into consideration Gas Pipeline's and other third-parties' regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks. At December 31, 2002, approximately $9 million was recorded as subject to refund, reflecting management's estimate of amounts invoiced to customers that may ultimately require refunding. This balance is associated entirely with one of Williams' gas pipelines as there are no significant rate proceedings currently pending for the other pipelines. During 2002, rate refund liability accruals were reduced by $87 million as a result of settlements of regulatory proceedings including amounts refunded to customers. From time to time, certain of the Gas Pipeline subsidiaries are involved in rate case proceedings. Depending on the results of these proceedings, the actual amounts allowed to be collected from customers could differ from management's estimate. Revenue Recognition -- Energy risk management and trading operations Energy Marketing & Trading and the natural gas liquids trading operations (reported within the Midstream Gas & Liquids segment) have energy risk management and trading operations that enter into energy and energy-related contracts to trade with and provide price-risk management services to its customers. Energy and energy-related contracts utilized in energy risk management and trading activities are recorded at fair value with the net change in fair value of those contracts representing unrealized gains and losses recognized in income currently (marked-to-market). The fair value of energy and energy-related contracts is determined based on the nature of the transaction and the market in which transactions are executed. Certain contracts are executed in exchange traded or over-the-counter markets where quoted prices in active markets may exist. Transactions are also executed in exchange-traded or over-the-counter markets for which market prices may exist, however, the market may be relatively inactive and price transparency is limited. Hence, the ability to determine the fair value of the contract would be more subjective than if an independent third party quote were available. Transactions are also executed for which quoted market prices are not available. Determining fair value for certain contracts involves complex assumptions and judgments when estimating prices at which market participants would transact if a market existed for the contract or transaction. 53 On October 25, 2002, the (EITF) concluded in Issue No. 02-3 to rescind Issue No. 98-10, under which non-derivative energy trading contracts were previously marked-to-market. A substantial portion of the energy marketing and trading activities previously reported on a fair-value basis will now be reflected under the accrual method of accounting beginning January 1, 2003. In addition, trading inventories will also no longer be marked to market but will be reported on a lower of cost or market basis. Upon adoption of this new standard on January 1, 2003, Energy Marketing & Trading and the natural gas liquids trading operations (reported within the Midstream Gas & Liquids segment) will record a charge as a cumulative effect of change in accounting principle. The impact of this change in accounting principle is expected to result in a decrease to net income of approximately $750 million to $800 million in total on an after-tax basis for both business units. For further discussion on this issue, please refer to Note 1 of Notes to Consolidated Financial Statements. Accounting for Energy Marketing & Trading's energy-related contracts, which include contracts such as transportation, storage, load serving, and tolling agreements, requires Williams to assess whether certain of these contracts are executory service agreements or leases pursuant to SFAS No. 13, "Accounting for Leases." On January 23, 2003, the EITF reached a tentative consensus on Issue No. 01-8, "Determining Whether an Arrangement Contains a Lease," and directed the Working Group it had formed to consider this issue to further address certain matters, including transition. The March 14, 2003 report of the Working Group indicates the Working Group supports a prospective transition of this Issue, where the consensus would be applied to arrangements consummated or substantively modified after the date of the final consensus. Williams' preliminary review indicates that certain of its tolling agreements could be considered to be leases under the tentative consensus. Accordingly, if the EITF did not adopt a prospective transition and applied the consensus to existing arrangements there could be a significant impact to Williams' financial position and results of operations. As a result of Williams' current liquidity constraints, Energy Marketing & Trading initiated efforts in 2002 to sell all or portions of its portfolio and/or pursue potential joint venture or business combination opportunities. No assurances can be made regarding the ultimate consummation of any sales or business combination activities currently being pursued. Energy Marketing & Trading is continuing to evaluate its potential alternatives. As discussed further in Note 1 of Notes to Consolidated Financial Statements, portions of Energy Marketing & Trading's portfolio have been recognized at their estimated fair value, which per generally accepted accounting principles is the amount at which they could be exchanged in a current transaction between willing parties other than in a forced liquidation or sale. Given the financial condition and liquidity constraints of Williams, however, amounts ultimately realized in any portfolio sales or business combination may be significantly different than fair value estimates presented in the financial statements. Additional discussion of the accounting for energy and energy-related contracts at fair value is included in Note 1 of Notes to Consolidated Financial Statements and Fair Value of Energy risk management and trading activities. Valuation of Deferred Tax Assets Williams is required to assess the ultimate realization of deferred tax assets generated from the basis difference in certain investments and businesses. This assessment takes into consideration tax planning strategies, including assumptions regarding the availability and character of future taxable income. At December 31, 2002, Williams maintains $43.2 million of valuation allowances for deferred tax assets from basis differences in investments and capital loss carry forward generated during the year for which the ultimate realization of the tax asset may be dependent on the availability of future capital gains. In arriving at this conclusion, management considered forecasts of future company performance, particularly the estimated impact of potential asset dispositions. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by potential changes in federal income laws and the circumstances upon the actual realization of related tax assets. 54 Impairment of Long-Lived Assets and Goodwill Williams evaluates the long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. In addition to those long-lived assets for which impairment charges were recorded (see Notes 2 and 4), numerous others were reviewed for which no impairment was required under a "held for use" computation, pursuant to Williams' announced strategy of selling assets as a source of funds to meet debt obligations and provide liquidity. These computations utilized judgments and assumptions inherent in management's estimate of undiscounted future cash flows and "hold for use" versus sale probabilities to determine recoverability of an asset. Pursuant to Williams' announced strategy during 2002 of selling significant levels of assets, numerous assets were considered more likely than not to be sold substantially in advance of their established recovery periods. To facilitate the actual sales, a reserve price auction process was employed for many of the assets. This type of process is one in which initial bids are received by interested parties, followed by submission of revised bids, with the company eventually selecting a single party in which to finalize a sale transaction. Under terms of the process, Williams is not obligated to accept an offer that it does not deem satisfactory. As a result, both the estimated fair value of an asset and management's assessment of the probability of sale often change through the course of the process. At December 31, 2002, certain assets are in various stages of sale negotiations. With respect to the most significant of these, a ten percent decrease in estimated fair value would result in additional impairment charges of approximately $80 million, while a ten percent increase in fair value would result in a decrease of impairment charges of approximately $70 million. It is possible that a computation under a "held for sale" situation for certain of these long-lived assets could result in a significantly different assessment because of market conditions, specific transaction terms and a buyer's different viewpoint of future cash flows. Goodwill is evaluated annually for impairment. Approximately $1 billion of Williams' goodwill is carried by Exploration & Production for which the estimated fair value of the reporting unit exceeds its carrying value, including goodwill, by over 75 percent. Contingent Liabilities Williams records liabilities for estimated loss contingencies when it is management's assessment that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon management's assumptions and estimates, advice of legal counsel or other third parties regarding the probable outcomes of the matter. Should the outcome differ from the assumptions and estimates, revisions to the estimated liabilities for contingent losses would be required. See Note 16 of Notes to Consolidated Financial Statements. 55 RESULTS OF OPERATIONS CONSOLIDATED OVERVIEW The following table and discussion is a summary of Williams' consolidated results of operations for the three years ended December 31, 2002. The results of operations by segment are discussed in further detail following this Consolidated Overview discussion.
YEARS ENDED DECEMBER 31, -------------------------------- 2002 2001 2000 --------- --------- -------- (MILLIONS) Revenues............................................. $ 5,608.4 $ 7,065.5 $6,559.3 ========= ========= ======== Operating income..................................... $ 790.8 $ 2,317.7 $1,936.8 Interest accrued -- net.............................. (1,200.5) (682.2) (606.9) Investing income (loss).............................. (109.7) (168.6) 89.1 Interest rate swap loss.............................. (124.2) -- -- Minority interest in income and preferred returns of consolidated subsidiaries.......................... (79.3) (80.7) (56.8) Other income (expense) -- net........................ 26.4 26.1 (.3) --------- --------- -------- Income (loss) from continuing operations before income taxes....................................... (696.5) 1,412.3 1,361.9 (Provision) benefit for income taxes................. 195.0 (609.6) (541.5) --------- --------- -------- Income (loss) from continuing operations............. (501.5) 802.7 820.4 Loss from discontinued operations.................... (253.2) (1,280.4) (296.1) --------- --------- -------- Net income (loss).................................... (754.7) (477.7) 524.3 Preferred stock dividends............................ 90.1 -- -- --------- --------- -------- Income (loss) applicable to common stock............. $ (844.8) $ (477.7) $ 524.3 ========= ========= ========
2002 vs. 2001 CONSOLIDATED OVERVIEW. Williams' revenue decreased $1,457.1 million, or 21 percent, due primarily to lower revenues associated with energy risk management and trading activities at Energy Marketing & Trading and the absence of $184 million of revenue related to the 198 convenience stores sold in May 2001 within Petroleum Services. Partially offsetting these decreases was the impact of an increase in net production volumes within Exploration & Production partly due to the August 2001 acquisition of Barrett Resources Corporation (Barrett). Costs and operating expenses decreased $193.1 million, or 5 percent, due primarily to the absence of the 198 convenience stores sold in May 2001 and lower fuel and product shrink gas purchases related to processing activities at Midstream Gas & Liquids. Slightly offsetting these decreases are increased depletion, depreciation and amortization and lease operating expenses at Exploration & Production due primarily to the addition of the former Barrett operations. Selling, general and administrative expenses decreased $69.1 million due primarily to lower variable compensation levels at Energy Marketing & Trading. Selling, general and administrative expenses for 2002 also include approximately $22 million of early retirement costs, $10 million of employee-related severance costs and approximately $6 million related to early payoff of employee stock ownership plan expenses. Other (income) expense -- net in 2002, that is part of operating income, includes $244.6 million of impairment charges and loss accruals within Energy Marketing & Trading comprised of $138.8 million of impairments and loss accruals for commitments for certain power assets associated with terminated power projects, $61.1 million goodwill impairments and a $44.7 million impairment charge related to the Worthington generation facility sold in January 2003. Also included in other (income) expense -- net in 2002 are 56 $115 million of impairment charges related to Midstream Gas & Liquids' Canadian assets and $18.4 million of impairment charges within Petroleum Services related to the Alaska refinery and convenience store assets. Partially offsetting these impairment charges and accruals are $141.7 million of net gains on sales of natural gas production properties at Exploration & Production in 2002. Other (income) expense -- net in 2001 includes a $75.3 million gain on the May 2001 sale of the convenience stores and impairment charges of $13.8 million and $12.1 million within Midstream Gas & Liquids and Petroleum Services, respectively (see Note 4). General corporate expenses increased $18.5 million, or 15 percent, due primarily to approximately $15 million of costs related to consulting services and legal fees associated with the liquidity and business issues addressed beginning third-quarter 2002, $6 million of expense related to the enhanced-benefit early retirement program offered to certain employee groups and $6 million of expense related to employee severance costs. Partially offsetting these increases were lower charitable contributions and advertising costs. Operating income decreased $1,526.9 million, or 66 percent, due primarily to lower net revenues associated with energy risk management and trading activities at Energy Marketing & Trading and the impairment charges and loss accruals noted above. Partially offsetting these decreases are the gains from the sales of natural gas production properties and the impact of increased net production volumes at Exploration & Production, higher demand revenues and the effect of the reductions in rate refund liabilities associated with rate case settlements at Gas Pipeline, higher natural gas liquids margins at Midstream Gas & Liquids and higher equity earnings. Interest accrued -- net increased $518.3 million, or 76 percent, due primarily to $154 million related to interest expense, including amortization of fees, on the RMT note payable (see Note 11), the $58 million effect of higher average interest rates, the $247 million effect of higher average borrowing levels and $56 million of higher debt issuance cost amortization expense. In 2002, Williams entered into interest rate swaps with external counter parties primarily in support of the energy trading portfolio. The swaps resulted in losses of $124.2 million (see Note 19). The 2002 investing loss decreased $66.9 million as compared to the 2001 investing loss. Investing loss for 2002 and 2001 consisted of the following components:
YEARS ENDED DECEMBER 31 ----------------- 2002 2001 ------- ------- (MILLIONS) Equity earnings (loss)*..................................... $ 72.0 $ 22.7 Income (loss) from investments*............................. 42.1 4.2 Write-down of WCG common stock investment................... -- (95.9) Loss provision for WCG receivables.......................... (268.7) (188.0) Interest income and other................................... 44.9 88.4 ------- ------- Investing loss.............................................. $(109.7) $(168.6) ======= =======
--------------- * These items are also included in the measure of segment profit (loss). The equity earnings increase includes a $27.4 million benefit reflecting a contractual construction completion fee received by an equity method investment of Williams (see Note 3) and $4 million of earnings in 2002 versus $20 million of losses in 2001 from the Discovery pipeline project, partially offset by an equity loss in 2002 of $13.8 million from Williams' investment in Longhorn Partners Pipeline LP. Income (loss) from investments in 2002 includes a $58.5 million gain on the sale of Williams' equity interest in a Lithuanian oil refinery, pipeline and terminal complex, which was included in the Other segment, a gain of $8.7 million related to the sale of Williams' general partner interest in Northern Borders Partners, L.P., a $12.3 million write-down of an investment in a pipeline project which was canceled and a $10.4 million net loss on the sale of Williams' equity interest in a Canadian and U.S. gas pipeline. Income (loss) from investments in 2001 57 includes a $27.5 million gain on the sale of Williams' limited partner equity interest in Northern Border Partners, L.P. offset by a $23.3 million loss from other investments, both which were determined to be other than temporary. See Note 2 for a discussion of the losses related to WCG. Interest income and other decreased due to a $22 million decrease in interest income related to margin deposits, a $4.9 million decrease in dividend income primarily as a result of the second-quarter 2001 sale of Ferrell gas Partners L.P. senior common units and write-downs of certain foreign investments. Other income (expense) -- net below operating income increased $.3 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, a $14 million decrease in losses from the sales of receivables to special purpose entities (see Note 15) and the absence in 2002 of a 2001 $10 million payment to settle a claim for coal royalty payments relating to a discontinued activity. Partially offsetting these increases was an $8 million loss related to early retirement of remarketable notes in first-quarter 2002. The provision (benefit) for income taxes was favorable by $804.6 million due primarily to a pre-tax loss in 2002 as compared to pre-tax income in 2001. The effective income tax rate for 2002 is greater than the federal statutory rate due primarily to the effect of taxes on foreign operations, non-deductible impairment of goodwill and income tax credits recapture that reduced the tax benefit of the pre-tax loss, somewhat offset by the reduction in valuation allowances. The effective income tax rate for 2001 is greater than the federal statutory rate due primarily to valuation allowances associated with the tax benefits for investing losses, for which no tax benefits were provided and the effect of state income taxes. In addition to the operating results from activities included in discontinued operations (see Note 2), the 2002 loss from discontinued operations includes pre-tax impairments and losses totaling $814.3. million. The $814.3 million consists of $240.8 million of impairments related to the Memphis refinery, $195.7 million of impairments related to bio-energy, $146.6 million of impairments related to travel centers, $133.5 million of impairments related to the soda ash operations, $91.3 million loss on sale related to the Central natural gas pipeline system and a $6.4 million loss on sale related to the Kern River natural gas pipeline system. Partially offsetting these impairments and losses was a pre-tax gain of $301.7 million related to the sale of the Mid- America and Seminole pipelines. Loss from discontinued operations in 2001 includes a $1.84 billion pre-tax charge for loss accruals related to guarantees and payment obligations for WCG and $184.7 million of other pre-tax charges for impairments and loss accruals including a $170 million pre-tax impairment charge related to the soda ash mining facility. 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 weighted-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 6) increased approximately 16 million from December 31, 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 earnings (loss) per share in 2002 of approximately $.05 per share. 2001 vs. 2000 Consolidated Overview. Williams' revenues increased $506.2 million, or 8 percent, due primarily to higher gas and electric power trading and services margins, a full year of Canadian operations within Midstream Gas & Liquids acquired in fourth-quarter 2000, higher natural gas sales prices and revenues from Barrett acquired in third-quarter 2001. Partially offsetting these increases was a decrease of $283 million in revenues related to the 198 convenience stores sold in May 2001, $116 million decrease in domestic natural gas liquids revenues and the effect in 2000 of a $69 million reduction of Gas Pipeline's rate refund liabilities. Total segment costs and expenses increased $98.2 million, or 2 percent, due primarily to costs for a full year of Canadian operations acquired in fourth-quarter 2000 and operating costs associated with Barrett acquired in third-quarter 2001. These increases were partially offset by a $286 million decrease in costs as a result of the sale of 198 convenience stores in May 2001 and the $75.3 million gain on the sale of these convenience stores. 58 Operating income increased $380.9 million, or 20 percent, due primarily to higher gas and electric power service margins, the $75.3 million pre-tax gain on the sale of the convenience stores in May 2001, increased realized natural gas sales prices, the impact of Barrett and the effect in 2000 of $63.8 million in guarantee loss accruals and impairment charges at Energy Marketing & Trading. Partially offsetting these increases were lower per-unit natural gas liquids margins at Midstream Gas & Liquids, the $69 million effect in 2000 of reductions to rate refund liabilities and approximately $26 million of impairment charges and loss accruals within Midstream Gas & Liquids and Petroleum Services. Included in operating income are general corporate expenses which increased $27.1 million, or 28 percent, due primarily to an increase in advertising costs (which includes a branding campaign of $12 million) and higher charitable contributions. Interest accrued -- net increased $75.3 million, or 12 percent, due primarily to the $71 million effect of higher borrowing levels offset by the $42 million effect of lower average interest rates, $19 million in interest expense related to an unfavorable court decision involving Transcontinental Gas Pipe Line (Transco), a $14 million increase in interest expense related to deposits received from customers relating to energy risk management and trading and hedging activities and a $12 million increase in amortization of debt expense. The increase in long-term debt includes the $1.1 billion of senior unsecured debt securities issued in January 2001 and $1.5 billion of long-term debt securities issued in August 2001 related to the cash portion of the Barrett acquisition. Investing income decreased $257.7 million, due primarily to fourth-quarter 2001 charges for a $103 million provision for doubtful accounts related to the minimum lease payments receivable from WCG, an $85 million provision for doubtful accounts related to a $106 million deferred payment for services provided to WCG and a $25 million write-down of the remaining investment basis in WCG common stock (see Note 2). In addition, the decrease also reflects a $94.2 million charge in third-quarter 2001, representing declines in the value of certain investments, including $70.9 million related to Williams' investment in WCG and $23.3 million related to losses from other investments, which were deemed to be other than temporary (see Note 3). In addition, the decrease in investing income reflects a $13 million decrease in dividend income due to the sale of the Ferrellgas Partners L.P. (Ferrellgas) senior common units in second-quarter 2001. The decreases to investing income (loss) were slightly offset by increased interest income related to margin deposits of $17 million. Minority interest in income and preferred returns of consolidated subsidiaries increased $23.9 million, or 42 percent, due primarily to preferred returns of Snow Goose LLC, formed in December 2000, and minority interest in income of Williams Energy Partners L.P., partially offset by a $10 million decrease of preferred returns related to the second-quarter 2001 redemption of Williams obligated mandatorily redeemable preferred securities of Trust. Other income (expense) -- net increased $26.4 million to $26.1 million of income in 2001 due primarily to an $11 million increase in capitalization of interest on internally generated funds related to various capital projects at certain FERC regulated entities and $6 million lower losses from the sales of receivables to special purpose entities (see Note 15). The provision for income taxes increased $68.1 million primarily due to higher pre-tax income and increase in valuation allowance. The effective income tax rate for 2001 is greater than the federal statutory rate due primarily to valuation allowances associated with the investing losses, for which no tax benefits were provided plus the effects of state income taxes. The effective income tax rate for 2000 is greater than the federal statutory rate due primarily to the effects of state income taxes. In addition to the operating results from the activities included in discontinued operations (see Note 2), the loss from discontinued operations for 2001 includes a $1.84 billion pre-tax charge for loss accruals for contingent obligations related to guarantees and payment obligations for WCG, $184.7 million of other pre-tax charges for impairments and loss accruals including a $170 million pre-tax impairment charge related to the soda ash mining facility. Loss from discontinued operations in 2000 primarily represents the operating results of the operations. 59 RESULTS OF OPERATIONS -- SEGMENTS Williams is currently organized into the following segments: Energy Marketing & Trading, Gas Pipeline, Exploration & Production, Midstream Gas & Liquids, Williams Energy Partners and Petroleum Services. Certain activities previously reported within the International segment have been included in Other. Williams currently evaluates performance based upon segment profit (loss) from operations (see Note 19). In addition to the impact to the segments as a result of discontinued operations previously discussed, the following changes occurred in 2002: - 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. - On April 11, 2002, Williams Energy Partners L.P., a partially owned and consolidated entity of Williams, acquired Williams Pipe Line, an operation previously included 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. - Management of an investment in an Argentine oil and gas exploration company was transferred from the previously reported 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
YEARS ENDED DECEMBER 31, ----------------------------- 2002 2001 2000 ------- -------- -------- (MILLIONS) Segment revenues....................................... $ (85.2) $1,705.6 $1,295.1 Segment profit (loss).................................. $(624.8) $1,270.0 $ 970.6
2002 vs. 2001 ENERGY MARKETING & TRADING'S revenues decreased $1,790.8 million, or 105 percent, due primarily to a $1,783.3 million decrease in risk management and trading revenues. During 2002, Energy Marketing & Trading's results were adversely affected by the impact of market movements against its portfolio as discussed below and a significant reduction in 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 Williams' limited ability to provide credit and liquidity support. The $1,783.3 million decrease in risk management and trading revenues is due primarily to a decrease of $1,901.4 million in the natural gas and power revenues partially offset by a $6.3 million increase in the petroleum products revenues, a $12 million increase in European trading revenues, and a $99.8 million increase in revenues from the net impact of interest rate movements including the impact of interest derivatives. The $1,783.3 million decrease in the risk management and trading revenues includes a $205 million decrease in revenues from new transactions originated and contract amendments as compared to 2001. Of the $1,901.4 million decline in natural gas and power revenues, $454.9 million is attributable to a decline in natural gas revenues, caused primarily by increasing prices on short natural gas positions during the third quarter of 2002. The remaining $1,446.5 million decline relates to lower revenues from the power portfolio caused primarily by smaller spark spreads on certain power tolling portfolios and lower volatility (the fair value of Energy Marketing & Trading's tolling agreements are adversely affected by declines in power and gas volatility) compared with 2001 as well as the net impact of portfolio valuation adjustments associated with the decline in market liquidity and portfolio liquidation activities. The $6.3 million increase in petroleum 60 products revenues is primarily due to origination activities during the first quarter of 2002. The $12 million increase in European trading revenues is principally due to the commencement of trading activities in the European office as compared to start-up activities in 2001. The European operations have now been reduced and are in the process of being wound down. As a result of Williams' current liquidity constraints, Energy Marketing & Trading initiated efforts in 2002 to sell all or portions of its portfolio and/or pursue potential joint venture or business combination opportunities. No assurances can be made regarding the ultimate consummation of any sales or business combination activities currently being pursued. Energy Marketing & Trading is continuing to pursue its potential alternatives. As discussed further in Note 1 of the Notes to Consolidated Financial Statements, portions of Energy Marketing & Trading's portfolio have been recognized at their estimated fair value, which under generally accepted accounting principles is the amount at which they could be exchanged in a current transaction between willing parties other than in a forced liquidation or sale. As a result of information obtained through the portfolio sales efforts in 2002, the estimated fair value of certain portions of the portfolio were adjusted to reflect viable market information received. For those portions of the portfolio for which no viable market information was received through sales efforts, fair value has been estimated using other market-based information and consistent application of valuation techniques. Portfolio valuation adjustments recognized in 2002 as a result of new market information obtained through sales efforts resulted in a $74.8 million decrease in operating profit. Given the financial condition and liquidity constraints of Williams which may accelerate sales, amounts ultimately realized in any portfolio sales or business combination may be significantly different than fair value estimates presented in the financial statements, depending on the timing and terms of any such transactions. Revenues for 2002 also includes a favorable fourth-quarter net effect of approximately $85 million resulting from a settlement with the state of California, the restructuring of associated energy contracts, and the related improved credit situation of the counterparties during the quarter. Energy Marketing & Trading's future results will be affected by the reduction in liquidity and credit support available from its parent, the willingness of counterparties to enter into transactions with Energy Marketing & Trading, the liquidity of markets in which Energy Marketing & Trading transacts, and the creditworthiness of other counterparties in the industry and their ability to perform under contractual obligations. Since Williams is not currently rated investment grade by credit rating agencies, Williams is required, in certain instances, to provide additional adequate assurances in the form of cash or credit support to enter into and maintain existing transactions. With the decision to continue to limit Williams' financial commitment and exposure to the trading business, it is likely that Energy Marketing & Trading will have greater exposure to market movements, which could result in 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 and default assessment related to the future value of its forward positions and the ability of such counterparties to perform under contractual obligations. The ultimate outcome of these items could result in significant future operating losses for Energy Marketing & Trading or limit Energy Marketing & Trading's ability to achieve profitable operations. Selling, general, and administrative expenses decreased by $124.7 million, or 37 percent. This cost reduction is primarily due to lower variable compensation levels associated with reduced segment profit and the impact of staff reductions in this segment. Other (income) expense -- net in 2002 includes $138.8 million of impairments and loss accruals associated with commitments for certain power projects that have been terminated, partial impairment of goodwill totaling $61.1 million, reflecting a decline in fair value resulting from deteriorating market conditions during 2002 and a $44.7 million impairment charge related to the January 2003 sale of the Worthington generation facility. Other (income) expense -- net in 2001 included $13.3 million due to a terminated expansion project. Segment profit (loss) decreased $1,894.8 million, or 149 percent, due primarily to the $1,783.3 million reduction of risk management and trading revenues and the other (income) expense -- net items discussed previously, partially offset by the $124.7 million reduction in selling, general and administrative expenses, 61 discussed above, and the $23.3 million charge from the write-downs in 2001 of marketable equity securities and a cost based investment (see Note 3). On October 25, 2002, the EITF concluded in Issue No. 02-3 to rescind Issue No. 98-10, under which non-derivative energy trading contracts were marked-to-market. A substantial portion of the energy marketing and trading activities previously reported on a fair-value basis will now be reflected under the accrual method of accounting beginning January 1, 2003. Certain of the trading activities utilizing derivative instruments will continue to be reported on a fair value basis to the extent that these instruments are not designated as hedges under SFAS No. 133. The related changes in fair value will be reported as unrealized gains or losses in the consolidated income statement. In addition, trading inventories will no longer be marked-to-market but will be reported on a lower of cost or market basis. Upon adoption of this new standard on January 1, 2003, Energy Marketing & Trading will record a charge as a cumulative effect of change in accounting principle. Energy Marketing & Trading's portion of the impact of this change in accounting principle is expected to be a decrease to net income of approximately $750 million to $800 million on an after-tax basis. For further discussion on this issue, please refer to Note 1 of Notes to Consolidated Financial Statements. Contingent liabilities and commitments that could affect the results of Energy Marketing & Trading, including a recent settlement between the FERC and Transcontinental Gas Pipe Line, Energy Marketing & Trading and Williams are discussed in Note 16 of the Notes to Consolidated Financial Statements. 2001 vs. 2000 Energy Marketing & Trading's revenues increased by $410.5 million, or 32 percent in 2001, due primarily to a $402.3 million increase in risk management and trading revenues. The $402.3 million increase in risk management and trading revenues results primarily from an increase in risk management activities surrounding Energy Marketing & Trading's power tolling portfolio. As further discussed in Note 15 of the Notes to Consolidated Financial Statements, power tolling agreements provide Energy Marketing & Trading the right, but not the obligation, to call on the counterparty to convert natural gas to electricity at a predefined heat conversion rate. Energy Marketing & Trading benefited from higher natural gas and electric power services margins through the first quarter of 2001 from power tolling agreements previously recognized in 2000. Energy Marketing & Trading, through its origination of new contracts, executed several offsetting positions throughout the year to mitigate declines in these margins that occurred subsequent to the first quarter 2001. These new contracts consisted of full requirements, load serving and power supply agreements and typically have terms of up to 15 years. Execution of these contracts had the effect of reducing the risk of future changes in natural gas and power prices within the portfolio and also provided further insight into the prices for which third parties would be willing to exchange in illiquid periods. This additional insight provided better information for the valuation of other existing contracts which generally had the effect of increasing the value recognized on these existing contracts. Subsequent to the execution of these origination transactions, natural gas and power prices declined dramatically. As a result of Energy Marketing & Trading's management strategies, this reduction had minimal impact to the overall portfolio fair value. Also contributing to the increase in the risk management and trading revenues during 2001 was an increase in successful forward natural gas financial trading. Through a variety of energy commodity and derivative contracts, Energy Marketing & Trading had credit exposure to Enron and certain of its subsidiaries which have sought protection from creditors under Chapter 11 of the U.S. Bankruptcy Code. During fourth-quarter 2001, Energy Marketing & Trading recorded a reduction in trading revenues of approximately $130 million through the valuation of contracts with Enron. Approximately $91 million of this reduction in value was recorded pursuant to events immediately preceding and following Enron's announced bankruptcy. At December 31, 2001, Williams had reduced its exposure to accounts receivable from Enron, net of margin deposits, to expected recoverable amounts. In 2002, Energy Marketing & Trading sold rights to certain Enron receivables to a third party in exchange for $24.5 million cash. That amount was recorded as trading revenues in the first quarter of 2002. Selling, general, and administrative expenses increased by $134.7 million, or 68 percent. This cost increase was primarily due to $42.5 million higher variable compensation levels associated with improved 62 operating performance, $19 million of costs related to the European trading and marketing office in London which began operation in 2001, $13 million of increased charitable contributions to state universities, as well as increased outside services costs and increased costs as a result of higher staffing levels. Other (income) expense -- net in 2001 includes a $13.3 million impairment charge due to a terminated expansion project. In 2000, other (income) expense -- net included $47.5 million in guarantee loss accruals and impairment charges and $16.3 million impairment of assets related to a distributed generation business. Segment profit increased $299.4 million, or 31 percent, due primarily to the $402.3 million higher trading revenues discussed above and the effect of the $63.8 million of guarantee loss accruals and impairment charges in 2000 noted above. Partially offsetting the increase to segment profit was the $134.7 million increase in selling, general and administrative costs, as discussed above, $23.3 million of write-downs in 2001 of marketable equity securities and a cost based investment and the $13.3 million impairment in 2001 noted above. Potential Impact of California Power Regulation and Litigation At December 31, 2002, Energy Marketing & Trading had net accounts receivable recorded of approximately $230 million compared to $388 million at December 31, 2001, for power sales to the California Independent System Operator and the California Power Exchange Corporation (CPEC). In March and April of 2001, two California power-related entities, the CPEC and Pacific Gas and Electric Company (PG&E), filed for bankruptcy under Chapter 11. 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 16 of Notes to Consolidated Financial Statements, the FERC and the DOJ have issued orders or initiated actions that relate to the activities of Energy Marketing & Trading in California and the western states. 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 experienced in 2000 and 2001 resulted from the exercise of market power and collusion of the power generators and sellers, including Energy Marketing & Trading. These allegations have resulted in multiple state and federal investigations as well as the filing of class-action lawsuits in which Energy Marketing & Trading is a named defendant. Energy Marketing & Trading's 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, Energy Marketing & Trading and Williams executed a settlement agreement on November 11, 2002, that is intended to resolve many of these disputes with the State of California and that includes renegotiated long-term energy contracts. The settlement is also intended to resolve complaints brought by the California Attorney General against Energy Marketing & Trading and the State of California's refund claims. In addition, the settlement is intended to resolve ongoing investigations by the States of California, Oregon, and Washington. The settlement is subject to various court and agency approvals (see Other legal matters in Note 16). There can be no assurance that these initiatives, investigations and proceedings will not have a material adverse effect on Williams' results of operations or financial condition. GAS PIPELINE
YEARS ENDED DECEMBER 31, ------------------------------ 2002 2001 2000 -------- -------- -------- (MILLIONS) Segment revenues....................................... $1,503.8 $1,426.0 $1,567.0 Segment profit......................................... $ 661.3 $ 571.7 $ 597.3
During 2002, Williams sold both its Central and Kern River interstate natural gas pipeline businesses. The following discussions exclude any gains or losses on such sales and the results of operations related to 63 these businesses which are reported within discontinued operations. The following discussions relate to the current continuing businesses of the Gas Pipeline segment which include Transco, Texas Gas Transmission (Texas Gas), Northwest Pipeline and various joint venture projects. On February 20, 2003, Williams announced its intention to sell Texas Gas. Segment revenues of Texas Gas were $266.4 million, $249.9 million and $260.9 million in 2002, 2001 and 2000, respectively. Segment profit of Texas Gas was $116.2 million, $99.6 million and $103.2 million for 2002, 2001 and 2000, respectively. 2002 vs. 2001 GAS PIPELINE'S revenues increased $77.8 million, or 5 percent, due primarily to $67 million higher demand revenues on the Transco system resulting from new expansion projects and new settlement rates effective September 1, 2001, the effect of $19 million in reductions in the rate refund liabilities associated with rate case settlements on the Transco and Texas Gas systems, $16 million higher transportation revenues on the Texas Gas and Northwest Pipeline systems, $9 million from environmental mitigation credit sales and services and $4 million higher revenues associated with tracked costs which are passed through to customers and offset in general and administrative expenses. Partially offsetting these increases were $23 million lower gas exchange imbalance settlements (offset in costs and operating expenses), $14 million lower storage revenues and $7 million lower revenues associated with the recovery of tracked costs which are passed through to customers (offset in costs and operating expenses). The decrease in storage revenues is due primarily to $9 million lower rates on Cove Point's short-term storage contracts (the Cove Point facility was sold in September 2002) and a $6 million decrease at Transco due primarily to lower storage demand revenues. Costs and operating expenses decreased $33 million, or 5 percent, due primarily to $23 million lower gas exchange imbalance settlements (offset in revenues), $22 million lower operations and maintenance expense due primarily to lower professional and other contractual services and telecommunications expenses, $7 million lower other tracked costs which are passed through to customers (offset in revenues) and a $5 million franchise tax refund for Transco. These decreases were partially offset by 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 $5 million higher depreciation expense. The $5 million higher depreciation expense reflects a $13 million increase due to increased property, plant and equipment placed into service (including depletion of property held for the environmental mitigation credit sales), partially offset by an $8 million adjustment related to the 2002 rate case settlements resulting in lower depreciation rates applied retrospectively. General and administrative costs increased $22 million, or 11 percent, due primarily to $14 million higher employee-related benefits expense, including $8 million related to higher pension and retiree medical expense due to decreases in assumed return on plan assets and approximately $4 million related to expense recognized as a result of accelerated company contributions to an employee stock ownership plan, $11 million in costs associated with an early retirement program, a $5 million write-off in 2002 of capitalized software development cost resulting from cancellation of a project and $4 million higher tracked costs (offset in revenues). These increases were partially offset by $13 million lower charitable contributions in 2002. Other (income) expense -- net in 2002 includes a $17 million charge associated with a FERC penalty (see Note 16) and a $3.7 million loss on the sale of the Cove Point facility. Other (income) expense -- net in 2001 includes an $18 million charge resulting from the unfavorable court decision and resulting settlement in one of Transco's royalty claims proceedings (an additional $19 million is included in interest expense). Segment profit, which includes equity earnings and income (loss) from investments (both included in investing income), increased $89.6 million, or 16 percent, due primarily to the higher demand revenues discussed above, the $27 million effect of rate refund liability reductions and other adjustments related to the finalization of rate cases during third-quarter 2002, $42.1 million higher equity earnings, the lower costs and operating expenses discussed above, the effect of the $18 million charge in 2001 discussed previously in other (income) expense -- net and an $8.7 million gain in 2002 on the sale of the general partnership interest in Northern Border Partners, L.P. These increases were partially offset by a $10.4 million loss on the sale of Gas Pipeline's 14.6 percent ownership interest in Alliance Pipeline, a $12.3 million write-down in 2002 of Gas 64 Pipeline's investment in a pipeline project that has been cancelled, the effect of a $27.5 million gain in 2001 from the sale of the limited partnership interest in Northern Border Partners, L.P., the $22 million increase in general and administrative costs discussed above, the $17 million FERC penalty and the $3.7 million loss on the sale of the Cove Point facility. The increase in equity earnings includes a $27.4 million benefit in 2002 related to the 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 reflects an $18 million increase from Gulfstream, $12 million of which is related to interest capitalized on the Gulfstream pipeline project in accordance with FERC regulations. 2001 vs. 2000 Gas Pipeline's revenues decreased $141 million, or 9 percent, due primarily to the effect of a $69 million reduction of rate refund liabilities in 2000 following the settlement of prior rate proceedings, $72 million lower gas exchange imbalance settlements (offset in costs and operating expenses), $10 million lower recovery of tracked costs which are passed through to customers (offset in general and administrative expenses), and $10 million lower transportation revenues at Texas Gas due primarily to turnback capacity remarketed at discounted rates and for shorter contracted terms. Partially offsetting these decreases were $13 million higher gas transportation demand revenues as a result of new expansion projects and new rates on the Transco system and $9 million higher revenues from a liquefied natural gas storage facility acquired in June 2000. Costs and operating expenses decreased $79 million, or 10 percent, due primarily to the $72 million lower gas exchange imbalance settlements (offset in revenues), $15 million resulting from the FERC's approval for recovery of fuel costs incurred in prior periods by Transco, and $6 million of accruals for gas exchange imbalances in 2000. Partially offsetting these decreases was $16 million in higher depreciation expense due to increased property, plant & equipment placed into service during 2001. General and administrative costs decreased $16 million resulting primarily from lower tracked costs which are passed through to customers (offset in revenues), partially offset by higher charitable contributions. Other (income) expense -- net in 2001 within segment costs and expenses includes an $18 million charge resulting from an unfavorable court decision in one of Transco's royalty claims proceedings (an additional $19 million is included in interest expense). Segment profit decreased $25.6 million due primarily to the lower revenues discussed previously and the item discussed previously in other (income) expense -- net. These decreases were partially offset by the lower costs and operating expenses discussed above, a $19 million increase in equity investment earnings from pipeline joint venture projects, a $27.5 million gain from the sale of Williams' limited partnership interest in Northern Border Partners, L.P. and the lower general and administrative expenses. The increase in equity investment earnings reflects $13 million from new projects which are primarily comprised of interest capitalized on internally generated funds as allowed by the FERC and a $6 million increase from earnings on existing projects. 65 EXPLORATION & PRODUCTION
YEARS ENDED DECEMBER 31, ------------------------ 2002 2001 2000 ------ ------ ------ (MILLIONS) Segment revenues........................................... $899.9 $615.2 $331.0 Segment profit............................................. $520.5 $234.1 $ 87.6
On February 20, 2003, Williams announced additional assets to be sold including Exploration & Production properties. Depending on the nature and size of the sales, future operating results could be impacted significantly. 2002 vs. 2001 EXPLORATION & PRODUCTION'S revenues increased $284.7 million, or 46 percent, due primarily to $284 million higher domestic production revenues, $27 million in unrealized gains from the mark-to-market financial instruments related to basis differentials on natural gas production, partially offset by $28 million lower domestic gas management revenues. The $284 million increase in domestic production revenues includes $254 million associated with an increase in net domestic production volumes as well as $30 million from increased 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 the former Barrett operations. Approximately 83 percent of domestic production in 2002 was hedged. Exploration & Production has entered into contracts that hedge approximately 85 percent of projected 2003 domestic natural gas production before consideration of any potential property sales in 2003. These hedges are entered into 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 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. During the third quarter of 2002, Energy Marketing & Trading had additional contracts not related to Enron that were terminated. The other comprehensive income related to these terminated contracts remains in accumulated other comprehensive income and is recognized as the underlying volumes are produced. During 2002, approximately $35 million related to the terminated contracts was recognized as revenues while $45 million remains in accumulated other comprehensive income at December 31, 2002. Domestic 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 non-producing 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. Costs and operating expenses, including selling, general and administrative expenses, increased $131 million, due primarily to increased depreciation, depletion and amortization, lease operating expenses and selling, general and administrative expenses due primarily to the addition of the former Barrett operations. The increases were partially offset by decreased gas management purchase costs. Other (income) expense-net in 2002 includes $120.3 million and $21.4 million in gains from the sales of substantially all of the interests in natural gas production properties in the Jonah field (Wyoming) and in the Anadarko Basin, respectively. The Jonah field properties represented approximately 11 percent of total reserves at December 31, 2001, the absence of which could impact future revenue levels. Segment profit increased $286.4 million due primarily to the gains from asset sales mentioned above, increased production volumes, and higher net realized average prices. Segment profit also includes $11.8 million and $15.4 million related to international activities for 2002 and 2001, respectively. 66 2001 vs. 2000 Exploration & Production's revenues increased $284.2 million, or 86 percent, due primarily to $263 million higher domestic production revenues including $119 million from increased net realized prices for production (including the effect of hedge positions) and $144 million associated with an increase in net volumes from domestic production. Approximately $115 million of the $144 million increase relates to volumes associated with Barrett, which became a consolidated entity on August 2, 2001. Approximately 75 percent of domestic production in 2001 was hedged. Revenues from domestic gas management activities increased $14 million. Segment costs and operating expenses increased $141 million, including a $24 million increase in selling, general and administrative expense. Segment costs and operating expenses increased due primarily to costs related to Barrett operations, comprised primarily of depreciation, depletion and amortization, lease operating expenses and gas management costs. In addition to the increase as a result of the Barrett acquisition, the higher segment costs and operating expenses reflect $10 million higher domestic lease operating expenses, $8 million higher domestic depreciation, depletion and amortization expenses and $6 million higher domestic production-related taxes. Other income (expense) -- net in 2000 includes a $6 million impairment charge for certain gas producing properties. The charge represented the impairment of these held for sale assets to fair value based on expected net proceeds. These properties were sold in March 2001. Segment profit increased $146.5 million, or 167 percent, due primarily to the higher domestic production revenues in excess of costs. A major portion of this increase can be attributed to the Barrett acquisition. In addition, segment profit included $9 million in equity earnings from the 50 percent investment in Barrett held by Williams for the period from June 11, 2001 through August 2, 2001, partially offset by $6 million lower equity earnings from an Argentina oil and gas investment. MIDSTREAM GAS & LIQUIDS
YEARS ENDED DECEMBER 31, ------------------------------ 2002 2001 2000 -------- -------- -------- (MILLIONS) Segment revenues....................................... $1,909.1 $1,906.8 $1,574.3 Segment profit......................................... $ 189.3 $ 171.9 $ 278.0
In August 2002, Williams completed the sale of 98 percent of Mapletree LLC and 98 percent of E-Oaktree, LLC to Enterprise Products Partners L.P. Mapletree owned all of Mid-America Pipeline, a 7,226-mile natural gas liquids pipeline system. E-Oaktree owned 80 percent of the Seminole Pipeline, a 1,281-mile natural gas liquids pipeline system. The gains on the sale of these businesses and the related results of operations have been reported as discontinued operations. Williams has also announced the intended sale of additional assets, including certain operations in Canada. Future asset sales would have the effect of lowering liquid product sales in periods following their sale but are expected to be offset by increasing deepwater or gathering and transportation revenue. The following discussion reflects the results of Midstream Gas & Liquids' continuing operations. 2002 vs 2001 MIDSTREAM GAS & LIQUIDS revenues increased $2.3 million as a result of a $60.3 million increase in domestic gathering, processing, transportation and liquid product sales revenues, a $48.7 million increase in Venezuelan revenues and a $10.3 million increase in Canadian revenues, offset by a $117 million decline in domestic petrochemical and trading revenues. The $60.3 million increase in domestic gathering, processing, transportation and liquid product sales revenues was driven by a $34 million increase in liquid sales, a $39 million increase in liquid product sales from Gulf Liquids, (a new off gas processing and olefin extraction facility that became a consolidated subsidiary in September 2002) and a $10 million increase in transportation revenues. Partially offsetting these increases is a $17 million decrease in gathering revenues primarily due to the third quarter 2002 sale of the 67 Kansas-Hugoton gathering system. The increase in liquid sales reflects a $67 million increase in gulf coast liquid sales resulting from higher production at existing processing facilities and the September 2001 completion of a new processing facility that processes natural gas gathered from deepwater projects off the coast of Texas. Offsetting the increase in gulf coast liquid sales was a $33 million decline in liquid sales in the west, primarily caused by a decline in average liquid sales prices. The $10 million increase in transportation revenues reflects the results of a new deepwater oil and gas transportation system which was completely operational by mid-year. The $117 million decline in petrochemicals and trading revenues is due largely to a change in the reporting during September 2001 of certain petrochemical and liquid product trading transactions from a gross revenue basis to a net revenue basis combined with lower natural gas liquid trading margins. The $48.7 million increase in Venezuelan revenues reflects a full year of results from a new gas compression facility that began operations in August 2001. The increase in Canadian revenues results from a $56 million increase in natural gas liquids product sales from fractionation activities reflecting a 48 percent increase in volumes. The increase in volumes sold was partially offset by a 19 percent decline in average liquid product sales prices. The increase in volumes resulted from improvements made at a parafins facility and higher volumes of natural gas liquid supply from processing facilities within Northern Alberta and British Columbia. The increase in Canadian revenues is partially offset by a $24 million decrease in processing revenues reflecting lower processing rates under cost of service agreements as a result of lower natural gas shrink prices combined with a $24 million decrease in liquid sales from processing activities which reflects lower average liquid sales prices. Costs and operating expenses decreased $112 million, or 7 percent, primarily reflecting a decline in fuel and product shrink costs at the Wyoming and Canadian processing facilities of $21 million and $85 million ($41 million from costs under cost of service processing agreements), respectively. These decreases reflect lower average natural gas prices in Canada and Wyoming, offset by higher volumes and prices in the gulf coast. The lower average gas prices in Wyoming during 2002 reflect a favorable differential between gas prices in Wyoming and the gulf as a result of limited transportation capacity from Wyoming to other markets. This favorable basis differential had the effect of lower shrink costs and increasing liquid sales margins from Wyoming processing plants and is not expected to continue once take away transportation capacity within this region has been expanded. Costs and operating expenses also reflect a $92 million decline in petrochemical and trading costs resulting from the change in reporting certain product trading classifications in September 2001, as discussed above. Partially offsetting these decreases are $32 million of higher product shrink costs at Gulf Liquids operations, $30 million higher depreciation costs from the addition of Gulf Liquids and other new facilities combined with $14 million higher transportation, fractionation, and marketing costs. Operations and maintenance expenses were relatively unchanged on a segment basis, with a $32 million decline in costs in the west primarily resulting from lower maintenance spending, offset by a corresponding increase in the gulf, Canada and Venezuela largely driven by the higher maintenance costs resulting from the new Venezuelan gas compression facility, Canadian olefins facility, the Gulf Liquids facilities and new deepwater offshore operations. Selling, general and administrative costs increased $10 million primarily due to the consolidation of Gulf Liquids during 2002. Other (income) expense -- net within segment costs and expense for 2002 includes a $115 million impairment associated with the Canadian processing, extraction and olefin extraction assets (see Note 4) and a $6 million impairment associated with the sale of the Kansas Hugoton gathering system in the third quarter. Reflected in 2001 are $13.8 million of impairment charges related to certain south Texas non-regulated gathering and processing assets. Segment profit of $189.3 million for 2002 was largely impacted by a $115 million impairment on Canadian natural gas processing, extraction and olefin extraction assets during the fourth quarter. Before this impairment charge, Midstream Gas & Liquids' 2002 segment profit reflects a $132 million increase over 2001. 68 This increase reflects a $70 million increase in domestic operations, a $20 million increase in Venezuelan operations and a $42 million increase in Canadian operations. Domestic segment profit reflects a $45 million increase in liquid sales margins resulting from the low fuel and shrink costs in the west reflecting the wide basis differential for natural gas prices in Wyoming. Domestic segment profit also increased $32 million due to income from equity investments primarily related to significant improvements in the operations of Discovery pipeline following new supply connections that resulted in higher transportation and liquid volumes. Domestic segment profit was also impacted by a $16 million increase in profits from an increase in deepwater operations, offset by $25 million in losses resulting from operational issues associated with Gulf Liquids. The increase in segment profit from Canadian operations (excluding the $115 million impairment discussed above) resulted from a $23 million increase in liquid product margins from fractionation activities due to higher liquid sales volumes and prices combined with a $37 million increase in liquid sales margins from processing activities primarily resulting from lower shrink costs. Offsetting these increases are higher depreciation, and operations and maintenance expense primarily resulting from the new olefins fractionation facility. Segment profit from Venezuelan operations reflects an increase resulting from a full year of results following the completion of a new gas compression facility in August 2001. Midstream Gas & Liquids Venezuelan assets were constructed and are currently operated for the exclusive benefit of Petroleos de Venezuela S.A. (PDVSA), the state owned Petroleum Corporation of Venezuela. During December 2002 and January 2003, a countrywide strike took place within Venezuela that resulted in significant political instability and a volatile economic environment. Employees of PDVSA joined this strike, which had an impact on the operations of most of the Venezuelan facilities. All owned facilities are presently operating. However, an operating agreement for the PDVSA owned oil terminaling facility is the subject of a contract dispute with PDVSA. The ultimate impact the political and economic situation within Venezuela will have on Midstream Gas and Liquids' revenues, segment profits and operating cash flows will depend upon the extent and duration of the political and economic instability and the enforceability of certain contractual arrangements provisions with PDVSA. 2001 vs. 2000 Midstream Gas & Liquids' revenues increased $332.5 million, or 21 percent, due primarily to $564 million in revenues for the first three quarters of 2001 from Canadian operations that were acquired in October 2000. The $564 million of increased revenues from Canadian operations consists primarily of $270 million of natural gas liquids sales from processing activities, $205 million of natural gas liquids sales from fractionation activities, and $81 million of processing revenues. Canadian revenues decreased $57 million for the comparable periods of 2001 and 2000 due primarily to natural gas liquids product sales price decline. Revenues were $32 million higher due to a new Venezuelan gas compression facility which began operations in August 2001. Revenues from domestic natural gas liquids trading operations decreased $112 million due primarily to declining prices on ethane and lower ethelyne volumes and prices related to marketing of products of a petrochemical plant acquired by Williams in early 1999, as well as a change in the reporting during 2001 of certain petrochemical and liquid product trading transactions from a gross revenue basis to a net revenue basis. Domestic natural gas liquids revenues decreased $116 million including $78 million from 15 percent lower volumes sold and $38 million due to lower average natural gas liquids sales prices. The 15 percent decrease in volumes sold is due primarily to less favorable processing economics. Additionally, there were $15 million lower revenues related to the petrochemical plant due to a plant turnaround in first-quarter 2001 and curtailed production. Domestic gathering revenues increased $11 million due primarily to higher volumes related to recent asset acquisitions in the Gulf Coast area. Costs and operating expenses increased $393 million to $1.6 billion, due primarily to $549 million of costs and operating expenses related to the Canadian operations for the first three quarters of 2001 and $18 million higher domestic general operating and maintenance costs and $13 million related to the new gas compression facility in Venezuela. Partially offsetting these increases were $95 million lower expenses related to decreased 69 ethane prices for the natural gas liquids trading operations, $58 million lower Canadian costs and operating expenses for the comparable periods of 2001 and 2000 due to lower shrink gas replacement costs, $38 million lower domestic shrink gas replacement costs and the effect in 2000 of $12 million of losses associated with certain propane storage transactions. General and administrative expenses increased $7 million, or 6 percent, due primarily to $11 million of general and administrative expenses related to the Canadian operations for the first three quarters of 2001 and higher general and administrative expenses for natural gas liquids trading operations, partially offset by $12 million of reorganization and early retirement costs incurred in 2000. Included in other (income) expense -- net within segment costs and expenses for 2001 is $13.8 million of impairment charges related to management's 2001 decisions and commitments to sell certain south Texas non-regulated gathering and processing assets. The charges represent the impairment of the assets to fair value based on expected proceeds from the sales. These sales closed during first-quarter 2002. Also included in other (income) expense-net within segment costs and expenses for 2000 is a $12.4 million gain on the sale of certain natural gas liquids contracts. Segment profit decreased $106.1 million, or 38 percent, due primarily to $54 million from lower average per-unit domestic natural gas liquids margins and $22 million from decreased domestic natural gas liquids volumes sold, $16 million lower margins from natural gas liquids trading activity, $18 million higher domestic operating and maintenance costs, $17 million lower operating profit from activities at the petrochemical plant as revenues decreased due to plant turnaround and curtailed production without a corresponding decrease in cost, $13.8 million and $12.4 million due to the 2001 impairment charge and the 2000 gain on sale of certain natural gas liquids contracts discussed above and $10 million higher losses from equity investments. Partially offsetting these decreases to segment profit were an $18 million increase from the new Venezuelan gas compression facility which began operations in third-quarter 2001, $6 million lower domestic general and administrative expenses, $11 million higher domestic gathering revenues and $12 million of losses associated with certain propane storage transactions during 2000. WILLIAMS ENERGY PARTNERS
YEARS ENDED DECEMBER 31, ------------------------ 2002 2001 2000 ------ ------ ------ (MILLIONS) Segment revenues........................................... $423.7 $402.5 $373.0 Segment profit............................................. $ 99.3 $101.2 $104.2
On February 20, 2003, Williams announced that it is pursuing a potential sale of its investment in Williams Energy Partners L.P., including its general partner interest. 2002 vs. 2001 WILLIAMS ENERGY PARTNERS' revenue increased $21.2 million, or 5 percent, reflecting increased revenues from petroleum products transportation, terminal and other activities. Transportation revenues increased as a result of higher average transportation rates slightly offset by lower volumes. The increase in average transportation rates were due to supply shifts within the Williams Pipe Line system, caused by the temporary capacity reductions of certain refineries, which created longer hauls during the current year. These refinery capacity reductions are not anticipated to recur in 2003. The increase in terminals and other revenues principally reflect increased utilization and higher rates. In addition, 2002 results benefited from the full-year impact of acquisitions made during 2001, which include two inland terminals and one marine terminal facility. Costs and operating expenses increased $17 million due primarily to $10 million of higher environmental expense accruals, a full year of operating expenses related to the marine facility and two inland terminals discussed above, and higher third-party pipeline lease expenses. Most of the increase in environmental expenses resulted from the completion of state-mandated environmental assessments at six terminal facilities 70 on the pipeline system during the current year. These increases were partially offset by lower transportation field expenses principally reflecting maintenance cost-reduction measures implemented in the current year. Segment profit decreased $1.9 million, or 2 percent, due to the items discussed above, $5.9 million higher selling, general and administrative expenses and decreased other income of $0.2 million. General and administrative costs increased due to costs incurred during 2002 by Williams Energy Partners relating to the acquisition of Williams Pipe Line, increased allocations from Williams and increased equity-based incentive compensation expense. 2001 vs. 2000 Williams Energy Partners' revenue increased $29.5 million, or 8 percent, due primarily to higher revenues from the petroleum products transportation activities, the acquisition of a marine terminal facility in September 2000 and higher revenues and rates from the storage of petroleum products at the Gulf Coast marine facilities. Segment profit decreased $3 million, or 3 percent, due primarily to higher operating costs corresponding with the revenue increase discussed above and higher general and administrative expenses. PETROLEUM SERVICES
YEARS ENDED DECEMBER 31, ---------------------------- 2002 2001 2000 ------ -------- -------- (MILLIONS) Segment revenues........................................ $866.0 $1,109.7 $1,456.3 Segment profit.......................................... $ 32.8 $ 145.7 $ 38.9
Petroleum Services' continuing operations include the North Pole, Alaska refining operations, retail operations from the 29 Williams Express convenience stores in Alaska, a 3.0845 percent undivided interest in the Trans-Alaska Pipeline System (TAPS) acquired in June 2000 and transportation operations. Transportation operations primarily include Williams' 32.1 percent interest in Longhorn Partners Pipeline LP (which is not yet operational), and gas liquids blending activities for Williams Pipe Line Company which is owned and part of the Williams Energy Partners segment. Williams has announced that it is pursuing the sale of its operations in Alaska. If a sale is approved and other conditions are met, these operations would be reported as discontinued operations in the future. In addition, 2001 and 2000 include the results of operations through May 2001 of 198 convenience stores in the Midsouth which were sold in May 2001. These operations did not qualify as discontinued operations under previous accounting guidance. 2002 vs. 2001 PETROLEUM SERVICES' revenues decreased $243.7 million, or 22 percent, due primarily to $194 million lower convenience store sales and $47 million lower Alaska refining revenues. The $194 million decrease in convenience store sales reflects the absence of $184 million in revenues related to the sale of the 198 convenience stores in May 2001 and an $11 million decrease in revenues related to the retained Alaska convenience stores. The $11 million decrease in revenues of the retained Alaska convenience stores reflects $7 million from a 9 percent decrease in gasoline sales volumes and $4 million from a 6 percent decrease in average gasoline sales prices. The $47 million decrease in refining revenues primarily includes $69 million from 9 percent lower average refined product sales prices, partially offset by $21 million from a 3 percent increase in refined product volumes sold. Costs and operating expenses decreased $228 million, or 23 percent, due primarily to $196 million lower convenience store costs and $32 million lower Alaska refining costs. The $196 million decrease in convenience store costs is due primarily to the absence of $185 million in costs related to the sale of the 198 convenience stores in May 2001 and an $11 million decrease in costs for the retained Alaska convenience stores. The $11 million decrease in costs for the retained Alaska convenience stores reflects $5 million from a 10 percent decrease in average gasoline purchase prices and $6 million from 9 percent lower gasoline sales volumes. The $32 million lower Alaska refining costs is due primarily to $50 million from 8 percent lower average refined 71 product purchase prices, partially offset by $17 million from a 3 percent increase in refined product volumes sold. Other (income) expense -- net in 2002 includes a total of $18.4 million of impairment charges related to the Alaska refining operations and the Alaska convenience stores. As previously mentioned, Williams has announced its intention to pursue a sale of its operations in Alaska. These impairment charges reflect the excess of the carrying cost of these assets over management's estimate of fair value. Other (income) expense -- net in 2001 includes the $75.3 million pre-tax gain from the sale of the 198 convenience stores and a $12.1 million impairment charge related to an end-to-end mobile computing systems business. Segment profit decreased $112.9 million, or 77 percent, due primarily to the $81.6 million net unfavorable effect related to the items noted above in other (income) expense -- net and $14 million lower operating profit from refining operations. In addition, the decrease reflects a 2002 equity loss of $13.8 million from its investment in Longhorn Partners Pipeline LP resulting almost entirely from fourth-quarter 2002 adjustments recorded by Longhorn Partners Pipeline LP to expense certain amounts previously capitalized as property costs. 2001 vs. 2000 Petroleum Services' revenue decreased $346.6 million, or 24 percent, due primarily to $279 million lower convenience store sales and $49 million lower refining revenues, partially offset by $28 million higher revenues from Williams' 3.0845 percent undivided interest in TAPS acquired in late June 2000. The $279 million decrease in convenience store sales is due primarily to a $283 million decrease in revenues related to the sale of the 198 convenience stores in May 2001, slightly offset by higher merchandise sales by the Alaska convenience stores. The $49 million decrease in refining revenues is due to $145 million resulting from 16 percent lower average refined product sales prices, partially offset by $96 million from 12 percent higher refined product volumes sold. Costs and operating expenses decreased $362 million, or 27 percent, due primarily to $278 million lower convenience store costs and $57 million lower refining costs. The $278 million decrease in convenience store costs is due primarily to the $282 million decrease in costs related to the 198 convenience stores which were sold in May 2001, slightly offset by higher merchandise costs by the Alaska convenience stores. The $57 million decrease in refining costs is due primarily to $138 million resulting from 18 percent lower average refined product costs, partially offset by $80 million from a 12 percent increase in refined volumes sold. Included in other (income) expense -- net within segment costs and expenses for 2001, is a $75.3 million pre-tax gain from the sale of the 198 convenience stores. Also included in other (income) expense -- net within segment costs and expenses in 2001 and 2000 are impairment charges of $12.1 million and $11.9 million, respectively, related to an end-to-end mobile computing systems business. The impairment charges result from management's decision in 2000 to sell certain of its end-to-end mobile computing systems and represent the impairment of the assets to fair value based on expected net sales proceeds, as revised. Other (income) expense -- net within segment costs and expenses in 2000 also included a $7 million write-off of a retail software system. Segment profit increased $106.8 million due primarily to $82.1 million net favorable effect related to the items noted above in other (income) expense -- net, $20 million from Williams interest in TAPS acquired in late June 2000 and $8 million higher operating profit from refining operations. 72 OTHER
YEARS ENDED DECEMBER 31, -------------------------- 2002 2001 2000 ------ ------- ------- (MILLIONS) Segment revenues............................................ $65.9 $ 80.3 $ 74.4 Segment profit (loss)....................................... $27.9 $(25.7) $(20.2)
2002 vs. 2001 OTHER segment profit in 2002 includes a $58.5 million gain from the September 2002 sale of Williams' 27 percent ownership interest in the Lithuanian refinery, pipeline and terminal complex and a $9.5 million decrease in equity losses from the Lithuanian operations for the period. Williams received proceeds of approximately $85 million from the sale of this investment. In addition, Williams sold its $75 million note receivable from the Lithuanian operations at face value. 73 FAIR VALUE OF ENERGY RISK MANAGEMENT AND TRADING ACTIVITIES As more thoroughly described in Note 1 of Notes to Consolidated Financial Statements, energy and energy-related contracts are carried at fair value and, with the exception of certain commodity inventories, are recorded in current and noncurrent energy risk management and trading assets and liabilities in the Consolidated Balance Sheet. Fair value of energy and energy-related contracts is determined based on the nature of the transaction and market in which transactions are executed. Certain transactions are executed in exchange-traded or over-the-counter markets for which quoted prices in active periods exist, while other transactions are executed where quoted market prices are not available or the contracts extend into periods for which quoted market prices are not available. Quoted market prices for varying periods in active markets are readily available for valuing forward contracts, futures contracts, swap agreements and purchase and sales transactions in the commodity markets in which Energy Marketing & Trading and the natural gas liquids trading operations transact. Market data in active periods is also available for interest rate transactions affecting the trading portfolio. For contracts or transactions that extend into periods for which actively quoted prices are not available, Energy Marketing & Trading estimates energy commodity prices in the illiquid periods by incorporating information obtained from commodity prices in actively quoted markets, prices reflected in current transactions and market fundamental analysis. For contracts where quoted market prices are not available, primarily transportation, storage, full requirements, load serving and power tolling contracts, Energy Marketing & Trading estimates fair value using proprietary models and other valuation techniques that reflect the best information available under the circumstances. In situations where Energy Marketing & Trading has received current information from negotiation activities with potential buyers of these contracts, the information is considered in the determination of the fair value of the contract. The valuation techniques used when estimating fair value for energy-related contracts incorporate option pricing theory, statistical and simulation analysis, present value concepts incorporating risk from uncertainty of the timing and amount of estimated cash flows and specific contractual terms. The estimates of fair value also assume liquidating the positions in an orderly manner over a reasonable period of time in a transaction between a willing buyer and seller. These valuation techniques utilize factors such as quoted energy commodity market prices, estimates of energy commodity market prices in the absence of quoted market prices, volatility factors underlying the positions, estimated correlation of energy commodity prices, contractual volumes, estimated volumes under option and other arrangements, liquidity of the market in which the contract is transacted, and a risk-free market discount rate. Fair value also reflects a risk premium that market participants would consider in their determination of fair value. Regardless of the method for which fair value is determined, the recognized fair value of all contracts also considers the risk of non-performance and credit considerations of the counterparty. The estimates of fair value are adjusted as assumptions change or as transactions become closer to settlement and enhanced estimates become available. In some cases, Energy Marketing & Trading enters into price-risk management contracts that have forward start dates commencing upon completion of construction and development of assets to be owned and operated by third parties. Until construction commences, revenue recognition and the fair value of these contracts is limited to the amount of any guaranty or similar form of acceptable credit support that encourages the counterparty to perform under the terms of the contract with appropriate consideration for any contractual provisions that provide for contract termination by the counterparty. Information used in determining the significant estimates and assumptions utilized in the determination of fair value of energy-related contracts is derived from market fundamental analysis. Interpreting this data requires judgment and Energy Marketing & Trading recognizes that others in the market place might interpret this data differently. It is reasonably possible that different interpretations of this data could result in a different estimation of fair value in periods for which estimates and assumptions are significant components of estimating fair value. In estimating fair value, Energy Marketing & Trading considers how it believes others in the market place would interpret this information in order to further validate that the estimates and assumptions used in estimating fair value provides the best estimate of the amount that active market participants would exchange in an arms-length transaction. Once offsetting contracts are entered into to mitigate commodity price risk, the reliance on management's assumptions and estimates utilized in the estimation of the fair value of each contract becomes less significant. However, the assumptions and estimates surrounding counterparty performance and credit are still an integral component in the estimation of fair value 74 for these contracts. Energy Marketing & Trading enhances its valuation techniques, models and significant estimates and assumptions as better information about the markets in which Energy Marketing & Trading transacts becomes available. On October 25, 2002, the EITF, concluded in Issue No. 02-3 to rescind Issue No. 98-10, under which non-derivative energy trading contracts were previously marked-to-market. A substantial portion of the energy marketing and trading activities previously reported on a fair-value basis will be reflected under the accrual method of accounting beginning January 1, 2003. In addition, trading inventories will no longer be marked-to-market but will be reported on a lower of cost or market basis. Upon adoption of this new standard on January 1, 2003 Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) will record a charge as a cumulative effect of change in accounting principle. The impact of this change in accounting principle is expected to be a decrease to net income of $750 million to $800 million on an after-tax basis. For further discussion on this issue, please refer to Note 1 of Notes to Consolidated Financial Statements. METHODS OF ESTIMATING FAIR VALUE Quoted prices in active markets Quoted market prices for varying periods in active markets are readily available for valuing forward contracts, futures contracts, swap agreements and purchase and sales transactions in the commodity markets in which Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) transact. These prices reflect the economic and regulatory conditions that currently exist in the market place and are subject to change in the near term due to changes in future market conditions. The availability of quoted market prices in active markets varies between periods and commodities based upon changes in market conditions. Quoted prices and other external factors in less active markets For contracts or transactions extending into periods for which actively quoted prices are not available, Energy Marketing & Trading and the natural gas liquids trading operations estimate energy commodity prices in these illiquid periods by incorporating information about commodity prices in actively quoted markets, quoted prices in less active markets, and other market fundamental analysis. While an active market may not exist for the entire period, quoted prices can generally be obtained for natural gas through 2012, power through 2006, crude and refined products through 2004 and natural gas liquids through 2003. The ability to obtain quoted market prices varies greatly from region to region, and the time periods mentioned above are an estimation of aggregate liquidity. Prices reflected in current transactions executed by Energy Marketing & Trading are used to further validate the estimates of these prices. The ability to validate prices has been limited due to the recent decline in overall market liquidity. Models and other valuation techniques Contracts for which quoted market prices are not available primarily include transportation, storage, full requirements, load serving, transmission, and power tolling contracts (energy-related contracts). A description of these contracts is included in Note 15 of Notes to Consolidated Financial Statements. Energy Marketing & Trading estimates fair value using models and other valuation techniques that reflect the best available information under the circumstances. The valuation techniques incorporate option pricing theory, statistical and simulation analysis, present value concepts incorporating risk from uncertainty of the timing and amount of estimated cash flows and specific contractual terms. Factors utilized in the valuation techniques include quoted energy commodity market prices, estimates of energy commodity market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors underlying the positions, estimated correlation of energy commodity prices, contractual volumes, estimated volumes, liquidity of the market in which the contract is transacted and a risk premium that market participants would consider in their determination of fair value. Although quoted market prices are not available for these energy-related contracts 75 themselves, quoted market prices for the underlying energy commodities are a significant component in the valuation of these contracts. Each of the methods discussed above also include counterparty performance and credit consideration in the estimation of fair value. The chart below reflects 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) by valuation methodology and the period in which the recorded fair value is expected to be realized. Refer to Note 1 of Notes to Consolidated Financial Statements regarding the estimated impact of the Company's January 1, 2003 adoption of EITF Issue No. 02-3 on fair values as reported below.
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 (YEAR 1) (YEARS 2-3) (YEARS 4-5) (YEARS 6-10) (YEARS 11+) VALUE VALUATION TECHNIQUE (MILLIONS) Based upon quoted prices in active markets and 12/31/2001 $ 757 $316 $ 345 $ 363 $ 18 $1,799 quoted prices & other 12/31/2002 (37) 413 221 193 37 827 external factors in less ------- ---- ----- ----- ---- ------ liquid markets(1) 2002 Change $ (794) $ 97 $(124) $(170) $ 19 $ (972) Based upon Models & 12/31/2001 $ 231 $ 12 $ (19) $ 50 $188 $ 462 Other Valuation 12/31/2002 (46) 98 108 295 350 805 ------- ---- ----- ----- ---- ------ Techniques(2) 2002 Change $ (277) $ 86 $ 127 $ 245 $162 $ 343 12/31/2001 $ 988 $328 $ 326 $ 413 $206 $2,261 Total 12/31/2002 (83) 511 329 488 387 1,632 ------- ---- ----- ----- ---- ------ 2002 Change $(1,071) $183 $ 3 $ 75 $181 $ (629) ======= ==== ===== ===== ==== ======
--------------- (1) A significant portion of the value expected to be realized relates to contracts within the California power market. The terms of these agreements provide for the sale of power at fixed prices ranging from $62.50 to $87.00 per megawatt hour at varying volumes through 2010 for up to 700 megawatts per hour, and a unit-specific dispatchable fuel conversion service with fixed capacity prices ranging from $117 to $140 per kilowatt year at varying capacities of up to 1,175 megawatts through 2010. (2) Quoted market prices of the underlying commodities are significant factors in estimating the fair value. SIGNIFICANT ESTIMATES AND ASSUMPTIONS USED IN THE VALUATION ESTIMATION PROCESS The most significant estimates and assumptions used to estimate the value of energy and energy-related contracts that extend beyond liquidly traded time periods include: - Estimates of natural gas, power, and refined products market prices in illiquid periods; - Estimates of volatility and correlation of natural gas, power and refined products prices; - Estimates of risk inherent in estimating cash flows; and - Estimates and assumptions regarding counterparty performance and credit considerations. Estimates of natural gas, power, and refined products market prices in illiquid periods Natural gas, power, and refined products prices are the most significant commodity prices impacting the fair value of Energy Marketing & Trading contracts at December 31, 2002. In estimating natural gas, power, and refined products prices during illiquid periods, Energy Marketing & Trading includes factors such as quoted market prices, prices of current market transactions and market fundamental analysis. Market fundamental analysis incorporates the most recent market data from industry publications, regulatory publications, existing and forecasted electricity generation capacity, natural gas reserve data, alternative fuel 76 source availability, weather patterns and other indicative information supporting supply and demand relationships. These estimated market prices are highly dependent upon actively quoted market prices for natural gas, power, and refined products, current economic and regulatory conditions, as well as, information supporting future conditions that would affect the supply and demand relationships. Alternative methods for determining prices in illiquid periods could materially impact management's estimate of fair value. As new information is obtained about market prices during illiquid periods, Energy Marketing & Trading incorporates this information in its estimates of market prices. Such new information includes additional executed transactions extending into these periods. These transactions give insight into the market prices for which market participants are willing to buy or sell in arms-length transactions. Estimation of volatility and correlation of natural gas, power, and refined products prices Volatility of natural gas, power, and refined products prices represents a significant assumption in the determination of fair value of contracts that contain optionality and whose fair value is estimated using option-pricing models. Correlation of natural gas, power, and refined products prices represents a significant assumption in the determination of fair value of contracts that contain optionality and involve multiple commodities and whose fair value is estimated using option-pricing models. Volatility and correlation can be implied from option based market transactions during periods when quoted market prices exist for natural gas and power. Volatility and correlation are estimated in periods during which quoted market prices are not available through quantitative analysis of historical volatility patterns of the commodities, expected future changes in estimated natural gas, power, and refined products prices, and market fundamental analysis. Estimates of volatility and correlation significantly impact the estimation of fair value for all periods in which the contract is valued using option-pricing models. Alternative methods for determining volatilities and correlations in illiquid periods could materially impact management's estimate of fair value. Estimates of risk inherent in estimating cash flows Risk inherent in estimating cash flows represents the uncertainty of events occurring in the future which could ultimately affect the realization of cash flows. Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) estimate the risk active market participants would include in the price exchanged in an arms-length transaction in the estimation of fair value for each contract. Energy Marketing & Trading and the natural gas liquids trading operation estimate risk utilizing the capital asset pricing theory in the estimation of fair value of energy-related contracts. The capital asset pricing theory considers that investors require a higher return for contracts perceived to embody higher risk of uncertainty in the market. This risk is most significant in illiquid periods and markets. Factors affecting the estimate of risk include liquidity of the market in which the contract is executed, ability to transact in future periods, existence of similar transactions in the market, uncertainty of timing and amounts of cash flows, and market fundamental analysis. Estimates and assumptions regarding counterparty performance and credit considerations Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) includes in its estimate of fair value for all contracts an assessment of the risk of counterparty non-performance. Such assessment considers the credit rating of each counterparty as represented by public rating agencies such as Standard & Poor's and Moody's Investor's Service, the inherent default probabilities within these ratings, the regulatory environment that the contract is subject to, as well as the terms of each individual contract. 77 The gross forward credit exposure from energy trading and price-risk management activities for Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) as of December 31, 2002 is summarized below.
INVESTMENT COUNTERPARTY TYPE GRADE(A) TOTAL ----------------- ---------- -------- (MILLIONS) Gas and electric utilities.................................. $2,326.4 $3,255.1 Energy marketers and traders................................ 2,371.7 3,661.1 Financial Institutions...................................... 1,006.8 1,007.0 Other....................................................... 1,176.4 1,182.4 -------- -------- $6,881.3 9,105.6 ======== Credit reserves............................................. (250.4) -------- Gross credit exposure from energy risk management & trading activities(b)............................................. $8,855.2 ========
Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) assess its credit exposure on a net basis when appropriate and contractually allowed. The net forward credit exposure from energy trading and price-risk management activities as of December 31, 2002 is summarized as below.
INVESTMENT COUNTERPARTY TYPE GRADE(A) TOTAL ----------------- ---------- -------- (MILLIONS) Gas and electric utilities.................................. $1,290.1 $2,648.5 Energy marketers and traders................................ 163.6 183.2 Financial Institutions...................................... 201.1 201.1 Other....................................................... 44.6 50.8 -------- -------- $1,699.4 $3,083.6 ======== Credit reserves............................................. (250.4) -------- Net credit exposure from energy risk management & trading activities(b)............................................. $2,833.2 ========
--------------- (a) "Investment Grade" is primarily determined using publicly available credit ratings along with consideration of cash, standby letters of credit, parent company guarantees, and property interests, including oil and gas reserves. Included in "Investment Grade" are counterparties with a minimum Standard & Poor's and Moody's Investors Service rating of BBB- or Baa3, respectively. (b) One counterparty within the California power market represents greater than ten percent of assets from energy risk management and trading activities and is included in "investment grade." Standard & Poor's and Moody's Investor's Service do not currently rate this counterparty. However, recent bond issuances by this counterparty have been rated as investment grade by the various rating agencies. This counterparty has been included in the "investment grade" column based upon contractual credit requirements in the event of assignment or novation. Certain of Energy Marketing & Trading's counterparties have experienced significant declines in their financial stability and creditworthiness which may adversely impact their ability to perform under contracts with Energy Marketing & Trading. In 2002, Energy Marketing & Trading closed out trading positions with a number of counterparties and has disputes associated with certain portions of this liquidation. One counterparty has disputed a settlement amount related to the liquidation of a trading position with Energy Marketing & Trading. The amount of settlement is in excess of $100 million payable to Energy Marketing & Trading. The matter is being arbitrated. Credit constraints, declines in market liquidity, and financial instability of market participants are expected to continue and potentially grow in 2003. Continued liquidity 78 and credit constraints of Williams may also significantly impact Energy Marketing & Trading's ability to manage market risk and meet contractual obligations. In addition to credit risk, Energy Marketing & Trading is subject to performance risk of parties with which it has significant contracts such as tolling agreements. Currently, approximately 5,400 megawatts of Energy Marketing & Trading's tolling portfolio are subject to agreements with subsidiaries of the AES Corporation. The ability of Energy Marketing & Trading to realize future estimated fair values may be significantly affected by the ability of such tolling parties to perform as contractually required. Electricity and natural gas markets, in California and elsewhere, continue to be subject to numerous and wide-ranging federal and state regulatory proceedings and investigations, as well as civil actions, regarding among other things, market structure, behavior of market participants, market prices, and reporting to trade publications. Energy Marketing & Trading may be liable for refunds and other damages and penalties as a part of these actions. Each of these matters as well as other regulatory and legal matters related to Energy Marketing & Trading are discussed in more detail in Note 16 of Notes to Consolidated Financial Statements. The outcome of these matters could affect the creditworthiness and ability to perform contractual obligations of Energy Marketing & Trading as well as the creditworthiness and ability to perform contractual obligations of other market participants. CHANGES IN FAIR VALUE DURING 2002 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 $629 million, or 28 percent, during 2002. The following table reflects the changes in fair value between December 31, 2001 and December 31, 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(1).......................... 32 Initial recorded value of new or amended contracts entered into during the period................................. 155 Changes in fair value attributable to changes in valuation techniques............................................. (20) Other changes in fair value of contracts(2)............... (796) ------ FAIR VALUE OF CONTRACTS OUTSTANDING AT DECEMBER 31, 2002.... $1,632 ======
--------------- (1) This category includes certain balance sheet reclassifications made in 2002 that did not impact 2002 earnings. (2) This category includes changes in the fair market value of contracts outstanding as a result of various market movements (including changes in market prices, market volatility, and market liquidity) and changes in the net balance of option premiums paid and received. 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 in the fair value of contracts outstanding and a decrease in cash; premiums received result in an initial decrease in the fair value of contracts outstanding and an increase in cash. The underlying value of the options associated with the premium payments are also included in the fair value of contracts outstanding. Changes in fair value during 2002 include the realization of cash flows on contracts outstanding at December 31, 2001 that were expected to be realized during 2002. These amounts may have differed from the values that were actually realized during 2002 due to changes in market prices, the creditworthiness of counterparties, and other factors that occurred during 2002 prior to the realization of those cash flows. During 2002, Energy Marketing & Trading recognized revenues resulting from the execution of new long-term contracts providing for energy price risk management services to customers. See Energy Marketing & Trading's 2002 Results of Operations for a discussion of the type of contracts executed during the year. The 79 fair value of new contracts at the time they are executed reflect the prices negotiated in long-term contracts which includes the premium Energy Marketing & Trading receives for managing the energy price risk of its customers. Additionally, as further discussed in Note 1 of Notes to Consolidated Financial Statements, Energy Marketing & Trading does not recognize revenue on contracts until all requirements for revenue recognition have been achieved. As a result, the fair value of these contracts at the time they were executed is likely to differ from the fair value of the contracts at the time they were initially recognized in the financial statements due to changes in market prices and other factors that may have occurred during the intervening period. Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) continuously evaluate the valuation techniques and models used in estimating fair value and modify and implement new valuation techniques based upon emerging financial theory in order to provide a better estimate of fair value. Changes attributable to market movements reflect the change in fair value of contracts resulting from changes in quoted market prices of commodities, interest rates, volatility and correlation of commodity prices. This also includes improvements in the estimates and assumptions that Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) use in estimating fair value based upon new information and data available in the marketplace. 80 FINANCIAL CONDITION AND LIQUIDITY LIQUIDITY Williams' liquidity comes from both internal and external sources. Certain of those sources are available to Williams (the parent) and others are available to certain of its subsidiaries. Williams' sources of liquidity consist of the following: - Cash-equivalent investments at the corporate level of $1.3 billion at December 31, 2002, as compared to $1.1 billion at December 31, 2001. - Cash and cash-equivalent investments of various international and domestic entities other than Williams Energy Partners of $354 million at December 31, 2002 as compared to $163 million at December 31, 2001. - Cash generated from operations and the future sales of certain assets. - $463 million available under Williams' revolving credit facility at December 31, 2002, as compared to $700 million at December 31, 2001. This credit facility is available to the extent that it is not used to satisfy the financial ratios and other covenants under certain credit agreements. As discussed in Note 11 of Notes to Consolidated Financial Statements, the borrowing capacity under this facility will reduce as assets are sold. - $3 million remaining at December 31, 2002, under a new $400 million secured short-term letter of credit facility obtained in third-quarter 2002. 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. Because of Williams' debt rating and loan covenant restrictions, it is unlikely that Williams would be able to issue securities under the shelf registration statement in the near term. In addition, there are outstanding registration statements filed with the Securities and Exchange Commission for Williams' wholly owned subsidiaries: Northwest Pipeline, Texas Gas Transmission and Transcontinental Gas Pipe Line. As of March 17, 2003, approximately $450 million of shelf availability remains under these outstanding registration statements and may be used to issue a variety of debt securities. Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets. On March 4, 2003, Northwest Pipeline Corporation, a subsidiary of Williams, completed an offering of $175 million of 8.125 percent senior notes due 2010 to certain institutional investors. The offering is exempt from the registration requirements of the Securities Act of 1933. The $450 million of shelf availability mentioned above is not affected by this offering. Williams expects to fund capital and investment expenditures, debt payments and working-capital requirements through (1) cash on hand, (2) cash generated from operations, (3) the sale of assets, (4) issuance of debt by certain subsidiaries and/or (5) amounts available under Williams' revolving credit facility. As discussed in Note 11 of Notes to Consolidated Financial Statements, Williams Production RMT Company (RMT), a wholly owned subsidiary, entered into a $900 million Credit Agreement (RMT note payable) dated as of July 31, 2002, with certain lenders including a subsidiary of Lehman Brothers, Inc., a related party to Williams. The RMT Note Payable is secured by substantially all of the assets of RMT and the capital stock of Williams Production Holdings LLC (parent of RMT), RMT and certain RMT subsidiaries. It is also guaranteed by Williams, Williams Production Holdings LLC (Holdings) and certain RMT subsidiaries. The assets of RMT are comprised primarily of the assets of the former Barrett Resources Corporation acquired in 2001, which were primarily natural gas properties in the Rocky Mountain region. Within 75 days of a parent liquidity event, Williams must sell RMT. Under the terms of the RMT Credit Agreements, Williams must provide liquidity projections on a weekly basis until the maturity date. Each projection covers a period extending 12 months from the report date. One of the parent liquidity provisions requires that Williams maintain actual and projected liquidity (a) at any time from the closing date (July 31, 2002) through the 81 180th day thereafter (January 27, 2003), of $600 million; (b) at any time thereafter through and including the maturity date, of $750 million; and (c) for liquidity projections provided during the term of the loan, projected liquidity after the maturity date, of $200 million. The loan matures on July 25, 2003. Outlook On February 20, 2003, Williams announced that it intended to sell an additional $2.25 billion over those previously announced in assets, properties and investments. To realize this level of proceeds, Williams announced that it was pursuing the sales of its general partnership interest and limited-partner investments in Williams Energy Partners, its 6,000 mile Texas Gas pipeline system and targeted assets in the Exploration & Production and Midstream Gas & Liquids segments. Based on the Company's forecast of cash flows and liquidity, Williams believes that it has the financial resources and liquidity to meet future cash requirements and satisfy current lending covenants through the first quarter of 2004. Included in this forecast are expected proceeds, net of related debt, totaling nearly $4 billion from the sale of assets. Including periods through first-quarter 2004, the Company has scheduled debt retirements (which includes certain contractual fees and deferred interest associated with an underlying debt) of approximately $3.8 billion. Realization of the proceeds from forecasted assets sales is a significant factor for the Company to satisfy its loan covenant which requires minimum levels of parent liquidity and to satisfy current scheduled debt maturities. 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 declines in Williams' senior unsecured long-term credit ratings assigned by Moody's Investors Service and Standard & Poor's (rating agencies). Obligations subject to these "ratings triggers" totaled $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 12). The obligations subject to "ratings triggers" were reduced to $182 million at March 31, 2002. As a result of the credit rating downgrades to below investment grade in July 2002, Williams redeemed $135 million of preferred interests on August 1, 2002 and repaid a $47 million loan in August 2002, thereby eliminating the remaining $182 million exposure. 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 requires alternate credit support under certain existing agreements. In addition, Williams is required to fund margin requirements pursuant to industry standard derivative agreements with cash, letters of credit or other negotiable instruments. As a result of Williams credit downgrade to non-investment grade during 2002, Williams is effectively required to post margins of 100 percent or more on forward positions which result in a loss. Any future liquidity requirements related to these instruments will be driven by changes in the value of such instruments as a result of changes in price, volatility, etc. At December 31, 2002, Williams has been assigned the following credit ratings on its senior unsecured long-term debt, which are considered to be below investment grade: Moody's Investors Service.................................. Caa1 (negative outlook) Standard & Poor's.......................................... B (negative watch)
82 Off-Balance Sheet Financing Arrangements and Guarantees of Debt or Other Commitments to Third Parties At December 31, 2001, Williams had operating lease agreements with special purpose entities (SPE's). The lease agreements relate to certain Williams travel center stores (included in discontinued operations), offshore oil and gas pipelines and an onshore gas processing plant. As a result of changes to the agreements in conjunction with the secured financing facilities completed in July 2002, the agreements no longer qualified for operating lease treatment. The operating leases were recorded as capital leases within long-term debt beginning in July 2002, however the travel center lease is reported in liabilities of discontinued operations and was repaid in March 2003 pursuant to the travel centers sale. 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. Williams provides a guarantee of approximately $126.9 million towards project financing of energy assets owned and operated by Discovery Producer Services LLC in which Williams owns an interest of 50 percent. This obligation is not consolidated in Williams' balance sheet as Williams does not maintain a controlling interest in the entity and therefore follows equity accounting for its interest. Performance under the guarantee generally would occur upon a failure of payment by the financed entity or certain events of default related to the guarantor. These events of default primarily relate to bankruptcy and/or insolvency of the guarantor. At December 31, 2002, there were no events of default by the guarantors or delinquent payments by the financed entity with respect to the project financings. The guarantee expires at the end of 2003. Williams has provided guarantees in the event of nonpayment by WCG on certain lease performance obligations of WCG that extend through 2042 and have a maximum potential exposure of approximately $53 million. Williams' exposure declines systematically throughout the remaining term of WCG's obligations. The carrying value of these guarantees was $48 million at December 31, 2002. In addition to these guarantees, Williams has issued guarantees and other similar arrangements with off-balance sheet risk as discussed under Guarantees in Note 15 of Notes to Consolidated Financial Statements. 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. Receivables included a $106 million deferred payment for services provided to WCG prior to the spinoff and $269 million from the long term lease to WCG of the Technology Center building and three aircraft. The $2.21 billion of guarantees and payment obligations included the indirect credit support for $1.4 billion of WCG's Note Trust Notes and the guarantee of WCG's obligations under the asset defeasance program (ADP) transaction (see Note 2). During 2002, Williams acquired all of the WCG Note Trust Notes by exchanging $1.4 billion of Williams Senior Unsecured 9.25 percent Notes due March 2004. WCG was indirectly obligated to reimburse Williams for any payments Williams is required to make in connection with the WCG Note Trust Notes. On March 29, 2002, Williams funded the purchase price of $754 million related to WCG's March 8, 2002 exercise of its option to purchase the covered network assets under the ADP transaction. Williams then became entitled to an unsecured claim from WCG for the same amount. On April 22, 2002, WCG filed for bankruptcy protection under Chapter 11 of the US Bankruptcy Code. The Chapter 11 Plan of Reorganization (Plan) was confirmed by the United States Bankruptcy Court for the Southern District of New York on September 30, 2002. On October 15, 2002, WCG consummated its Plan. The Plan included the sale, by Williams to Leucadia National Corporation (Leucadia) for $180 million in cash of Williams' claims against WCG for the WCG Note Trust Notes, the funding of the WCG Purchase option for the covered network assets under the ADP transaction and the deferred payment for services. It also included the sale by Williams to WCG of the Technology Center building for (a) a seven and one-half year promissory note in the principal amount of $100 million with interest at 7 percent (Long Term Note) and (b) a four year promissory note (which may be prepaid without penalty) with face amount of $74.4 million 83 and an original principal amount of $44.8 million (Short Term Note) both of which are secured by a mortgage on the Technology Center and certain other collateral. At December 31, 2002, Williams had a $121.5 million receivable (original principal amount of $144.8 million) from WCG for the promissory notes relating to the sale of the Technology Center. The notes were initially recorded at fair value based on contractual cash flows and an estimated discount rate considering the creditworthiness of WCG, the amount and timing of the cash flows and Williams' security in the Technology Center and certain other collateral. The fourth-quarter 2002 sale of certain of Williams' claims against WCG to Leucadia resulted in the elimination of $2.26 billion of receivables, and the associated $2.08 billion allowance, from Williams' Consolidated Balance Sheet. Williams continues to guarantee approximately $53 million, previously discussed of WCG obligation under certain contractual commitments. For more information regarding Williams and WCG, see WCG in Note 2 of Notes to Consolidated Financial Statements. OPERATING ACTIVITIES Cash provided (used) by continuing operating activities was: 2002 -- $(800) million; 2001 -- $1.7 billion; and 2000 -- $324 million. The 2002 $633.4 million increase in margin deposits is due to higher deposits required by counterparties relating to trading activities at Energy Marketing & Trading. The decrease in accounts payable for 2002 is primarily due to decreased levels of trading activity at Energy Marketing & Trading. The decrease in receivables which provides cash in 2002 relates to the decrease in trading activities at Energy Marketing & Trading offset by the expiration in 2002 of the various sale of receivables programs which served to delay the realization of cash related to receivables. The decrease in 2002 of accrued liabilities is due to lower employee costs and decreased deposits received from customers relating to energy risk management and trading and hedging activities (see Note 10). In March 2002, WCG exercised its option to purchase certain network assets under the ADP transaction 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 (see WCG section for further discussion). In 2002, Williams recorded in continuing operations additional pre-tax charges of $268.7 million related to the settlement of these receivables and claims (see Note 2). In 2001, Williams had recorded a $188 million charge related to estimated recovery of amounts from WCG. During 2002, Williams recorded approximately $455 million in provisions for losses on property and other assets. Those provisions consisted primarily of impairments of Canadian assets within Midstream Gas & Liquids and impairments of goodwill and loss accruals related to power generating turbines at Energy Marketing & Trading. The net gain on disposition of assets in 2002 primarily relates to the sales of Exploration & Production properties (see Note 4) and Williams' investment in AB Mazeikiu Nafta (see Note 3). The amortization of deferred set-up fee and fixed rate interest on the RMT note payable relates to amounts recognized in the income statement as interest expense, but generally will not be paid until maturity. During 2002, Williams was required to provide $108 million of cash collateral in support of surety bonds underwritten by various insurance companies and provide cash collateral in support of letters of credit due to downgrades by credit rating agencies. During 2002, Williams also made $78 million in contributions to its qualified pension plans. FINANCING ACTIVITIES Net cash provided by financing activities of continuing operations was: 2002 -- $16.6 million; 2001 -- $2.0 billion; and 2000 -- $2.0 billion. Long-term debt proceeds, net of principal payments, were $1.4 billion, $1.9 billion, and $283 million, during 2002, 2001, and 2000, respectively. Notes payable payments, net of notes payable proceeds, were $1.1 billion and $801 million, during 2002 and 2001, respectively. Notes payable proceeds, net of notes payable payments were $1.5 billion in 2000. The increase in net borrowings from 84 2001 per the Consolidated Balance Sheet also reflects the assumption of the $1.4 billion of WCG notes. The increase in net borrowings during 2001 and 2000 reflects borrowings to fund capital expenditures, investments and acquisitions of businesses. 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. 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. As discussed in Note 11 of Notes to Consolidated Financial Statements and under the Liquidity heading of Management's Discussion and Analysis, RMT entered into a $900 million credit agreement dated as of July 31, 2002. For a discussion of other borrowings and repayments in 2002, see Note 11 of Notes to Consolidated Financial Statements. The proceeds from issuance of Williams common stock in 2001 reflect $1.3 billion in net proceeds from approximately 38 million shares of common stock issued by Williams in January 2001 in a public offering at $36.125 per share. Additionally, the proceeds from issuance of Williams common stock in 2002, 2001 and 2000 reflect exercise of stock options under the plans providing for common-stock-based awards to employees and to non-employee directors. The proceeds from issuance of preferred stock in 2002 reflect $271 million in net proceeds for the issuance of approximately 1.5 million shares of 9.875 percent cumulative convertible preferred stock for $275 million, which were issued concurrent with its sale of Kern River to MEHC. Dividends on the preferred stock are payable quarterly (see Note 13). Dividends paid on common stock decreased $110 million from 2001 levels as Williams' board of directors' reduced the quarterly dividend on common stock, beginning in July 2002, 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. Dividends on common stock in 2001 increased $75.2 million from 2000 reflecting an increase in the number of shares outstanding and an increase in the per share dividends. The number of shares increased due primarily to the 38 million shares issued in January 2001 and the 29.6 million shares issued in the Barrett acquisition. Third-quarter 2001 and fourth-quarter 2001 dividends increased to 18 cents per share and 20 cents per share, respectively, up from the quarterly dividend of 15 cents per share in 2000. In May 2002, Williams Energy Partners L.P., a partially owned and consolidated entity, issued approximately 8 million common units at $37.15 per unit resulting in approximately $279 million of net proceeds. Proceeds from sale of limited partners units of consolidated partnership in 2001 reflect an initial public offering of Williams Energy Partners L.P., then a wholly owned partnership, of approximately 4.6 million common units at $21.50 per unit for net proceeds of approximately $92 million. In December 2001, Williams received net proceeds of $95.3 million from sale of a non-controlling preferred interest in Piceance Production Holdings LLC (Piceance) to an outside investor (see Note 12). During 2000, Williams received net proceeds totaling $546.8 million from the sale of a preferred return interest in Snow Goose Associates, L.L.C. (Snow Goose) to an outside investor (see Note 12). During 2002, 85 changes to these limited liability company member interests and interests in Castle Associates L.P. (Castle) required classification of these outside investor interests as debt. The changes to the Snow Goose structure also included the repayment of the investor's preferred interest in installments. During 2002, approximately $558 million was repaid related to these interests and are included in the payments of long-term debt. In third-quarter 2002, the downgrade of Williams' senior unsecured rating below BB by Standard & Poor's, or Ba1 by Moody's Investors Service, resulted in the early retirement of an outside investor's preferred ownership interest for $135 million (see Note 12). In April 2001, Williams redeemed the Williams obligated mandatorily redeemable preferred securities of Trust holding only Williams indentures for $194 million. Proceeds from the sale of the Ferrellgas senior common units held by Williams were used for this redemption. Long-term debt, including long-term debt due within one year: at December 31, 2002 was $13.0 billion compared with $9.7 billion at December 31, 2001, and $7.7 billion at December 31, 2000. At December 31, 2001, $844 million of current debt obligations were classified as noncurrent obligations based on Williams' intent and ability to refinance on a long-term basis. The 2002 increase in long-term debt is due primarily to the $1.1 billion related to the FELINE PACS issuance discussed above, the combined $1.5 billion issued on March 19, 2002 and the assumption of the $1.4 billion of WCG Note Trust notes. Williams' long-term debt to debt-plus-equity ratio (excluding debt of discontinued operations) was 70.2 percent at December 31, 2002, compared to 59.0 percent and 52.5 percent at December 31, 2001 and 2000, respectively. If short-term notes payable and long-term debt due within one year are included in the calculations, these ratios would be 73.4 percent at December 31, 2002 compared to 64.8 percent and 62.2 percent at December 31, 2001 and 2000, respectively. Additionally, the long-term debt to debt-plus-equity ratio as calculated for covenants under certain debt agreements was 65.2 percent at December 31, 2002 as compared to 61.5 percent at December 31, 2001. See Note 11 of Notes to Consolidated Financial Statements for discussion of this and other covenants. Significant items reflected as discontinued operations within financing activities in the Consolidated Statement of Cash Flows include the cash provided by financing activities in 2001, primarily reflecting the issuance of $1.4 billion of WCG Note Trust Notes for which Williams provided indirect credit support (see Note 2). WCG retained all of the proceeds from this issuance. In 2000, WCG issued $1 billion in long-term debt obligations consisting of $575 million in 11.7 percent notes due 2008 and $425 million in 11.875 percent notes due 2010. During 2000, WCG received net proceeds of approximately $240.5 million from the issuance of five million shares of 6.75 percent redeemable cumulative preferred stock. INVESTING ACTIVITIES Net cash provided (used) by investing activities of continuing operations was: 2002 -- $1.3 billion; 2001 -- $(3.3) billion; and 2000 $(2.0) billion. Capital expenditures of Energy Marketing & Trading, primarily to purchase power generating turbines, were $136 million in 2002, $104 million in 2001 and $63 million in 2000. Capital expenditures of Gas Pipeline, primarily to expand deliverability into the east and west coast markets and upgrade current facilities, were $697 million in 2002, $632 million in $2001, and $448 million in 2000. Capital expenditures for Midstream Gas & Liquids, primarily to acquire, expand and modernize gathering and processing facilities and terminals, were $497 million in 2002, $560 million in 2001, and $326 million in 2000. Capital expenditures for Exploration & Production, primarily for continued development of the company's natural gas reserves base through the drilling of wells, were $380 million in 2002, $218 million in 2001, and $70 million in 2000. Capital expenditures for Williams Energy Partners, primarily to expand and upgrade existing facilities, increase storage and develop pipeline connections to new supply sources, were $40 million in 2002, $35 million in 2001, and $73 million in 2000. Capital expenditures for Petroleum Services, were $18 million in 2002, $13 million in 2001, and $42 million in 2000. Budgeted capital expenditures and investments for continuing operations for 2003 are estimated to be approximately $900 million to $1.05 billion. The acquisition of businesses in 2001 reflects the June 11, 2001, acquisition by Williams of 50 percent of Barrett's outstanding common stock in a cash tender offer of $73 per share for a total of approximately $1.2 billion. On August 2, 2001, Williams completed the acquisition of Barrett by issuing 29.6 million shares 86 of Williams common stock in exchange for the remaining Barrett shares. In 2000, Williams acquired various energy-related operations in Canada for approximately $540 million. Included in the purchase were interests in several NGL extraction and fractionation plants, NGL transportation pipeline and storage facilities, and a natural gas processing plant. The purchase of investments/advances to affiliates in 2002 includes approximately $234 million towards the development of the Gulfstream joint venture project, a Williams equity investment. In 2001, Williams contributed $437 million toward the development of Williams' joint interest in the Gulfstream project. For 2002, net cash proceeds from asset dispositions, the sales of businesses and disposition of investments include the following: - $1.15 billion related to the sale of Mid-American and Seminole Pipeline. - $464 million related to the sale of Kern River. - $380 million related to the sale of Central. - $326 million from the sale of properties in Jonah Field and the Anadarko Basin. - $229 million related to the sale of the Cove Point LNG facility. - $173 million related to the sale of Williams' interest in Alliance Pipeline. - $85 million related to the sale of Williams' interest in the Lithuanian refinery. - $77 million related to the sale of Kansas Hugoton. - $12 million from the sale of the general partner interest in Northern Border Partners. The proceeds received from disposition of investments and other assets in 2001 reflects Williams' sale of the Ferrellgas senior common units to an affiliate of Ferrellgas for proceeds of $199 million in April 2001 and the sale of certain convenience stores for approximately $150 million in May 2001. In 2001, the purchase of assets subsequently leased to seller reflects Williams' purchase of the Williams Technology Center, other ancillary assets and three corporate aircraft for $276 million. As discussed previously, Williams received $180 million in proceeds from the sale of claims against WCG to Leucadia in fourth-quarter 2002. Significant items reflected as discontinued operations within investing activities of the Consolidated Statement of Cash Flows include the following: - Capital expenditures of WCG and network and purchase of investments by WCG, totaled 1.5 billion in 2001 and 4.9 billion in 2000. WCG also had proceeds from sales of investments of $2.9 billion in 2000. - Capital expenditures of Kern River, primarily for expansion of its interstate natural gas pipeline system, were $134 million in 2001 and $5 million in 2000. 87 COMMITMENTS The table below summarizes some of the more significant contractual obligations and commitments by period.
2003 2004 2005 2006 2007 THEREAFTER TOTAL ------ ------ ------ ------ ------ ---------- ------- (MILLIONS) Notes payable...................... $ 935(1) $ -- $ -- $ -- $ -- $ -- $ 935 Long-term debt, including current portion.......................... 1,083 1,832 1,364(2) 1,057 855 6,788 12,979 Debt of discontinued operations.... 69(3) -- -- -- -- 8 77 Operating leases................... 34 22 18 11 9 28 122 Fuel conversion and other service contracts(4)..................... 420 443 446 449 452 5,517 7,727 ------ ------ ------ ------ ------ ------- ------- Total.............................. $2,541 $2,297 $1,828 $1,517 $1,316 $12,341 $21,840 ====== ====== ====== ====== ====== ======= =======
--------------- (1) An additional $228 million will be paid at maturity of the RMT note payable related to a deferred set-up fee and deferred interest. (2) Includes $1.1 billion of 6.5 percent notes, payable 2007 subject to remarketing in 2004 (FELINE PACS). If the remarketing is unsuccessful in 2004 and a second remarketing in February 2005 is unsuccessful as defined in the offering document of the FELINE PACS, then Williams could exercise its right to foreclose on the notes in order to satisfy the obligation of the holders of the equity forward contracts requiring the holder to purchase Williams common stock. (3) $67 million was paid in 2003 related to the sale of the travel centers. (4) Energy Marketing & Trading has entered into certain contracts giving Williams 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. These contracts are included at fair value within energy risk management and trading assets and liabilities. Additionally, at December 31, 2002, commitments for construction and acquisition of property, plant and equipment are approximately $448 million. At December 31, 2002, commitments for additional investment in Gulfstream Natural Gas System, LLC, and certain international cost investments are $49 million. RECENTLY ISSUED ACCOUNTING STANDARDS See Note 1 of Notes to Consolidated Financial Statements for a discussion of recently issued accounting standards. EFFECTS OF INFLATION Williams' cost increases in recent years have benefited from relatively low inflation rates during that time. Approximately 43 percent of Williams' gross property, plant and equipment is at Gas Pipeline and approximately 57 percent is at other operating units. Gas Pipeline is subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, Williams believes it will be allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulation along with competition and other market factors may limit the ability to recover such increased costs. For the other operating units, operating costs are influenced to a greater extent by specific price changes in oil and gas and related commodities than by changes in general inflation. Crude, refined product, natural gas, natural gas liquids and power prices are particularly sensitive to OPEC production levels and/or the market perceptions concerning the supply and demand balance in the near future. 88 ENVIRONMENTAL Williams is a participant in certain environmental activities in various stages involving assessment studies, cleanup operations and/or remedial processes. The sites, some of which are not currently owned by Williams (see Note 16 of our Notes to Consolidated Financial Statements), are being monitored by Williams, other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities in a coordinated effort. In addition, Williams maintains an active monitoring program for its continued remediation and cleanup of certain sites connected with its refined products pipeline activities. Williams is jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such cleanup activities are approximately $87 million, all of which is accrued at December 31, 2002. Williams expects to seek recovery of approximately $31 million of the accrued costs through future natural gas transmission rates. Williams will fund these costs from operations and/or available bank-credit facilities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. At December 31, 2002, certain assessment studies were still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors. Williams is subject to the federal Clean Air Act and to the federal Clean Air Act Amendments of 1990 which require the EPA to issue new regulations. Williams is also subject to regulation at the state and local level. In September 1998, the EPA promulgated rules designed to mitigate the migration of ground-level ozone in certain states. Williams estimates that capital expenditures necessary to install emission control devices over the next five years to comply with rules will be between $306 million and $344 million. The actual costs incurred will depend on the final implementation plans developed by each state to comply with these regulations. In December 1999, standards promulgated by the EPA for tailpipe emissions and the content of sulfur in gasoline were announced. Williams estimates that capital expenditures necessary to bring its refinery into compliance over the next five years will be approximately $51 million. The actual costs incurred will depend on the final implementation plans. In addition to the above mentioned capital expenditures pertaining to the Clean Air Act and amendments, estimated future capital expenditures as of December 31, 2002, for various compliance issues across the company are approximately $19 million. 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. 89 ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK INTEREST RATE RISK Williams' current interest rate risk exposure is related primarily to its debt portfolio and its energy risk management and trading portfolio. Williams' interest rate risk exposure resulting from its debt portfolio is influenced by short-term rates, primarily LIBOR-based borrowings from commercial banks and long-term U.S. Treasury rates. To mitigate the impact of fluctuations in interest rates, Williams targets to maintain a significant portion of its debt portfolio in fixed rate debt. Williams has also utilized interest-rate swaps to change the ratio of its fixed and variable rate debt portfolio based on management's assessment of future interest rates, volatility of the yield curve and Williams' ability to access the capital markets in a timely manner. Williams periodically enters into interest-rate forward contracts to establish an effective borrowing rate for anticipated long-term debt issuances. The maturity of Williams' long-term debt portfolio is partially influenced by the expected life of its operating assets. At December 31, 2002 and 2001, the amount of Williams' fixed and variable rate debt was at targeted levels. Williams has historically maintained an investment grade credit rating as one aspect of managing its interest rate risk. However, in July 2002, Moody's Investors Service and Standard & Poor's downgraded their credit ratings of Williams' long-term unsecured debt to below investment grade. Williams also has interest rate risk in long-dated energy-related contracts included in its energy risk management and trading portfolio. The value of these transactions can fluctuate daily based on movements in the underlying interest rate curves used to assign value to the transactions. Williams strives to mitigate the associated interest rate risk from the value of these transactions by fixing the underlying interest rate inherent in the energy risk management and trading portfolio. During 2001, Williams began actively managing this exposure as a component of its targeted levels of fixed to floating obligations. Williams uses both floating to fixed interest rate swaps and other derivative transactions to manage this variable rate exposure. Due to Williams' credit situation at December 31, 2002, only $300 million notional of interest rate swaps were outstanding. The tables on the following page provide information as of December 31, 2002 and 2001, about Williams' interest rate risk sensitive instruments. For notes payable and long-term debt the table presents principal cash flows and weighted-average interest rates by expected maturity dates. For interest-rate swaps, the table presents notional amounts and weighted-average interest rates by contractual maturity dates. Notional amounts are used to calculate the contractual cash flows to be exchanged under the interest-rate swaps. 90
FAIR VALUE DECEMBER 31, 2003 2004 2005 2006 2007 THEREAFTER TOTAL 2002 ------ ------ ------ ---- ---- ---------- ------- ------------ (DOLLARS IN MILLIONS) Notes payable................ $ 935 $ -- $ -- $ -- $ -- $ -- $ 935 $1,002 Interest rate................ 5.8%(1) Long-term debt, including current portion: Fixed rate................. $ 328 $1,741 $1,355 $969 $695 $6,648 $11,736 $8,214 Interest rate.............. 7.8% 7.7% 7.6% 7.8% 7.9% 8.2% Variable rate.............. $ 755 $ 91 $ 9 $ 88 $160 $ -- $ 1,103 $1,103 Interest rate(2) Capital leases............. $ -- $ -- $ 140 $ -- $ -- $ -- $ 140 $ 140 Lease rate................. 6.4%
FAIR VALUE DECEMBER 31, 2002 2003 2004 2005 2006 THEREAFTER TOTAL 2001 ------ ------ ------ ---- ---- ---------- ------- ------------ (DOLLARS IN MILLIONS) Notes payable................ $1,425 $ -- $ -- $ -- $ -- $ -- $ 1,425 $1,425 Interest rate................ 3.3% Long-term debt, including current portion: Fixed rate................. $ 796 $ 292 $ 581 $240 $954 $5,282 $ 8,145 $8,300 Interest rate.............. 7.2% 7.3% 7.3% 7.3% 7.4% 7.6% Variable rate.............. $ 204 $ 402 $ 941 $ -- $ -- $ -- $ 1,547 $1,547 Interest rate(2) Interest rate swaps(3)
--------------- (1) This is the variable rate portion related to these notes which is based on the Eurodollar rate plus 4 percent per annum. An additional 14 percent fixed rate, compounded quarterly, accrues to the RMT note payable (see Note 11). (2) 2002-Weighted-average interest rate through 2006 is LIBOR plus an applicable margin ranging from 1.125 percent to 5.0 percent, except $178 million at Eurodollar plus 4.25 percent; weighted-average interest rate in 2007 is Eurodollar plus 4.25 percent. 2001-Weighted-average interest rates is LIBOR plus one percent for all years. (3) The interest rate swaps at December 31, 2001 are reflected at fair value within energy risk management and trading assets and liabilities in the Consolidated Balance Sheet as these swaps are entered into to mitigate the interest rate risk inherent in the energy risk management and trading portfolio. Notional amounts total approximately $1 billion at December 31, 2001. COMMODITY PRICE RISK TRADING Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) have trading operations that incur commodity price risk as a consequence of providing price-risk management services to third-party customers. The most significant exposure to commodity price-risk is associated with the natural gas and electricity markets in the United States. This exposure is primarily within the portfolio of transportation, storage, full-requirements, load serving, transmission, and power tolling contracts. Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) also has commodity price-risk exposure to crude oil, refined products, electricity and natural gas in the United States and Europe, natural gas liquids markets in the United States and the natural gas markets in Canada through other energy contracts such as forward, futures, 91 options, swaps, and purchase and sale contracts. These energy and energy-related contracts are valued at fair value and unrealized gains and losses from changes in fair value are recognized in income (see Note 1 of Notes to Consolidated Financial Statements regarding change in accounting principle due to adoption of EITF No. 02-3 effective January 1, 2003). These energy and energy-related contracts are subject to risk from changes in energy commodity market prices, volatility and correlation of those commodity prices, the portfolio position of its contracts, the liquidity of the market in which the contract is transacted and changes in interest rates. Energy Marketing & Trading and the natural gas liquids trading operations actively seek 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 this risk in accordance with parameters established in its trading policy. A Risk Control Group monitors compliance with the established trading policy and measures the risk associated with the trading portfolio. Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) measures the market risk in its trading portfolio utilizing a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of its trading operations. At December 31, 2002 and 2001, the value at risk for the trading operations was $50.2 million and $92.7 million, respectively. This decline in value at risk is primarily a result of the 28 percent decline in overall portfolio value outlined in previous sections. 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. NON-TRADING Williams is also exposed to market risks from changes in energy commodity prices within Exploration & Production, Petroleum Services, the non-trading operations of Midstream Gas & Liquids and the non-trading operations of Energy Marketing & Trading. Exploration & Production has commodity price risk associated with the sales prices of the natural gas and crude oil it produces. Petroleum Services' refinery is exposed to commodity price risk for crude oil purchases and refined product sales. Midstream Gas & Liquids is exposed to commodity price risk related to natural gas purchases, natural gas liquids purchases and sales, and electricity cost. Energy Marketing & Trading is exposed to changing prices of natural gas purchased for the production of electricity. Williams manages its exposure to certain of these commodity price risks through the use of derivative commodity instruments. Williams' non-trading derivative commodity instruments primarily consist of natural gas price and basis swaps in its Exploration & Production business. A value-at-risk methodology was used to measure the market risk of these derivative commodity instruments in the non-trading portfolio. It estimates the potential one-day loss from adverse changes in the fair value of these instruments. The value-at-risk model did not consider the underlying commodity positions to which these derivative commodity instruments relate; therefore, it is not representative of actual losses that could occur on a total non-trading portfolio basis that includes the underlying commodity positions. At December 31, 2002, the value-at-risk for the non-trading derivative commodity instruments was approximately $45 million. 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 non-trading derivative commodity instruments. The value-at-risk model 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 non-trading derivative commodity instruments will not exceed the value-at-risk. The value-at-risk model uses historical simulations 92 to estimate hypothetical movements in future market prices assuming normal market conditions based upon historical market prices. Gains and losses on these derivative commodity instruments would be substantially offset by corresponding gains and losses on the hedged commodity positions. FOREIGN CURRENCY RISK Williams has international investments that could affect the financial results if the investments incur a permanent decline in value as a result of changes in foreign currency exchange rates and the economic conditions in foreign countries. International investments accounted for under the cost method totaled $130 million and $143 million at December 31, 2002, and 2001, respectively. The fair value of these investments is deemed to approximate their carrying amount as the investments are primarily in non-publicly traded companies for which it is not practicable to estimate the fair value of these investments. Williams continues to believe that it can realize the carrying value of these investments considering the status of the operations of the companies underlying these investments. If a 20 percent change occurred in the value of the underlying currencies of these investments against the U.S. dollar, the fair value of these investments at December 31, 2002, could change by approximately $26 million assuming a direct correlation between the currency fluctuation and the value of the investments. The net assets of foreign operations whose functional currency is the local currency, which are consolidated are located primarily in Canada and approximate 15 percent of Williams' net assets at December 31, 2002. These foreign operations do not have significant transactions or financial instruments denominated in other currencies. However, these investments do have the potential to impact Williams' financial position, due to fluctuations in these local currencies arising from the process of re-measuring the local functional currency into the U.S. dollar. As an example, a 20 percent change in the respective functional currencies against the U.S. dollar could have changed stockholders' equity by approximately $148 million at December 31, 2002. Williams historically has not utilized derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies with the exception of a Canadian dollar-denominated note receivable (see Note 15). However, Williams evaluates currency fluctuations and will consider the use of derivative financial instruments or employment of other investment alternatives if cash flows or investment returns so warrant. EQUITY PRICE RISK Equity price risk primarily arises from investments in publicly traded energy-related companies. The investments in the energy-related companies are carried at fair value and totaled approximately $14 million and $8 million at December 31, 2002 and 2001, respectively. 93 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA REPORT OF INDEPENDENT AUDITORS To The Stockholders of The Williams Companies, Inc. We have audited the accompanying consolidated balance sheet of The Williams Companies, Inc. as of December 31, 2002 and 2001, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of The Williams Companies, Inc. at December 31, 2002 and 2001, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects, the information set forth therein. ERNST & YOUNG LLP Tulsa, Oklahoma March 5, 2003 94 THE WILLIAMS COMPANIES, INC. CONSOLIDATED STATEMENT OF OPERATIONS
YEARS ENDED DECEMBER 31, -------------------------------------- 2002 2001 2000 ----------- ----------- ---------- (MILLIONS, EXCEPT PER-SHARE AMOUNTS) Revenues: Energy Marketing & Trading................................ $ 56.2 $ 1,705.6 $1,295.1 Gas Pipeline.............................................. 1,503.8 1,426.0 1,567.0 Exploration & Production.................................. 899.9 615.2 331.0 Midstream Gas & Liquids................................... 1,909.1 1,906.8 1,574.3 Williams Energy Partners.................................. 423.7 402.5 373.0 Petroleum Services*....................................... 866.0 1,109.7 1,456.3 Other..................................................... 65.9 80.3 74.4 Intercompany eliminations................................. (116.2) (180.6) (111.8) --------- --------- -------- Total revenues.......................................... 5,608.4 7,065.5 6,559.3 --------- --------- -------- Segment costs and expenses: Costs and operating expenses*............................. 3,653.5 3,846.6 3,828.9 Selling, general and administrative expenses.............. 723.9 793.0 617.8 Other (income) expense -- net............................. 297.4 (16.1) 78.6 --------- --------- -------- Total segment costs and expenses........................ 4,674.8 4,623.5 4,525.3 --------- --------- -------- General corporate expenses.................................. 142.8 124.3 97.2 --------- --------- -------- Operating income (loss): Energy Marketing & Trading................................ (471.7) 1,294.6 968.2 Gas Pipeline.............................................. 586.8 497.9 570.3 Exploration & Production.................................. 516.8 219.5 75.8 Midstream Gas & Liquids................................... 171.7 185.9 282.0 Williams Energy Partners.................................. 99.3 101.2 104.2 Petroleum Services........................................ 48.1 145.8 39.5 Other..................................................... (17.4) (2.9) (6.0) General corporate expenses................................ (142.8) (124.3) (97.2) --------- --------- -------- Total operating income.................................. 790.8 2,317.7 1,936.8 --------- --------- -------- Interest accrued............................................ (1,229.5) (720.6) (641.2) Interest capitalized........................................ 29.0 38.4 34.3 Interest rate swap loss..................................... (124.2) -- -- Investing income (loss)..................................... (109.7) (168.6) 89.1 Minority interest in income and preferred returns of consolidated subsidiaries................................. (79.3) (80.7) (56.8) Other income (expense) -- net............................... 26.4 26.1 (.3) --------- --------- -------- Income (loss) from continuing operations before income taxes..................................................... (696.5) 1,412.3 1,361.9 Provision (benefit) for income taxes........................ (195.0) 609.6 541.5 --------- --------- -------- Income (loss) from continuing operations.................... (501.5) 802.7 820.4 Loss from discontinued operations........................... (253.2) (1,280.4) (296.1) --------- --------- -------- Net income (loss)........................................... (754.7) (477.7) 524.3 Preferred stock dividends................................... 90.1 -- -- --------- --------- -------- Income (loss) applicable to common stock.................... $ (844.8) $ (477.7) $ 524.3 ========= ========= ======== Basic earnings (loss) per common share: Income (loss) from continuing operations.................. $ (1.14) $ 1.62 $ 1.85 Loss from discontinued operations......................... (.49) (2.58) (.67) --------- --------- -------- Net income (loss)....................................... $ (1.63) $ (.96) $ 1.18 ========= ========= ======== Diluted earnings (loss) per common share: Income (loss) from continuing operations.................. $ (1.14) $ 1.61 $ 1.83 Loss from discontinued operations......................... (.49) (2.56) (.66) --------- --------- -------- Net income (loss)....................................... $ (1.63) $ (.95) $ 1.17 ========= ========= ========
--------------- * Includes consumer excise taxes of $10.8 million, $33.4 million and $95.6 million in 2002, 2001 and 2000, respectively. See accompanying notes. 95 THE WILLIAMS COMPANIES, INC. CONSOLIDATED BALANCE SHEET
DECEMBER 31, --------------------- 2002 2001 --------- --------- (DOLLARS IN MILLIONS, EXCEPT PER SHARE AMOUNTS) ASSETS Current assets: Cash and cash equivalents................................. $ 1,728.3 $ 1,258.5 Restricted cash........................................... 102.8 -- Accounts and notes receivable less allowance of $113.2 ($252.2 in 2001)........................................ 2,524.4 2,762.4 Inventories............................................... 443.1 543.5 Energy risk management and trading assets................. 5,276.5 6,401.1 Margin deposits........................................... 804.8 171.4 Assets of discontinued operations......................... 981.3 800.3 Deferred income taxes..................................... 569.2 440.6 Other current assets and deferred charges................. 455.7 447.2 --------- --------- Total current assets.................................. 12,886.1 12,825.0 Restricted cash............................................. 188.3 -- Investments................................................. 1,475.6 1,555.9 Property, plant and equipment -- net........................ 14,717.7 14,388.9 Energy risk management and trading assets................... 3,578.7 4,030.4 Goodwill.................................................... 1,082.5 1,141.4 Assets of discontinued operations........................... -- 3,571.4 Receivables from Williams Communications Group, Inc. (less allowance of $103.2 in 2001).............................. 120.3 137.2 Other assets and deferred charges........................... 939.3 964.0 --------- --------- Total assets.......................................... $34,988.5 $38,614.2 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Notes payable............................................. $ 934.8 $ 1,424.5 Accounts payable.......................................... 2,027.5 2,571.0 Accrued liabilities....................................... 1,552.0 1,767.8 Liabilities of discontinued operations.................... 304.1 560.5 Energy risk management and trading liabilities............ 5,359.6 5,412.7 Guarantees and payment obligations related to Williams Communications Group, Inc. ............................. 47.7 645.6 Long-term debt due within one year........................ 1,082.8 999.4 --------- --------- Total current liabilities............................. 11,308.5 13,381.5 Long-term debt.............................................. 11,896.4 8,692.7 Deferred income taxes....................................... 3,353.6 3,689.9 Liabilities and minority interests of discontinued operations................................................ -- 898.7 Energy risk management and trading liabilities.............. 1,863.5 2,757.6 Guarantees and payment obligations related to Williams Communications Group, Inc. ............................... -- 1,120.0 Other liabilities and deferred income....................... 1,093.8 891.2 Contingent liabilities and commitments (Note 16) Minority interests in consolidated subsidiaries............. 423.7 162.2 Preferred interests in consolidated subsidiaries............ -- 976.4 Stockholders' equity: Preferred stock, $1 per share par value, 30 million shares authorized, 1.5 million issued in 2002, none in 2001.... 271.3 -- Common stock, $1 per share par value, 960 million shares authorized, 519.9 million issued in 2002, 518.9 million issued in 2001.......................................... 519.9 518.9 Capital in excess of par value............................ 5,177.2 5,085.1 Retained earnings (deficit)............................... (884.3) 199.6 Accumulated other comprehensive income.................... 33.8 345.1 Other..................................................... (30.3) (65.0) --------- --------- 5,087.6 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............................ 5,049.0 6,044.0 --------- --------- Total liabilities and stockholders' equity............ $34,988.5 $38,614.2 ========= =========
See accompanying notes. 96 THE WILLIAMS COMPANIES, INC. CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
ACCUMULATED CAPITAL IN RETAINED OTHER PREFERRED COMMON EXCESS OF EARNINGS COMPREHENSIVE TREASURY STOCK STOCK PAR VALUE (DEFICIT) INCOME OTHER STOCK TOTAL --------- ------ ---------- --------- ------------- ------ -------- --------- (DOLLARS IN MILLIONS, EXCEPT PER-SHARE AMOUNTS) BALANCE, DECEMBER 31, 1999.......... $ -- $444.5 $2,356.7 $2,807.2 $ 99.5 $(77.6) $(45.1) $ 5,585.2 Comprehensive income: Net income -- 2000................. -- -- -- 524.3 -- -- -- 524.3 Other comprehensive loss: Net unrealized depreciation on marketable equity securities, net of reclassification adjustments.................... -- -- -- -- (47.4) -- -- (47.4) Foreign currency translation adjustments.................... -- -- -- -- (23.9) -- -- (23.9) --------- Total other comprehensive loss..... (71.3) --------- Total comprehensive income.......... 453.0 Cash dividends -- Common stock ($.60 per share)...... -- -- -- (265.8) -- -- -- (265.8) Stockholders' notes issued.......... -- -- -- -- -- (18.0) -- (18.0) Stockholders' notes repaid.......... -- -- -- -- -- 6.6 -- 6.6 Stock award transactions, including tax benefit (including 3.6 million common shares)..................... -- 3.4 113.9 -- -- .3 2.6 120.2 ESOP loan repayment................. -- -- -- -- -- 7.5 -- 7.5 Other............................... -- -- 3.3 -- -- -- -- 3.3 ------ ------ -------- -------- ------- ------ ------ --------- BALANCE, DECEMBER 31, 2000.......... -- 447.9 2,473.9 3,065.7 28.2 (81.2) (42.5) 5,892.0 Comprehensive loss: Net loss -- 2001................... -- -- -- (477.7) -- -- -- (477.7) Other comprehensive income: Net unrealized gains on cash flow hedges, net of reclassification adjustments.................... -- -- -- -- 370.2 -- -- 370.2 Net unrealized depreciation on marketable equity securities, net of reclassification adjustments.................... -- -- -- -- (35.3) -- -- (35.3) Foreign currency translation adjustments.................... -- -- -- -- (37.1) -- -- (37.1) Minimum pension liability adjustment..................... -- -- -- -- (2.2) -- -- (2.2) --------- Total other comprehensive income... 295.6 --------- Total comprehensive loss............ (182.1) Issuance of common stock (38 million shares)............................ -- 38.0 1,295.4 -- -- -- -- 1,333.4 Issuance of common stock for acquisition of business (29.6 million shares).................... -- 29.6 1,206.1 -- -- -- -- 1,235.7 Cash dividends -- Common stock ($.68 per share)...... -- -- -- (341.0) -- -- -- (341.0) Stockholders' notes issued.......... -- -- -- -- -- (8.8) -- (8.8) Stockholders' notes repaid.......... -- -- -- -- -- 6.3 -- 6.3 Stock award transactions, including tax benefit (including 3.6 million common shares)..................... -- 3.4 98.6 -- -- .7 2.8 105.5 Distribution of Williams Communications Groups' common stock.............................. -- -- -- (2,047.4) 21.3 18.0 -- (2,008.1) Other............................... -- -- 11.1 -- -- -- -- 11.1 ------ ------ -------- -------- ------- ------ ------ --------- BALANCE, DECEMBER 31, 2001.......... -- 518.9 5,085.1 199.6 345.1 (65.0) (39.7) 6,044.0 Comprehensive loss: Net loss -- 2002................... -- -- -- (754.7) -- -- -- (754.7) Other comprehensive loss: Net unrealized losses on cash flow hedges, net of reclassification adjustments... -- -- -- -- (298.9) -- -- (298.9) Net unrealized appreciation on marketable equity securities, net of reclassification adjustments.................... -- -- -- -- 4.6 -- -- 4.6 Foreign currency translation adjustments.................... -- -- -- -- (.1) -- -- (.1) Minimum pension liability adjustment..................... -- -- -- -- (16.9) -- -- (16.9) --------- Total other comprehensive loss..... (311.3) --------- Total comprehensive loss............ (1,066.0) Issuance of 9 7/8 percent cumulative convertible preferred stock (1.5 million shares).................... 271.3 -- -- -- -- -- -- 271.3 Cash dividends -- Common stock ($.42 per share)...... -- -- -- (216.8) -- -- -- (216.8) Preferred stock($14.14 per share)........................... -- -- -- (20.8) -- -- -- (20.8) Issuance of equity of consolidated limited partnership................ -- -- 44.6 -- -- -- -- 44.6 Beneficial conversion option on issuance of convertible preferred stock (Note 13).................... -- -- 69.4 (69.4) -- -- -- -- FELINE PACS equity contract adjustment (Note 13)............... -- -- (76.7) -- -- -- -- (76.7) Allowance for and repayments of stockholders' notes................ -- -- -- -- -- 7.8 (1.3) 6.5 Stock award transactions, including tax benefit (including 1.2 million common shares)..................... -- 1.0 33.1 -- -- .4 2.4 36.9 ESOP loan repayment................. -- -- -- -- -- 26.5 -- 26.5 Other............................... -- -- 21.7 (22.2) -- -- -- (.5) ------ ------ -------- -------- ------- ------ ------ --------- BALANCE, DECEMBER 31, 2002.......... $271.3 $519.9 $5,177.2 $ (884.3) $ 33.8 $(30.3) $(38.6) $ 5,049.0 ====== ====== ======== ======== ======= ====== ====== =========
See accompanying notes. 97 THE WILLIAMS COMPANIES, INC. CONSOLIDATED STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31, --------------------------------- 2002 2001 2000 --------- --------- --------- (MILLIONS) OPERATING ACTIVITIES: Income (loss) from continuing operations................... $ (501.5) $ 802.7 $ 820.4 Adjustments to reconcile to cash provided (used) by operations: Depreciation, depletion and amortization................. 775.1 628.2 520.4 Provision (benefit) for deferred income taxes............ (122.1) 362.7 376.9 Payments of guarantees and payment obligations related to Williams Communications Group, Inc. ................... (753.9) -- -- Provision for loss on property and other assets.......... 455.2 157.4 57.3 Net gain on dispositions of assets....................... (193.6) (91.8) (11.5) Provision for uncollectible accounts: Williams Communications Group, Inc. ................... 268.7 188.0 -- Other.................................................. 10.2 13.7 3.4 Accrual for interest included in RMT note payable........ 32.2 -- -- Amortization of deferred set-up fee and fixed rate interest on RMT note payable........................... 110.9 -- -- Minority interest in income and preferred returns of consolidated subsidiaries.............................. 79.3 80.7 56.8 Tax benefit received and amortization of stock-based awards................................................. 32.3 48.4 36.7 Cash provided (used) by changes in current assets and liabilities: Restricted cash........................................ (4.0) -- -- Accounts and notes receivable.......................... 192.5 357.6 (1,537.7) Inventories............................................ 81.9 269.3 (288.5) Margin deposits........................................ (633.4) 559.5 (671.7) Other current assets and deferred charges.............. (342.0) 136.3 16.8 Accounts payable....................................... (616.8) (430.3) 1,264.7 Accrued liabilities.................................... (275.3) 221.8 279.8 Changes in current energy risk management and trading assets and liabilities................................... 1,071.4 (742.9) (218.8) Changes in noncurrent energy risk management and trading assets and liabilities................................... (442.4) (806.1) (485.2) Changes in noncurrent restricted cash...................... (104.2) -- -- Other, including changes in noncurrent assets and liabilities.............................................. 80.0 (56.9) 104.3 --------- --------- --------- Net cash provided (used) by operating activities of continuing operations................................. (799.5) 1,698.3 324.1 Net cash provided by operating activities of discontinued operations............................... 257.3 152.7 259.7 --------- --------- --------- Net cash provided (used) by operating activities....... (542.2) 1,851.0 583.8 --------- --------- --------- FINANCING ACTIVITIES: Proceeds from notes payable................................ 1,613.0 1,830.0 2,190.4 Payments of notes payable.................................. (2,724.4) (2,631.4) (723.9) Proceeds from long-term debt............................... 3,970.0 3,525.1 984.6 Payments of long-term debt................................. (2,596.1) (1,663.4) (701.9) Proceeds from issuance of common stock..................... 5.2 1,388.5 64.1 Proceeds from issuance of preferred stock.................. 271.3 -- -- Dividends paid............................................. (230.8) (341.0) (265.8) Proceeds from sale of limited partner units of consolidated partnership.............................................. 279.3 92.5 -- Net proceeds from issuance of preferred interests of consolidated subsidiaries................................ -- 95.3 546.8 Retirement of preferred interest in consolidated subsidiary............................................... (135.0) -- -- Redemption of Williams obligated mandatorily redeemable preferred securities of Trust holding only Williams indentures............................................... -- (194.0) -- Payments/dividends to minority and preferred interests..... (70.8) (56.9) (35.7) Changes in restricted cash................................. (182.1) -- -- Payments for debt issuance costs........................... (203.9) (45.8) (3.9) Changes in cash overdrafts................................. 29.4 (28.8) (31.9) Other -- net............................................... (8.5) (.1) (.1) --------- --------- --------- Net cash provided by financing activities of continuing operations............................................ 16.6 1,970.0 2,022.7 Net cash provided (used) by financing activities of discontinued operations............................... (143.7) 1,360.0 1,728.3 --------- --------- --------- Net cash provided (used) by financing activities....... (127.1) 3,330.0 3,751.0 --------- --------- --------- INVESTING ACTIVITIES: Property, plant and equipment: Capital expenditures..................................... (1,823.8) (1,624.1) (1,169.2) Proceeds from dispositions............................... 566.6 29.9 31.7 Acquisitions of businesses (primarily property, plant and equipment), net of cash acquired......................... -- (1,343.1) (726.4) Purchases of investments/advances to affiliates............ (308.7) (568.3) (181.9) Proceeds from sales of businesses.......................... 2,300.4 163.7 -- Proceeds from dispositions of investments and other assets................................................... 273.0 243.9 47.2 Proceeds received on advances to affiliates................ 75.0 95.0 -- Proceeds received on sale of claims against Williams Communications Group, Inc. .............................. 180.0 -- -- Purchase of assets subsequently leased to seller........... (8.9) (276.0) -- Other -- net............................................... 35.8 24.4 .7 --------- --------- --------- Net cash provided (used) by investing activities of continuing operations................................. 1,289.4 (3,254.6) (1,997.9) Net cash used by investing activities of discontinued operations............................................ (185.2) (1,739.5) (2,207.8) --------- --------- --------- Net cash provided (used) by investing activities....... 1,104.2 (4,994.1) (4,205.7) --------- --------- --------- Cash of discontinued operations at spinoff.................. -- (96.5) -- --------- --------- --------- Increase in cash and cash equivalents....................... 434.9 90.4 129.1 Cash and cash equivalents at beginning of year.............. 1,301.1 1,210.7 1,081.6 --------- --------- --------- Cash and cash equivalents at end of year*................... $ 1,736.0 $ 1,301.1 $ 1,210.7 ========= ========= =========
--------------- * Includes cash and cash equivalents of discontinued operations of $7.7 million, $42.6 million and $246.9 million for 2002, 2001 and 2000, respectively. See accompanying notes. 98 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 2002 OVERVIEW AND RECENT DEVELOPMENTS Events over the past year and a half have significantly impacted the Company's operations and these events will have a continuing impact on the Company's operations in the future. In the first quarter of 2002, 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 to strengthen its balance sheet and support retention of its then-current investment grade ratings. During first-quarter 2002, Williams sold Kern River Gas Transmission (Kern River). During the second quarter of 2002, the results of the Energy Marketing & Trading business were not profitable, reflecting significantly unfavorable market movements against its portfolio and a decline in origination activities. These unfavorable conditions were in large part a result of market concerns about Williams' credit and liquidity situation and limited Energy Marketing & Trading's ability to manage market risk and exercise hedging strategies as market liquidity deteriorated. During third-quarter 2002, Williams' credit ratings were lowered below investment grade. Williams was also unable to complete a renewal of its unsecured short-term bank credit facility which expired July 24, 2002. Following these events and in response to a potential liquidity shortfall, Williams sold assets in July 2002 receiving net proceeds of approximately $1.5 billion, obtained secured credit facilities totaling $1.3 billion, including the $900 million short-term payable (RMT note payable), and amended its revolving credit facility to make it secured. Also during the third and fourth quarters of 2002, Williams completed additional asset sales resulting in net cash proceeds of approximately $1 billion. Segment losses continued in the third and fourth quarters of 2002 from the Energy Marketing & Trading business reflecting the continued negative market movements against the portfolio, the absence of origination activities and the adverse affects of Williams' overall liquidity and credit ratings issues, which impact Energy Marketing & Trading's ability to enter into price risk management and hedging activities. As of December 31, 2002, the Company has scheduled debt retirements due through first-quarter 2004 of approximately $3.8 billion, which includes certain contractual fees and deferred interest associated with an underlying debt, and anticipates significant additional asset sales to meet its liquidity needs over that period. The Company has also reduced projected levels of capital expenditures and the board of directors reduced the quarterly dividend on common stock beginning in third-quarter 2002 from the prior level of $.20 per share to $.01 per share. The Company has also announced its intentions to reduce its commitment to the Energy Marketing & Trading business, which could be realized by entering into a joint venture with a third party or through the sale of a portion or all of the marketing and trading portfolio. On February 20, 2003, Williams outlined its planned business strategy for the next several years and believes it to be a comprehensive response to the events which have impacted the energy sector and Williams during 2002. The plan focuses on retaining a strong, but smaller, portfolio of natural-gas businesses and bolstering Williams' liquidity through more asset sales, limited levels of financing at the subsidiary level and additional reductions in its operating costs. The plan is designed to provide Williams with a clear strategy to address near-term and medium-term liquidity issues and further de-leverage the company with the objective of returning to investment grade status by 2005, while retaining businesses with favorable returns and opportunities for growth in the future. As part of this plan, Williams expects to generate proceeds, net of related debt, of nearly $4 billion from asset sales during 2003, including approximately $2.25 billion in newly announced offerings combined with those assets already under contract or in negotiations for sale. Newly announced offerings include the Texas Gas pipeline system, Williams' general partnership interest and limited partner investment in Williams Energy Partners, and certain properties and assets within Exploration & Production and Midstream Gas & Liquids. During first-quarter 2003, Williams closed the sales of the retail travel centers and the Midsouth refinery. While the Company believes that these actions will significantly address liquidity and credit concerns through the first quarter of 2004, the resulting downsizing of the Company will have a significant impact on 99 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the Company's future financial position and results of operations. The Company's ability to maintain liquidity and future operations could be significantly impacted by other events, including the possibility that the asset sales and reduction of the Company's commitment to its Energy Marketing & Trading business will not be accomplished as currently anticipated. The timing and amount of proceeds to be realized from the sale of assets is subject to several variables, including negotiations with prospective buyers, industry conditions, lender consents to the sale of collateral, regulatory approvals and Williams' assessment of its short and long-term liquidity requirements. The reduction of the Company's commitment to Energy Marketing & Trading activities could be affected by the willingness of buyers and/or potential partners to enter into transactions with Williams, giving consideration to the current condition of the energy trading sector and liquidity and credit constraints of Williams. As a result of these factors, the proceeds that may be realized from the sales of assets, including the trading portfolio, may be less than the carrying values at December 31, 2002, and could result in additional impairments and losses. In the event that Williams' financial condition does not improve or becomes worse, or if it fails to complete asset sales and reduce its commitment to its Energy Marketing & Trading business, Williams may have to consider other options including the possibility of seeking protection in a bankruptcy proceeding. DESCRIPTION OF BUSINESS Operations of The Williams Companies, Inc. (Williams) are located principally in the United States and are organized into the following reporting segments: Energy Marketing & Trading, Gas Pipeline, Exploration & Production, Midstream Gas & Liquids, Williams Energy Partners and Petroleum Services. Energy Marketing & Trading is a national energy services provider that buys, sells and transports a full suite of energy-related commodities, including power, natural gas, crude oil, refined products and emission credits, primarily on a wholesale level. Gas Pipeline is comprised primarily of three interstate natural gas pipelines located throughout the United States as well as investments in natural gas pipeline-related companies. The three Gas Pipeline operating segments have been aggregated for reporting purposes and include Northwest Pipeline, Texas Gas Transmission and Transcontinental Gas Pipe Line. Exploration & Production includes natural gas exploration, production and marketing activities primarily in the Rocky Mountain, Midwest and Gulf Coast regions of the United States and Argentina. Midstream Gas & Liquids is comprised of natural gas gathering and processing and treating facilities in the Rocky Mountain, Midwest and Gulf Coast regions of the United States, majority-owned natural gas compression and transportation facilities in Venezuela, and assets in Canada including several natural gas liquids extraction and fractionation plants, a natural gas liquids pipeline, storage facilities, and a natural gas processing plant. Williams Energy Partners segment includes Williams Energy Partners L.P. (a partially-owned and consolidated entity of Williams) and Williams' general partnership interests. Williams GP LLC, WEG GP LLC, Williams Energy Partners L.P. and its subsidiaries are legally separate and distinct entities from The Williams Companies, Inc. and its other subsidiaries. The assets owned by Williams Energy Partners L.P., Williams GP LLC and WEG GP LLC, are generally not available for the payment of debts owed to the creditors of Williams and its other subsidiaries. Williams Energy Partners L.P. includes a network of storage, transportation and distribution assets for crude petroleum products and ammonia and a petroleum products pipeline. Petroleum Services includes petroleum refining and marketing in Alaska and convenience stores in Alaska. Prior year amounts for Petroleum Services also include the results of operations of convenience stores in the Midsouth which were sold in May 2001. Williams is currently pursuing the sale of the Alaska operations. 100 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) On February 20, 2003, Williams announced that it was pursuing the sales of its Texas Gas pipeline system and its general partnership interest and limited partner investment in Williams Energy Partners, and certain properties and assets within Exploration & Production and Midstream Gas & Liquids. BASIS OF PRESENTATION In accordance with the provisions related to discontinued operations within Statement of Financial Accounting Standard (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the accompanying consolidated financial statements and notes reflect the results of operations, financial position and cash flows of the following components as discontinued operations (see Note 2): - Kern River Gas Transmission (Kern River), previously one of Gas Pipeline's segments - Central natural gas pipeline, previously one of Gas Pipeline's segments - Colorado soda ash mining operations, part of the previously reported International segment - Two natural gas liquids pipeline systems, Mid-America Pipeline and Seminole Pipeline, previously part of the Midstream Gas & Liquids segment - Refining and marketing operations in the Midsouth, including the Midsouth refinery, previously part of the Petroleum Services segment - Retail travel centers concentrated in the Midsouth, previously part of the Petroleum Services segment - Bio-energy operations, previously part of the Petroleum Services segment Additionally, the results of operations and cash flows of WCG are reflected as discontinued operations in the accompanying financial statements. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to the continuing operations of Williams. Williams expects that other components of its business will be classified as discontinued operations in the future as the sales of those assets occur. Additionally, activities of certain of Williams' segments were realigned or changed due to certain transactions during 2002. These realignments include the following: - During first-quarter 2002, management of APCO Argentina was transferred from the previously reported International segment to the Exploration & Production segment. - On April 11, 2002, Williams Energy Partners L.P., a partially owned and consolidated entity of Williams, acquired Williams Pipe Line, an operation previously included within Petroleum Services. Accordingly, Williams Pipe Line's operations have been transferred from the Petroleum Services segment to the Williams Energy Partners segment. - 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 remaining operations of the previously reported International segment have been included within Other as a result of the decrease in significance of that segment. Any segment information in the Notes to the Consolidated Financial Statements has been restated for all prior periods presented to reflect the changes noted above. Certain prior year amounts have been reclassified to conform to current year classifications. 101 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In 2001, through two transactions, Williams acquired all of the outstanding stock of Barrett Resources Corporation (Barrett). On June 11, 2001, Williams acquired 50 percent of Barrett's outstanding common stock in a cash tender offer totaling approximately $1.2 billion. Williams acquired the remaining 50 percent of Barrett's outstanding common stock on August 2, 2001, through a merger by exchanging each remaining share of Barrett common stock for 1.767 shares of Williams common stock for a total of approximately 30 million shares of Williams common stock valued at $1.2 billion. The unaudited pro forma net income (loss) for 2001 and 2000, if the purchase of 100 percent of Barrett occurred at the beginning of each of those years, was $(396.0) million and $480.9 million, respectively, or $(.76) per diluted share and $1.00 per diluted share. Pro forma financial information is not necessarily indicative of results of operations that would have occurred if the acquisition had occurred at the beginning of each year presented or of future results of operations of the combined companies. The estimated fair values of the significant assets acquired and liabilities assumed at August 2, 2001, the date of acquisition, were: Current assets-$127.6 million; Property, plant & equipment-$2,520.4 million; Goodwill and other assets-$1,114.5 million; Current liabilities-$171.6 million; Long-term debt-$312.1 million; Deferred income taxes-$634.7 million; and Other noncurrent liabilities-$127.1 million. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of Williams and its majority-owned subsidiaries and investments. Companies in which Williams and its subsidiaries own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. USE OF ESTIMATES 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. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) impairment assessments of long-lived assets and goodwill; 2) litigation-related contingencies; 3) valuations of energy contracts, including energy-related contracts; 4) environmental remediation obligations; 5) realization of amounts due from WCG; 6) realization of deferred income tax assets; and 7) Gas Pipeline revenues subject to refund. These estimates are discussed further throughout the accompanying notes. CASH AND CASH EQUIVALENTS Cash and cash equivalents include demand and time deposits, certificates of deposit and other marketable securities with maturities of three months or less when acquired. RESTRICTED CASH Restricted cash within current assets consists primarily of cash collateral as required under the $900 million short-term Credit Agreement (see Note 11) and letters of credit. Restricted cash within noncurrent assets consists primarily of collateral in support of surety bonds underwritten by an insurance company, debt service reserves and letters of credit. Williams does not expect this cash to be released within the next twelve months. 102 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The current and noncurrent restricted cash is primarily invested in short-term money market accounts with financial institutions and an insurance company as well as treasury securities. 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. ACCOUNTS RECEIVABLE Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. No allowance for doubtful accounts is recognized at the time the revenue, which generates the accounts receivable, is recognized. Management estimates the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is recognized at the time full payment is received. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. INVENTORY VALUATION Inventories are stated at cost, which is not in excess of market, except for certain assets held for energy risk management activities by Energy Marketing & Trading and Midstream Gas & Liquids, which are primarily stated at fair value prior to the application of Emerging Issues Task Force (EITF) Issue No. 02-3 (see Recent accounting standards). The cost of certain natural gas inventories held by Transcontinental Gas Pipe Line are determined using the last-in, first-out (LIFO) cost method; and the cost of the remaining inventories is primarily determined using the average-cost method or market, if lower. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at cost. The carrying value of these assets is also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. Depreciation is provided primarily on the straight-line method over estimated useful lives. Gains or losses from the ordinary sale or retirement of property, plant and equipment for regulated pipelines are credited or charged to accumulated depreciation; other gains or losses are recorded in net income (loss). Oil and gas exploration and production activities are accounted for under the successful efforts method of accounting. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to expense. Other exploration costs, including lease rentals, are expensed as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred. Unproved properties are evaluated annually, or as conditions warrant, to determine any impairment in carrying value. Depreciation, depletion and amortization are provided under the units of production method. Proved properties, including developed and undeveloped, and costs associated with probable reserves, are assessed for impairment using estimated future cash flows. Estimating future cash flows involves the use of complex judgments such as estimation of the proved and probable oil and gas reserve quantities, risk associated with the different categories of oil and gas reserves, timing of development and production, expected future commodity prices, capital expenditures and production costs. GOODWILL Goodwill represents the excess of cost over fair value of assets of businesses acquired. In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," approximately $1 billion of goodwill acquired subsequent to June 30, 2001, in the acquisition of Barrett Resources Corporation, was not amortized in 2001. 103 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Beginning January 1, 2002, all goodwill is no longer amortized, but is tested annually for impairment. Application of the nonamortization provisions of SFAS No. 142 did not materially impact the comparability of the Consolidated Statement of Operations. Energy Marketing & Trading's goodwill was approximately $45 million and $106 million at December 31, 2002, and December 31, 2001, respectively (see Note 4). Exploration & Production's goodwill was approximately $1 billion at December 31, 2002 and 2001. Beginning January 1, 2002, the impairment of goodwill and other intangible assets is measured pursuant to the guidelines of SFAS No. 142. Goodwill is evaluated for impairment by first comparing management's estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. When a reporting unit is sold or classified as held for sale, any goodwill of that reporting unit is included in its carrying value for purposes of determining any impairment or gain/loss on sale. If a portion of a reporting unit with goodwill is sold or classified as held for sale and that asset group represents a business, a portion of the reporting unit's goodwill is allocated to and included in the carrying value of that asset group. Except for bio-energy, none of the operations sold during 2002 or classified as held for sale at December 31, 2002 represented reporting units with goodwill or businesses within reporting units to which goodwill was required to be allocated. Judgments and assumptions are inherent in management's estimate of undiscounted future cash flows used to determine the estimate of the reporting unit's fair value. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements. TREASURY STOCK Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of shares are credited or charged to capital in excess of par value using the average-cost method. ENERGY COMMODITY RISK MANAGEMENT AND TRADING ACTIVITIES AND REVENUES Williams, through Energy Marketing & Trading and the natural gas liquids trading operations (reported within the Midstream Gas & Liquids segment), has energy commodity risk management and trading operations that enter into energy and energy-related contracts to provide price-risk management services to its third-party customers involving power, natural gas, refined products, natural gas liquids and crude oil. Energy contracts utilized in energy commodity risk management and trading activities are valued at fair value in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," and EITF No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." Williams adopted SFAS No. 133 effective January 1, 2001. Such adoption had no impact on the accounting for energy commodity risk management and trading activities. Prior to adopting SFAS No. 133, Energy Marketing & Trading followed the guidance in EITF No. 98-10. See Recent accounting standards section within this Note for changing accounting standards regarding recording certain energy contracts and commodity trading inventories at fair value. Energy contracts include forward contracts, futures contracts, option contracts, swap agreements, certain physical commodity inventories, short-and long-term purchase and sale commitments, which involve physical delivery of an energy commodity and energy-related contracts, such as transportation, storage, full requirements, load serving and power tolling contracts. In addition, Williams enters into interest rate swap agreements and credit default swaps to manage the interest rate and credit risk in its energy trading portfolio. These energy contracts and credit default swap agreements, with the exception of physical trading commodity inventories, are recorded in current and noncurrent energy risk management and 104 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) trading assets and energy risk management and trading liabilities in the Consolidated Balance Sheet. The classification of current versus noncurrent is based on the timing of expected future cash flows. In accordance with SFAS No. 133 and EITF No. 98-10, the net change in fair value of these contracts representing unrealized gains and losses is recognized in income currently, and recorded as revenues in the Consolidated Statement of Operations. Energy Marketing & Trading and the natural gas liquids trading operations, report their trading operations' physical sales transactions net of the related purchase costs, consistent with fair value accounting for such trading activities. The accounting for Energy Marketing & Trading's energy-related contracts requires Williams to assess whether certain of these contracts are executory service arrangements or leases pursuant to SFAS No. 13, "Accounting for Leases." As a result, Williams assesses each of its energy-related contracts and makes the determination based on the substance of each contract focusing on factors such as physical and operational control of the related asset, risks and rewards of owning, operating and maintaining the related asset and other contractual terms. See Recent accounting standards section within this Note for recent developments regarding guidance determining whether an arrangement contains a lease. The fair values of energy and energy-related contracts are determined based on the nature of the transaction and the market in which transactions are executed. Certain transactions are executed in exchange-traded or over-the-counter markets for which quoted prices in active periods exist, while other transactions are executed where quoted market prices are not available or the contracts extend into periods for which quoted market prices are not available. Quoted market prices for varying periods in active markets are readily available for valuing forward contracts, futures contracts, swap agreements and purchase and sales transactions in the commodity markets in which Energy Marketing & Trading and the natural gas liquids trading operations transact. Market data in active periods is also available for interest rate transactions affecting the trading portfolio. For contracts or transactions that extend into periods for which actively quoted prices are not available, Energy Marketing & Trading and the natural gas trading operations estimate energy commodity prices in the illiquid periods by incorporating information obtained from commodity prices in actively quoted markets, prices in less active markets, prices reflected in current transactions and market fundamental analysis. For contracts where quoted market prices are not available, primarily transportation, storage, full requirements, load serving, transmission and power tolling contracts (energy-related contracts), Energy Marketing & Trading estimates fair value using proprietary models and other valuation techniques that reflect the best information available under the circumstances. In situations where Energy Marketing & Trading has received current information from negotiation activities with potential buyers of these contracts, the information is considered in the determination of the fair value of the contract. The valuation techniques used when estimating fair value for energy-related contracts incorporate option pricing theory, statistical and simulation analysis, present value concepts incorporating risk from uncertainty of the timing and amount of estimated cash flows and specific contractual terms. The estimates of fair value also assume liquidating the positions in an orderly manner over a reasonable period of time in a transaction between a willing buyer and seller. These valuation techniques utilize factors such as quoted energy commodity market prices, estimates of energy commodity market prices in the absence of quoted market prices, volatility factors underlying the positions, estimated correlation of energy commodity prices, contractual volumes, estimated volumes under option and other arrangements, liquidity of the market in which the contract is transacted, and a risk-free market discount rate. Fair value also reflects a risk premium that market participants would consider in their determination of fair value. Regardless of the method for which fair value is determined, the recognized fair value of all contracts also considers the risk of non-performance and credit considerations of the counterparty. The estimates of fair value are adjusted as assumptions change or as transactions become closer to settlement and enhanced estimates become available. In some cases, Energy Marketing & Trading enters into price-risk management contracts that have forward start dates commencing upon completion of construction and development of assets to be owned and operated by third parties. Until construction commences, revenue recognition and the fair value of these contracts is limited to the amount of any guaranty or similar form of acceptable credit support that encourages 105 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the counterparty to perform under the terms of the contract with appropriate consideration for any contractual provisions that provide for contract termination by the counterparty. The fair value of Williams' trading portfolio is continually subject to change due to changing market conditions and changing trading portfolio positions. Determining fair value for these contracts also involves complex assumptions including estimating natural gas and power market prices in illiquid periods and markets, estimating market volatility and liquidity and correlation of natural gas and power prices, evaluating risk arising from uncertainty inherent in estimating cash flows and estimates regarding counterparty performance and credit considerations. Changes in valuation methodologies or the underlying assumptions could result in significantly different fair values. GAS PIPELINE REVENUES Revenues for sales of products are recognized in the period of delivery, and revenues from the transportation of gas are recognized in the period the service is provided. Gas Pipeline is subject to Federal Energy Regulatory Commission (FERC) regulations and, accordingly, certain revenues collected may be subject to possible refunds upon final orders in pending rate cases. Gas Pipeline records estimates of rate refund liabilities considering Gas Pipeline and other third-party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks. REVENUES, OTHER THAN GAS PIPELINE AND ENERGY COMMODITY RISK MANAGEMENT AND TRADING ACTIVITIES Revenues generally are recorded when services have been performed or products have been delivered. A portion of Williams Energy Partners' operations is subject to FERC regulations and, accordingly, the method of recording these revenues is consistent with Gas Pipeline's method discussed above. Certain Midstream Gas & Liquids revenues are from trading activities. See the previous discussion of Energy commodity risk management and trading activities and revenues for additional information. Additionally, revenues from the domestic production of natural gas in properties for which Exploration & Production has an interest with other producers, are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on Exploration & Production's net working interest, which are determined to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are not significant. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES, INCLUDING INTEREST RATE SWAPS All derivatives, other than derivatives within Midstream Gas & Liquids and Energy Marketing & Trading's energy commodity risk management and trading activities which are accounted for at fair value as discussed above, are reflected on the balance sheet at their fair value and are recorded in other current assets, other assets and deferred charges, accrued liabilities and other liabilities and deferred income in the Consolidated Balance Sheet as of December 31, 2002 and 2001. Derivative instruments held by Williams, other than those utilized in the energy risk management and trading activities, consist primarily of futures contracts, swap agreements, forward contracts and option contracts. Most of these transactions are executed in exchange-traded or over-the-counter markets for which quoted prices in active periods exist. For contracts with lives exceeding the time period for which quoted prices are available, fair value determination involves estimating commodity prices during the illiquid periods by incorporating information obtained from commodity prices in actively quoted markets, prices reflected in current transactions and market fundamental analysis. 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 106 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 within the segment disclosures (Note 19). The results of interest rate swaps with external counterparties are shown as interest rate swap loss in the Consolidated Statement of Operations below operating income (loss). The accounting for changes in the fair value of a derivative depends upon whether it has been designated in a hedging relationship and, further, on the type of hedging relationship. To qualify for designation in a hedging relationship, specific criteria must be met and the appropriate documentation maintained. Hedging relationships are established pursuant to Williams' risk management policies and are initially and regularly evaluated to determine whether they are expected to be, and have been, highly effective hedges. If a derivative ceases to be a highly effective hedge, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized in earnings each period. Changes in the fair value of derivatives not designated in a hedging relationship are recognized in earnings each period. For derivatives designated as a hedge of a recognized asset or liability or an unrecognized firm commitment (fair value hedges), the changes in the fair value of the derivative as well as changes in the fair value of the hedged item attributable to the hedged risk are recognized each period in earnings. If a firm commitment designated as the hedged item in a fair value hedge is terminated or otherwise no longer qualifies as the hedged item, any asset or liability previously recorded as part of the hedged item is recognized currently in earnings. For derivatives designated as a hedge of a forecasted transaction or of the variability of cash flows related to a recognized asset or liability (cash flow hedges), the effective portion of the change in fair value of the derivative is reported in other comprehensive income and reclassified into earnings in the period in which the hedged item affects earnings. Amounts excluded from the effectiveness calculation and any ineffective portion of the change in fair value of the derivative are recognized currently in earnings. Gains or losses deferred in accumulated other comprehensive income associated with terminated derivatives, derivatives that cease to be highly effective hedges and cash flow hedges that have been otherwise discontinued remain in accumulated other comprehensive income until the hedged item affects earnings or it is probable that the hedged item will not occur by the end of the originally specified time period or within two months thereafter. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. When it is probable the forecasted transaction will not occur, any gain or loss deferred in accumulated other comprehensive income is recognized in earnings at that time. On January 1, 2001, Williams recorded a cumulative effect of an accounting change associated with the adoption of SFAS No. 133, as amended, to record all derivatives at fair value. The cumulative effect of the accounting change was not material to net income (loss), but resulted in a $95 million reduction of other comprehensive income (net of income tax benefits of $59 million) related to derivatives which hedge the variable cash flows of certain forecasted energy commodity transactions. With the adoption of SFAS No. 133 on January 1, 2001, the accounting for certain aspects of derivative instruments and hedging activities was different in periods prior to the adoption of SFAS No. 133. Prior to 2001, Williams entered into energy derivative financial instruments and derivative commodity instruments (primarily futures contracts, option contracts and swap agreements) to hedge against market price fluctuations of certain commodity inventories and sales and purchase commitments. Certain of these instruments were not required to be recorded on the balance sheet; there was not a distinction between cash flow and fair value hedges and no ineffectiveness was required to be recorded currently in earnings. Unrealized and realized gains and losses on those hedge contracts were deferred and recognized in income in the same manner as the 107 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) hedged item. No unrealized gains or losses were required to be reported in other comprehensive income. These contracts were initially and regularly evaluated to determine that there was high correlation between changes in the fair value of the hedge contract and fair value of the hedged item. In instances where the anticipated correlation of price movements did not occur, hedge accounting was terminated and future changes in the value of the instruments were recognized as gains or losses. If the hedged item of the underlying transaction was sold or settled, the instrument was recognized into income (loss). Williams entered into interest-rate swap agreements to modify the interest characteristics of its long-term debt. These agreements were designated with all or a portion of the principal balance and term of specific debt obligations. These agreements involved the exchange of amounts based on a fixed interest rate for amounts based on variable interest rates without an exchange of the notional amount upon which the payments are based. The difference to be paid or received was accrued and recognized as an adjustment of interest accrued. Gains and losses from terminations of interest-rate swap agreements were deferred and amortized as an adjustment of the interest expense on the outstanding debt over the remaining original term of the terminated swap agreement. In the event the designated debt was extinguished, gains and losses from terminations of interest-rate swap agreements were recognized into income (loss). IMPAIRMENT OF LONG-LIVED ASSETS Williams evaluates the long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. Beginning January 1, 2002, the impairment evaluation of tangible long-lived assets is measured pursuant to the guidelines of SFAS No. 144. When an indicator of impairment has occurred, management's estimate of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether an impairment has occurred. A probability-weighted approach is applied to consider the likelihood of different cash flow assumptions and possible outcomes including a sale in the near term or hold for the remaining estimated useful life. If an impairment of the carrying value has occurred, the amount of the impairment recognized in the financial statements is determined by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. For assets identified to be disposed of in the future and considered held for sale in accordance with SFAS No. 144, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is redetermined when related events or circumstances change. Judgments and assumptions are inherent in management's estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset's fair value used to calculate the amount of impairment to recognize. Additionally, management's judgment is used to determine the probability of sale with respect to assets considered for disposal pursuant to Williams' announced strategy of selling assets as a significant source of liquidity. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements. CAPITALIZATION OF INTEREST Williams capitalizes interest on major projects during construction. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by unregulated companies are based on the average interest rate on debt. Interest capitalized on internally generated funds, as permitted by FERC rules, is included in non-operating other income (expense) -- net. 108 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) EMPLOYEE STOCK-BASED AWARDS Employee stock-based awards are accounted for under Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees" and related interpretations. Fixed-plan common stock options generally do not result in compensation expense because the exercise price of the stock options equals the market price of the underlying stock on the date of grant. The plans are described more fully in Note 14. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation."
YEARS ENDED DECEMBER 31, --------------------------- 2002 2001 2000 ------- ------- ------- (DOLLARS IN MILLIONS) Net income (loss), as reported.......................... $(754.7) $(477.7) $ 524.3 Add: Stock-based employee compensation expense included in the Consolidated Statement of Operations, net of related tax effects................................... 19.1 13.6 6.8 Deduct: Total stock based employee compensation expense determined under fair value based method for all awards, net of related tax effects.................... (34.5) (24.7) (149.7) ------- ------- ------- Pro forma net income (loss)............................. $(770.1) $(488.8) $ 381.4 ======= ======= ======= Earnings (loss) per share: Basic-as reported..................................... $ (1.63) $ (.96) $ 1.18 ======= ======= ======= Basic-pro forma....................................... $ (1.66) $ (.98) $ .86 ======= ======= ======= Diluted-as reported................................... $ (1.63) $ (.95) $ 1.17 ======= ======= ======= Diluted-pro forma..................................... $ (1.66) $ (.98) $ .85 ======= ======= =======
Pro forma amounts for 2002 include compensation expense from certain Williams awards made in 1999 and compensation expense from Williams awards made in 2002 and 2001. Pro forma amounts for 2001 include compensation expense from certain Williams awards made in 1999 and compensation expense from Williams awards made in 2001. Pro forma amounts for 2000 include compensation expense from certain Williams awards made in 1999 and the total compensation expense from Williams awards made in 2000, as these awards fully vested in 2000 as a result of the accelerated vesting provisions. Pro forma amounts for 2000 include $36.7 million for Williams awards and $106.3 million related to discontinued operations. Since compensation expense from stock options is recognized over the future years' vesting period for pro forma disclosure purposes and additional awards are generally made each year, pro forma amounts may not be representative of future years' amounts. INCOME TAXES Williams includes the operations of its subsidiaries in its consolidated tax return. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of Williams' assets and liabilities. Management's judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets. 109 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) EARNINGS (LOSS) PER SHARE Basic earnings (loss) per share are based on the sum of the weighted average number of common shares outstanding and issuable restricted and vested deferred shares. Diluted earnings (loss) per share include any dilutive effect of stock options, unvested deferred shares and, for applicable periods presented, convertible preferred stock. FOREIGN CURRENCY TRANSLATION The functional currency of certain of Williams' continuing foreign operations is the local currency for the applicable foreign subsidiary or equity method investee. These foreign currencies include the Canadian dollar, British pound and Euro. Assets and liabilities of certain foreign subsidiaries and equity investees are translated at the spot rate in effect at the applicable reporting date, and the combined statements of operations and Williams' share of the results of operations of its equity affiliates are translated into the U.S. dollar at the average exchange rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component of other comprehensive income (loss). Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in transactions gains and losses which are reflected in the Consolidated Statement of Operations. ISSUANCE OF EQUITY OF CONSOLIDATED SUBSIDIARY Sales of equity, common stock or limited partnership units by a consolidated subsidiary are accounted for as capital transactions with the adjustment to capital in excess of par value. No gain or loss is recognized on these transactions. SECURITIZATIONS AND TRANSFERS OF FINANCIAL INSTRUMENTS Through July 2002, Williams had agreements to sell, on an ongoing basis, certain of its trade accounts receivable through revolving securitization structures and retained servicing responsibilities as well as a subordinate interest in the transferred receivables. These agreements expired in July 2002 and were not renewed. Williams accounted for the securitization of trade accounts receivable in accordance with SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." As a result, the related receivables were removed from the Consolidated Balance Sheet and a retained interest was recorded for the amount of receivables sold in excess of cash received. Williams determined the fair value of its retained interests based on the present value of future expected cash flows using management's best estimates of various factors, including credit loss experience and discount rates commensurate with the risks involved. These assumptions were updated periodically based on actual results, thus the estimated credit loss and discount rates utilized were materially consistent with historical performance. The fair value of the servicing responsibility was estimated based on internal costs, which approximate market. Costs associated with the sale of receivables are included in nonoperating other income (expense) -- net in the Consolidated Statement of Operations. RECENT ACCOUNTING STANDARDS The Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs and amends SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The Statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset 110 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) retirement costs be capitalized as part of the carrying amount of the long-lived asset. The Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002 with the impact of adoption to be reported as a cumulative effect of change in accounting principle. Williams adopted the new rules on asset retirement obligations on January 1, 2003. As required by the new rules, Williams recorded liabilities equal to the present value of expected future asset retirement obligations at January 1, 2003. The obligations related to producing wells, offshore platforms and underground storage caverns. The liabilities are partially offset by increases in net assets, net of accumulated depreciation, recorded as if the provisions of the Statement had been in effect at the date the obligation was incurred. As a result of the adoption of SFAS No. 143, Williams recorded a long-term liability of $33 million; property, plant and equipment, net of accumulated depreciation, of $15 million and a cumulative effect of a change in accounting principle of $5 million (net of $3 million of taxes). Williams also recorded a $10 million regulatory asset for retirement costs expected to be recovered through regulated rates. In connection with adoption of SFAS No. 143, Williams changed its method of accounting to include salvage value of equipment related to producing wells in the calculation of depreciation, resulting in a $9 million reduction in accumulated depreciation and a cumulative effect of change in accounting principle of $6 million (net of $3 million of taxes) in 2003. Williams has not recorded liabilities for pipeline transmission assets, processing and refining assets, and gas gathering systems. A reasonable estimate of the fair value of the retirement obligations for these assets cannot be made as the remaining life of these assets is not currently determinable. 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, any gains and losses from debt extinguishments will not be accounted for as extraordinary items. 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 EITF 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)." Under this Statement, a liability for a cost associated with an exit or disposal activity is recognized at fair value when the liability is incurred rather than at the date of an entity's commitment to an exit plan. The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002; hence, initial adoption of this Statement on January 1, 2003, did not have any impact on Williams' results of operations or financial position. The FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation -- Transition and Disclosure," which is effective for fiscal years ending after December 15, 2002. SFAS No. 148 amends SFAS No. 123 to permit two additional transition methods for a voluntary change to the fair value based method of accounting for stock-based employee compensation from the intrinsic method under APB No. 25. The 111 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) prospective method of transition under SFAS No. 123 is an option to the entities that adopt the recognition provisions under this statement in a fiscal year beginning before December 15, 2003. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements concerning the method of accounting used for stock-based employee compensation and the effects of that method on reported results of operations. Under SFAS No. 148, pro forma disclosures will be required in a specific tabular format in the "Summary of Significant Accounting Policies." Williams has applied the disclosure requirements of this statement effective December 31, 2002. The adoption had no effect on Williams' consolidated financial position or results of operations. Williams continues to account for its stock-based compensation plans under APB Opinion No. 25. See Employee stock-based awards. The FASB issued FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This Interpretation requires the fair value of guarantees issued or modified after December 31, 2002, be initially recognized by the guarantor at the inception of the guarantee, and expands the disclosure requirements for guarantees. Initial adoption of this Interpretation did not have any impact on Williams' results of operations or financial position. The expanded disclosure requirements have been presented in the Notes to Consolidated Financial Statements. The FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities." The Interpretation defines a variable interest entity (VIE) as an entity in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. The investments or other interests that will absorb portions of the VIE's expected losses or receive portions of the VIE's expected residual returns are called variable interests. Variable interests may include, but are not limited to, equity interests, debt instruments, beneficial interests, derivative instruments and guarantees. The Interpretation requires an entity to consolidate a VIE if that entity will absorb, through either a single variable interest or combination of variable interests, a majority of the VIE's expected losses, receive a majority of the VIE's expected residual returns, or both. If no party will absorb a majority of the expected losses or expected residual returns, no party will consolidate the VIE. The Interpretation must be applied to all VIE's created after January 31, 2003 and to existing VIE's for periods beginning after June 15, 2003. The assets, liabilities and non-controlling interests of a VIE consolidated as a result of this Interpretation should be measured and recorded at their carrying amount at the effective date of the Interpretation. Any difference between the net consolidated amount and the amount of any previously recognized interest in the newly consolidated entity shall be recognized as the cumulative effect of a change in accounting principle. Williams has completed a preliminary review of its investments and contractual arrangements to identify variable interest entities to meet the 2002 disclosure requirements of the Interpretation and has presented such disclosures in the Notes to Consolidated Financial Statements. Williams has not completed its full evaluation but currently believes that the effect of adoption of the Interpretation will not be material to the consolidated financial statements. On October 25, 2002, the EITF reached a consensus on Issue No. 02-3, "Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities." This Issue rescinds EITF Issue No. 98-10, the impact of which is to preclude fair value accounting for energy trading contracts that are not derivatives pursuant to SFAS No. 133 and commodity trading inventories. The EITF also reached a consensus that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. The consensus is applicable for fiscal periods beginning after December 15, 2002, except for physical trading commodity inventories purchased after October 25, 2002 which may not be reported at fair value. Williams will initially apply the consensus effective January 1, 2003 and will report the initial application as a cumulative effect of a change in accounting principle. The effect of initially applying the consensus will reduce net income by approximately $750 million to $800 million on an after tax basis. Physical trading commodity inventories at December 31, 2002 that were purchased prior to October 25, 2002 were reported at fair value at December 31, 2002 and 112 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) included in the effect of initially applying the consensus. The change results primarily from power tolling load serving, transportation and storage contracts not meeting the definition of a derivative and no longer being reported at fair value. These contracts will be accounted for under an accrual model. Physical trading commodity inventories will be stated at cost, not to be in excess of market. The accounting for Energy Marketing & Trading's energy-related contracts, which include contracts such as transportation, storage, load serving and tolling agreements, requires Williams to assess whether certain of these contracts are executory service arrangements or leases pursuant to SFAS No. 13. On January 23, 2003, the EITF reached a tentative consensus on Issue No. 01-8, "Determining Whether an Arrangement Contains a Lease," and directed the Working Group considering this Issue to further address certain matters, including transition. The March 14, 2003 report of the Working Group indicates the Working Group supports a prospective transition of this Issue where the consensus would be applied to arrangements consummated or substantively modified after the date of the final consensus. Williams is currently reviewing the impact of the tentative consensus on its energy-related contracts. Williams' preliminary review indicates that certain tolling agreements could be leases under the tentative consensus. If the EITF did not adopt a prospective transition and applied the consensus to existing arrangements there could be a significant impact to Williams' financial position and results of operations. 113 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 2. DISCONTINUED OPERATIONS SUMMARIZED RESULTS OF DISCONTINUED OPERATIONS Summarized results of discontinued operations for the years ended December 31, 2002, 2001, and 2000 are as follows:
2002 2001 2000 -------- --------- -------- (MILLIONS) 2002 TRANSACTIONS Revenues............................................ $3,793.2 $ 4,511.0 $3,219.9 Income (loss) from operations: Income before income taxes....................... $ 115.0 $ 238.0 $ 233.4 Impairment and net losses on sales............... (512.6) (184.7) -- Benefit (provision) for income taxes............. 144.4 (20.6) (88.4) -------- --------- -------- Income (loss) from discontinued operations..... $ (253.2) $ 32.7 $ 145.0 -------- --------- -------- WCG Revenues............................................ $ -- $ 329.5* $ 818.8 Loss from operations: Loss before income taxes......................... $ -- $ (271.3)* $ (252.4) Estimated before tax loss on disposal of WCG's Solutions segment.............................. -- -- (323.9) Estimated losses attributable to probable performance on WCG guarantee obligations....... -- (1,839.2) -- Benefit for income taxes......................... -- 797.4 156.8 Cumulative effect of change in accounting principle...................................... -- -- (21.6) -------- --------- -------- Loss from discontinued operations.............. $ -- $(1,313.1) $ (441.1) -------- --------- -------- Total net loss from discontinued operations.... $ (253.2) $(1,280.4) $ (296.1) ======== ========= ========
--------------- * Represents revenues and results of operations from January 1, 2001 through April 23, 2001. 114 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) SUMMARIZED ASSETS AND LIABILITIES OF DISCONTINUED OPERATIONS Summarized assets and liabilities of discontinued operations as of December 31, 2002 and 2001, are as follows:
2002 2001 ------ -------- (MILLIONS) Total current assets........................................ $441.6 $ 800.3 ------ -------- Property, plant and equipment -- net........................ 520.5 3,330.3 Other noncurrent assets..................................... 19.2 241.1 ------ -------- Total noncurrent assets................................... 539.7 3,571.4 ------ -------- Total assets.............................................. $981.3 $4,371.7 ====== ======== Long-term debt due within one year.......................... $ 68.6 $ 37.4 Other current liabilities................................... 217.3 523.1 ------ -------- Total current liabilities................................. 285.9 560.5 ------ -------- Long-term debt.............................................. 8.5 808.0 Other noncurrent liabilities................................ 9.7 90.7 ------ -------- Total noncurrent liabilities.............................. 18.2 898.7 ------ -------- Total liabilities......................................... $304.1 $1,459.2 ====== ========
The December 31, 2002 amounts include the assets and liabilities of the soda ash operations, the Midsouth refinery and related assets, the travel centers, and the bio-energy facilities as these had been approved for sale by Williams' board of directors although the sales were not yet complete. Because the sales are expected to close within twelve months, the noncurrent assets and liabilities of discontinued operations have been included in the current section of the Consolidated Balance Sheet as assets and liabilities held for sale at December 31, 2002. Therefore, the total assets of $981.3 million and the total liabilities of $304.1 million are recorded as current assets and current liabilities of discontinued operations in the Consolidated Balance Sheet at December 31, 2002. For 2001, the noncurrent assets and liabilities for these assets were not reclassified to current assets and liabilities in the Consolidated Balance Sheet, but are included in the assets and liabilities of discontinued operations. 2002 TRANSACTIONS As previously discussed, Williams began the process in 2002 of selling assets and/or businesses to address liquidity issues. In accordance with the provisions related to discontinued operations within SFAS No. 144, the results of operations (including any impairments, gains or losses), financial position and cash flows for the following assets and/or businesses, which have been sold or approved for sale, have been reflected in the consolidated financial statements and notes as 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 was recognized as income from discontinued operations in third-quarter 2002. Included as a component of 115 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) impairments and net losses on sales from discontinued operations (included in the preceding table) is a pre-tax loss of $6.4 million for the year ended December 31, 2002. Kern River was a segment within Gas Pipeline. Central During third-quarter 2002, Williams' board of directors approved an agreement to sell Central natural gas pipeline, for $380 million in cash and the assumption by the purchaser of $175 million in debt. The sale closed November 15, 2002. The sale agreement resulted from efforts to market this asset through a reserve price auction process that was initiated during second-quarter 2002. Included as a component of impairments and net losses on sales (included in the preceding table) is a pre-tax loss of $91.3 million for the year ended December 31, 2002. Central was a segment within Gas Pipeline. Soda ash operations In March 2002, Williams announced its intentions to sell its soda ash mining facility located in Colorado. During third-quarter 2002, Williams' board of directors approved a plan authorizing management to negotiate and facilitate a sale of its interest in the soda ash operations pursuant to terms of a proposed sales agreement. As a result of the board of directors' approval and management's expectation of consummation of a sale, these operations met the criteria within SFAS No. 144 to be reported as held for sale at December 31, 2002. The soda ash facility was previously written-down by $170 million in fourth-quarter 2001 to an estimated fair value at December 31, 2001. In April 2002, Williams initiated a reserve-auction process. As this process and negotiations with interested parties progressed through 2002, new information regarding estimated fair value became available. As a result, additional impairment charges totaling $133.5 million were recognized in 2002. The impairment charges are recorded as a component of impairments and net losses on sales (included in the preceding table), and are reflective of management's estimate of fair value associated with revised terms of its negotiations to sell the operations. The soda ash operations were part of the previously reported International segment. Mid-America and Seminole Pipelines On August 1, 2002, Williams completed the sale of its 98 percent interest in Mid-America Pipeline and 98 percent of its 80 percent ownership interest in Seminole Pipeline for $1.2 billion. The sale generated net cash proceeds of $1.15 billion. Included as a component of impairments and net losses on sales (included in the preceding table) is a pre-tax gain of $301.7 million for the year ended December 31, 2002. These assets were part of the Midstream Gas & Liquids segment. A performance guarantee of $50 million for Seminole Pipeline remained in effect at December 31, 2002. This guarantee was terminated in February 2003. Midsouth refinery and related assets During the second quarter of 2002, management announced its intention to sell its refining operations. On November 26, 2002 and pursuant to board of director approval, Williams announced it had reached an agreement to sell its refinery and other related operations located in Memphis, Tennessee. Impairment charges totaling $240.8 million were recorded during 2002 to reduce the carrying cost to management's estimate of fair market value based on information available through the reserve auction process and sales agreement negotiations. These impairments are recorded as components of impairments and net losses on sales (included in the preceding table). The sale closed on March 4, 2003. These operations were part of the Petroleum Services segment. Williams travel centers The travel centers had been identified as a business that does not fit into the new core focus and were marketed for sale through a reserve auction process. During the fourth quarter 2002 and pursuant to board of 116 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) director approval, Williams announced that it had signed a definitive agreement for the sale of the travel centers. Impairment charges and liability accruals totaling $146.6 million were recorded during 2002 to reduce the carrying cost to management's estimate of fair market value based on information available through the reserve auction process and sales agreement negotiations. In 2001, Williams also recorded $14.7 million of impairment and loss accruals relating to the travel centers. These impairments are recorded as components of impairments and net losses on sales from discontinued operations (included in the preceding table). The sale closed on February 27, 2003. These operations were part of the Petroleum Services segment. Bio-energy facilities Williams' bio-energy operations have been identified as assets not related to the new more narrowly focused business. During fourth-quarter 2002, Williams' board of directors approved a plan authorizing management to negotiate and facilitate a sale pursuant to terms of a proposed sales agreement. As a result of the board of directors' approval and management's expectation of consummation of a sale with the year, these operations met the criteria within SFAS No. 144 to be held for sale at December 31, 2002. On February 20, 2003, Williams announced it had signed a definitive agreement to sell these operations to a new company formed by Morgan Stanley Capital Partners. Impairment charges totaling $195.7 million, including $23 million related to goodwill, were recorded in 2002 to reduce the carrying cost to management's estimate of fair market value based on information available through a reserve auction process and sales agreement negotiations. These impairments are recorded as components of impairments and net losses on sales (included in the preceding table). These operations were part of the Petroleum Services segment. WCG Spinoff and related information 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, to holders of record on April 9, 2001, of Williams' common stock. Distribution of .822399 of a share of WCG common stock for each share of Williams common stock occurred on April 23, 2001. In accordance with APB Opinion 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, financial position and cash flows for WCG have been reflected in the accompanying consolidated financial statements and notes as discontinued operations. Williams, prior to the spinoff and in an effort to strengthen WCG's capital structure, entered into an agreement under which Williams contributed an outstanding promissory note from WCG of approximately $975 million and certain other assets, including the Williams Technology Center (Technology Center) and other ancillary assets under construction and a commitment to complete the construction. In return, Williams received newly issued common shares of WCG. The WCG common stock distribution was recorded as a dividend and resulted in a decrease to consolidated stockholders' equity of approximately $2 billion, which included an increase to accumulated other comprehensive income of approximately $21.3 million. The WCG shares retained by Williams had a carrying value of $95.9 million at the spinoff date. In addition, prior to the spinoff, Williams 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. See 2002 developments and accounting below for an update. 117 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Williams also provided a guarantee of WCG's obligations under a 1998 asset defeasance program (ADP) 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 lessor's cost of $750 million. See 2002 developments and accounting below for an update. 2001 post spinoff and accounting In third-quarter 2001, Williams purchased the Technology Center and three corporate aircraft from WCG for $276 million, which represents the approximate actual cost of construction of the Technology Center and the acquisition costs of the ancillary assets and aircraft. Williams then entered into long-term lease arrangements under which WCG was the sole lessee of the Technology Center and aircraft. Disclosures and announcements by WCG, prior to the filing of Williams 2001 Annual Report on Form 10-K on March 7, 2002, including WCG's announcement that it might seek to reorganize under the U.S. Bankruptcy Code, resulted in Williams concluding that it was probable that it would not fully realize the $375 million of receivables from WCG at December 31, 2001 nor recover its investment in WCG common stock. The receivables included a $106 million deferred payment for services provided to WCG prior to the spinoff and $269 million from the long term lease to WCG of the Technology Center and aircraft. In addition, Williams determined that it was probable that it would be required to perform under the $2.21 billion of guarantees and payment obligations, including the indirect credit support for $1.4 billion of WCG's Note Trust Notes and the guarantee of WCG's obligations under the ADP transaction. Other events that affected Williams' assessment included the credit downgrades of WCG, the bankruptcy of a significant competitor announced on January 28, 2002, and public statements by WCG regarding an ongoing comprehensive review of its bank secured credit arrangements. As a result of these factors, Williams, using the best information available prior to March 7, 2002 and under the circumstances, developed an estimated range of loss related to its total WCG exposure. Management utilized the assistance of external legal counsel and an external financial and restructuring advisor in making estimates related to its guarantees and payment obligations and ultimate recovery of the contractual amounts receivable from WCG. At that time, management believed that no loss within the range was more probable than another. Accordingly, Williams recorded the $2.05 billion minimum amount of the range of loss which is 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 in 2001 of $1.84 billion includes $1.77 billion minimum amount of the estimated range of loss from performance on $2.21 billion of guarantees and payment obligations, interest of $58 million on the WCG Note Trust Notes assumed by Williams and other expenses. With the exception of the interest on the WCG Note Trust Notes and other expenses, Williams assumed for purposes of this estimated loss that it would become an unsecured creditor of WCG for all or part of the amounts paid under the guarantees and payment obligations. However, it was probable that Williams would not be able to recover a significant portion of these unsecured claims. The estimated loss from the performance of the guarantees and payment obligations was based on the overall estimate of recoveries on amounts owed Williams as discussed below. Due to the amendment of the WCG Note Trust Notes discussed above, $1.1 billion of the accrued loss was classified as a long-term liability in the Consolidated Balance Sheet at December 31, 2001. The charge to continuing operations in 2001 of $213 million includes estimated losses from an assessment of the recoverability of carrying amounts of the $106 million deferred payment for services provided to WCG, the $269 million minimum lease payment receivable from WCG, and the remaining $25 million investment in WCG common stock. In third-quarter 2001, Williams recognized a $70.9 million loss related to the write-down of its investment in WCG common stock due to the decline in value which was determined to be other than temporary. A provision of $85 million on the deferred payment was based on the overall estimate of recoveries on amounts receivable using the same assumptions on collectability as discussed below. A provision of $103 million on the minimum lease payments receivable was based on an estimate of the fair value of the 118 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) leased assets. The $25 million write-off of the WCG stock investment was based on management's assessment of realization as a result of WCG's balance sheet restructuring program. The estimated range of loss assumed that Williams, as a creditor of WCG, would recover only a portion of its unsecured claims against WCG. Such claims included a $2.21 billion receivable from performance on guarantees and payment obligations and a $106 million deferred payment for services provided to WCG. With the assistance of external legal counsel and an external financial and restructuring advisor, and considering the best information available at that time and under the circumstances, management developed a range of loss on these receivables with a minimum loss of 80 percent on claims in a bankruptcy of WCG. Estimating the range of loss as a creditor involves making complex judgments and assumptions about uncertain outcomes. The actual loss differed from the 2001 recorded loss as Williams recognized additional losses in 2002. The minimum amount of loss in the range was estimated based on recoveries from a successful reorganization process under Chapter 11 of the U.S. Bankruptcy Code. To estimate recoveries of the unsecured creditors, Williams estimated an enterprise value of WCG using a present value analysis and reduced the enterprise value by the level of secured debt which may exist in WCG's restructured balance sheet. In its estimate of WCG's enterprise value, Williams considered a range of cash flow estimates based on information from WCG and from other external sources. Future cash flow projections were valued using discount rates ranging from 17 percent to 25 percent. The range of cash flows was based on different scenarios related to the growth, if any, of WCG's revenues and the impact that a bankruptcy may have on revenue growth. The range of discount rates considered WCG's assumed restructured capital structure and the market return that equity investors may require to invest in a telecommunications business operating in the current distressed industry environment. The range of loss also considered recoveries based on transaction values from recent telecommunications restructurings and from a liquidation of WCG's assets. At December 31, 2001, Williams had financial exposure from WCG of $375 million of receivables for which allowances totaling $188 million were established in 2001 and $2.21 billion of guarantees and payment obligations for which a total accrued loss of $1.77 billion was recorded in 2001. 2002 developments and accounting In 2002, Williams acquired all of the WCG Note Trust Notes by exchanging $1.4 billion of Williams Senior Unsecured 9.25 percent Notes due March 2004. WCG was indirectly obligated to reimburse Williams for any payments Williams is required to make in connection with the WCG Note Trust Notes. On March 29, 2002, Williams funded the purchase price of $754 million related to WCG's March 8, 2002 exercise of its option to purchase the covered network assets under the ADP transaction. Williams then became entitled to an unsecured note from WCG for the same amount. On April 22, 2002, WCG filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. WCG's Chapter 11 Plan of Reorganization (Plan) was confirmed by the United States Bankruptcy Court for the Southern District of New York (Court) on September 30, 2002. On October 15, 2002, WCG consummated the Plan. The Plan includes (1) mutual releases, effective October 15, 2002, between WCG (and all of its affiliates and each of their present and former directors, officers, employees and agents), the Official Creditors Committee and Williams (and all of its affiliates and each of their present and former directors, officers, employees and agents), which forever bar causes of action against Williams that are based in whole or in part on any act, omission, event, condition or thing in existence or that occurred in whole or in part prior to October 15, 2002, and arising out of or relating in any way to WCG or its present or former assets; (2) a channeling injunction, effective October 15, 2002, which enjoins the holders of unsecured claims against WCG from taking any action to assert, seek or obtain a recovery from Williams; (3) the sale by Williams to Leucadia National Corporation (Leucadia) for $180 million in cash of Williams' claims against WCG related to the WCG Note Trust Notes, the funding of the WCG purchase option for the covered network assets and 119 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the deferred payment for services and (4) the sale by Williams to WCG of the Technology Center for (a) a seven and one-half year promissory note in the principal amount of $100 million with interest at 7 percent (Long Term Note), and (b) a four year promissory note (which may be pre-paid without penalty) with a face amount of $74.4 million and an original principal amount of $44.8 million (Short Term Note), both of which are secured by a mortgage on the Technology Center and certain other collateral. Interest on the principal amount of the Short Term Note is capitalized on December 31 of each year beginning in 2003 and accrues at the following rates: 10 percent interest from October 15, 2002 to December 31, 2003; 12 percent interest from January 1, 2004 to December 31, 2004; 14 percent interest from January 1, 2005 to December 31, 2005 and 16 percent interest from January 1, 2006 to December 29, 2006. The sale of certain of Williams' claims against WCG to Leucadia for $180 million in cash and the sale by Williams to WCG of the Technology Center were completed in 2002. The Plan does not extinguish or eliminate claims that WCG shareholders have made against Williams and its directors and officers. For information relating to litigation involving the distribution of WCG shares and claims that WCG shareholders have made against Williams and its directors and officers see Note 16. At December 31, 2002, Williams has a $121.5 million receivable (original principal amount of $144.8 million) from WCG for the promissory notes relating to the sale of the Technology Center pursuant to the Plan. The notes were initially recorded at fair value based on contractual cash flows and an estimated discount rate considering the creditworthiness of WCG, the amount and timing of the cash flows and Williams' security in the Technology Center and certain other collateral. The fourth quarter 2002 sale of certain of Williams' claims against WCG to Leucadia resulted in the elimination of $2.26 billion of receivables, and the associated $2.08 billion allowance, from Williams' Consolidated Balance Sheet. In 2002, Williams recorded in continuing operations additional pre-tax charges of $268.7 million related to the recovery and settlement of these receivables and claims. Williams has provided guarantees in the event of nonpayment by WCG on certain lease performance obligations of WCG that extend through 2042 and have a maximum potential exposure of approximately $53 million. Williams' exposure declines systematically throughout the remaining term of WCG's obligations. The carrying value of these guarantees was approximately $48 million at December 31, 2002 and are recorded as liabilities. OTHER WCG-RELATED INFORMATION Williams has received a private letter ruling from the Internal Revenue Service (IRS) stating that the distribution of WCG common stock associated with the 2001 spin-off would be tax-free to Williams and its stockholders. Although private letter rulings are generally binding on the IRS, Williams will not be able to rely on this ruling if any of the factual representations or assumptions that were made to obtain the ruling are, or become, incorrect or untrue in any material respect. However, Williams is not aware of any facts or circumstances that would cause any of the representations or assumptions to be incorrect or untrue in any material respect. The distribution could also become taxable to Williams, but not Williams shareholders, under the Internal Revenue Code (IRC) in the event that Williams' or WCG's subsequent business combinations were deemed to be part of a plan contemplated at the time of distribution and would constitute a total cumulative change of more than 50 percent of the equity interest in either company. Williams, with respect to shares of WCG's common stock that Williams retained, committed to the IRS to dispose of all of the WCG common stock that it retained as soon as market conditions allow, but in any event not longer than five years after the spinoff. As part of a separation agreement, but subject to an additional favorable ruling by the IRS that such a limitation is not inconsistent with any ruling issued to Williams regarding the tax-free treatment of the spinoff, Williams agreed not to dispose of the retained WCG shares for three years from the date of distribution and to notify WCG of an intent to dispose of such shares. However, on February 28, 2002, Williams filed with the IRS a request to withdraw its request for a ruling that 120 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the agreement between Williams and WCG that Williams would not transfer any retained WCG stock for a three year period from the spinoff would not be inconsistent with the favorable tax-free treatment ruling issued to Williams. Williams represented in the withdrawal request that it had abandoned its intent to make the lock-up effective, thereby making the ruling request moot. WCG common stock held by Williams was included in the WCG equity interests cancelled and discharged in accordance with the Plan. NOTE 3. INVESTING ACTIVITIES Investing income (loss) for the years ended December 31, 2002, 2001 and 2000, is as follows:
2002 2001 2000 ------- ------- ----- (MILLIONS) Equity earnings (losses)*................................. $ 72.0 $ 22.7 $21.6 Income (loss) from investments*........................... 42.1 4.2 .8 Write-down of investment in WCG stock..................... -- (95.9) -- Loss provision for WCG receivables (see Note 2)........... (268.7) (188.0) -- Interest income and other................................. 44.9 88.4 66.7 ------- ------- ----- Total................................................... $(109.7) $(168.6) $89.1 ======= ======= =====
--------------- * Items also included in segment profit. Equity earnings for the year ended December 31, 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 Natural Gas System (Gulfstream), an interstate natural gas pipeline subject to FERC regulations and an equity affiliate of Williams. The fee paid by Gulfstream, 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. Income (loss) from investments for the year ended December 31, 2002, includes the following: - $58.5 million gain on sale of Williams' investment in AB Mazeikiu Nafta, a Lithuanian oil refinery, pipeline and terminal complex, which was included in the previously reported International segment - $12.3 million write-down of Gas Pipeline's investment in a pipeline project which was cancelled in 2002 - $10.4 million net write-down pursuant to the sale of Williams' equity interest in Alliance Pipeline, a Canadian and U.S. gas pipeline, which was included in the Gas Pipeline segment - $8.7 million gain on sale of Williams' general partner equity interest in Northern Border Partners, L.P., which was included in the Gas Pipeline segment Income (loss) from investments for the year ended December 31, 2001, includes the following: - $27.5 million gain on the sale of Williams' limited partnership interest in Northern Border Partners, L.P., which was included in the Gas Pipeline segment - $23.3 million of write-downs of certain investments which were included in the Energy Marketing & Trading segment The $95.9 million write-down of the WCG investment in 2001 resulted from a decline in the value of the WCG common stock which was determined to be other than temporary. 121 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Investments at December 31, 2002 and 2001, are as follows:
2002 2001 -------- -------- (MILLIONS) Equity method: Gulfstream Natural Gas System, LLC -- 50%................. $ 734.4 $ 467.8 Alliance Pipeline -- 14.6% in 2001........................ -- 186.8 Longhorn Partners Pipeline, L.P. -- 32.1%................. 89.3 105.1 Discovery Pipeline -- 50%................................. 75.3 70.2 ACCROVEN -- 49.3%......................................... 60.4 57.1 Alliance Aux Sable -- 14.6%............................... 54.8 53.9 AB Mazeikiu Nafta -- 33% in 2001.......................... -- 39.1 Other..................................................... 177.8 191.0 -------- -------- 1,192.0 1,171.0 Cost method: Gulf Liquids Holdings, LLC................................ -- 92.2 Algar Telecom S.A. -- common and preferred stock.......... 52.8 52.8 Asian Infrastructure Fund................................. 27.0 36.3 Indonesian Toll Road...................................... 23.7 23.7 Other..................................................... 61.1 64.4 -------- -------- 164.6 269.4 Advances to affiliates and other............................ 119.0 115.5 -------- -------- $1,475.6 $1,555.9 ======== ========
As previously noted, investments in Alliance Pipeline and AB Mazeikiu Nafta were sold during 2002. During 2002, Williams consolidated Gulf Liquids Holdings, LLC due to changes in 2002. Advances to affiliates at December 31, 2001 include a $75 million loan to AB Mazeikiu Nafta, which was sold in third-quarter 2002. At December 31, 2002, advances to affiliates are primarily related to notes and interest receivable from Longhorn Partners Pipeline, L.P. (Longhorn) which was held by Petroleum Services. Dividends and distributions received from companies carried on the equity basis were $81 million, $51 million and $21 million in 2002, 2001 and 2000, respectively. The $27.4 million construction completion fee described previously is included in the 2002 distributions. At December 31, 2002, commitments for additional investments in Gulfstream and certain international cost investments are $48.6 million. Williams, Williams Gas Pipeline Company, L.L.C. and/or Williams Production Holdings LLC have guaranteed commercial letters of credit totaling $16.9 million on behalf of ACCROVEN. These expire in January 2004, have no carrying value and are fully collateralized with cash. Certain of the entities in which Williams invests continue to be reviewed to determine if they are variable interest entities under FASB Interpretation No. 46, which will be adopted for existing entities in the third quarter of 2003. These entities are Gulfstream, Longhorn Partners Pipeline, L.P. and Discovery Pipeline. Gulfstream is a joint venture that constructed and operates a natural gas pipeline extending from Alabama through the Gulf of Mexico and into Florida. Gulfstream recognized net income of approximately $61.7 million on $28.5 million of revenues in 2002 and holds $1.5 billion of total assets at December 31, 2002. The net income total includes $51.2 million of AFUDC income. Williams has a commitment to provide an additional $19.3 million investment in Gulfstream. Longhorn is a joint venture that is currently developing a pipeline to transport gasoline, diesel and jet fuel from Gulf Coast refineries to terminals in the Permian Basin and the 122 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) El Paso gateway market. Due to continued start-up activities related to its development of the pipeline, Longhorn did not recognize revenue in 2002 but had $495 million of total assets at December 31, 2002. Williams holds a receivable from Longhorn of approximately $138.8 million at December 31, 2002. Discovery Pipeline (Discovery) is a joint venture gas gathering and processing system in southeast Louisiana and offshore Gulf of Mexico. Discovery recognized net income of approximately $4.7 million on $83.2 million of revenue in 2002 and holds $432 million of total assets at December 31, 2002. In addition to its investment, Williams has provided a guarantee in the event of nonperformance on 50 percent of Discovery's debt obligation, or approximately $126.9 million at December 31, 2002. Performance under the guarantee generally would occur upon a failure of payment by the financed entity or certain events of default related to the guarantor. These events of default primarily relate to bankruptcy and/or insolvency of the guarantor. The guarantee expires at the end of 2003, and no amounts have been accrued as of December 31, 2002. Summarized financial position and results of operations of Williams' equity method investments are as follows: Financial position at December 31, 2002 and 2001, is as follows:
2002 2001 -------- -------- (MILLIONS) Current assets.............................................. $ 244.1 $ 199.1 Noncurrent assets........................................... 3,739.6 3,031.6 Current liabilities......................................... 256.7 252.3 Noncurrent liabilities...................................... 813.0 917.3
Results of operations for the years ended December 31, 2002, 2001 and 2000, are as follows:
2002 2001 2000 ------ ------ ------ (MILLIONS) Gross revenue.............................................. $621.7 $588.2 $322.7 Operating profit........................................... 148.6 54.0 85.1 Net income................................................. 177.4 22.2 33.9
123 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 4. ASSET SALES, IMPAIRMENTS AND OTHER ACCRUALS Significant gains or losses from asset sales, impairments and other accruals included in other (income) expense -- net within segment costs and expenses for the years ended December 31, 2002, 2001 and 2000, are as follows:
(GAINS) LOSSES ------------------------ 2002 2001 2000 ------- ------ ----- (MILLIONS) ENERGY MARKETING & TRADING Guarantee loss accruals and write-offs................... $ 56.2 $ -- $47.5 Impairment of Worthington generation facility............ 44.7 -- -- Loss accruals and impairment of other power related assets................................................ 82.6 -- 16.3 Impairment of goodwill................................... 61.1 -- -- Impairment of plant for terminated expansion............. -- 13.3 -- GAS PIPELINE Loss accrual for litigation and claims................... -- 18.3 -- EXPLORATION & PRODUCTION Gain on sale of certain interests in gas producing properties in Wyoming................................. (120.3) -- -- Gain on sale of certain interests in gas producing properties in Anadarko Basin.......................... (21.4) -- -- MIDSTREAM GAS & LIQUIDS Impairment of Canadian assets............................ 115.0 -- -- Impairment of south Texas assets......................... -- 13.8 -- PETROLEUM SERVICES Impairment of Alaska assets.............................. 18.4 -- -- Gain on sale of certain convenience stores............... -- (75.3) -- Impairment of end-to-end mobile computing systems business.............................................. -- 12.1 11.9
The guarantee loss accruals and write-offs within Energy Marketing & Trading of $56.2 million in 2002 includes accruals for commitments for certain assets that were previously planned to be used in power projects, write-offs associated with a terminated power plant project and a $13.2 million reversal of loss accruals related to the wind-down of its mezzanine lending business. The impairment of the Worthington generation facility was recorded pursuant to the sale of the facility, which closed in first-quarter 2003. The loss accruals and impairments of other power related assets were recorded pursuant to reducing activities associated with the distributive power generation business. The impairment of goodwill includes a $57.5 million goodwill impairment loss in second-quarter 2002 reflecting a decline in the fair value from 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 inclusive of the fair value of contracts with affiliates, which are not reflected at fair value in the financial statements. The fair value of these contracts was estimated using a discounted cash flow model with natural gas pricing assumptions based on current market information. The remaining goodwill was evaluated for impairment at the end of 2002 and an additional impairment of $3.0 million was required based on management's estimate of the fair value of Energy Marketing & Trading at December 31, 2002. 124 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Approximately $38 million of the Canadian asset impairment reflects a reduction of carrying cost to management's estimate of fair market value, determined primarily from information available from efforts to sell these assets. The balance is associated with assets whose carrying costs were determined not fully recoverable and reduced to estimated fair value. NOTE 5. PROVISION (BENEFIT) FOR INCOME TAXES The provision (benefit) for income taxes from continuing operations includes:
2002 2001 2000 ------- ------ ------ (MILLIONS) Current: Federal................................................. $(126.7) $211.2 $138.8 State................................................... 27.4 22.7 21.6 Foreign................................................. 26.4 13.0 4.2 ------- ------ ------ (72.9) 246.9 164.6 Deferred: Federal................................................. (98.5) 306.4 320.8 State................................................... (49.3) 38.6 58.8 Foreign................................................. 25.7 17.7 (2.7) ------- ------ ------ (122.1) 362.7 376.9 ------- ------ ------ Total provision (benefit)............................ $(195.0) $609.6 $541.5 ======= ====== ======
Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the provision (benefit) for income taxes are as follows:
2002 2001 2000 ------- ------ ------ (MILLIONS) Provision (benefit) at statutory rate..................... $(243.8) $494.4 $476.7 Increases (reductions) in taxes resulting from: State income taxes (net of federal benefit)............. (14.2) 39.8 52.3 Foreign operations -- net............................... 94.7 12.2 (2.1) Change in valuation allowance (federal only)............ (119.1) 44.5 -- Non-deductible impairment of goodwill................... 21.7 -- -- Income tax (credits) recapture.......................... 26.8 -- (5.7) Other -- net............................................ 38.9 18.7 20.3 ------- ------ ------ Provision (benefit) for income taxes...................... $(195.0) $609.6 $541.5 ======= ====== ======
125 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Significant components of deferred tax liabilities and assets as of December 31, 2002 and 2001, are as follows:
2002 2001 -------- -------- (MILLIONS) Deferred tax liabilities: Property, plant and equipment............................. $2,223.5 $3,075.1 Energy risk management and trading -- net................. 582.7 1,023.1 Investments............................................... 568.0 510.2 Other..................................................... 168.9 170.6 -------- -------- Total deferred tax liabilities......................... 3,543.1 4,779.0 -------- -------- Deferred tax assets: Guarantee obligations related to WCG...................... 16.9 742.5 Minimum tax credits....................................... 151.7 249.0 Accrued liabilities....................................... 314.5 245.4 Investments............................................... 12.5 173.3 Receivables............................................... 8.2 63.1 Loss carryovers........................................... 216.2 73.5 Rate refunds.............................................. 3.4 35.7 Other..................................................... 78.5 120.5 -------- -------- Total deferred tax assets.............................. 801.9 1,703.0 -------- -------- Valuation allowance....................................... 43.2 173.3 -------- -------- Net deferred tax assets................................ 758.7 1,529.7 -------- -------- Overall net deferred tax liabilities...................... $2,784.4 $3,249.3 ======== ========
Cash payments for income taxes, net of refunds were $36 million, $87 million and $112 million in 2002, 2001 and 2000, respectively. Valuation allowances were established during 2001 for deferred tax assets from basis differences in investments for which the ultimate realization of the tax asset was dependent on future capital gains. The recording of the investment in the retained shares of WCG after the spinoff (see Note 2) resulted in a $129 million tax asset for which a valuation allowance of $129 million was established. The remaining $44 million of the tax asset, for which a valuation allowance was established, resulted from the financial impairment of certain investments during 2001 (see Note 3). These valuation allowances were reduced during 2002 as a result of capital gains generated during the year. The impact of foreign operations on the effective tax rate increased during 2002 due to the recognition of U.S. tax on foreign dividend distributions and recording of a financial impairment on certain foreign assets for which a valuation allowance was established. Federal net operating loss carryovers of $480 million at the end of 2002 are expected to be utilized by Williams prior to expiration in 2012 through 2022. Capital loss carryovers of $67 million at the end of 2002 are not expected to be utilized by Williams prior to expiration in 2007; therefore, a valuation allowance of $26 million was established. 126 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 6. EARNINGS (LOSS) PER SHARE Basic and diluted earnings (loss) per common share are computed for the years ended December 31, 2002, 2001 and 2000, as follows:
2002 2001 2000 ----------- ----------- ----------- (DOLLARS IN MILLIONS, EXCEPT PER-SHARE AMOUNTS; SHARES IN THOUSANDS) Income (loss) from continuing operations............. $ (501.5) $ 802.7 $ 820.4 Convertible preferred stock dividends (see Note 13)................................................ (90.1) -- -- -------- -------- -------- Income (loss) from continuing operations available to common stockholders for basic and diluted earnings per share.......................................... $ (591.6) $ 802.7 $ 820.4 ======== ======== ======== Basic weighted-average shares........................ 516,793 496,935 444,416 Effect of dilutive securities: Stock options...................................... -- 3,632 4,904 -------- -------- -------- Diluted weighted-average shares...................... 516,793 500,567 449,320 -------- -------- -------- Earnings (loss) per share from continuing operations: Basic.............................................. $ (1.14) $ 1.62 $ 1.85 ======== ======== ======== Diluted............................................ $ (1.14) $ 1.61 $ 1.83 ======== ======== ========
For the year ended December 31, 2002, diluted earnings (loss) per share is the same as the basic calculation. The inclusion of any stock options, convertible preferred stock and unvested deferred stock would be antidilutive as Williams reported a loss from continuing operations for this period. As a result, for the year ended December 31, 2002, approximately 666 thousand weighted-average stock options, approximately 11.3 million weighted-average shares related to the assumed conversion of the 9 7/8 percent cumulative convertible preferred stock and approximately 3.6 million weighted-average unvested deferred shares, that otherwise would have been included, have been excluded from the computation of diluted earnings per common share. Additionally, approximately 38.7 million, 15.3 million and 7.2 million options to purchase shares of common stock with weighted-average exercise prices of $19.90, $36.12 and $43.11, respectively, were outstanding on December 31, 2002, 2001 and 2000, respectively, but have been excluded from the computation of diluted earnings per share. Inclusion of these shares would have been antidilutive, as the exercise prices of the options exceeded the average market prices of the common shares for the respective years. NOTE 7. EMPLOYEE BENEFIT PLANS The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated. It also presents a reconciliation of the funded status of these benefits to the amount recorded in the Consolidated Balance Sheet at December 31 of each year indicated. Prior year amounts have been restated to exclude those benefit plans where it is anticipated that Williams will no longer serve as sponsor related to those operations reported as discontinued operations (see Note 1). Changes in the obligations or assets of continuing plans associated with the transfer of such 127 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) obligations or assets in a sale or planned sale reflected as discontinued operations have been reflected as divestitures in the following tables.
OTHER POSTRETIREMENT PENSION BENEFITS BENEFITS ----------------- --------------------- 2002 2001 2002 2001 ------- ------- --------- --------- (MILLIONS) Change in benefit obligation: Benefit obligations at beginning of year..... $ 994.2 $ 907.2 $ 489.0 $ 466.8 Service cost................................. 37.8 36.1 7.1 6.9 Interest cost................................ 67.5 69.5 31.8 29.5 Plan participants' contributions............. -- -- 3.9 2.7 Curtailment.................................. (.8) -- -- -- Settlement benefits paid..................... (31.6) -- -- -- Benefits paid................................ (117.8) (62.6) (26.3) (23.8) Divestitures................................. (3.3) (2.3) (27.0) -- Special termination benefit cost............. 33.0 -- 1.5 -- Actuarial (gain) loss........................ (72.5) 46.3 (69.5) 6.9 ------- ------- ------- ------- Benefit obligation at end of year............ 906.5 994.2 410.5 489.0 ------- ------- ------- ------- Change in plan assets: Fair value of plan assets at beginning of year...................................... 866.4 959.0 247.6 254.2 Actual return on plan assets................. (112.2) (79.9) (34.9) (14.4) Divestitures................................. -- (11.8) (20.2) -- Employer contributions....................... 98.3 61.7 23.8 28.9 Plan participants' contributions............. -- -- 3.9 2.7 Benefits paid................................ (117.8) (62.6) (26.3) (23.8) Settlement benefits paid..................... (31.6) -- -- -- ------- ------- ------- ------- Fair value of plan assets at end of year..... 703.1 866.4 193.9 247.6 ------- ------- ------- ------- Funded status.................................. (203.4) (127.8) (216.6) (241.4) Unrecognized net actuarial loss................ 353.1 254.0 14.3 37.9 Unrecognized prior service credit.............. (11.9) (15.4) (1.5) (1.3) Unrecognized transition obligation............. -- -- 28.2 44.8 ------- ------- ------- ------- Prepaid (accrued) benefit cost................. $ 137.8 $ 110.8 $(175.6) $(160.0) ======= ======= ======= =======
Amounts recognized in the Consolidated Balance Sheet consist of: Prepaid benefit cost............................. $200.6 $135.1 $ -- $ -- Accrued benefit cost............................. (91.6) (28.2) (175.6) (160.0) Intangible asset................................. -- 1.4 -- -- Accumulated other comprehensive income (before tax)........................................... 28.8 2.5 -- -- ------ ------ ------- ------- Prepaid (accrued) benefit cost................... $137.8 $110.8 $(175.6) $(160.0) ====== ====== ======= =======
128 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Net pension and other postretirement benefit expense consists of the following:
PENSION BENEFITS ------------------------ 2002 2001 2000 ------ ------ ------ (MILLIONS) Components of net periodic pension expense: Service cost............................................. $ 37.8 $ 36.1 $ 33.2 Interest cost............................................ 67.5 69.5 67.4 Expected return on plan assets........................... (77.6) (96.5) (94.1) Amortization of transition asset......................... -- (1.1) (1.2) Amortization of prior service credit..................... (2.8) (2.6) (2.6) Recognized net actuarial loss............................ 4.0 .7 .2 Regulatory asset amortization (deferral)................. (8.4) 5.3 5.1 Settlement/curtailment expense........................... 9.4 -- -- Special termination benefit cost......................... 33.0 -- 11.6 ------ ------ ------ Net periodic pension expense............................... $ 62.9 $ 11.4 $ 19.6 ====== ====== ======
OTHER POSTRETIREMENT BENEFITS ------------------------------ 2002 2001 2000 -------- -------- -------- (MILLIONS) Components of net periodic postretirement benefit expense: Service cost............................................. $ 7.1 $ 6.9 $ 7.5 Interest cost............................................ 31.8 29.5 33.1 Expected return on plan assets........................... (18.9) (22.6) (17.3) Amortization of transition obligation.................... 4.1 4.1 4.1 Amortization of prior service cost....................... .2 .1 .2 Recognized net actuarial loss (gain)..................... -- (2.6) (.9) Regulatory asset amortization............................ 3.7 14.7 8.7 Settlement/curtailment expense........................... 13.5 -- -- Special termination benefit cost......................... 1.5 -- 1.4 ------ ------ ------ Net periodic postretirement benefit expense................ $ 43.0 $ 30.1 $ 36.8 ====== ====== ======
The projected benefit obligation and fair value of plan assets for the pension plans with projected benefit obligations in excess of plan assets were $392.7 million and $186.3 million, respectively, as of December 31, 2002, and $891.8 million and $743.7 million, respectively, as of December 31, 2001. The accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $260.3 million and $169.9 million, respectively, as of December 31, 2002. The accumulated benefit obligation for pension plans with accumulated benefit obligations in excess of plan assets was $28.2 million as of December 31, 2001. There were no assets for these plans as of December 31, 2001. 129 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following are the weighted-average assumptions utilized as of December 31 of the year indicated:
OTHER POSTRETIREMENT PENSION BENEFITS BENEFITS ----------------- --------------- 2002 2001 2002 2001 ------- ------- ------ ------ Discount rate........................................... 7% 7.5% 7% 7.5% Expected return on plan assets.......................... 8.5 10 8.5 10 Expected return on plan assets (net of effective tax rate)................................................. N/A N/A 7 8.2 Rate of compensation increase........................... 5 5 N/A N/A
The annual assumed rate of increase in the health care cost trend rate for 2003 is 12 percent, and systematically decreases to 5 percent by 2016. The various nonpension postretirement benefit plans which Williams sponsors provide for retiree contributions and contain other cost-sharing features such as deductibles and coinsurance. The accounting for these plans anticipates future cost-sharing changes to the written plans that are consistent with Williams' expressed intent to increase the retiree contribution rate generally in line with health care cost increases. The health care cost trend rate assumption has a significant effect on the amounts reported. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
POINT INCREASE POINT DECREASE -------------- -------------- (MILLIONS) Effect on total of service and interest cost components... $ 5.6 $ (4.6) Effect on postretirement benefit obligation............... 54.5 (44.5)
The amount of postretirement benefit costs deferred as a regulatory asset at December 31, 2002 and 2001, is $57.5 million and $56 million, respectively, and is expected to be recovered through rates over approximately 11 years. Williams maintains various defined-contribution plans. Williams recognized costs related to continuing operations of $53 million in 2002, $35 million in 2001 and $29 million in 2000 for these plans. In 2002, these costs included the cost related to additional contributions to an employee stock ownership plan resulting from the retirement of related external debt. 130 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 8. INVENTORIES Inventories at December 31, 2002 and 2001, are as follows:
2002 2001 ------ ------ (MILLIONS) Raw materials: Crude oil................................................. $ 18.3 $ 31.0 Finished goods: Refined products.......................................... 73.6 111.0 Natural gas liquids....................................... 115.6 142.6 General merchandise....................................... 4.4 5.4 ------ ------ 193.6 259.0 ------ ------ Materials and supplies...................................... 105.8 117.1 Natural gas in underground storage.......................... 125.4 136.4 ------ ------ $443.1 $543.5 ====== ======
As of December 31, 2002 and 2001, approximately 43 percent and 52 percent of inventories, respectively, were stated at fair value. Inventories, primarily related to energy risk management and trading activities, stated at fair value at December 31, 2002 and 2001, included refined products of $23.1 million and $90.8 million, respectively; natural gas in underground storage of $76.2 million and $65.3 million, respectively; and natural gas liquids of $90.7 million and $97.9 million, respectively. Inventories determined using the LIFO cost method were approximately six percent of inventories at both December 31, 2002 and 2001. The remaining inventories were primarily determined using the average-cost method. During 2002, lower-of-cost or market reductions of approximately $18.2 million were recognized with respect to certain power-related inventories included in materials and supplies. EITF No. 02-3, issued October 25, 2002, does not permit mark-to-market accounting for inventory purchased subsequent to that date. Inventories purchased up to that date are permitted to apply mark-to-market accounting until EITF No. 02-3 is adopted. As of December 31, 2002, Williams had between $30 million and $50 million of marked-to-market inventory that will be included in a January 1, 2003 cumulative effect of change in accounting principle upon adoption of EITF No. 02-3 (see Recent accounting standards in Note 1). 131 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 9. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment at December 31, 2002 and 2001, is as follows:
2002 2001 --------- --------- (MILLIONS) Cost: Energy Marketing & Trading................................ $ 420.9 $ 362.6 Gas Pipeline.............................................. 8,152.5 7,760.1 Exploration & Production.................................. 3,417.0 3,348.0 Midstream Gas & Liquids................................... 5,181.4 4,868.2 Williams Energy Partners.................................. 1,348.1 1,304.8 Petroleum Services........................................ 291.0 506.2 Other..................................................... 228.8 285.4 --------- --------- 19,039.7 18,435.3 Accumulated depreciation, depletion and amortization........ (4,322.0) (4,046.4) --------- --------- $14,717.7 $14,388.9 ========= =========
Depreciation, depletion and amortization expense for property, plant and equipment was $770.9 million, $622.2 million and $511 million, respectively, in 2002, 2001 and 2000. Included in gross property, plant and equipment at December 31, 2002 and 2001, is approximately $1 billion and $940 million, respectively, of construction in progress which is not yet subject to depreciation. In addition, property of Exploration & Production includes approximately $774 million and $839 million at December 31, 2002 and 2001, respectively, of capitalized costs from the Barrett acquisition related to properties with probable reserves not yet subject to depletion. Commitments for construction and acquisition of property, plant and equipment are approximately $448 million at December 31, 2002. Included in net property, plant and equipment is approximately $1.6 billion and $1.7 billion at December 31, 2002 and 2001, respectively, related to amounts in excess of the original cost of the regulated facilities within Gas Pipeline as a result of Williams' and prior acquisitions. This amount is being amortized over the estimated remaining useful lives of these assets at the date of acquisition. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction. 132 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 10. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES Under Williams' cash-management system, certain subsidiaries' cash accounts reflect credit balances to the extent checks written have not been presented for payment. The amounts of these credit balances included in accounts payable are approximately $59 million and $30 million at December 31, 2002 and 2001, respectively. Accrued liabilities at December 31, 2002 and 2001, are as follows:
2002 2001 -------- -------- (MILLIONS) Interest.................................................... $ 307.9 $ 209.0 Accrued liabilities related to the RMT note payable......... 237.0 -- Employee costs.............................................. 215.3 350.6 Deposits received from customers relating to energy risk management and trading and hedging activities............. 141.2 265.5 Taxes other than income taxes............................... 127.9 106.8 Income taxes................................................ 63.3 105.7 Derivative liability........................................ 53.2 37.7 Transportation and exchange gas payable..................... 52.3 62.3 Deferred revenue............................................ 45.9 87.9 Other....................................................... 308.0 542.3 -------- -------- $1,552.0 $1,767.8 ======== ========
133 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 11. DEBT, LEASES AND BANKING ARRANGEMENTS NOTES PAYABLE AND LONG-TERM DEBT Notes payable and long-term debt at December 31, 2002 and 2001, is as follows:
WEIGHTED- AVERAGE DECEMBER 31, INTEREST -------------------- RATE(1) 2002 2001 --------- --------- -------- (MILLIONS) Notes payable: Secured(2).......................................... 5.8% $ 934.8 $ -- Unsecured notes payable............................. -- -- 1,424.5 --------- -------- Total notes payable................................... $ 934.8 $1,424.5 ========= ======== Long-term debt: Secured long-term debt Revolving credit loans........................... 7.6% $ 81.0 $ -- Debentures, 9.9%, payable 2020................... 9.9 28.7 -- Notes, 7.7%-9.45%, payable through 2022.......... 8.3 558.8 -- Notes, adjustable rate, payable through 2007..... 5.7 183.2 -- Other, payable 2003.............................. 6.7 20.9 -- Unsecured long-term debt Revolving credit loans........................... -- -- 53.7 Commercial paper(3).............................. -- -- 300.0 Debentures, 6.25%-10.25%, payable through 2031... 7.4 1,548.2 1,585.4 Notes, 6.125%-9.25%, payable through 2032(4)..... 7.8 9,500.5 6,510.7 Notes, adjustable rate, payable through 2004..... 5.7 759.9 1,192.9 Other, payable through 2006...................... 5.2 158.1 49.4 Capital leases, payable through 2005............. 6.6 139.9 -- --------- -------- 12,979.2 9,692.1 Long-term debt due within one year.................... (1,082.8) (999.4) --------- -------- Total long-term debt.................................. $11,896.4 $8,692.7 ========= ========
--------------- (1) At December 31, 2002. (2) Interest rate for $921.8 million is based on the Eurodollar rate plus 4 percent per annum. The principal balance includes interest accruing to the note at a fixed rate of 14 percent compounded quarterly. (3) 2001 included $300 million of commercial paper which was classified as noncurrent based on Williams' intent and ability to refinance on a long-term basis. (4) Includes $1.1 billion of 6.5 percent notes, payable 2007 subject to remarketing in 2004 (FELINE PACS). If a remarketing is unsuccessful in 2004 and a second remarketing in February 2005 is unsuccessful as defined in the offering document of the FELINE PACS, then Williams could exercise its right to foreclose on the notes in order to satisfy the obligation of the holders of the equity forward contracts requiring the holder to purchase Williams common stock (see Note 13). 134 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Notes payable at December 31, 2002, includes a $921.8 million secured note (RMT note payable), which is discussed in detail below. In addition, Williams has entered into a short-term credit agreement secured by the assets of a gas processing plant in Colorado within Exploration & Production with $13 million outstanding at December 31, 2002. Notes payable at December 31, 2001, included $1.1 billion of commercial paper and $300 million of other various short-term credit agreements with a weighted-average interest rate of 3.33 percent. During third-quarter 2002, Williams' credit ratings were lowered below investment grade and Williams was unable to complete a renewal of its unsecured short-term-credit facility. As a result, Williams amended its revolving credit facility to make it secured, obtained additional secured credit facilities and amended other outstanding debt agreements. The following is a discussion of the terms of these arrangements. REVOLVING CREDIT FACILITIES Under the terms of Williams' amended revolving credit agreement, Northwest Pipeline and Transcontinental Gas Pipe Line have access to $400 million and Texas Gas Transmission has access to $200 million, while Williams (Parent) has access to all unborrowed amounts. Interest rates vary based on LIBOR plus an applicable margin (which varies with Williams' senior unsecured credit ratings). As Williams completes asset sales, the commitments from participating banks in the revolving credit facility will be initially reduced to $400 million. After 1) the commitments are reduced to $400 million, 2) certain pre-existing debt with a balance of $448.2 million at December 31, 2002, is paid off and pre-existing letters of credit totaling $55.8 million at December 31, 2002, are cash collateralized and 3) and in some cases, the letter of credit facility (discussed below) is collateralized, the commitments may be further reduced to zero as a result of additional asset sales. As of December 31, 2002, the revolving credit facility commitment has been reduced from $700 million to $463 million and no amounts were outstanding under this agreement. Subsequent to December 31, 2002, as a result of asset sales in first-quarter 2003, the revolving credit facility commitment has been further reduced to $400 million as of March 2003. Under the amended terms of the revolving credit facility, the company is no longer required to make a "no material adverse change" representation prior to obtaining borrowings on the facility. Significant new covenants under the agreement include: (i) restrictions on the creation of new subsidiaries, (ii) additional restrictions on pledging assets to other creditors, (iii) restrictions on the disposition of assets, (iv) a covenant that the ratio of interest expense plus cash flow to interest expense be greater than 1.5 to 1, (v) a limit on dividends on common stock paid by Williams in any quarter of $6.25 million, (vi) certain restrictions on declaration or payment of dividends on preferred stock issued after July 30, 2002, (vii) a limit on investments in others of $50 million annually, (viii) 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. and (ix) a modified consolidated debt to consolidated net worth plus consolidated debt financial covenant to increase the threshold to 70 percent through December 30, 2002, 68 percent from December 30, 2002 through March 30, 2003 and 65 percent after March 30, 2003. Consolidated net worth is defined as total assets plus all non-cash losses resulting from the write-down or disposition of the Trading Book less total liabilities and minority interests in consolidated subsidiaries plus certain minority interests and exceptions as defined in the debt agreements, and the $1.1 billion FELINE PACS. Debt is defined as 1) all debt, other than non-recourse debt and the $1.1 billion FELINE PACS, 2) Williams' guarantees as defined in the agreements, 3) capital leases, 4) payments necessary to exercise a purchase option with respect to property encumbered by a Synthetic Lease as defined in the agreements, 5) obligations under any Financing Transaction as defined in the agreements, and 6) liabilities from deferred purchase price of property or services (other than trade payables incurred in the ordinary course of business not overdue by more than 60 days). Williams' ratio of consolidated debt to consolidated net worth plus consolidated debt, as defined in Williams' amended revolving credit facility, at December 31, 2002, was 65.2 percent. The ratio of interest expense plus cash flow to interest expense as defined in the agreements was 2.2. Failure to meet any of these covenants could become an event 135 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) of default and could result in acceleration of amounts due under this facility and other company debt obligations with similar covenants, or for which there are certain provisions for cross-default in place. The amended revolving credit facility expires July 2005 and is secured by substantially all 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. It is also guaranteed by many of Williams' subsidiaries, except for Transcontinental Gas Pipe Line, Texas Gas, Northwest Pipeline and Williams Energy Partners L.P. In addition to the revolving credit facility discussed above, $81 million included in the previous table is outstanding under the terms of a separate $83 million revolving credit facility secured by certain olefin processing assets in Louisiana within Midstream Gas & Liquids. Williams Energy Partners L.P. also has an $85 million unsecured revolving credit facility with no amounts outstanding at December 31, 2002 and $49.5 million at December 31, 2001. SHORT-TERM CREDIT AGREEMENT -- $900 MILLION Williams Production RMT Company (RMT), a wholly owned subsidiary, entered into a $900 million short-term Credit Agreement dated July 31, 2002, with certain lenders including a subsidiary of Lehman Brothers, Inc., a related party to Williams. The loan, reported in notes payable in the Consolidated Balance Sheet, is secured by substantially all of the assets of RMT and the capital stock of Williams Production Holdings LLC (Holdings) (parent of RMT), RMT and certain RMT subsidiaries. It is also guaranteed by Williams, Holdings and certain RMT subsidiaries. The assets of RMT are comprised primarily of the assets of the former Barrett Resources Corporation acquired in 2001, which were primarily natural gas properties in the Rocky Mountain region. The loan matures on July 25, 2003, and bears interest payable quarterly at the Eurodollar rate plus 4 percent per annum (5.76 percent at December 31, 2002), plus additional interest of 14 percent per annum compounded quarterly, which is accrued and added to the principal balance. The principal balance at December 31, 2002, was $921.8 million. 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 (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 loan amount. 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 computed on a consolidated RMT basis of greater than 1.5 to 1, (ii) a fixed charge coverage ratio computed on a consolidated RMT basis 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. Under the RMT Credit Agreements, Williams must provide liquidity projections on a weekly basis until the maturity date. Each projection covers a period extending 12 months from the report date. Williams must maintain actual and projected parent liquidity (a) at any time from the closing date (July 31, 2002) through the 180th day thereafter (January 27, 2003), of $600 million; (b) at any time thereafter through and including 136 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the maturity date, of $750 million; and (c) for liquidity projections provided during the term of the loan, projected liquidity after the maturity date, of $200 million. If the parent liquidity requirement is not met, RMT must be sold within 75 days. The loan is also required to be prepaid with the net cash proceeds of any sales of RMT's assets, and, in the event of a company sale, the loan is required to be prepaid in full. A prepayment or acceleration of the loan requires RMT to pay to the lenders (i) a make-whole amount, and (ii) the deferred set-up fee set forth above. A partial prepayment of the loan requires RMT to pay a pro rata portion of the make-whole amount and deferred set-up fee. LETTER OF CREDIT FACILITY -- $400 MILLION The $400 million letter of credit facility expires July 2003 and is secured by substantially all 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. It is also guaranteed by many of Williams' subsidiaries, except for Transcontinental Gas Pipe Line, Texas Gas, Northwest Pipeline and Williams Energy Partners L.P. Letters of credit totaling $396.8 million have been issued by the participating financial institutions under this facility at December 31, 2002. Significant covenants under the terms of this facility are the same as previously described within Revolving credit facilities. AMENDMENTS TO OTHER OUTSTANDING DEBT AGREEMENTS An additional $159 million of preexisting public securities were also ratably secured in accordance with the indentures covering those securities with the same assets used to secure the revolving credit facility and the $400 million letter of credit facility. During 2002, the terms of the Snow Goose Associates, L.L.C. (Snow Goose) $560 million priority return structure and the terms of the Piceance Production Holdings LLC (Piceance) $100 million priority return structure, both previously classified as preferred interest in consolidated subsidiaries, were amended. These amendments resulted in new payment terms that changed the nature of the transactions; hence, the remaining outstanding preferred interests of $224 million and $78.5 million, respectively, are classified as debt at December 31, 2002. See Note 12 for further information. The terms of various operating lease agreements were also amended. These leases are secured by the related leased assets and are now reflected as capital leases totaling $207 million, of which $67 million is included in liabilities of discontinued operations on the Consolidated Balance Sheet at December 31, 2002. See Leases-Lessee below for further discussion. The terms of the amended Piceance and lease agreements described above, three amended term loan agreements with $448.2 million outstanding at December 31, 2002, and pre-existing letters of credit with $55.8 million outstanding at December 31, 2002, require prepayment of amounts outstanding and posting of cash collateral as Williams completes asset sales. Credit facilities and letters of credit referred to above along with Snow Goose agreements are guaranteed by at least one of the following: Williams (Parent), Williams Gas Pipeline Company, L.L.C. and/or Holdings. These guarantees expire as the corresponding principal balances are repaid in 2003 through 2006. The total guaranteed under these agreements was $1.1 billion as of December 31, 2002. OTHER Pursuant to completion of a consent solicitation during first-quarter 2002 with WCG Note Trust Note holders, Williams recorded $1.4 billion of long-term debt obligations. 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. In November 2002, Williams acquired the remaining outstanding WCG Note Trust Notes (see Note 2). 137 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. OTHER ISSUANCES AND RETIREMENTS In addition to the items previously discussed, significant issuances and retirements of long-term debt, including capital leases, and excluding amounts under revolving credit agreements, for the year ended December 31, 2002 are as follows:
PRINCIPAL ISSUE/TERMS DUE DATE AMOUNT ----------- --------- ---------- (MILLIONS) Issuances of long-term debt in 2002: 6.5% notes (see Note 13).................................. 2007 $1,100.0 8.125% notes.............................................. 2012 650.0 8.75% notes............................................... 2032 850.0 8.875% notes (Transcontinental Gas Pipe Line)............. 2012 325.0 7.67% senior secured notes (Williams Energy Partners L.P.).................................................. 2007 264.0 7.93% senior secured notes (Williams Energy Partners L.P.).................................................. 2007 38.0 Adjustable rate senior secured notes (Williams Energy Partners L.P.)......................................... 2007 178.0 Retirements/prepayments of long-term debt in 2002: 6.125% notes(1)........................................... 2012 $ 240.0 6.2% notes................................................ 2002 350.0 6.5% notes................................................ 2002 150.0 8.875% notes (Transcontinental Gas Pipe Line)............. 2002 125.0 Adjustable rate note (Transcontinental Gas Pipe Line)..... 2002 150.0 Preferred interest (Castle Associates L.P., see Note 12).................................................... 2002 200.0 Various notes, 5.1% -- 9.45%.............................. 2002-2003 208.2 Various notes, adjustable rate............................ 2002-2005 240.3
--------------- (1) Paid due to being subject to redemption at par in 2002. On March 4,2003, Northwest Pipeline completed an offering of $175 million of 8.125 percent senior notes due 2010. Terms of certain subsidiaries' borrowing arrangements with lenders limit the transfer of funds to Williams (Parent). At December 31, 2002, approximately $526 million of net assets of consolidated subsidiaries was restricted. In addition, certain equity method investees' borrowing arrangements and foreign government regulations limit the amount of dividends or distributions to Williams. Restricted net assets of equity method investees was approximately $156 million at December 31, 2002. 138 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Aggregate minimum maturities of long-term debt, excluding capital leases, for each of the next five years are as follows:
(MILLIONS) ---------- 2003........................................................ $1,083 2004........................................................ 1,832 2005........................................................ 1,364(1) 2006........................................................ 1,057 2007........................................................ 855
--------------- (1) Includes $1.1 billion of 6.5 percent notes due 2007 (FELINE PACS) due to the remarketing provisions previously described, that have the potential of Williams reacquiring the notes in 2005 through a foreclosure on its security interest in the notes. Cash payments for interest (net of amounts capitalized) were as follows: 2002 -- $905 million; 2001 -- $572 million; and 2000 -- $581 million. LEASES-LESSEE Future minimum annual rentals under noncancelable operating leases as of December 31, 2002, are payable as follows:
(MILLIONS) ---------- 2003........................................................ $ 33.6 2004........................................................ 21.9 2005........................................................ 18.0 2006........................................................ 11.3 2007........................................................ 9.4 Thereafter.................................................. 27.4 ------ Total....................................................... $121.6 ======
Total rent expense was $102 million in 2002, $91 million in 2001, and $95 million in 2000. In July 2002, Williams amended the terms of an operating lease with a special-purpose entity owned by third parties through which Williams leases an offshore oil and gas pipeline and an onshore gas processing plant. The amended terms caused the lease to be reclassified as a capital lease within the Midstream Gas & Liquids segment under the criteria established in SFAS No. 13. The lease is secured by leased assets with a net book value of $174.3 million as of December 31, 2002. The lease term includes a five-year base term with an optional five-year renewal upon the mutual agreement of the lessor and lessee. Williams provides a residual value guarantee on the leased assets. Williams also has an option to purchase the leased assets during the lease term at an amount approximating the lessors' cost. In the event that Williams does not exercise its purchase option, Williams expects the fair market value of the covered assets to substantially offset Williams' obligation under the residual value guarantee. As a result of the adoption of FASB Interpretation No. 46 in 2003, the special-purpose entity lessor will be included in the 2003 consolidated financial statements of Williams. The impact of the consolidation is not expected to be material. At December 31, 2002, gross property, plant and equipment recorded under the capital lease was $178.5 million. 139 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Future minimum capital lease payments as of December 31, 2002 are:
(MILLIONS) ---------- 2003........................................................ $ 9.0 2004........................................................ 9.0 2005........................................................ 148.1 ------ Total minimum capital lease payments........................ 166.1 Less: Amount representing interest at 6.4%.................. 26.2 ------ Present value of net minimum capital lease payments......... $139.9 ======
140 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 12. PREFERRED INTERESTS IN CONSOLIDATED SUBSIDIARIES In 2001 and 2002 Williams owned the controlling interest in various entities formed in separate transactions that resulted in the sale of a non-controlling preferred ownership interest in one entity in each transaction to an outside investor. The assets and liabilities of each of these entities are included in the Consolidated Balance Sheet. For 2001, the preferred ownership interest in each entity is reflected in the preferred interest in consolidated subsidiaries caption of the Consolidated Balance Sheet. As a result of changes to the underlying agreements in 2002, any remaining outside preferred ownership interest at December 31, 2002, is reflected within debt. The outside investors in these entities are unconsolidated special purpose entities formed solely for the purpose of purchasing the preferred ownership interest in the respective entity and are capitalized with no less than three-percent equity from an independent third party. Each outside investor is entitled to a priority return paid from the operating results of the entity in which they have an investment. Williams has the option to acquire each outside investor's interest in each entity for an amount approximating the fair value of their ownership interest. Absent the occurrence of certain events, the purchase option can be exercised at any time prior to the expiration of the initial priority return period. In addition to financial support in favor of these entities, Williams provides the outside investor in each entity with certain assurances that the entities involved in each transaction will maintain certain financial ratios and follow various restrictive covenants similar to, but in some cases broader than those found in Williams' credit agreements. A violation of any restrictive covenant, a default by Williams on its debt obligations, a failure to make priority distributions, or a failure to negotiate new priority return structures prior to the end of the initial priority return structure period, could ultimately result in an election by the outside investor in the impacted entity to liquidate the assets of that entity. A liquidation could result in a demand of repayment on any Williams obligation as well as the sale of other assets owned or secured by the entity in order to generate proceeds to return the investor's capital account balance. Williams can prevent liquidation of each entity through the exercise of the option to purchase the outside investor's preferred ownership interest. SNOW GOOSE ASSOCIATES, L.L.C. 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, representing an adjustable rate structure. The initial priority return period was set 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 of $224 million is classified as long-term debt due within one year on Williams' Consolidated Balance Sheet at December 31, 2002. Priority returns prior to this amendment are included in preferred returns and minority interest in income of consolidated subsidiaries in the Consolidated Statement of Operations. Significant covenants, other than those noted previously, include: (i) an obligation of Williams Energy (Canada), Inc. to have earnings before interest, taxes, depreciation and amortization each quarter that are at least three times greater than the interest due on its loan from Arctic Fox for the quarter; (ii) an obligation of Williams Energy (Canada), Inc. to have total debt that is less than 50 percent of its total capitalization; (iii) an obligation of Arctic Fox to have assets with a book value that is at least two times larger than the unrecovered capital of the outside investor in Snow Goose; and (iv) an obligation of Arctic Fox to have cash 141 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) flow each quarter that is at least three times greater than amounts payable to the outside investor in Snow Goose for that quarter. PICEANCE PRODUCTION HOLDINGS LLC In December 2001, Williams formed Piceance and Rulison Production Company LLC (Rulison) in a series of transactions that resulted in the sale of a non-controlling preferred interest in Piceance to an outside investor for $100 million. At December 31, 2002, the outside investor amount was $78.5 million. Williams used the proceeds of the sale for general corporate purposes. The assets of Piceance include fixed-price overriding royalty interests in certain oil and gas properties owned by a Williams subsidiary as well as a $135 million note from Rulison. The outside investor is entitled to quarterly priority distributions beginning in January 2002, based upon an adjustable rate structure currently approximating 2.9 percent in addition to participation in a portion of the operating results of Piceance. The initial priority return structure is currently scheduled to expire in December 2006. Piceance must satisfy certain financial covenants beyond those found in Williams' standard credit agreements, including a requirement that it have assets with a value of at least 1.35 times the investor's capital account, and a requirement that at the end of each fiscal quarter, Piceance's profits for the year to date be at least 1.2 times the investor's priority return. Williams is allowed to access the excess cash flow of Piceance and Rulison between distribution periods through demand loans. Following Williams' credit ratings decline to levels below BBB- by Standard & Poor's and Baa3 by Moody's Investors Service or below BB+ by Standard & Poor's or below Ba1 by Moody's Investors Service, Williams is now prevented from using demand loans, and therefore excess cash will be retained between distribution periods. Also, the existing demand loans were repaid by Williams and replaced by other permitted assets. These ratings triggers do not force an acceleration. Failure to satisfy the terms of the agreements would entitle the investor to deliver a transfer notice declaring the occurrence of a transfer event. In such case, unless the Williams subsidiary that is a member of Piceance exercises its purchase option, the managing member interest will automatically be transferred to the investor ten days following the transfer event. Upon a transfer event, the managing member can elect to liquidate and wind-up Piceance. WILLIAMS RISK HOLDINGS L.L.C. During 1998, Williams formed Williams Risk Holdings L.L.C. (Holdings) in a series of transactions that resulted in the sale of a non-controlling preferred interest in Holdings to an outside investor for $135 million. Williams used the proceeds from the sale for general corporate purposes. The outside investor in Holdings is not a special purpose entity. The outside investor was entitled to monthly preferred distributions based upon an adjustable rate structure of approximately 5.9 percent at December 31, 2001, in addition to participation in a portion of the operating results of Holdings. The initial priority return structure of Holdings was scheduled to expire in September 2003. In July 2002, the downgrade of Williams' senior unsecured rating below BB by Standard & Poor's or Ba1 by Moody's Investors Service, resulted in an early retirement of substantially all the outside investors' ownership interest. However, the structure remains in place. CASTLE ASSOCIATES L.P. In December 1998, Williams formed Castle Associates L.P. (Castle) through a series of transactions that resulted in the sale of a non-controlling preferred interest in Castle to an outside investor for $200 million. Williams used the proceeds of the sale for general corporate purposes. At December 31, 2001, the assets of Castle included approximately $145 million in loans from Williams payable upon demand (demand loans), a $125 million loan from a Williams subsidiary secured by operating assets and a Williams guarantee due in 142 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) December 2003, $60 million in third-party receivables guaranteed by Williams, and approximately $204 million in other various assets. While no event of default arose from a downgrade of Williams' unsecured credit rating below Baa3 by Moody's Investors Service and below BBB- by Standard & Poor's, Williams no longer is able to substitute demand loans for existing assets. The outside investor was entitled to quarterly priority distributions based upon an adjustable rate structure, in addition to a portion of the participation in the operating results of Castle. Williams purchased the outside investors interest in December 2002. NOTE 13. STOCKHOLDERS' EQUITY Concurrent with the sale of Kern River to MidAmerican Energy Holdings Company (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 year ended December 31, 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 $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. The holder of the equity forward contract can settle the contract early in the event Williams is involved in a merger in which at least 30 percent of the proceeds received by Williams shareholders is cash. In this event the holder will be entitled to pay the purchase price and receive the kind and amount of securities they would have received had they settled the equity forward contract immediately prior to the acquisition. In addition to the 6.5 percent interest payment on the notes, Williams also makes a contract adjustment payment related to the equity forward contract of 2.5 percent annually during the three year term of the contract. The present value of the total of the contract adjustment payments at the date the FELINE PACS were issued was $76.7 million and was recorded as a liability and a reduction to capital in excess of par at that time. In January 2001, Williams issued approximately 38 million shares of common stock in a public offering at $36.125 per share. The impact of this issuance resulted in increases of approximately $38 million to common stock and $1.3 billion to capital in excess of par value. Williams maintains a Stockholder Rights Plan under which each outstanding share of Williams common stock has one-third of a preferred stock purchase right attached. Under certain conditions, each right may be exercised to purchase, at an exercise price of $140 (subject to adjustment), one two-hundredth of a share of Series A Junior Participating Preferred Stock. The rights may be exercised only if an Acquiring Person acquires (or obtains the right to acquire) 15 percent or more of Williams common stock; or commences an offer for 15 percent or more of Williams common stock; or the board of directors determines an Adverse Person has become the owner of a substantial amount of Williams common stock. The rights, which until exercised do not have voting rights, expire in 2006 and may be redeemed at a price of $.01 per right prior to their expiration, or within a specified period of time after the occurrence of certain events. In the event a 143 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) person becomes the owner of more than 15 percent of Williams common stock or the board of directors determines that a person is an Adverse Person, each holder of a right (except an Acquiring Person or an Adverse Person) shall have the right to receive, upon exercise, Williams common stock having a value equal to two times the exercise price of the right. In the event Williams is engaged in a merger, business combination or 50 percent or more of Williams' assets, cash flow or earnings power is sold or transferred, each holder of a right (except an Acquiring Person or an Adverse Person) shall have the right to receive, upon exercise, common stock of the acquiring company having a value equal to two times the exercise price of the right. NOTE 14. STOCK-BASED COMPENSATION Williams has several plans that provide or have provided for common-stock-based awards to employees and to non-employee directors. Effective May 16, 2002, Williams' shareholders approved a new plan that will provide common-stock-based awards going forward to both employees and non-employee directors. Options outstanding in all prior plans remain in those plans with their respective terms and provisions. The new plan permits the granting of various types of awards including, but not limited to, stock options, restricted stock and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable after three years from the date of the grant and can be subject to accelerated vesting if certain future stock prices or if specific financial performance targets are achieved. Stock options expire 10 years after grant. At December 31, 2002, 57.8 million shares of Williams common stock were reserved for issuance pursuant to existing and future stock awards, of which 14.8 million shares were available for future grants (18.2 million at December 31, 2001). The prior plans, from which no further grants are expected, permitted the granting of various types of awards including, but not limited to, stock options, stock appreciation rights, restricted stock and deferred stock. Awards were granted for no consideration other than prior and future services or based on certain financial performance targets being achieved. The purchase price per share for stock options and the grant price for stock appreciation rights were not less than the market price of the underlying stock on the date of grant. Stock options under these prior plans generally became exercisable in one-third increments each year from the anniversary of the grant or after three or five years, subject to accelerated vesting if certain future stock prices or if specific financial performance targets are achieved. Stock options under the prior plans expire 10 years after grant. Prior to November 14, 2001, the stock option loan programs for the Williams 1996 Stock Plan, Williams 1990 Stock Plan, Williams 1988 Stock Option Plan for Non-Employee Directors and Williams 1985 Stock Option Plan allowed Williams to loan money to participants to exercise stock options using stock certificates as collateral. Effective November 14, 2001, Williams no longer issues new loans under the stock option loan programs. Current loan holders were offered a one-time opportunity in January 2002 to refinance outstanding loans at a market rate of interest commensurate with the borrower's credit standing. The refinancing is in the form of a full recourse note, interest payable annually in cash, and loan maturity of no later than December 31, 2005. The loan will remain in force until maturity in the event of the employee's termination. Williams continues to hold the collateral shares and can review the borrower's financial position at any time. The variable rate of interest on the loans of participants who elected new terms was determined at the signing of the promissory note and is based on 1.75 percent plus the current three-month London Interbank Offered Rate (LIBOR). The rate is subject to change every three months beginning with the first three-month anniversary of the promissory note. If a current loan holder did not elect to refinance, the loans remain outstanding under the original terms with no refinancing at maturity. Under the original terms of the loan, the interest rate is based on the 144 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) minimum applicable federal rates required to avoid imputed income, interest payments are due annually, the principal is due at the end of either a three-or five-year loan term, and if the participant leaves Williams during the loan period, they are required to pay the loan balance and any accrued interest within 30 days of termination. The total amount of loans outstanding at December 31, 2002 and 2001, was approximately $30.3 million (net of a $5 million allowance) and $38.1 million, respectively. The following summary reflects stock option activity for Williams common stock and related information for 2002, 2001 and 2000:
2002 2001 2000 ---------------------- ---------------------- ---------------------- WEIGHTED- WEIGHTED- WEIGHTED- AVERAGE AVERAGE AVERAGE OPTIONS EXERCISE OPTIONS EXERCISE OPTIONS EXERCISE (MILLIONS) PRICE (MILLIONS) PRICE (MILLIONS) PRICE ---------- --------- ---------- --------- ---------- --------- Outstanding -- beginning of year.............. 25.6 $28.23 23.1 $28.63 22.8 $25.03 Granted................ 15.8 6.64 4.8 37.45 3.8 45.87 Exercised.............. (.5) 11.77 (3.3) 18.47 (3.3) 23.12 Barrett option conversions.......... -- -- 2.0 21.57 -- -- Adjustment for WCG spinoff(1)........... -- -- 2.1 -- -- -- Canceled............... (2.1) 26.31 (3.1) 32.35 (.2) 38.19 ---- ---- ---- Outstanding -- end of year................. 38.8 $19.85 25.6 $28.23 23.1 $28.63 ==== ==== ==== Exercisable -- end of year................. 21.7 $27.42 20.0 $26.41 22.1 $28.24 ==== ==== ====
--------------- (1) Effective with the spinoff of WCG on April 23, 2001, the number of unexercised Williams stock options and the exercise price were adjusted to preserve the intrinsic value of the stock options that existed prior to the spinoff. The following summary provides information about Williams stock options outstanding and exercisable at December 31, 2002:
STOCK OPTIONS OUTSTANDING ------------------------------------ STOCK OPTIONS EXERCISABLE WEIGHTED- -------------------------- WEIGHTED- AVERAGE WEIGHTED- AVERAGE REMAINING AVERAGE EXERCISE CONTRACTUAL EXERCISE RANGE OF EXERCISE PRICES OPTIONS PRICE LIFE OPTIONS PRICE ------------------------ ---------- --------- ----------- ------------ ----------- (MILLIONS) (MILLIONS) $1.35 to $5.40................... 11.1 $ 2.79 9.2 years .2 $ 2.58 $6.71 to $15.39.................. 4.4 12.48 2.5 years 4.4 12.48 $15.51 to $15.86................. 4.0 15.85 8.7 years .3 15.85 $15.89 to $25.14................. 4.8 20.62 3.6 years 4.8 20.62 $26.79 to $42.52................. 14.5 36.06 5.9 years 12.0 36.34 ---- ---- Total.......................... 38.8 19.85 6.5 years 21.7 27.42 ==== ====
145 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The estimated fair value at date of grant of options for Williams common stock granted in 2002, 2001 and 2000, using the Black-Scholes option pricing model, is as follows:
2002 2001 2000 ----- ------ ------ Weighted-average grant date fair value of options for Williams common stock granted during the year............. $2.77 $10.93 $15.44 ===== ====== ====== Assumptions: Dividend yield............................................ 1% 1.9% 1.5% Volatility................................................ 56% 35% 31% Risk-free interest rate................................... 3.6% 4.8% 6.5% Expected life (years)..................................... 5.0 5.0 5.0
Pro forma net income (loss) and earnings per share, assuming Williams had applied the fair-value method of SFAS No. 123, "Accounting for Stock-Based Compensation" in measuring compensation cost beginning with 1997 employee stock-based awards is disclosed under Employee stock-based awards in Note 1. Williams granted deferred shares of approximately 2,738,000 in 2002, 1,423,000 in 2001 and 332,000 in 2000. Deferred shares are valued at the date of award, and the weighted-average grant date fair value of the shares granted was $12.26 in 2002, $40.84 in 2001 and $39.13 in 2000. Approximately $31 million, $22 million and $11 million was recognized as expense for deferred shares of Williams in 2002, 2001 and 2000, respectively. Expense related to deferred shares is recognized in the performance year or over the vesting period, depending on the terms of the awards. Williams issued approximately 499,000 in 2002, 260,000 in 2001 and 140,000 in 2000, of the deferred shares previously granted. 146 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 15. FINANCIAL INSTRUMENTS, DERIVATIVES, INCLUDING ENERGY TRADING ACTIVITIES, AND CONCENTRATION OF CREDIT RISK FINANCIAL INSTRUMENTS FAIR VALUE Fair-value methods The following methods and assumptions were used by Williams in estimating its fair-value disclosures for financial instruments: Cash and cash equivalents, restricted cash and notes payable: The carrying amounts reported in the balance sheet approximate fair value due to the short-term maturity of these instruments with the exception of the RMT note payable for which Williams used the expertise of outside investment banking firms to assist with the estimate of fair value. Retained interest in accounts receivable sold to SPEs: The carrying amounts reported in the balance sheet for December 31, 2001 approximate fair value. Fair value was based on the present value of future expected cash flows using management's best estimates of various factors, including credit loss experience and discount rates commensurate with the risks involved. Notes and other noncurrent receivables, margin deposits and deposits received from customers relating to energy trading and hedging activities: The carrying amounts reported in the balance sheet approximate fair value as these instruments have interest rates approximating market or maturities of less than three years. Investment in WCG: The carrying amount reflects write-downs of the WCG investment to zero (see Note 2). Fair value at December 31, 2001 was calculated based on the year-end closing price of WCG common stock. Long-term debt: The fair value of Williams' long-term debt is valued using indicative year-end traded bond market prices for publicly traded issues, while private debt is valued based on the prices of similar securities with similar terms and credit ratings. At December 31, 2002 and 2001, 73 percent and 81 percent, respectively, of Williams' long-term debt was publicly traded. Williams used the expertise of outside investment banking firms to assist with the estimate of the fair value of long-term debt. Energy derivatives and other energy-related contracts: Derivatives and other energy-related contracts utilized in trading activities include forward contracts, futures contracts, option contracts, swap agreements, physical commodity inventories, short- and long-term purchase and sale commitments, (which involve physical delivery of an energy commodity) and energy-related contracts, such as transportation, storage, full requirements, load serving, transmission and power tolling contracts. In addition, Williams enters into interest-rate swap agreements and credit default swaps to manage the interest rate and credit risk in its energy trading portfolio. Fair value of energy contracts is determined based on the nature of the transaction and the market in which transactions are executed. Certain transactions are executed in exchange-traded or over-the-counter markets for which quoted prices in active periods exist, while other transactions are executed where quoted market prices are not available or the contracts extend into periods for which quoted market prices are not available. See Note 1 regarding Energy commodity risk management and trading activities and revenues and Derivative instruments and hedging activities including interest rate swaps for further discussion about determining fair value for energy contracts. Foreign currency hedges: Fair value is determined by discounting estimated future cash flows using forward foreign exchange rates derived from the year-end forward exchange curve. Fair value was calculated by the financial institution that is counterparty to the agreement. Interest-rate derivatives: Fair value is determined by discounting estimated future cash flows using forward-interest rates derived from the year-end yield curve. Fair value was calculated by the financial institutions that are the counterparties to the derivatives. 147 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Carrying amounts and fair values of Williams' financial instruments and energy risk management and trading activities
2002 2001 ----------------------- ------------------------ CARRYING CARRYING ASSET (LIABILITY) AMOUNT FAIR VALUE AMOUNT FAIR VALUE ----------------- ---------- ---------- --------- ---------- (MILLIONS) Financial instruments: Cash and cash equivalents................... $ 1,728.3 $ 1,728.3 $ 1,258.5 $ 1,258.5 Restricted cash (current and noncurrent).... 291.1 291.1 -- -- Retained interest in accounts receivable sold to SPEs............................. -- -- 205.0 205.0 Notes and other noncurrent receivables...... 165.3 165.3 39.6 39.6 Investments -- cost and advances to affiliates............................... 269.9 (a) 376.6 (a) Investment in WCG........................... -- -- -- 49.8 Notes payable............................... (934.8) (1,001.6) (1,424.5) (1,424.5) Long-term debt, including current portion... (12,839.3) (9,316.8) (9,692.1) (9,847.3) Margin deposits............................. 804.8 804.8 171.4 171.4 Deposits received from customers relating to energy risk management and trading and hedging activities....................... (141.2) (141.2) (265.5) (265.5) Guarantees.................................. 65.7 (b) 1,785.6(c) (b) Energy derivatives and other energy-related contracts: Energy risk management and trading activities: Assets................................... 8,855.2 8,855.2 10,431.5 10,431.5 Liabilities.............................. (7,223.1) (7,223.1) (8,170.3) (8,170.3) Energy commodity cash flow and fair-value hedges: Assets(d)................................ 82.0 82.0 488.9 488.9 Liabilities.............................. (32.7) (32.7) (28.1) (28.1) Other energy commodity derivatives: Assets................................... 46.4 46.4 -- -- Liabilities(e)........................... (19.7) (19.7) (11.8) (11.8) Foreign currency hedges....................... 24.0 24.0 16.9 16.9 Interest -- rate derivatives.................. (27.9) (27.9) (f) (f)
--------------- (a) These investments and long-term receivables due from affiliated companies are primarily in non-publicly traded companies for which it is not practicable to estimate fair value. (b) It is not practicable to estimate the fair value of these financial instruments because of their unusual nature and unique characteristics. (c) Includes $1.1 billion related to the WCG Note Trust Notes and $600 million related to the WCG fiber optic network lease guarantee. (d) Includes $20.0 million and $7.6 million of assets related to discontinued operations in 2002 and 2001, respectively. (e) Includes $(19.7) million and $(11.8) million of liabilities related to discontinued operations in 2002 and 2001, respectively. (f) At December 31, 2001, Williams had interest rate swaps to mitigate its interest rate risk in its energy trading portfolio which were included in energy risk management and trading assets and liabilities. 148 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) GUARANTEES In addition to the guarantees and payment obligations discussed elsewhere in these footnotes (see Notes 2, 3 and 16), Williams has issued guarantees and other similar arrangements with off-balance sheet risk as discussed below. In 2001, Williams sold its investment in Ferrellgas Partners L.P. senior common units (Ferrellgas units). As part of the sale, Williams became party to a put agreement whereby the purchaser's lenders can unilaterally require Williams to repurchase the units upon nonpayment by the purchaser of its term loan due to its lender or failure or default by Williams under any of its debt obligations greater than $60 million. The maximum potential obligation under the put agreement at December 31, 2002, was $91.5 million. Williams' contingent obligation decreases as purchaser's payments are made to the lender. Collateral and other recourse provisions include the outstanding Ferrellgas units and a guarantee from Ferrellgas Partners L.P. to cover any shortfall from the sale of the Ferrellgas units at less than face value. The proceeds from the liquidation of the Ferrellgas units combined with the Ferrellgas Partners' guarantee should be sufficient to cover any required payment by Williams. The put agreement expires December 30, 2005. There have been no events of default and the purchaser has performed as required under payment terms with the lender. No amounts have been accrued for this contingent obligation as management believes it is not probable that Williams would be required to perform under this obligation. In connection with the 1993 public offering of units in the Williams Coal Seam Gas Royalty Trust (Royalty Trust), Exploration & Production entered a gas purchase contract for the purchase of the natural gas in which the Royalty Trust holds a net profits interest. Under this agreement, Exploration & Production guarantees a minimum purchase price that the Royalty Trust will realize in the calculation of its net profits interest. Exploration and Production has an annual option to discontinue this minimum purchase price guarantee and pay solely based on an index price. The maximum potential future exposure associated with this guarantee is not determinable because it is dependent upon natural gas prices and production volumes. No amounts have been accrued for this contingent obligation, as the index price continues to exceed the minimum purchase price. In connection with the 1987 sale of certain real estate assets associated with its Tulsa headquarters, Williams guaranteed 70 percent of the principal and interest payments through 2007 on revenue bonds issued by the purchaser to finance those assets. In the event that future operating results from these assets are not sufficient to make the principal and interest payments, Williams is required to fund that short-fall. The maximum potential future payments under this guarantee are $8.6 million, all of which is accrued at December 31, 2002. In connection with the construction of a joint venture pipeline project, Williams guaranteed 50 percent of the joint venture's project financing. Williams' maximum potential liability under this guarantee is $9.7 million at December 31, 2002. This guarantee expires March 2005 and no amounts have been accrued at December 31, 2002. Williams provided credit support to a crude oil trading joint venture in the form of performance guarantees for the benefit of the trading counterparties. These guarantees, which would have required Williams to make payments in the event of nonperformance by the joint venture under the crude oil purchase and sale contracts, expired or were terminated in early 2003. Although the maximum potential future payments would vary based on commodity prices, Williams' guarantees were capped at a total of $338 million. This joint venture is no longer active and no amounts were accrued for these guarantees at December 31, 2002. 149 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) OTHER FINANCIAL INSTRUMENTS Through July 25, 2002 Williams, through wholly owned bankruptcy remote subsidiaries, sold certain trade accounts receivable to special purpose entities (SPEs) in a securitization structure requiring annual renewal. Williams acted as the servicing agent for the sold receivables and received a servicing fee approximating the fair value of such services. At December 31, 2001, approximately $625 million of accounts receivable that would otherwise be Williams' receivables were sold to the SPEs in exchange for $420 million in cash and a $205 million subordinated retained interest in the accounts receivable sold to the SPEs. For 2002 and 2001, Williams received cash proceeds from the SPEs of approximately $4.7 billion and $12.8 billion, respectively. The sales of these receivables resulted in a charge to results of operations of approximately $4 million and $17 million in 2002 and 2001, respectively. The retained interest in accounts receivable sold to the SPEs was subject to credit risk to the extent that these receivables were not collected. On July 25, 2002, these agreements expired and were not renewed. See Concentration of credit risk below. DERIVATIVES AND ENERGY-RELATED CONTRACTS Energy risk management and trading activities Williams, through Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment), has energy commodity risk management and trading operations that enter into energy and energy-related contracts to provide price-risk management services associated with the energy industry to its customers, including power, natural gas, refined products, natural gas liquids and crude oil. Contracts utilized in energy commodity risk management and trading activities include forward contracts, futures contracts, option contracts, swap agreements, physical commodity inventories, short- and long-term purchase and sale commitments which involve physical delivery of an energy commodity and energy-related contracts, including transportation, storage, full requirements, load serving, transmission and power tolling contracts. In addition, Energy Marketing & Trading enters into interest rate swap agreements and credit default swaps to manage the interest rate and credit risk in its energy portfolio. During 2002, Williams began managing its interest rate risk, including the interest rate and credit risk in Energy Marketing & Trading's energy portfolio, on an enterprise basis by the corporate parent. Energy Marketing & Trading also directly entered into third-party interest rate futures agreements to mitigate interest rate risk. These futures are included within energy risk management and trading assets and liabilities. See Note 1 for a description of the accounting valuation for these energy commodity risk management and trading activities. The net gain or (loss) recognized in revenues from the price-risk management and trading activities was a $(109) million net loss in 2002 and net gains of $1,696 million and $1,285.1 million in 2001 and 2000, respectively. Futures contracts are commitments to either purchase or sell a commodity at a future date for a specified price and are generally settled in cash, but may be settled through delivery of the underlying commodity. Exchange-traded or over-the-counter markets providing quoted prices in active periods are available and other market indicators where quoted prices are not available exist for the futures contracts entered into by Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment). The fair value of these contracts is based on quoted prices. Swap agreements call for Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment), to make payments to (or receive payments from) counterparties based upon the differential between a fixed and variable price or variable prices of energy commodities for different locations. Forward contracts and purchase and sale commitments with fixed volumes which involve physical delivery of energy commodities, contain both fixed and variable pricing terms. Swap agreements, forward contracts and purchase and sale commitments with fixed volumes are valued based on prices of the underlying energy commodities over the contract life and contractual or notional volumes with the resulting expected future cash flows discounted to a present value using a risk-free market interest rate. 150 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Certain of Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) purchase and sale commitments, which involve physical delivery of energy commodities, contain optionality clauses or other arrangements that result in varying volumes. In addition, Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) buy and sell physical and financial option contracts which give the buyer the right to exercise the option and receive the difference between a predetermined strike price and a market price at the date of exercise. These contracts are valued based on option pricing models considering prices of the underlying energy commodities over the contract life, volatility of the commodity prices, contractual volumes, estimated volumes under option and other arrangements and a risk-free market interest rate. Energy-related contracts include transportation, storage, full requirements, load serving, transmission and power tolling contracts. Transportation and transmission contracts provide Energy Marketing & Trading the right, but not the obligation, to transport/transmit physical quantities of natural gas or refined products or electricity from one location to another on a daily basis. The payment or settlement required typically has a fixed component paid regardless of whether the transportation/transmission capacity is used and a variable payment component for shipments actually made during the month. Storage contracts provide Energy Marketing & Trading the right, but not the obligation, to store physical quantities of gas. Energy Marketing & Trading enters full requirements arrangements which are structured to manage natural gas and power supply requirements, service load growth, manage unplanned outages and other scenarios. Load serving agreements require Energy Marketing & Trading to procure energy supplies for its customers necessary to meet their load or energy needs. Power tolling contracts provide Energy Marketing & Trading the right, but not the obligation, to call on the counterparty to convert natural gas to electricity at a predefined heat conversion rate. Energy Marketing & Trading supplies the natural gas to the power plants and markets the electricity output. In exchange for this right, Energy Marketing & Trading pays a monthly fixed fee and a variable fee based on usage. Fair value of these energy-related contracts is estimated using valuation techniques that incorporate option pricing theory, statistical and simulation analysis, present value concepts incorporating risk from uncertainty of the timing and amount of estimated cash flows and specific contractual terms. These valuation techniques utilize factors such as quoted energy commodity market prices, estimates of energy commodity market prices in the absence of quoted market prices, volatility factors underlying the positions, estimated correlation of energy commodity prices, contractual volumes, estimated volumes under option and other arrangements, the liquidity of the market in which the contract is transacted and a risk-free market discount rate. Fair value also reflects a risk premium that market participants would consider in their determination of fair value. In situations where Energy Marketing & Trading has received current information from negotiation activities with potential buyers of these contracts that they believe to be representative of the market, the information is considered in the determination of the fair value of the contract. Interest-rate swap and futures agreements, including those with the parent, are used to manage the interest rate risk in the energy trading portfolio. Under these swap agreements, Energy Marketing & Trading pays a fixed rate and receives a variable rate on the notional amount of the agreements. Financial futures contracts are commitments to either purchase or sell a financial instrument, such as a Eurodollar deposit, U.S. Treasury bond or U.S. Treasury note, at a future date for a specified price and are generally settled in cash, but may be settled through delivery of the underlying instrument. The fair value of these contracts is determined by discounting estimated future cash flows using forward interest rates derived from interest rate yield curves. Credit default swaps are used to manage counterparty credit exposure in the energy trading portfolio. Under these agreements, Energy Marketing & Trading pays a fixed rate premium for a notional amount of risk coverage associated with certain credit events. The covered credit events are bankruptcy, obligation acceleration, failure to pay and restructuring. The fair value of these agreements is based on current pricing received from the counterparties. 151 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The valuation of the contracts entered into by Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) also considers factors such as the liquidity of the market in which the contract is transacted, uncertainty regarding the ability to liquidate the position considering market factors applicable at the date of such valuation and risk of non-performance and credit considerations of the counterparty. For contracts or transactions that extend into periods for which actively quoted prices are not available, Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) estimate energy commodity prices in the illiquid periods by incorporating information obtained from commodity prices in actively quoted markets, prices reflected in current transactions and market fundamental analysis. Determining fair value for contracts also involves complex assumptions including estimating natural gas and power market prices in illiquid periods and markets, estimating market volatility and liquidity and correlation of natural gas and power prices, evaluating risk from uncertainty inherent in estimating cash flows and estimates regarding counterparty performance and credit considerations. Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) has the risk of loss as a result of counterparties not performing pursuant to the terms of their contractual obligations. Risk of loss can result from credit considerations and the regulatory environment of the counterparty. Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) attempts to minimize credit-risk exposure to trading counterparties and brokers through formal credit policies, consideration of credit ratings from public rating agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. The concentration of counterparties within the energy and energy trading industry impacts Williams' overall exposure to credit risk in that these counterparties are similarly influenced by changes in the economy and regulatory issues. 152 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The gross forward contract credit exposure from energy trading and price-risk management activities for Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) as of December 31, 2002 and 2001 is summarized below.
2002 2001 --------------------- ---------------------- INVESTMENT INVESTMENT GRADE(A) TOTAL GRADE(A) TOTAL ---------- -------- ---------- --------- (MILLIONS) Gas and electric utilities................. $2,326.4 $3,255.1 $4,253.9 $ 4,924.5 Energy marketers and traders............... 2,371.7 3,661.1 5,353.5 5,766.2 Financial institutions..................... 1,006.8 1,007.0 249.8 341.7 Other...................................... 1,176.4 1,182.4 16.4 47.3 -------- -------- -------- --------- Total.................................... $6,881.3 9,105.6 $9,873.6 11,079.7 ======== ======== Credit reserves............................ (250.4) (648.2) -------- --------- Gross credit exposure from price-risk management activities(b)................. $8,855.2 $10,431.5 ======== =========
Energy Marketing & Trading and the natural gas liquids trading operations (reported in the Midstream Gas & Liquids segment) assess their credit exposure on a net basis when appropriate and contractually allowed. The net forward credit exposure from energy trading and price-risk management activities as of December 31, 2002 and 2001 is summarized below.
2002 2001 --------------------- --------------------- INVESTMENT INVESTMENT GRADE(A) TOTAL GRADE(A) TOTAL ---------- -------- ---------- -------- (MILLIONS) Gas and electric utilities.................. $1,290.1 $2,648.5 $2,310.8 $2,867.6 Energy marketers and traders................ 163.6 183.2 607.4 730.0 Financial institutions...................... 201.1 201.1 397.6 401.4 Other....................................... 44.6 50.8 242.7 362.4 -------- -------- -------- -------- Total.................................. $1,699.4 3,083.6 $3,558.5 4,361.4 ======== ======== Credit reserves............................. (250.4) (648.2) -------- -------- Net credit exposure from price-risk management activities(b).................. $2,833.2 $3,713.2 ======== ========
--------------- (a) "Investment Grade" is primarily determined using publicly available credit ratings along with consideration of cash, standby letters of credit, parent company guarantees and property interests, including oil and gas reserves. Included in "Investment Grade" are counterparties with a minimum Standard & Poor's or Moody's Investor's Service rating of BBB- or Baa3, respectively. (b) One counterparty within the California power market represents greater than ten percent of assets from energy risk management and trading activities and is included in "investment grade." Standard & Poor's or Moody's Investor's Service does not rate this counterparty. However, recent bond issuances by this counterparty have been rated as investment grade by the various rating agencies. This counterparty has been included in the "investment grade" column based upon contractual credit requirements in the event of assignment or novation. 153 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Energy commodity cash flow hedges Williams is also exposed to market risk from changes in energy commodity prices within Exploration & Production and Petroleum Services and the non-trading operations of Energy Marketing & Trading and Midstream Gas & Liquids. Williams utilizes derivatives to manage its exposure to the variability in expected future cash flows attributable to commodity price risk associated with forecasted purchases and sales of natural gas, refined products, crude oil, electricity, ethanol and corn. These derivatives have been designated as cash flow hedges. Williams produces, buys and sells natural gas and crude oil at different locations throughout the United States. To reduce exposure to a decrease in revenues or an increase in costs from fluctuations in natural gas and crude oil market prices, Williams enters into natural gas and crude oil futures contracts and swap agreements to fix the price of anticipated sales and purchases of natural gas and crude oil. Williams' refineries purchase crude oil for processing and sell the refined products. To reduce the exposure to increasing costs of crude oil and/or decreasing refined product sales prices due to changes in market prices, Williams enters into crude oil and refined products futures contracts and swap agreements to lock in the prices of anticipated purchases of crude oil and sales of refined products. There were no forecasted transactions hedged subsequent to December 31, 2002 related to the Midsouth refinery. Additionally, hedge accounting related to the Alaska refinery was discontinued when forecasted transactions were no longer probable because of the refinery's anticipated sale in 2003. Williams' electric generation facilities utilize natural gas in the production of electricity. To reduce the exposure to increasing costs of natural gas due to changes in market prices, Williams enters into natural gas futures contracts and swap agreements to fix the prices of anticipated purchases of natural gas. To reduce the exposure to decreasing revenues from electricity sales, Williams enters into fixed-price forward physical contracts to fix the prices of anticipated sales of electric production. Hedge accounting was discontinued for one of the electric generation facilities due to the sale of the facility which closed in February 2003. Derivative gains or losses from these cash flow hedges are deferred in other comprehensive income and reclassified into earnings in the same period or periods during which the hedged forecasted purchases or sales affect earnings. To match the underlying transaction being hedged, derivative gains or losses associated with anticipated purchases are recognized in costs and operating expenses and amounts associated with anticipated sales are recognized in revenues in the Consolidated Statement of Operations. Approximately $.5 million of losses and $.7 million of gains from hedge ineffectiveness are included in revenues and costs and operating expenses, respectively, in the Consolidated Statement of Operations during 2002. Approximately $1 million of gains from hedge ineffectiveness is included in revenues in the Consolidated Statement of Operations during 2001. Hedge accounting was discontinued and net gains of $43 million were reclassified out of accumulated other comprehensive income and recognized in the Consolidated Statement of Operations during 2002 as a result of it becoming probable that certain forecasted transactions would not occur. No hedges were discontinued during 2001 as a result of it becoming probable that the forecasted transaction will not occur. For 2002 and 2001, there were no derivative gains or losses excluded from the assessment of hedge effectiveness. There are approximately $83 million and $142 million of pre-tax gains related to terminated derivatives included in accumulated other comprehensive income at December 31, 2002 and 2001, respectively. The 2002 amounts will be recognized into net income as the hedged transactions occur. As of December 31, 2002, Williams had hedged future cash flows associated with anticipated energy commodity purchases and sales for up to 13 years, and, based on recorded values at December 31, 2002, approximately $42 million of net gains (net of income tax provision of $26 million) will be reclassified into earnings within the next year offsetting net losses that will be realized in earnings from previous unfavorable market movements associated with the underlying hedged transactions. 154 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Energy commodity fair-value hedges Williams' refineries carry inventories of crude oil and refined products. Williams enters into crude oil and refined products futures contracts and swap agreements to reduce the market exposure of these inventories from changing energy commodity prices. These derivatives have been designated as fair-value hedges. Derivative gains and losses from these fair-value hedges are recognized in earnings currently along with the change in fair value of the hedged item attributable to the risk being hedged. Gains and losses related to hedges of inventory are recognized in costs and operating expenses in the Consolidated Statement of Operations. Approximately $8 million and $5 million of net gains from hedge ineffectiveness was recognized in costs and operating expenses in the Consolidated Statement of Operations during 2002 and 2001, respectively. There were no derivative gains or losses excluded from the assessment of hedge effectiveness. During third-quarter 2002, Williams discontinued the fair value hedges related to refined products. Fair value hedges for crude oil will continue until the completion of the Midsouth refinery sale. Other energy commodity derivatives Williams' operations associated with crude oil refining and refined products marketing also include derivative transactions (primarily forward contracts, futures contracts, swap agreements and option contracts) which are not designated as hedges. The forward contracts are for the procurement of crude oil and refined products supply for operational purposes, while the other derivatives manage certain risks associated with market fluctuations in crude oil and refined product prices related to refined products marketing. The net change in fair value of these derivatives, representing unrealized gains and losses, is recognized in earnings currently as revenues or costs and operating expenses in the Consolidated Statement of Operations. As a result of the completion of the sale of the Midsouth refinery during first-quarter 2003, these derivatives have been discontinued. Williams' operations associated with the production of natural gas enter into basis swap agreements fixing the price differential between the Rocky Mountain natural gas prices and Gulf Coast natural gas prices as part of their overall natural gas price risk management program to reduce risk of declining natural gas prices in basins with limited pipeline capacity to other markets. Certain of these basis swaps do not qualify for hedge accounting treatment under SFAS No. 133; hence, the net change in fair value of these derivatives representing unrealized gains and losses is recognized in earnings currently as revenues in the Consolidated Statement of Operations. Foreign currency hedges Williams has a Canadian-dollar-denominated note receivable that is exposed to foreign-currency risk. To protect against variability in the cash flows from the repayment of the note receivable associated with changes in foreign currency exchange rates, Williams entered into a forward contract to fix the U.S. dollar principal cash flows from this note. This derivative was designated as a cash flow hedge and was expected to be highly effective over the period of the hedge. Hedge accounting was discontinued effective October 1, 2002 because the hedge is no longer expected to be highly effective. Gains and losses from the change in fair value of the derivative prior to October 1, 2002, are deferred in other comprehensive income (loss) and reclassified to other income (expense) -- net below operating income when the Canadian-dollar-denominated note receivable impacts earnings as it is translated into U.S. dollars. There were no derivative gains or losses recorded in the Consolidated Statement of Operations from hedge ineffectiveness or from amounts excluded from the assessment of hedge effectiveness, and no foreign currency hedges were discontinued during 2002 or 2001 as a result of it becoming probable that the forecasted transaction will not occur. The $2.4 million of net losses (net of income tax benefits of $1.5 million) deferred in other comprehensive income (loss) at December 31, 2002, will be reclassified into earnings during 2003 as the note receivable impacts earnings. 155 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Interest-rate derivatives Williams enters into interest-rate swap agreements to manage its exposure to interest rates and modify the interest characteristics of its long-term debt. These agreements are designated with specific debt obligations, and involve the exchange of amounts based on the difference between fixed and variable interest rates calculated by reference to an agreed-upon notional amount. Interest-rate swaps in place during 2001 effectively modified Williams' exposure to interest rates by converting a portion of Williams' fixed rate debt to a variable rate. These derivatives were designated as fair value hedges and were perfectly effective. As a result, there was no current impact to earnings due to hedge ineffectiveness or due to the exclusion of a component of a derivative from the assessment of effectiveness. The change in fair value of the derivatives and the adjustments to the carrying amount of the underlying hedged debt were recorded as equal and offsetting gains and losses in other income (expense) -- net below operating income in the Consolidated Statement of Operations. There are no interest-rate derivatives designated as fair value hedges at December 31, 2002 or 2001. During 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 instrument as stated above, 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 corporate parent determines the level, term and nature of derivative instruments entered into with external parties. At December 31, 2002, these external derivative instruments did not qualify for hedge accounting per SFAS No. 133 and therefore are marked to market, the effect of which is shown as interest rate swap loss in the Consolidated Statement of Operations below operating income. At December 31, 2002, the loss totaled approximately $124.2 million. CONCENTRATION OF CREDIT RISK Williams' cash equivalents consist of high-quality securities placed with various major financial institutions with credit ratings at or above AA by Standard & Poor's or Aa by Moody's Investor's Service. Williams' investment policy limits its credit exposure to any one issuer/obligor. The following table summarizes concentration of receivables, net of allowances, by product or service at December 31, 2002 and 2001:
2002 2001 -------- -------- (MILLIONS) Receivables by product or service: Sale or transportation of natural gas and related products............................................... $ 915.6 $ 326.6 Power sales and related services.......................... 1,009.1 1,445.3 Sale or transportation of petroleum products.............. 408.4 598.8 Retained interest in accounts receivable sold to SPEs..... -- 205.0 Income taxes receivable................................... 152.0 -- Other..................................................... 39.3 186.7 -------- -------- Total................................................ $2,524.4 $2,762.4 ======== ========
Natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the eastern, northwestern and midwestern United States. Power customers include the California Independent System Operator (ISO), the California Department of Water Resources, other power marketers and utilities located throughout the majority of the United States. Petroleum products customers include wholesale, commercial, governmental, industrial and individual consumers and independent dealers located primarily in Alaska and the Gulf Coast region of the United States. Collection of the retained 156 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) interest in accounts receivable sold to the SPEs was dependent on the collection of the receivables. The accounts receivable sold to SPEs were primarily for the sale or transportation of natural gas and related products or services and the sale of petroleum products in the United States. As a general policy, collateral is not required for receivables, but customers' financial condition and credit worthiness are evaluated regularly. As of December 31, 2002, approximately $230 million of certain power receivables from the ISO and the California Power Exchange have not been paid (compared to $388 million at December 31, 2001). Williams believes that it has appropriately reflected the collection and credit risk associated with receivables and trading assets in its statement of position and results of operations at December 31, 2002. Also approximately 5,400 megawatts of Energy Marketing & Trading's tolling portfolio are subject to agreements with subsidiaries of the AES Corporation. The ability of Energy Marketing & Trading to realize future estimated fair values may be significantly affected by the ability of such parties to perform as contractually required. Additionally, one counterparty has disputed a settlement amount related to the liquidation of a trading position with Energy Marketing & Trading. The amount of settlement is in excess of $100 million payable to Energy Marketing & Trading. The matter is being arbitrated. NOTE 16. 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 $9 million for potential refund as of December 31, 2002. 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 2002, the FERC issued an order which provided that, for the period between October 2, 2000 and December 31, 2002, the FERC 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. On November 20, 2002, pursuant to an order from the 9th Circuit, FERC issued an order permitting the California parties to conduct additional discovery into market manipulation by sellers in the California markets. The California parties sought this discovery in order to potentially expand the scope of the refunds. The California parties had until March 3, 2003, to submit evidence on market manipulation. Williams and other sellers will also submit comments to the additional evidence. The judge issued his findings in the refund case on December 12, 2002. Under these findings, Williams' refund obligation to the California ISO is $192 million, excluding emissions costs and interest. The judge found that Williams' refund obligation to the California PX is $21.5 million, excluding interest. However, the judge found that the ISO owes Williams $246.8 million, excluding interest, and that the PX owes Williams $31.7 million, excluding interest, and $2.9 million in charge backs. The judge's findings do not include the $18 million in emissions costs that the judge found Williams is entitled to use as an offset to refund liability, and the judge's refund amounts are not based on final mitigated market clearing prices. FERC has not acted on the proposed change to the gas methodology. 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 was in effect from June 20, 2001 through September 30, 2002, established a market clearing price for spot sales in all hours of the day that was based on the bid of the 157 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) highest-cost gas-fired California generating unit that was needed to serve the Independent System Operator's (ISO's) load. When generation operating reserves fell 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 was the market clearing price. When generation operating reserves rise to seven percent or above in California, absent cost-based justification for a higher price, Williams' maximum price was 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 order 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 would 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 expired September 30, 2002, but the cap was later extended by FERC to October 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 FERC reaffirmed these elements in an order issued October 9, 2002, with the following clarification: (a) generators may bid above the ISO cap, but their bids cannot set the market clearing price and they will be subject to justification and refund, (b) if the market clearing price is projected to be above $91.87 per MWh in any zone, automatic mitigation will be triggered in all zones, (c) the 10 percent creditworthiness adder will be removed effective October 31, 2002. On January 17, 2003, FERC clarified that bids below $91.87 per MWh are not entitled to a safe harbor from mitigation, and where a seller is subject to the must-offer obligation but fails to submit a bid, the ISO may impose a proxy bid. On October 31, 2002, FERC found that the ISO has not explained how it will treat generators that are running at minimum load and dispatched for instructed energy. On December 2, 2002, the ISO proposed to pay for energy at minimum load the uninstructed energy price even when a unit is dispatched for instructed energy. Williams protested on January 2, 2003, arguing that the ISO's proposal fails to keep sellers whole. 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 California Electricity Oversight Board (CEOB) made a similar filing on February 27, 2002. The FERC set the complaint for hearing on April 25, 2002, but held the hearing in 158 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. The settlement discussions noted above have resulted in Williams entering into a settlement agreement with the State of California and other non-Federal parties that includes renegotiated long-term energy contracts. These contracts are made up of block energy sales, dispatchable products and a gas contract. The original contract contained only block energy sales. The settlement does not extend to criminal matters or matters of willful fraud, but will resolve civil 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. Pursuant to the settlement, Williams also will provide consideration of $147 million over eight years and six gas powered electric turbines. In addition, the settlement is intended to resolve ongoing investigations by the States of California, Oregon and Washington. The settlement was reduced to writing and executed on November 11, 2002. The settlement closed on December 31, 2002, after FERC issued an order granting Williams' motion for partial dismissal from the refund proceedings. The dismissal affects Williams' refund obligations to the settling parties, but not to other parties, such as investor-owned utilities. Pursuant to the settlement, the CPUC and CEOB filed on January 13, 2003, a motion to withdraw their complaints against Williams regarding the original block energy sales contract. Private class action plaintiffs also executed the settlement. Various court filings and approvals are necessary to make the settlement effective as to plaintiffs and to terminate the class actions as to Williams. 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. The hearing was conducted December 13 through December 20, 2002, at FERC. The judge issued an initial decision on February 27, 2003 dismissing the complaints. Williams expects this decision to be appealed to the FERC. 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 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. As a result of federal court orders, FERC released the data it obtained from Williams that gave rise to the show cause order. 159 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 December 11, 2002, the FERC staff informed Transco of a number of issues the FERC staff identified during the course of a formal, nonpublic investigation into the relationship between Transco and its marketing affiliate, Energy Marketing & Trading. The FERC staff asserted that Energy Marketing & Trading personnel had access to Transco data bases and other information, and that Transco had failed to accurately post certain information on its electronic bulletin board. Williams, Transco and Energy Marketing & Trading did not agree with all of the FERC staff's allegations and furthermore believe that Energy Marketing & Trading did not profit from the alleged activities. Nevertheless, in order to avoid protracted litigation, on March 13, 2003, Williams, Transco and Energy Marketing & Trading executed a settlement of this matter with the FERC staff. An Order approving the settlement was issued by the FERC on March 17, 2003. Pursuant to the terms of the settlement agreement, Transco will pay a civil penalty in the amount of $20 million, beginning with a payment of $4 million within thirty (30) days of the date the FERC Order approving the settlement becomes final. If no requests for rehearing are filed, the first payment would be due by May 16, 2003, and $4 million payments on or before the first, second, third and fourth anniversaries of the first payment. As a result of the settlement agreement, effective December 31, 2002, Transco recorded a charge to income and established a liability of $17 million on a discounted basis to reflect the future payments to be made over the next four years. In addition, Transco will provide notice to its merchant sales service customers that it will be terminating such services when it is able to do so under the terms of any applicable contracts and FERC certificates authorizing such services. Most of these sales are made through a Firm Sales (FS) program, and under this program Transco must provide two-year advance notice of termination. Therefore, Transco will notify the FS customers of its intention to terminate the FS service effective April 1, 2005. As part of the settlement, Energy Marketing & Trading has agreed, subject to certain exceptions, that it will not enter into new transportation agreements that would increase the transportation capacity it holds on certain affiliated interstate gas pipelines, including Transco. Finally, Transco and certain affiliates have agreed to the terms of a compliance plan designed to ensure future compliance with the provisions of the settlement agreement and the FERC's rules governing the relationship of Transco and Energy Marketing & Trading. 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 requested that interested parties respond to various questions related to the FERC's negotiated rate policies and practices. Williams' Gas Pipeline companies have negotiated rates under the FERC's existing negotiated rate programs and participated in comments filed in this proceeding by Williams in support of the FERC's existing negotiated rate program. On August 1, 2002, the FERC issued a NOPR that proposes restrictions on various types of cash management program employed by companies in the energy industry, such as Williams and its subsidiaries. In 160 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. Williams participated in comments in this proceeding on August 28, 2002, by the Interstate Natural Gas Association of America. On September 25, 2002, the FERC convened a technical conference to discuss the issues raised in the comments filed by parties in this proceeding. 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 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 Williams 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) and the U.S. Department of Justice (DOJ) are conducting an investigation regarding gas and power trading and have requested information from Williams in connection with this investigation. Williams disclosed on October 25, 2002, that certain of its gas traders had reported inaccurate information to a trade publication that published gas price indices. On November 8, 2002, Williams received a subpoena from a federal grand jury in Northern California seeking documents related to Williams' involvement in California markets, including its reporting to trade publications for both gas and power transactions. Williams is in the process of completing its response to the subpoena. The CFTC's and the DOJ's investigations into this matter are continuing. On May 31, 2002, Williams received a request from the Securities and Exchange Commission (SEC) to voluntarily produce documents and information regarding "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 161 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 has responded to the SEC's requests. 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. On December 3, 2002, an administrative law judge at the FERC issued an initial decision in Transcontinental Gas Pipe Line Corporation's general rate case which, among other things, rejects the recovery of the costs of Transco's Mobile Bay expansion project from its shippers on a "rolled-in" basis and finds that incremental pricing for the Mobile Bay expansion project is just and reasonable. The initial decision does not address the issue of the effective date for the change to incremental pricing, although Transco's rates reflecting recovery of the Mobile Bay expansion project costs on a "rolled-in" basis have been in effect since September 1, 2001. The administrative law judge's initial decision is subject to review by the FERC. Energy Marketing & Trading holds long-term transportation capacity on the Mobile Bay expansion project. If the FERC adopts the decision of the administrative law judge on the pricing of the Mobile Bay expansion project and also requires that the decision be implemented effective September 1, 2001, Energy Marketing & Trading could be subject to surcharges of approximately $22 million for prior periods, in addition to increased costs going forward. 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 December 31, 2002, these subsidiaries had accrued liabilities totaling approximately $31 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 and Texas Gas have identified polychlorinated biphenyl contamination in air compressor systems, soils and related properties at certain compressor station sites. Transcontinental Gas Pipe Line and Texas Gas have also been involved in negotiations with the U.S. Environmental Protection Agency (EPA) and state agencies to develop screening, sampling and cleanup programs. In addition, negotiations with certain environmental authorities and other programs concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites have been commenced by Texas Gas and Transcontinental Gas Pipe Line. Texas Gas and Transcontinental Gas Pipe Line likewise had accrued liabilities for these costs which are included in the $31 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. In addition to its Gas Pipelines, Williams and its subsidiaries, including those reported in discontinued operations, 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 162 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) former propane marketing operations primarily related to soil and groundwater contamination. In addition, Williams owns a discontinued petroleum refining facility that is being evaluated for potential remediation efforts. At December 31, 2002, Williams and its subsidiaries, including those reported in discontinued operations, had accrued liabilities totaling approximately $52 million for these costs. Williams and its subsidiaries, including those reported in discontinued operations, accrue 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 December 31, 2002, Williams and its subsidiaries, including those reported in discontinued operations, 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 December 31, 2002, Williams had approximately $9 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. 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 from July 1, 1998 through July 2, 2001. In November 2001, Williams furnished its response. In 2002, Williams Refining & Marketing, LLC (Williams Refining) submitted to the EPA a self-disclosure letter indicating noncompliance with the EPA's benzene waste "NESHAP" regulations. This unintentional noncompliance had occurred due to a regulatory interpretation that resulted in under-counting the total annual benzene level at the Memphis refinery. Also in 2002, the EPA conducted an all-media audit of the Memphis refinery. The EPA anticipates releasing a report of its audit findings in mid-2003. The EPA will likely assess a penalty on Williams Refining due to the benzene waste NESHAP issue, but the amount of any such penalty is not known. On March 4, 2003, Williams completed the sale of the Memphis refinery, and Williams is obligated to indemnify the purchaser for any such penalty. 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. Transcontinental Gas Pipe Line, through its agent Williams Energy Marketing & Trading, continues to purchase gas under contracts which extend, in some cases, through the life of the associated gas reserves. Certain of these contracts contain royalty indemnification provisions which have no carrying value. Producers have received and may receive other demands, which could result in claims pursuant to royalty indemnification provisions. Indemnification for royalties will depend on, among other things, the specific lease provisions between the producer and the lessor and the terms of the agreement between the producer and either Transcontinental Gas Pipe Line or Texas Gas. Consequently, the potential maximum future payments under such indemnification provisions cannot be determined. As a result of the settlements, Transcontinental Gas Pipe Line has been sued by certain producers seeking indemnification from Transcontinental Gas Pipe Line. In one of the cases, a jury verdict found that Transcontinental Gas Pipe Line was required to pay a producer damages of $23.3 million including $3.8 million in attorneys' fees. 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 163 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) petition for review. As a result, Transcontinental Gas Pipe Line recorded a pre-tax charge to income 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 the producer the amount of the judgment and accrued interest. Transcontinental Gas Pipe Line is currently defending two lawsuits in which producers have asserted damages, including interest calculated through December 31, 2002, of approximately $18 million. 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 FERC 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 January 2002, most of the Williams defendants, along with a group of Coordinating Defendants, filed a motion to dismiss for lack of personal jurisdiction. On August 19, 2002, the defendants' motion to dismiss on nonjurisdictional grounds was denied. On September 17, 2002, the plaintiffs filed a motion for class certification. The Williams entities joined with other defendants in contesting certification of the class and this issue with the personal jurisdiction motion remain pending. In 1998, the 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 any liability relating to this claim, including legal fees. The maximum amount of future payments that Williams could potentially be required to pay under this indemnification depends upon the ultimate resolution of the claim and cannot currently be determined. No amounts have been accrued for this indemnification. Grynberg has also filed claims against approximately 300 other energy companies and alleged that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought was 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. On October 9, 2002, the court granted a motion to dismiss Grynberg's royalty valuation claims. Grynberg's measurement claims remain pending against Williams and the other defendants. 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 $20 million based on interest rate variations, and punitive damages in the amount of approximately $1.4 million dollars. On October 7, 2002, the Williams 164 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) defendants filed a motion to stay the proceedings in this case based on the pendency of the False Claims Act litigation discussed in the preceding paragraph. 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 agreed on the settlement documents, which provide that Williams and its subsidiaries will be dismissed with prejudice before consummating the settlement. Williams is awaiting return of the executed documents and the dismissal. 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 administratively consolidated in San Diego County Superior Court. As part of a comprehensive settlement with the State of California and other parties, Williams and the lead plaintiffs in these suits have resolved the claims. While the settlement is final as to the State of California, the San Diego Superior Court must still approve it as to the plaintiff ratepayers. 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 Williams 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 administratively consolidated with the other class actions in San Diego Superior Court. As part of a comprehensive settlement with the State of California and other parties, Williams and the lead plaintiffs in these suits have resolved the claims. While the settlement is final as to the State of California, the San Diego Superior Court must still approve it as to the plaintiffs in this suit. 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. Private plaintiffs have also brought five similar cases 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. In January, 2003, the federal district court granted the plaintiffs' motion to remand the case to San Diego Superior Court, but on February 20, 2003, the United States Court of Appeals for the Ninth Circuit, on its own motion, stayed the remand order pending its review of an appeal of the 165 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) remand order by certain defendants. As part of a comprehensive settlement with the State of California and other parties, Williams and the lead plaintiffs in these suits have resolved the claims. While the settlement is final as to the State of California, once the jurisdictional issue is resolved, either the San Diego Superior Court or the United States District Court for the Southern District of California must still approve the settlement as to the plaintiff ratepayers and taxpayers. 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. 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. As part of a comprehensive settlement with the State of California and other parties, Williams and the plaintiffs in these suits have resolved the claims. The settlement is final, and the complaint has been withdrawn. Numerous shareholder class action suits have been filed against Williams 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. These cases have all been consolidated and an order has been issued requiring separate amended consolidated complaints by Williams and WCG equity holders. The amended complaint of the WCG securities holders was filed on September 27, 2002, and the amended complaint of the WMB securities holders was filed on October 7, 2002. 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. Williams and other defendants have filed motions to dismiss each of these suits and oral arguments on the motions will be held in April 2003. 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. On July 26, 2002, Williams entered into a Settlement Agreement with its former telecommunications subsidiary, WCG, the official committee of unsecured creditors, and Leucadia, whereby Williams settled its claims against WCG in exchange for $180 million cash for the sale of its claims to Leucadia and the sale of the Williams Technology Center to WCG. The settlement closed into escrow on October 15, 2002, and was finalized on December 2, 2002. This matter is discussed more fully in Note 2. 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 Gulf Coast Gathering Company (WGCGC), 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 166 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) are related to offers of gathering service by WFS and its subsidiaries on the recently spundown and deregulated North Padre Island offshore gathering system. On September 5, 2002, the FERC issued an order reasserting jurisdiction over that portion of the North Padre Island facilities previously transferred to WFS. The FERC also determined an unbundled gathering rate for service on these facilities which is to be collected by Transco. Transco, WGP, WGCGC and WFS believe their actions were reasonable and lawful and have sought rehearing of the FERC's order. On October 23, 2002, Western Gas Resources, Inc. and its subsidiary, Lance Oil and Gas Company, Inc. filed suit against Williams Production RMT Company in District Court for Sheridan, Wyoming, claiming that the merger of Barrett Resources Corporation and Williams triggered a preferential right to purchase a portion of the coal bed methane development properties owned by Barrett in the Powder River Basin of northeastern Wyoming. In addition, Western claims that the merger triggered certain rights of Western to replace Barrett as operator of those properties. Mediation efforts were not successful in resolving the dispute. The Company believes that the claims have no merit. Williams Alaska Petroleum, Inc. (WAPI) is actively engaged in administrative litigation being conducted jointly by the FERC and the Regulatory Commission of Alaska concerning the Trans-Alaska Pipeline System (TAPS) Quality Bank. Primary issues being litigated include the appropriate valuation of the naphtha, heavy distillate, vacuum gas oil and residual product cuts within the TAPS Quality Bank as well as the appropriate retroactive effects of the determinations. WAPI's interest in these proceedings is material as the matter involves claims by crude producers and the State of Alaska for retroactive payments plus interest from WAPI in the range of $150 million to $200 million in aggregate. Because of the complexity of the issues involved, however, the outcome cannot be predicted within certainty nor can the likely result be quantified. 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. Williams has filed its proofs of claim prior to the court-ordered October 15, 2002, bar date. 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 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 was recorded within the trading revenues in first-quarter 2002. Energy Marketing & Trading has paid and received various settlement amounts in conjunction with the liquidation of trading positions in 2002. Additionally, one counterparty has disputed a settlement amount related to the liquidation of a trading position with Energy Marketing & Trading and the amount of settlement is in excess of $100 million payable to Energy Marketing & Trading. The matter is being arbitrated. SUMMARY Litigation, arbitration, regulatory matters and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the net income of the period in which the ruling occurs. Management, including internal counsel, currently believes 167 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 not have a materially adverse effect upon Williams' future financial position. 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 currently in operation throughout the continental United States. At December 31, 2002, annual estimated committed payments under these contracts range from approximately $60 million to $462 million, resulting in total committed payments over the next 20 years of approximately $8 billion. NOTE 17. RELATED PARTY TRANSACTIONS LEHMAN BROTHERS HOLDINGS, INC. Lehman Brothers Inc. is a related party as a result of a director that serves on both Williams' and Lehman Brothers Holdings, Inc.'s board of directors. In third-quarter 2002, RMT, a wholly owned subsidiary, entered into a $900 million short-term Credit Agreement dated July 31, 2002, with certain lenders, including a subsidiary of Lehman Brothers Inc. (see Note 11). Included in interest accrued on the Consolidated Statement of Operations for 2002 are $154.1 million of interest expense, including amortization of deferred set-up fees related to the RMT note. As of December 31, 2002, the amount payable related to the RMT note and related interest was approximately $1 billion. In addition, Williams paid $39.6 million and $27 million to Lehman Brothers Inc. in 2002 and 2001, respectively, primarily for underwriting fees related to debt and equity issuances as well as strategic advisory and restructuring success fees. AMERICAN ELECTRIC POWER COMPANY, INC. American Electric Power Company, Inc. (AEP) is a related party as a result of a director that serves on both Williams' and AEP's board of directors. Williams' Energy Marketing & Trading segment engaged in forward and physical power and gas trading activities with AEP. Net revenues from AEP were $133.9 million in 2002. At December 31, 2002, amounts due from and due to AEP were $96.4 million and $331.3 million, respectively. EXXON MOBIL CORPORATION Exxon Mobil Corporation was a related party as a result of a director that serves on both Williams' and Exxon Mobil Corporation's board of directors. Transactions with Exxon Mobil Corporation result primarily from the purchase and sale of crude oil, refined products and natural gas liquids in support of crude oil, refined products and natural gas liquids trading activities and strategies as well as revenues generated from gathering and processing activities. Aggregate revenues, including those reported on a net basis, from this customer were $217.6 million, $38.9 million and $10.2 million in 2002, 2001 and 2000, respectively, while aggregate purchases from this customer were $15.6 million, $6.4 million and $69.9 million in 2002, 2001 and 2000, respectively. Amounts due from Exxon Mobil were $22.1 million and $8.3 million as of December 31, 2002 and 2001, respectively. Amounts due to Exxon Mobil were $66.9 million and $140.3 million as of December 31, 2002 and 2001, respectively. 168 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) NOTE 18. ACCUMULATED OTHER COMPREHENSIVE INCOME The table below presents changes in the components of accumulated other comprehensive income.
INCOME (LOSS) -------------------------------------------------------------- UNREALIZED APPRECIATION FOREIGN MINIMUM CASH FLOW (DEPRECIATION) CURRENCY PENSION HEDGES ON SECURITIES TRANSLATION LIABILITY TOTAL --------- -------------- ----------- --------- ------- (MILLIONS) Balance at December 31, 1999................. $ -- $ 120.1 $(20.6) $ -- $ 99.5 ------- ------- ------ ------ ------- 2000 change: Pre-income tax amount...................... -- 218.1 (28.2) -- 189.9 Income tax provision....................... -- (82.2) -- -- (82.2) Minority interest in other comprehensive income (loss)............................ -- (20.4) 4.3 -- (16.1) Net realized gains in net income (net of $118.3 income tax and $28.0 minority interest)................................ -- (162.9) -- -- (162.9) ------- ------- ------ ------ ------- -- (47.4) (23.9) -- (71.3) ------- ------- ------ ------ ------- Balance at December 31, 2000................. -- 72.7 (44.5) -- 28.2 ------- ------- ------ ------ ------- 2001 change: Cumulative effect of change in accounting for derivative instruments (net of $58.9 income tax).............................. (94.5) -- -- -- (94.5) Pre-income tax amount...................... 896.8 (69.7) (39.9) (3.6) 783.6 Income tax benefit (provision)............. (343.3) 27.5 -- 1.4 (314.4) Minority interest in other comprehensive loss..................................... -- 5.4 2.8 -- 8.2 Net realized gains in net income (net of $.1 income tax and $1.8 minority interest)................................ -- 1.5 -- -- 1.5 Net reclassification into earnings of derivative instrument gains (net of $55.7 income tax).............................. (88.8) -- -- -- (88.8) ------- ------- ------ ------ ------- 370.2 (35.3) (37.1) (2.2) 295.6 Adjustment due to spinoff of WCG............. -- (36.5) 57.8 -- 21.3 ------- ------- ------ ------ ------- Balance at December 31, 2001................. 370.2 .9 (23.8) (2.2) 345.1 ------- ------- ------ ------ ------- 2002 change: Pre-income tax amount...................... (170.7) 5.3 (.1) (27.3) (192.8) Income tax benefit (provision)............. 65.0 (1.9) -- 10.4 73.5 Minority interest in other comprehensive loss..................................... .4 -- -- -- .4 Net realized loss in net loss (net of $.7 income tax).............................. -- 1.2 -- -- 1.2 Net reclassification into earnings of derivative instrument gains (net of $119.2 income tax)....................... (193.6) -- -- -- (193.6) ------- ------- ------ ------ ------- (298.9) 4.6 (.1) (16.9) (311.3) ------- ------- ------ ------ ------- Balance at December 31, 2002................. $ 71.3 $ 5.5 $(23.9) $(19.1) $ 33.8 ======= ======= ====== ====== =======
The adjustment due to the spinoff of WCG for 2001 includes unrealized appreciation (depreciation) on securities and foreign currency translation balances which relate to WCG and are included in the $2.0 billion decrease to stockholders' equity (see Note 2). In addition, the balances at December 31 in the previous table 169 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) include components of accumulated other comprehensive income that are related to discontinued operations. The amounts related to discontinued operations for the years ended December 31 are as follows:
INCOME (LOSS) ------------------------------------------------------------- UNREALIZED APPRECIATION FOREIGN MINIMUM CASH FLOW (DEPRECIATION) CURRENCY PENSION HEDGES ON SECURITIES TRANSLATION LIABILITY TOTAL --------- -------------- ----------- --------- ------ (MILLIONS) 1999............................ $ -- $120.1 $(13.6) $ -- $106.5 2000............................ -- 76.1 (38.5) -- 37.6 2001............................ -- -- -- (.7) (.7) 2002............................ -- -- -- (1.2) (1.2)
NOTE 19. 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 and certain activities previously reported within the International segment. Effective July 1, 2002, management of certain operations previously conducted by Energy Marketing & Trading, the previously reported International segment 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 for all periods presented 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 and the segment information is reflected as such for all periods presented. Segment amounts for 2001 and 2000 reflect the reclassification of the International segment to other. 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. The accounting policies of the segments are the same as those described in Note 1, Summary of significant accounting policies. 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. Generally, the level, term and nature of derivative instruments entered into with external parties were 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 within the following tables. The results of interest rate swaps with external 170 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) counterparties are shown as interest rate swap loss in the Consolidated Statement of Operations below operating income. The majority of energy commodity hedging by the Exploration & Production and Petroleum 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 third parties. The following geographic area data includes revenues from external customers based on product shipment origin and long-lived assets based upon physical location.
UNITED STATES OTHER TOTAL ------------- -------- --------- (MILLIONS) Revenues from external customers: 2002............................................. $ 4,763.0 $ 845.4 $ 5,608.4 2001............................................. 6,241.2 824.3 7,065.5 2000............................................. 6,251.1 308.2 6,559.3 Long-lived assets: 2002............................................. $14,606.9 $1,207.0 $15,813.9 2001............................................. 14,190.1 1,356.5 15,546.6
Long-lived assets are comprised of property, plant and equipment, goodwill and other intangible assets. In 2001, one of Energy Marketing & Trading's customers exceeded 10 percent of Williams' revenues with sales of approximately $937 million. In 2002 and 2000, there were no customers who exceeded 10 percent of Williams' revenues. 171 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ENERGY MIDSTREAM WILLIAMS MARKETING GAS EXPLORATION GAS & ENERGY PETROLEUM & TRADING PIPELINE & PRODUCTION LIQUIDS PARTNERS SERVICES OTHER ----------- -------- ------------- --------- -------- --------- ------ (MILLIONS) 2002 Segment revenues: External............................ $ 977.8 $1,443.2 $ 62.7 $1,869.9 $386.7 $ 841.5 $ 26.6 Internal............................ (1,063.0)* 60.6 837.2 39.2 37.0 24.5 39.3 --------- -------- -------- -------- ------ -------- ------ Total segment revenues................ (85.2) 1,503.8 899.9 1,909.1 423.7 866.0 65.9 Less intercompany interest rate swap gain (loss)......................... (141.4) -- -- -- -- -- -- --------- -------- -------- -------- ------ -------- ------ Total revenues........................ $ 56.2 $1,503.8 $ 899.9 $1,909.1 $423.7 $ 866.0 $ 65.9 ========= ======== ======== ======== ====== ======== ====== Segment profit (loss)................. $ (624.8) $ 661.3 $ 520.5 $ 189.3 $ 99.3 $ 32.8 $ 27.9 Less: Equity earnings (losses)............ (9.7) 88.4 3.7 17.6 -- (14.6) (13.4) Income (loss) from investments...... (2.0) (13.9) -- -- -- (.7) 58.7 Intercompany interest rate swap gain (loss)............................ (141.4) -- -- -- -- -- -- --------- -------- -------- -------- ------ -------- ------ Segment operating income (loss)....... $ (471.7) $ 586.8 $ 516.8 $ 171.7 $ 99.3 $ 48.1 $(17.4) ========= ======== ======== ======== ====== ======== ====== General corporate expenses............ Consolidated operating income (loss).............................. Other financial information: Additions to long-lived assets...... $ 135.8 $ 732.3 $ 398.7 $ 821.8 $ 41.2 $ 23.0 $ 43.9 Depreciation, depletion & amortization...................... $ 33.1 $ 263.7 $ 199.9 $ 202.4 $ 37.9 $ 21.8 $ 16.3 2001 Segment revenues: External............................ $ 2,260.2 $1,384.5 $ 121.6 $1,826.3 $354.1 $1,077.8 $ 41.0 Internal............................ (554.6)* 41.5 493.6 80.5 48.4 31.9 39.3 --------- -------- -------- -------- ------ -------- ------ Total revenues and segment revenues... $ 1,705.6 $1,426.0 $ 615.2 $1,906.8 $402.5 $1,109.7 $ 80.3 ========= ======== ======== ======== ====== ======== ====== Segment profit (loss)................. $ 1,270.0 $ 571.7 $ 234.1 $ 171.9 $101.2 $ 145.7 $(25.7) Less: Equity earnings (losses)............ (1.3) 46.3 14.6 (14.0) -- (.1) (22.8) Income (loss) from investments...... (23.3) 27.5 -- -- -- -- -- --------- -------- -------- -------- ------ -------- ------ Segment operating income (loss)....... $ 1,294.6 $ 497.9 $ 219.5 $ 185.9 $101.2 $ 145.8 $ (2.9) ========= ======== ======== ======== ====== ======== ====== General corporate expenses............ Consolidated operating income (loss).............................. Other financial information: Additions to long-lived assets...... $ 209.2 $ 657.3 $3,784.7 $ 565.6 $ 87.7 $ 32.5 $ 35.3 Depreciation, depletion & amortization...................... $ 20.0 $ 265.0 $ 101.1 $ 169.7 $ 34.5 $ 22.4 $ 15.5 2000 Segment revenues: External............................ $ 2,165.5 $1,514.4 $ 76.4 $1,050.5 $314.0 $1,402.7 $ 35.8 Internal............................ (870.4)* 52.6 254.6 523.8 59.0 53.6 38.6 --------- -------- -------- -------- ------ -------- ------ Total revenues and segment revenues... $ 1,295.1 $1,567.0 $ 331.0 $1,574.3 $373.0 $1,456.3 $ 74.4 ========= ======== ======== ======== ====== ======== ====== Segment profit (loss)................. $ 970.6 $ 597.3 $ 87.6 $ 278.0 $104.2 $ 38.9 $(20.2) Less: Equity earnings (losses)............ 1.6 27.0 11.8 (4.0) -- (.6) (14.2) Income (loss) from investments...... .8 -- -- -- -- -- -- --------- -------- -------- -------- ------ -------- ------ Segment operating income (loss)....... $ 968.2 $ 570.3 $ 75.8 $ 282.0 $104.2 $ 39.5 $ (6.0) ========= ======== ======== ======== ====== ======== ====== General corporate expenses............ Consolidated operating income (loss).............................. Other financial information: Additions to long-lived assets...... $ 68.3 $ 607.3 $ 75.4 $ 942.5 $ 65.6 $ 56.6 $ 44.8 Depreciation, depletion & amortization...................... $ 17.1 $ 249.6 $ 30.8 $ 147.6 $ 30.3 $ 24.3 $ 20.7 ELIMINATIONS TOTAL ------------ -------- (MILLIONS) 2002 Segment revenues: External............................ $ -- $5,608.4 Internal............................ 25.2 -- ------- -------- Total segment revenues................ 25.2 5,608.4 Less intercompany interest rate swap gain (loss)......................... 141.4 -- ------- -------- Total revenues........................ $(116.2) $5,608.4 ======= ======== Segment profit (loss)................. $ -- $ 906.3 Less: Equity earnings (losses)............ -- 72.0 Income (loss) from investments...... -- 42.1 Intercompany interest rate swap gain (loss)............................ -- (141.4) ------- -------- Segment operating income (loss)....... $ -- 933.6 ======= General corporate expenses............ (142.8) -------- Consolidated operating income (loss).............................. $ 790.8 ======== Other financial information: Additions to long-lived assets...... $ -- $2,196.7 Depreciation, depletion & amortization...................... $ -- $ 775.1 2001 Segment revenues: External............................ $ -- $7,065.5 Internal............................ (180.6) -- ------- -------- Total revenues and segment revenues... $(180.6) $7,065.5 ======= ======== Segment profit (loss)................. $ -- $2,468.9 Less: Equity earnings (losses)............ 22.7 Income (loss) from investments...... -- 4.2 ------- -------- Segment operating income (loss)....... $ -- 2,442.0 ======= General corporate expenses............ (124.3) -------- Consolidated operating income (loss).............................. $2,317.7 ======== Other financial information: Additions to long-lived assets...... $ -- $5,372.3 Depreciation, depletion & amortization...................... $ -- $ 628.2 2000 Segment revenues: External............................ $ -- $6,559.3 Internal............................ (111.8) -- ------- -------- Total revenues and segment revenues... $(111.8) $6,559.3 ======= ======== Segment profit (loss)................. $ -- $2,056.4 Less: Equity earnings (losses)............ -- 21.6 Income (loss) from investments...... -- .8 ------- -------- Segment operating income (loss)....... $ -- 2,034.0 ======= General corporate expenses............ (97.2) -------- Consolidated operating income (loss).............................. $1,936.8 ======== Other financial information: Additions to long-lived assets...... $ -- $1,860.5 Depreciation, depletion & amortization...................... $ -- $ 520.4
--------------- * Energy Marketing & Trading intercompany cost of sales, which are netted in revenues consistent with fair-value accounting, exceed intercompany revenues. 172 THE WILLIAMS COMPANIES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
TOTAL ASSETS EQUITY METHOD INVESTMENTS --------------------------- --------------------------- DECEMBER 31, DECEMBER 31, DECEMBER 31, DECEMBER 31, 2002 2001 2002 2001 ------------ ------------ ------------ ------------ (MILLIONS) Energy Marketing & Trading......... $12,533.2 $14,707.6 $ -- $ -- Gas Pipeline....................... 8,196.5 7,506.5 778.4 715.5 Exploration & Production........... 5,816.4 5,045.6 35.8 31.6 Midstream Gas & Liquids............ 5,027.0 4,720.4 282.0 274.7 Williams Energy Partners........... 1,110.2 1,033.6 -- -- Petroleum Services................. 1,189.6 1,039.7 95.7 110.1 Other.............................. 6,829.1 7,542.7 .1 39.1 Eliminations....................... (6,694.8) (7,353.6) -- -- --------- --------- -------- -------- 34,007.2 34,242.5 1,192.0 1,171.0 --------- --------- -------- -------- Net assets of discontinued operations....................... 981.3 4,371.7 -- -- --------- --------- -------- -------- Total assets....................... $34,988.5 $38,614.2 $1,192.0 $1,171.0 ========= ========= ======== ========
173 THE WILLIAMS COMPANIES, INC QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data are as follows (millions, except per-share amounts). Certain amounts have been restated or reclassified as described in Note 1 of Notes to Consolidated Financial Statements.
FIRST SECOND THIRD FOURTH 2002 QUARTER QUARTER QUARTER QUARTER ---- -------- -------- -------- -------- Revenues..................................... $1,622.0 $1,057.4 $1,226.3 $1,702.7 Costs and operating expenses................. 816.7 835.7 937.3 1,063.8 Income (loss) from continuing operations..... 98.4 (301.3) (174.0) (124.6) Net income (loss)............................ 107.7 (349.1) (294.1) (219.2) Basic and diluted earnings (loss) per common share: Income (loss) from continuing operations... .05 (.59) (.35) (.26) Net income (loss).......................... .07 (.68) (.58) (.44)
FIRST SECOND THIRD FOURTH 2001 QUARTER QUARTER QUARTER QUARTER ---- -------- -------- -------- -------- Revenues..................................... $2,091.8 $1,689.1 $1,709.2 $1,575.4 Costs and operating expenses................. 1,127.1 988.3 830.7 900.5 Income (loss) from continuing operations..... 354.9 291.5 180.7 (24.4) Net income (loss)............................ 199.2 339.5 221.3 (1,237.7) Basic earnings (loss) per common share: Income (loss) from continuing operations... .74 .60 .36 (.05) Net income (loss).......................... .42 .70 .44 (2.39) Diluted earnings (loss) per common share: Income (loss) from continuing operations... .73 .59 .36 (.05) Net income (loss).......................... .41 .69 .44 (2.39)
The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding and rounding. Energy Marketing & Trading's net revenues 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 contracts. Energy Marketing & Trading's net segment revenues were $355.0 million, $(278.6) million, $(290.2) million and $128.6 million for the first, second, third and fourth quarters respectively for 2002. Net loss for fourth-quarter 2002 includes the following items which are pre-tax: - $85.0 million net revenue impact related to the settlement of Energy Marketing & Trading contracts with the State of California - $44.7 million impairment of the Worthington generation facility at Energy Marketing & Trading (see Note 4) - $50.8 million loss accruals and impairments of other power related assets at Energy Marketing & Trading (see Note 4) - $17.0 million charge associated with a FERC settlement (see Note 16) - $115.0 million impairment of Canadian assets at Midstream Gas & Liquids (see Note 4) 174 THE WILLIAMS COMPANIES, INC QUARTERLY FINANCIAL DATA -- (CONTINUED) - $18.4 million impairment of Alaska assets at Petroleum Services (see Note 4) - $19.2 million income from discontinued operations (see Note 2) - $172.0 million loss from discontinued operations for impairments and net losses on sales (see Note 2) Net loss for third-quarter 2002 includes the following items which are pre-tax: - $10.5 million loss accruals related to commitments for certain assets previously planned to be used in power projects at Energy Marketing & Trading (see Note 4) - $11.6 million net write-down pursuant to the sale of Williams' equity interest in a Canadian and U.S. gas pipeline, at Gas Pipeline (see Note 3) - $143.9 million gain related to the sale of certain natural gas production properties at Exploration & Production (see Note 4) - $58.5 million gain on sale of Williams' investment in a Lithuanian oil refinery, pipeline and terminal complex, which was included in the previously reported International segment (see Note 3) - $22.9 million charge included in continuing operations related to estimated losses from an assessment of the recoverability of WCG related receivables (see Note 2) - $22.5 million income from discontinued operations (see Note 2) - $231.4 million loss from discontinued operations for impairments and net losses on sales (see Note 2) Net loss for second-quarter 2002 includes the following items which are pre-tax: - $57.5 million impairment of goodwill due to deteriorating market conditions in the merchant energy sector at Energy Marketing & Trading (see Note 4) - $58.9 million of loss accruals related to commitments for certain assets previously planned to be used in power projects and write-offs associated with a terminated power plant project at Energy Marketing & Trading (see Note 4) - $31.8 million impairment of other power related assets at Energy Marketing & Trading (see Note 4) - $12.3 million write-down of Gas Pipeline's investment in a pipeline project which was cancelled in 2002 (see Note 3) - $27.4 million benefit which reflects a contractual construction completion fee received by Williams whose operations are accounted for under the equity method of accounting (see Note 3) - $15.0 million charge included in continuing operations related to estimated losses from an assessment of the recoverability of WCG related receivables (see Note 2) - $29.4 million of expense was recorded for Williams' early retirement option - $20.8 million income from discontinued operations (see Note 2) - $71.1 million loss from discontinued operations for impairments and net losses on sales (see Note 2) 175 THE WILLIAMS COMPANIES, INC QUARTERLY FINANCIAL DATA -- (CONTINUED) Net income for first-quarter 2002 includes the following items which are pre-tax: - $232.0 million charge included in continuing operations related to estimated losses from an assessment of the recoverability of WCG related receivables (see Note 2) - $52.5 million income from discontinued operations (see Note 2) - $38.1 million loss from discontinued operations for impairments and net losses on sales (see Note 2) Energy Marketing and Trading's net segment revenues for first, second, third and fourth quarters of 2001 were $598.2 million, $337.7 million, $493.1 million and $276.6 million respectively. Energy Marketing and Trading's revenues can vary as discussed above. Net loss for fourth-quarter 2001 includes the following items which are pre-tax: - $130.0 million decrease to revenues and an approximate $4 million charge to bad debt expense related to Williams' estimated net exposure for the Enron bankruptcy at Energy Marketing & Trading and Gas Pipeline, respectively (see Note 16) - $13.3 million impairment charge for the termination of a plant expansion at Energy Marketing & Trading (see Note 4) - $37.4 million charge resulting from an unfavorable court decision in one of Transcontinental Gas Pipe Line's royalty claims proceedings (see Note 16) - $213.0 million charge included in continuing operations related to estimated losses from an assessment of the recoverability of WCG related receivables (see Note 2) - $57.7 million income from discontinued operations (see Note 2) - $2,023.9 million loss from discontinued operations for impairments and net losses on sales (see Note 2) Net income for third-quarter 2001 includes the following items which are pre-tax: - $23.3 million charge related to the write-down of certain equity and cost basis investments at Energy Marketing & Trading (see Note 3) - $70.9 million charge included in continuing operations related to estimated losses from an assessment of the recoverability of WCG related receivables (see Note 2) - $65.2 million income from discontinued operations (see Note 2) Net income for second-quarter 2001 includes the following items which are pre-tax: - $72.1 million gain from the sale of certain convenience stores at Petroleum Services (see Note 4) - $10.9 million impairment loss related to certain south Texas non-regulated gathering and processing assets at Midstream Gas & Liquids (see Note 4) - $27.5 million gain on sale of Williams' limited partnership interest in Northern Border Partners, L.P. at Gas Pipeline (see Note 3) - $77.6 million income from discontinued operations (see Note 2) 176 THE WILLIAMS COMPANIES, INC QUARTERLY FINANCIAL DATA -- (CONTINUED) Net income for first-quarter 2001 includes the following items which are pre-tax: - $11.2 million impairment charge related to Petroleum Services' end-to-end mobile computing systems business (see Note 4) - $233.8 million loss from discontinued operations (see Note 2) 177 THE WILLIAMS COMPANIES, INC. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED) The following information pertains to the Williams' oil and gas producing activities and is presented in accordance with SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." The information is required to be disclosed by geographic region. Williams has significant oil and gas producing activities primarily in the Rocky Mountain and Mid-continent regions of the United States. Additionally, Williams has oil and gas producing activities in Argentina, however, proved reserves and revenues related to these activities are approximately 5.2 percent and 3.1 percent, respectively, of Williams' total oil and gas producing activities. The following information relates only to the oil and gas activities in the United States. CAPITALIZED COSTS
AS OF DECEMBER 31, ------------------- 2002 2001 -------- -------- (MILLIONS) Proved properties........................................... $2,544.8 $2,415.2 Unproved properties......................................... 784.5 851.9 -------- -------- 3,329.3 3,267.1 Accumulated depreciation, depletion, and amortization, and valuation provisions...................................... 417.7 268.3 -------- -------- Net capitalized costs....................................... $2,911.6 $2,998.8 ======== ========
- Capitalized costs include the cost of equipment and facilities for oil and gas producing activities. This amount for 2002 and 2001 does not include approximately $1 billion of goodwill related to the purchase of Barrett Resources Corp. (Barrett) in 2001. - Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); successful exploratory wells and related equipment and facilities (and uncompleted exploratory well costs) and support equipment. - Unproved properties consist primarily of acreage related to probable reserves acquired through the Barrett acquisition in addition to a small portion of unproved exploratory acreage. COSTS INCURRED
FOR THE YEAR ENDED DECEMBER 31, ------------------- 2002 2001 ------- --------- (MILLIONS) Acquisition................................................. $ -- $2,557.0 Exploration................................................. 15.5 35.6 Development................................................. 374.3 198.9 ------ -------- $389.8 $2,791.5 ====== ========
- Costs incurred include capitalized and expensed items. - Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property, the majority of which is related to the Barrett acquisition during 2001. 178 THE WILLIAMS COMPANIES, INC. SUPPLEMENTAL OIL AND GAS DISCLOSURES -- (CONTINUED) - Exploration costs include the costs of geological and geophysical activity, dry holes, drilling and equipping exploratory wells, and the cost of retaining undeveloped leaseholds. - Development costs include costs incurred to gain access to and prepare development well locations for drilling and to drill and equip development wells. RESULTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, ------------------ 2002 2001 -------- ------- (MILLIONS) Revenues: Oil and gas revenues........................................ $ 698.0 $408.4 Other revenues.............................................. 174.0 171.2 ------- ------ Total revenues.............................................. 872.0 579.6 ------- ------ Costs: Production costs............................................ 119.5 79.3 General & administrative.................................... 62.9 40.1 Exploration expenses........................................ 13.9 10.1 Depreciation, depletion & amortization...................... 191.0 94.0 Property impairments........................................ 8.4 7.2 Gain on sale of interests in Jonah and Anadarko properties................................................ (141.7) -- Other expenses.............................................. 109.2 138.7 ------- ------ Total costs................................................. 363.2 369.4 ------- ------ Results of operations....................................... 508.8 210.2 Equity earnings............................................. -- 8.5 Provision for income taxes.................................. (186.9) (80.4) ------- ------ Exploration and production net income....................... $ 321.9 $138.3 ======= ======
- Results of operations for producing activities consist of all related activities within the Exploration & Production reporting unit. - Oil and gas revenues consist primarily of natural gas production sold to Energy Marketing & Trading and includes the impact of intercompany hedges. - Other revenues and other expenses consist of activities within the Exploration & Production segment that are not a direct part of the producing activities. These non-producing 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 party purchasers. In addition, other revenues include recognition of income from transactions which transferred certain non-operating benefits to a third party. - Production costs consist of costs incurred to operate and maintain wells and related equipment and facilities used in the production of petroleum liquids and natural gas. These costs also include production related taxes other than income taxes, and administrative expenses related to the production activity. Excluded are depreciation, depletion and amortization of capitalized acquisition, exploration and development costs. 179 THE WILLIAMS COMPANIES, INC. SUPPLEMENTAL OIL AND GAS DISCLOSURES -- (CONTINUED) - Exploration expenses include unsuccessful exploratory dry hole costs, leasehold impairment, geological and geophysical expenses and the cost of retaining undeveloped leaseholds. - Depreciation, depletion and amortization includes depreciation of support equipment. PROVED RESERVES
2002 2001 ------ ------ (BCFE) (BCFE) Proved reserves at beginning of period...................... 3,178 1,202 Revisions................................................. (87) (69) Purchases................................................. -- 1,949 Extensions and discoveries................................ 385 239 Production................................................ (211) (131) Sale of minerals in place................................. (431) (12) ----- ----- Proved reserves at end of period............................ 2,834 3,178 ===== ===== Proved developed reserves at end of period.................. 1,368 1,599 ===== =====
- The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Williams' proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled or where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. - Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit. Crude oil reserves are insignificant and have been included in the proved reserves on a basis of billion cubic feet equivalents (Bcfe). STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES The following is based on the estimated quantities of proved reserves and the year-end prices and costs. The average year end natural gas prices used in the following estimates were $3.85, $2.31 and $9.17 per mmcfe at December 31, 2002, 2001 and 2000, respectively. Future income tax expenses have been computed considering available carryforwards and credits and the appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by SFAS No. 69. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs. Of the $1,215 million of future development costs, $147 million, $186 million and $197 million are estimated to be spent in 2003, 2004 and 2005, respectively. Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject 180 THE WILLIAMS COMPANIES, INC. SUPPLEMENTAL OIL AND GAS DISCLOSURES -- (CONTINUED) to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
AT DECEMBER 31, ---------------- 2002 2001 ------- ------ (MILLIONS) Future cash inflows......................................... $10,904 $7,334 Less: Future production costs................................... 2,828 1,958 Future development costs.................................. 1,215 1,114 Future income tax provisions.............................. 2,346 1,317 ------- ------ Future net cash flows....................................... 4,515 2,945 Less 10 percent annual discount for estimated timing of cash flows..................................................... 2,243 1,513 ------- ------ Standardized measure of discounted future net cash flows.... $ 2,272 $1,432 ======= ======
SOURCES OF CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
2002 2001 ------- ------ (MILLIONS) Standardized measure of discounted future net cash flows beginning of period....................................... $ 1,432 $2,720 Changes during the year: Sales of oil and gas produced, net of operating costs..... (322) (270) Net change in prices and production costs................. 1,602 (3,945) Extensions, discoveries and improved recovery, less estimated future costs................................. 546 153 Development costs incurred during year.................... 374 199 Changes in estimated future development costs............. (326) (41) Purchase of reserves in place, less estimated future costs.................................................. -- 1,069 Sales of reserves in place, less estimated future costs... (611) (8) Revisions of previous quantity estimates.................. (123) (43) Accretion of discount..................................... 203 426 Net change in income taxes................................ (537) 1,077 Other..................................................... 34 95 ------- ------ Net changes............................................... 840 (1,288) ------- ------ Standardized measure of discounted future net cash flows end of period................................................. $ 2,272 $1,432 ======= ======
181 THE WILLIAMS COMPANIES, INC. SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
ADDITIONS --------------------- CHARGED TO COSTS BEGINNING AND ENDING BALANCE EXPENSES OTHER DEDUCTIONS BALANCE --------- -------- -------- ---------- ------- (MILLIONS) Year ended December 31, 2002: Allowance for doubtful accounts -- Accounts and notes receivable(a).................. $252.2 $ 22.9 $ -- $ 161.9(c) $113.2 Other noncurrent assets(a)....... 103.2 256.0 1,720.0(e) 2,079.2(c) -- Price-risk management credit reserves(a)...................... 648.2 (397.8)(f) -- -- 250.4 Refining and processing plant major maintenance accrual(b)........... 4.0 .9 .6 2.8(d) 2.7 Year ended December 31, 2001: Allowance for doubtful accounts -- Accounts and notes receivables(a)................. 7.2 98.5 145.6(g) (.9)(c) 252.2 Other noncurrent assets(a)....... -- 103.2 -- -- 103.2 Price-risk management credit reserves(a)...................... 60.9 728.5(f) (141.2)(h) -- 648.2 Refining and processing plant major maintenance accrual(b)........... 6.0 4.0 -- 6.0(d) 4.0 Year ended December 31, 2000: Allowance for doubtful accounts -- Accounts and notes receivables(a)................. 3.5 3.4 -- (.3)(c) 7.2 Price-risk management credit reserves(a)...................... 10.6 50.3(f) -- -- 60.9 Refining and processing plant major maintenance accrual(b)........... 5.0 1.0 -- -- 6.0
--------------- (a) Deducted from related assets. (b) Included in liabilities. (c) Represents balances written off, net of recoveries and reclassifications. (d) Represents payments made. (e) Reflects a reclassification of amounts included in the liability for Guarantees and payment obligations related to Williams Communications Group, Inc. at December 31, 2001 (see Note 2 of Notes to Consolidated Financial Statements). (f) Included in revenue. (g) Reflects a reclassification of the reserve related to Enron from Price-risk management credit reserves to Allowance for doubtful accounts -- Accounts and notes receivable (see Note 16 of Notes to Consolidated Financial Statements) and amounts related to acquisitions of businesses. (h) Reflects a reclassification of the reserve related to Enron from Price-risk management credit reserves to Allowance for doubtful accounts -- Accounts and notes receivable (see Note 16 of Notes to consolidated Financial Statements). ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 182 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information regarding our directors and nominees for director required by Item 401 of Regulation S-K will be presented under the heading "Election of Directors" in our Proxy Statement prepared for the solicitation of proxies in connection with our Annual Meeting of Stockholders for 2003 (the "Proxy Statement"), which information is incorporated by reference herein. Information regarding our executive officers is presented as Item 4A herein as permitted by General Instruction G(3) to Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K. Information required by Item 405 of Regulation S-K will be included under the heading "Compliance with Section 16(a) of the Securities Exchange Act of 1934" in the Proxy Statement, which information is incorporated by reference herein. ITEM 11. EXECUTIVE COMPENSATION The information required by Item 402 of Regulation S-K regarding executive compensation will be presented under the headings "Election of Directors" and "Executive Compensation and Other Information" in the Proxy Statement, which information is incorporated by reference herein. Notwithstanding the foregoing, the information provided under the headings "Compensation Committee Report on Executive Compensation" and "Stockholder Return Performance Presentation" in the Proxy Statement is not incorporated by reference herein. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information regarding the security ownership of certain beneficial owners and management required by Item 403 of Regulation S-K will be presented under the headings "Security Ownership of Certain Beneficial Owners and Management" in the Proxy Statement, which information is incorporated by reference herein. The information regarding our Equity Compensation Stock Plans required by Item 201(d) of Regulation S-K will be presented under the heading "Equity Compensation Stock Plans" in our Proxy Statement prepared for the solicitation of proxies in connection with our Annual Meeting of Stockholders for 2003 (the "Proxy Statement"), which information is incorporated by reference herein. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information regarding certain relationships and related transactions required by Item 404 of Regulation S-K will be presented under the heading "Certain Relationships and Related Transactions" in the Proxy Statement, which information is incorporated by reference herein. ITEM 14. CONTROLS AND PROCEDURES An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-14(c) and 15d-14(c) of the Securities Exchange Act) was performed within the 90 days prior to the filing date of this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Acting Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Acting Chief Financial Officer concluded that these disclosure controls and procedures are effective. There have been no significant changes in our internal controls or other factors that could significantly affect internal controls since the certifying officers' most recent evaluation of those controls. 183 ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) 1 and 2.
PAGE ---- Covered by report of independent auditors: Consolidated statement of operations for each of the three years ended December 31, 2002.......................... 97 Consolidated balance sheet at December 31, 2002 and 2001................................................... 98 Consolidated statement of stockholders' equity for each of the three years ended December 31, 2002................ 99 Consolidated statement of cash flows for each of the three years ended December 31, 2002.......................... 100 Notes to consolidated financial statements................ 101 Schedule for each of the three years ended December 31, 2002: II -- Valuation and qualifying accounts................ 184 Not covered by report of independent auditors: Quarterly financial data (unaudited)...................... 177 Supplemental oil and gas disclosures (unaudited).......... 180
All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto. (a) 3 and (c). The exhibits listed below are filed as part of this annual report. INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION ------- ----------- 3.1 -- Restated Certificate of Incorporation, as supplemented 3.2* -- Restated By-laws (filed as Exhibit 99.1 to Form 8-K filed January 19, 2000). 4.1* -- Form of Senior Debt Indenture between Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.1 to Form S-3 filed September 8, 1997). 4.2* -- Form of Subordinated Debt Indenture between Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.2 to Form S-3 filed September 8, 1997). 4.3* -- Form of Floating Rate Senior Note (filed as Exhibit 4.3 to Form S-3 filed September 8, 1997). 4.4* -- Form of Fixed Rate Senior Note (filed as Exhibit 4.4 to Form S-3 filed September 8, 1997). 4.5* -- Form of Floating Rate Subordinated Note (filed as Exhibit 4.5 to Form S-3 filed September 8, 1997). 4.6* -- Form of Fixed Rate Subordinated Note (filed as Exhibit 4.6 to Form S-3 filed September 8, 1997). 4.7** -- First Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of September 8, 2000. 4.8** -- Second Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of December 7, 2000. 4.9** -- Third Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee dated as of December 20, 2000. 4.10* -- Fourth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed as Exhibit 4(j) to Form 10-K for the fiscal year ended December 31, 2000).
184
EXHIBIT NO. DESCRIPTION ------- ----------- 4.11* -- Fifth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed as Exhibit 4(k) to Form 10-K for the fiscal year ended December 31, 2000). 4.12* -- Sixth Supplemental Indenture dated January 14, 2002, between Williams and Bank One Trust Company, National Association, as Trustee (filed as Exhibit 4.1 to Form 8-K filed January 23, 2002). 4.13* -- Seventh Supplemental Indenture dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed as Exhibit 4.1 to Form 10-Q filed May 9, 2002). 4.14* -- Form of Senior Debt Indenture between Williams and The Chase Manhattan Bank (formerly Chemical Bank), as Trustee (filed as Exhibit 4.1 to Form S-3 filed February 2, 1990). 4.15* -- Indenture dated May 1, 1990, between Transco Energy Company and The Bank of New York, as Trustee (filed as an Exhibit to Transco Energy Company's Form 8-K dated June 25, 1990). 4.16* -- First Supplemental Indenture dated June 20, 1990, between Transco Energy Company and The Bank of New York, as Trustee (filed as an Exhibit to Transco Energy Company's Form 8-K dated June 25, 1990). 4.17* -- Second Supplemental Indenture dated November 29, 1990, between Transco Energy Company and The Bank of New York, as Trustee (filed as an Exhibit to Transco Energy Company's Form 8-K dated December 7, 1990). 4.18* -- Third Supplemental Indenture dated April 23, 1991, between Transco Energy Company and The Bank of New York, as Trustee (filed as an Exhibit to Transco Energy Company's Form 8-K dated April 30, 1991). 4.19* -- Fourth Supplemental Indenture dated August 22, 1991, between Transco Energy Company and The Bank of New York, as Trustee (filed as an Exhibit to Transco Energy Company's Form 8-K dated August 27, 1991). 4.20* -- Fifth Supplemental Indenture dated May 1, 1995, among Transco Energy Company, Williams and The Bank of New York, as Trustee (filed as Exhibit 4(l) to Form 10-K for the fiscal year ended December 31, 1998). 4.21* -- Form of Senior Debt Indenture between Williams Holdings of Delaware, Inc. and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Williams Holdings of Delaware, Inc.'s Form 10-Q filed October 18, 1995). 4.22* -- First Supplemental Indenture dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Citibank, N.A., as Trustee (filed as Exhibit 4(o) to Form 10-K for the fiscal year ended December 31, 1999). 4.23* -- Indenture dated March 31, 1990, between MAPCO Inc. and Bankers Trust Company, as Trustee (filed as Exhibit 4.0 to MAPCO Inc.'s Form 8-K filed February 19, 1991). 4.24* -- First Supplemental Indenture dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bankers Trust Company, as Trustee (filed as Exhibit 4(f) to Williams Holdings of Delaware, Inc.'s Form 10-K for the fiscal year ended December 31, 1998). 4.25* -- Second Supplemental Indenture dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Bankers Trust Company, as Trustee (filed as Exhibit 4(p) to Form 10-K for the fiscal year ended December 31, 1999). 4.26* -- Senior Indenture dated February 25, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.5.1 to MAPCO Inc.'s Amendment No. 1 to Form S-3 dated February 25, 1997). 4.27* -- Supplemental Indenture No. 1 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.(o) to MAPCO Inc.'s Form 10-K for the fiscal year ended December 31, 1997). 4.28* -- Supplemental Indenture No. 2 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.(p) to MAPCO Inc.'s Form 10-K for the fiscal year ended December 31, 1997).
185
EXHIBIT NO. DESCRIPTION ------- ----------- 4.29* -- Supplemental Indenture No. 3 dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(j) to Williams Holdings of Delaware, Inc.'s Form 10-K for the fiscal year ended December 31, 1998). 4.30* -- Supplemental Indenture No. 4 dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(q) to Form 10-K for the fiscal year ended December 31, 1999). 4.31* -- Revised Form of Indenture between Barrett Resources Corporation, as Issuer, and Bankers Trust Company, as Trustee, with respect to Senior Notes including specimen of 7.55% Senior Notes (filed as Exhibit 4.1 to Barrett Resources Corporation's Amendment No. 2 to Registration Statement on Form S-3 filed February 10, 1997). 4.32* -- First Supplemental Indenture dated 2001, between Barrett Resources Corporation, as Issuer, and Bankers Trust Company, as Trustee (filed as Exhibit 4.3 to Form 10-Q filed November 13, 2001). 4.33* -- Second Supplemental Indenture dated as of August 2, 2001, among Barrett Resources Corporation, as Issuer, Resources Acquisition Corp., The Williams Companies, Inc. and Bankers Trust Company, as Trustee (filed as Exhibit 4.4 to Form 10-Q filed November 13, 2001). 4.34* -- Rights Agreement dated as of February 6, 1996, between Williams and First Chicago Trust Company of New York (filed as Exhibit 4 to Form 8-K filed January 24, 1996). 4.35* -- Certificate of Increase of Authorized Number of Shares of Series A Junior Participating Preferred Stock (filed as Exhibit 3(f) to Form 10-K for the fiscal year ended December 31, 1995). 4.36* -- Certificate of Increase of Authorized Number of Shares of Series A Junior Participating Preferred Stock (filed as Exhibit 3(g) to Form 10-K for the fiscal year ended December 31, 1997). 4.37* -- Form of Note (filed as Exhibit 4.2 and included in Exhibit 4.1 to Form 8-K filed January 23, 2002). 4.38* -- Purchase Contract Agreement dated January 14, 2002, between Williams and JPMorgan Chase Bank, as Purchase Contract Agent (filed as Exhibit 4.3 to Form 8-K filed January 23, 2002). 4.39* -- Form of Income PACS Certificate (filed as Exhibit 4.4 and included in Exhibit 4.3 to Form 8-K filed January 23, 2002). 4.40* -- Pledge Agreement dated January 14, 2002, among Williams, JPMorgan Chase Bank, as Collateral Agent, and JPMorgan Chase Bank, as Purchase Contract Agent (filed as Exhibit 4.5 to Form 8-K filed January 23, 2002). 4.41* -- Remarketing Agreement dated January 14, 2002, among Williams, JPMorgan Chase Bank, as Purchase Contract Agent, and Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Remarketing Agent (filed as Exhibit 4.6 to Form 8-K filed January 23, 2002). 4.42* -- Indenture dated as of March 28, 2001, among WCG Note Trust, Issuer, WCG Note Corp., Inc., Co-Issuer, and United States Trust Company of New York, Indenture Trustee and Securities Intermediary (filed as Exhibit 10.8 to Form 10-Q filed November 13, 2001). 4.43* -- First Supplemental Indenture dated as of March 5, 2002, among WCG Note Trust (the "Issuer"), WCG Note Corp., Inc., (the "Co-Issuer") and Bank of New York, as Indenture Trustee (filed as Exhibit 10.4 to Form 10-Q filed May 9, 2002). 10.1* -- Credit Agreement dated as July 25, 2000, among Williams and certain of its subsidiaries, the banks named therein and Citibank, N.A., as agent (filed as Exhibit 4.1 to Form 10-Q filed August 11, 2000). 10.2* -- Waiver and First Amendment to Credit Agreement dated as of January 31, 2001, to Credit Agreement dated July 25, 2000, among Williams and certain of its subsidiaries, the banks named therein and Citibank, N.A., as agent (filed as Exhibit 4(jj) to Form 10-K for the fiscal year ended December 31, 2000). 10.3* -- Second Amendment to Credit Agreement dated as of February 7, 2002, among Williams and certain of its subsidiaries, the Banks named therein and Citibank, N.A., as agent (filed as Exhibit 10(c) to Form 10-K for the fiscal year ended December 31, 2001).
186
EXHIBIT NO. DESCRIPTION ------- ----------- 10.4* -- Third Amendment to Credit Agreement dated as of March 11, 2002, by and among Williams and certain of its subsidiaries, as Borrowers, 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 (filed as Exhibit 10.1 to Form 10-Q filed May 9, 2002). 10.5* -- 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 (filed as Exhibit 10.12 to Form 10-Q filed August 14, 2002). 10.6* -- First Amended and Restated Credit Agreement dated as of October 31, 2002, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation and Texas Gas Transmission Corporation, as Borrowers, the Banks named therein, JPMorgan Chase Bank and Commerzbank AG, as Co-Syndication Agents, Credit Lyonnais New York Branch, as Documentation Agent, Citicorp USA, Inc. as Agent, and Salomon Smith Barney Inc., as Arranger (filed as Exhibit 10.2 to Form 10-Q filed November 13, 2002). 10.7* -- Credit Agreement dated as of July 25, 2000, among Williams, the banks named therein and Citibank, N.A., as agent (filed as Exhibit 4.2 to Form 10-Q filed August 11, 2000). 10.8* -- Waiver and First Amendment to Credit Agreement dated as of January 31, 2001, to Credit Agreement dated July 25, 2000, among Williams, the banks named therein and Citibank, N.A., as agent (filed as Exhibit 4(jj) to form 10-K for the fiscal year ended December 31, 2000). 10.9* -- Limited Waiver and Second Amendment to Credit Agreement Dated July 24, 2001, among Williams, the banks named therein and Citibank, N.A., as agent (filed as Exhibit 10(f) to Form 10-K for the fiscal year ended December 31, 2001). 10.10* -- Third Amendment to Credit Agreement dated as of February 7, 2002, among Williams, the banks named therein and Citibank, N.A., as agent (filed as Exhibit 10(g) to Form 10-K filed March 7, 2002). 10.11* -- Fourth Amendment to Credit Agreement dated as of March 11, 2002 By and among Williams, as Borrower, the Banks from time to time party to the Credit Agreement, the Co-Syndication Agents as named therein and Citibank, N.A., as agent for the Banks (filed as Exhibit 10.2 to Form 10-Q filed May 9, 2002). 10.12* -- U.S. $400,000,000 Term Loan Agreement dated April 7, 2000, among Williams, the lenders named therein and Credit Lyonnais New York Branch, as administrative agent (filed as Exhibit 4(r) to Form 10-K for the fiscal year ended December 31, 1999). 10.13* -- First Amendment dated as of August 21, 2000, to Term Loan Agreement dated April 7, 2000, among Williams, the lenders named therein and Credit Lyonnais New York Branch, as administrative agent (filed as Exhibit 4(nn) to Form 10-K for the fiscal year ended December 31, 2000). 10.14* -- Form of Waiver and Second Amendment dated as of January 31, 2001, to Term Loan Agreement dated April 7, 2000, among Williams, the lenders named therein and Credit Lyonnais New York Branch, as administrative agent (filed as Exhibit 4(oo) to Form 10-K for the fiscal year ended December 31, 2000). 10.15* -- Third Amendment dated as of February 7, 2002, to Term Loan Agreement dated April 7, 2000, among Williams, the lenders named therein and Credit Lyonnais New York Branch, as administrative agent (filed as Exhibit 10(k) to Form 10-K for the fiscal year ended December 31, 2001). 10.16* -- Fourth Amendment to Term Loan Agreement effective as of March 11, 2002, among Williams, Credit Lyonnais New York New York Branch, as Administrative Agent and certain Lenders of the Term Loan Agreement (filed as Exhibit 10.3 to Form 10-Q filed May 9, 2002). 10.17 -- Fifth Amendment to Term Loan Agreement effective as of July 31, 2002, among Williams, Credit Lyonnais New York New York Branch, as Administrative Agent and certain Lenders Of the Term Loan Agreement.
187
EXHIBIT NO. DESCRIPTION ------- ----------- 10.18* -- First Amended and Restated Term Loan Agreement dated as of October 31, 2002 among The Williams Companies, Inc., as Borrower, Credit Lyonnais New York Branch, as Administrative Agent, Commerzbank AG New York and Grand Cayman Branches, As Syndication Agent, The Bank of Nova Scotia, as Documentation Agent, and the Lenders named therein (filed as Exhibit 10.10 to Form 10-Q filed November 14, 2002). 10.19* -- Participation Agreement among Williams, Williams Communications Group, Inc., Williams Communications, LLC, WCG Note Trust, WCG Note Corp., Inc., Williams Share Trust, United States Trust Company of New York and Wilmington Trust Company dated as of March 22, 2001 (filed as Exhibit 10(a) to Form 10-Q filed May 15, 2001). 10.20* -- Williams Preferred Stock Remarketing, Registration Rights and Support Agreement among Williams, Williams Share Trust, WCG Note Trust, United States Trust Company of New York and Credit Suisse First Boston Corporation dated as of March 28, 2001 (filed as Exhibit 10(b) to Form 10-Q filed May 15, 2001). 10.21* -- Intercreditor Agreement dated as of September 8, 1999, among Williams, Williams Communications Group, Inc., Williams Communications, LLC and Bank of America N.A. (filed as Exhibit 10.7 to Form 10-Q filed November 13, 2001). 10.22* -- Amendment and Consent dated as of August 17, 2000, to the Amended and Restated Participation Agreement, attaching as Exhibit A the Second Amended and Restated Guaranty Agreement dated as of August 17, 2000, between Williams, State Street Bank and Trust Company of Connecticut, National Association, State Street Bank and Trust Company and Citibank, N.A., as Agent (filed as Exhibit 10(q) to Form 10-K for the fiscal year ended December 31, 2001). 10.23* -- Amendment, Waiver and Consent dated as of January 31, 2001, to Second Amended and Restated Guaranty Agreement between Williams, State Street Bank and Trust Company of Connecticut, National Association, State Street Bank and Trust Company and Citibank, N.A., as Agent (filed as Exhibit 10(r) to Form 10-K for the fiscal year ended December 31, 2001). 10.24* -- Amendment and Consent dated as of February 7, 2002, to Second Amended and Restated Guaranty Agreement between Williams, State Street Bank and Trust Company of Connecticut, National Association, State Street Bank and Trust Company and Citibank, N.A., as Agent (filed as Exhibit 10(s) to Form 10-K for the fiscal year ended December 31, 2001). 10.25* -- The Williams Companies, Inc. Supplemental Retirement Plan effective as of January 1, 1988 (filed as Exhibit 10(iii)(c) to Form 10-K for the fiscal year ended December 31, 1987). 10.26* -- Form of The Williams Companies, Inc. Change in Control Protection Plan among Williams and employees (filed as Exhibit 10(iii)(e) to Form 10-K for the fiscal year ended December 31, 1989). 10.27* -- The Williams Companies, Inc. 1985 Stock Option Plan (filed as Exhibit A to the Proxy Statement dated March 13, 1985). 10.28* -- The Williams Companies, Inc. 1988 Stock Option Plan for Non-Employee Directors (filed as Exhibit A to the Proxy Statement dated March 14, 1988). 10.29* -- The Williams Companies, Inc. 1990 Stock Plan (filed as Exhibit A to the Proxy Statement dated March 12, 1990). 10.30* -- The Williams Companies, Inc. Stock Plan for Non-Officer Employees (filed as Exhibit 10(iii)(g) to Form 10-K for the fiscal year ended December 31, 1995). 10.31* -- The Williams Companies, Inc. 1996 Stock Plan (filed as Exhibit A to the Proxy Statement dated March 27, 1996). 10.32* -- The Williams Companies, Inc. 1996 Stock Plan for Non-Employee Directors (filed as Exhibit B to the Proxy Statement dated March 27, 1996). 10.33* -- Indemnification Agreement effective as of August 1, 1986, among Williams, members of the Board of Directors and certain officers of Williams (filed as Exhibit 10(iii)(e) to Form 10-K for the year ended December 31, 1986). 10.34* -- The Williams International Stock Plan (filed as Exhibit 10(iii)(l) to Form 10-K for the fiscal year ended December 31, 1998).
188
EXHIBIT NO. DESCRIPTION ------- ----------- 10.35* -- Form of Stock Option Secured Promissory Note and Pledge Agreement among Williams and certain employees, officers and non-employee directors (filed as Exhibit 10(iii)(m) to Form 10-K for the fiscal year ended December 31, 1998). 10.36* -- The Williams Companies, Inc. 2001 Stock Plan (filed as Exhibit 4.1 to Form S-8 filed August 1, 2001). 10.37* -- Amended and Restated Separation Agreement dated April 23, 2001, between Williams and Williams Communications Group, Inc. (filed as Exhibit 99.1 to Form 8-K filed May 3, 2001). 10.38 -- Second Amended Joint Chapter 11 Plan dated August 12, 2002, of Williams Communications Group, Inc. and CG Austria, Inc. 10.39 -- Modifications to Second Amended Joint Chapter 11 Plan dated as of September 30, 2002, of Williams Communications Group, Inc. and CG Austria, Inc. 10.40 -- Settlement Agreement dated as of July 26, 2002, among Williams, Williams Communications Group, Inc., CG Austria, Inc., the Official Committee of Unsecured Creditors of Williams Communications Group, Inc., and Leucadia National Corporation. 10.41 -- First Amendment to Settlement Agreement dated as of August 13, 2002, among Williams, Williams Communications Group, Inc., CG Austria, Inc., the Official Committee of Unsecured Creditors of Williams Communications Group, Inc., and Leucadia National Corporation. 10.42 -- Second Amendment to Settlement Agreement dated as of September 30, 2002, among Williams, Williams Communications Group, Inc., CG Austria, Inc., the Official Committee of Unsecured Creditors of Williams Communications Group, Inc., and Leucadia National Corporation. 10.43 -- Purchase and Sale Agreement dated as of July 26, 2002, by and between Williams and Leucadia National Corporation. 10.44 -- Amendment to Purchase and Sale Agreement dated as of October 15, 2002, by and between Williams and Leucadia National Corporation. 10.45 -- Agreement for the Resolution of Continuing Contract Disputes dated July 26, 2002, among Williams, Williams Communications Group, Inc., and Williams Communications, LLC. 10.46 -- Amendment to Agreement for the Resolution of Continuing Contract Disputes dated October 15, 2002, among Williams, Williams Communications Group, Inc., and Williams Communications, LLC. 10.47 -- Tax Cooperation Agreement dated July 26, 2002, by and between Williams and Williams Communications Group, Inc. 10.48 -- Guaranty Indemnification Agreement dated July 26, 2002, by and between Williams and Williams Communications Group, Inc. 10.49 -- Real Property Purchase and Sale Agreement dated as of July 26, 2002, by and between Williams Headquarters Building Company, Williams Technology Center, LLC, Williams Communications, LLC, Williams Communications Group, Inc., and Williams Aircraft Leasing, LLC. 10.50 -- First Amendment to Real Property Purchase and Sale Agreement dated October 15, 2002, by and between Williams Headquarters Building Company, Williams Technology Center, LLC, Williams Communications, LLC, Williams Communications Group, Inc., WilTel Communications Group, Inc., Williams Aircraft, Inc., and CG Austria, Inc. 10.51 -- Second Amendment to Real Property Purchase and Sale Agreement dated October 23, 2002, by and between Williams Headquarters Building Company, Williams Technology Center, LLC, Williams Communications, LLC, Williams Communications Group, Inc., WilTel Communications Group, Inc., Williams Aircraft, Inc., and CG Austria, Inc. 10.52* -- Underwriting Agreement dated January 7, 2002, between Williams and the several underwriters named therein (filed as Exhibit 1.1 to Form 8-K filed January 23, 2002). 10.53* -- Purchase Agreement between E-Birchtree, LLC and Enterprise Products Operating L.P. dated as of July 31, 2002 (filed as Exhibit 10.1 to Form 10-Q filed August 14, 2002). 10.54* -- Purchase Agreement between E-Birchtree, LLC and E-Cypress, LLC dated as of July 31, 2002 (filed as Exhibit 10.2 to Form 10-Q filed August 14, 2002).
189
EXHIBIT NO. DESCRIPTION ------- ----------- 10.55* -- $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 (filed as Exhibit 10.3 to Form 10-Q filed August 14, 2002). 10.56* -- Amendment No. 1 dated as of October 31, 2002, to Credit Agreement dated as 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, and 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 (filed as Exhibit 10.1 to Form 10-Q filed November 14, 2002). 10.57* -- 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 (filed as Exhibit 10.4 to Form 10-Q filed August 14, 2002). 10.58* -- Termination Agreement between The Williams Companies, Inc. and Keith E. Bailey dated May 1, 2002 (filed as Exhibit 10.5 to Form 10-Q filed August 14, 2002). 10.59* -- Security Agreement dated as of July 31, 2002, among The Williams Companies, Inc. and each of the Subsidiaries which is a signatory thereto or which subsequently becomes a party thereto in favor of Citibank, N.A., as collateral trustee for the benefit of the holders of the Secured Obligations (filed as Exhibit 10.6 to Form 10-Q filed August 14, 2002). 10.60* -- First Amendment dated as of October 31, 2002, to Security Agreement dated as of July 31, 2002, among the Williams Companies, Inc., and each of the Subsidiaries which is or subsequently becomes a party to the Security Agreement in favor of Citibank, N.A., as collateral trustee for the benefit of the holders of the Secured Obligations (filed As Exhibit 10.4 to Form 10-Q filed November 14, 2002). 10.61* -- Pledge Agreement dated as of July 31, 2002, among The Williams Companies, Inc. and each of the Subsidiaries which is a signatory thereto or which subsequently becomes a party thereto in favor of Citibank, N.A., as collateral trustee for the benefit of the holders of the Secured Obligations (filed as Exhibit 10.7 to Form 10-Q filed August 14, 2002). 10.62* -- First Amendment dated as of October 31, 2002, to Pledge Agreement dated as of July 31, 2002, among The Williams Companies, Inc. and each of the Subsidiaries which is or subsequently becomes a party to the Pledge Agreement in favor of Citibank, N.A., as collateral trustee for the benefit of the holders of the Secured Obligations (filed as Exhibit 10.5 to Form 10-Q filed November 14, 2002). 10.63* -- Guaranty dated as of July 31, 2002, by Williams Gas Pipeline Company, L.L.C. in favor of the Financial Institutions as defined therein (filed as Exhibit 10.8 to Form 10-Q filed August 14, 2002). 10.64* -- First Amendment dated as of October 31, 2002, to Guaranty dated as of July 31, 2002, by Williams Gas Pipeline Company, L.L.C. in favor of the Financial Institutions as defined therein (filed as Exhibit 10.6 to Form 10-Q filed November 14, 2002). 10.65* -- 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 (filed as Exhibit 10.9 to Form 10-Q filed August 14, 2002). 10.66* -- First Amendment dated as of October 31, 2002, to Collateral Trust Agreement dated as of July 31, 2002, among The Williams Companies, Inc. and certain of its Subsidiaries, as Debtors, and Citibank, N.A., as Collateral Trustee (filed as Exhibit 10.7 to Form 10-Q filed November 14, 2002).
190
EXHIBIT NO. DESCRIPTION ------- ----------- 10.67* -- Form of Guaranty dated July 31, 2002, by each of the entities named on the signature pages thereto in favor of Citibank, N.A., as surety administrative agent for the holders of the Secured Obligations (filed as Exhibit 10.10 to Form 10-Q filed August 14, 2002). 10.68* -- First Amendment to Guaranty by Midstream Entities dated as of October 31, 2002, to Guaranty dated as of July 31, 2002, by certain Midstream Subsidiaries, as defined therein, in favor of Citibank, N.A., as surety administrative agent for the holders of the Secured Obligations (filed as Exhibit 10.8 to Form 10-Q filed November 14, 2002). 10.69* -- Form of Subordinated Guaranty dated as of July 31, 2002, by Williams Production Holdings LLC in favor of the Financial Institutions (filed as Exhibit 10.11 to Form 10-Q filed August 14, 2002). 10.70* -- Amended and Restated Subordinated Guaranty dated as of October 31, 2002, by Williams Production Holdings LLC in favor of the Financial Institutions as defined herein (filed as Exhibit 10.9 to Form 10-Q filed November 14, 2002). 10.71* -- 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 therein, as Banks, and Salomon Smith Barney Inc., as Arranger (filed as Exhibit 10.13 to Form 10-Q filed August 14, 2002). 10.72* -- Amended and Restated Credit Agreement dated as of October 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., Bank of America N.A. and The Bank of Nova Scotia, as Issuing Banks, the Banks named therein, as Banks, and Salomon Smith Barney Inc., as Arranger (filed as Exhibit 10.3 to Form 10-Q filed November 14, 2002). 10.73* -- Settlement and Retention Agreement dated August 7, 2002, between The Williams Companies, Inc. and William G. von Glahn (filed as Exhibit 10.11 to Form 10-Q filed November 14, 2002). 10.74* -- Form of Change in Control Severance Agreement between the Company and certain executive officers (filed as Exhibit 10.12 to Form 10-Q filed November 14, 2002). 10.75 -- Settlement and Retention Agreement dated December 18, 2002, between The Williams Companies, Inc. and Jack D. McCarthy. 10.76 -- Contribution Agreement between and among Williams Energy Services, LLC, Williams GP LLC, The Williams Companies, Inc. and Williams Energy Partners L.P. dated April 11, 2002. 10.77 -- Purchase Agreement by and between The Williams Companies, Inc., Williams Gas Pipeline Company, LLC, Williams Western Pipeline Company LLC, and Kern River Acquisition, LLC, as Sellers, and MidAmerican Energy Holdings Company, KR Holdings, LLC, KR Acquisition 1, LLC, and KR Acquisition 2, LLC, as Buyers, dated March 7, 2002. 10.78 -- Purchase Agreement by and between Williams Gas Pipeline Company, LLC, as Seller, and Southern Star Central Corp., as Buyer, dated September 13, 2002. 10.79 -- Settlement Agreement, by and among the Governor of the State of California and the several other parties named therein and The Williams Companies, Inc. and Williams Energy Marketing & Trading Company dated November 11, 2002. 10.80 -- Asset Purchase and Sale Agreement between Williams Refining & Marketing L.L.C., Williams Generating Memphis, L.L.C., Williams Memphis Terminal, Inc., Williams Petroleum Pipeline Systems, Inc. and Williams Mid-South Pipelines, LLC and The Williams Companies, Inc., and The Premcor Refining Group, Inc. and Premcor Inc. dated November 25, 2002. 10.81 -- Stock Purchase Agreement by and among The Williams Companies, Inc, MEHC Investment, Inc. and MidAmerican Energy Holdings Company dated March 7, 2002. 12 -- Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements. 20* -- Definitive Proxy Statement of Williams for 2003 (to be filed with the Securities and Exchange Commission on or before March 31, 2003). 21 -- Subsidiaries of the registrant.
191
EXHIBIT NO. DESCRIPTION ------- ----------- 23.1 -- Consent of Independent Auditors, Ernst & Young LLP. 23.2 -- Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc. 23.3 -- Consent of Independent Petroleum Engineers, Ryder Scott Company, L.P. 23.4 -- Consent of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD. 24 -- Power of Attorney together with certified resolution.
--------------- * Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference. ** Williams agrees upon request to furnish each such exhibit to the Securities and Exchange Commission. The total amount of the securities authorized under each such exhibit does not exceed ten percent of the total assets of Williams and its subsidiaries taken as a whole. (b) Reports on Form 8-K. During fourth-quarter 2002, Williams filed an Item 5 Form 8-K on October 24, 2002, and an Item 9 Form 8-K on the following dates: October 24, 25 and 30 (2 Form 8-Ks filed on this date), November 8, 12, 15 and 26 and December 5, 17 and 19, 2002. (d) The financial statements of partially owned companies are not presented herein since none of them individually, or in the aggregate, constitute a significant subsidiary. 192 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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) By: /s/ BRIAN K. SHORE ------------------------------------ Brian K. Shore Attorney-in-fact Date: March 19, 2003 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE --------- ----- ---- /s/ STEVEN J. MALCOLM* President, Chief Executive Officer March 19, 2003 ------------------------------------------------ and Chairman of the Board Steven J. Malcolm (Principal Executive Officer) /s/ GARY R. BELITZ* Acting Chief Financial Officer March 19, 2003 ------------------------------------------------ (Principal Financial Officer) and Gary R. Belitz Controller (Principal Accounting Officer) /s/ HUGH M. CHAPMAN* Director March 19, 2003 ------------------------------------------------ Hugh M. Chapman /s/ THOMAS H. CRUIKSHANK* Director March 19, 2003 ------------------------------------------------ Thomas H. Cruikshank /s/ WILLIAM E. GREEN* Director March 19, 2003 ------------------------------------------------ William E. Green /s/ W.R. HOWELL* Director March 19, 2003 ------------------------------------------------ W.R. Howell /s/ JAMES C. LEWIS* Director March 19, 2003 ------------------------------------------------ James C. Lewis /s/ CHARLES M. LILLIS* Director March 19, 2003 ------------------------------------------------ Charles M. Lillis /s/ GEORGE A. LORCH* Director March 19, 2003 ------------------------------------------------ George A. Lorch
193
SIGNATURE TITLE DATE --------- ----- ---- /s/ FRANK T. MACINNIS* Director March 19, 2003 ------------------------------------------------ Frank T. MacInnis /s/ GORDON R. PARKER* Director March 19, 2003 ------------------------------------------------ Gordon R. Parker /s/ JANICE D. STONEY* Director March 19, 2003 ------------------------------------------------ Janice D. Stoney /s/ JOSEPH H. WILLIAMS* Director March 19, 2003 ------------------------------------------------ Joseph H. Williams *By: /s/ BRIAN K. SHORE March 19, 2003 ----------------------------------------- Brian K. Shore Attorney-in-fact
194 CERTIFICATIONS I, Steven J. Malcolm, certify that: 1. I have reviewed this annual report on Form 10-K of The Williams Companies, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14), for the registrant and have: a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. By: /s/ STEVEN J. MALCOLM ------------------------------------ Steven J. Malcolm President and Chief Executive Officer (Principal Executive Officer) Date: March 19, 2003 195 I, Gary R. Belitz, certify that: 1. I have reviewed this annual report on Form 10-K of The Williams Companies, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14), for the registrant and have: a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. By: /s/ GARY R. BELITZ ------------------------------------ Gary R. Belitz Acting Chief Financial Officer (Principal Financial Officer) and Controller (Principal Accounting Officer) Date: March 19, 2003 196 INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION ------- ----------- 3.1 -- Restated Certificate of Incorporation, as supplemented 3.2* -- Restated By-laws (filed as Exhibit 99.1 to Form 8-K filed January 19, 2000). 4.1* -- Form of Senior Debt Indenture between Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.1 to Form S-3 filed September 8, 1997). 4.2* -- Form of Subordinated Debt Indenture between Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.2 to Form S-3 filed September 8, 1997). 4.3* -- Form of Floating Rate Senior Note (filed as Exhibit 4.3 to Form S-3 filed September 8, 1997). 4.4* -- Form of Fixed Rate Senior Note (filed as Exhibit 4.4 to Form S-3 filed September 8, 1997). 4.5* -- Form of Floating Rate Subordinated Note (filed as Exhibit 4.5 to Form S-3 filed September 8, 1997). 4.6* -- Form of Fixed Rate Subordinated Note (filed as Exhibit 4.6 to Form S-3 filed September 8, 1997). 4.7** -- First Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of September 8, 2000. 4.8** -- Second Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of December 7, 2000. 4.9** -- Third Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee dated as of December 20, 2000. 4.10* -- Fourth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed as Exhibit 4(j) to Form 10-K for the fiscal year ended December 31, 2000). 4.11* -- Fifth Supplemental Indenture between Williams and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed as Exhibit 4(k) to Form 10-K for the fiscal year ended December 31, 2000). 4.12* -- Sixth Supplemental Indenture dated January 14, 2002, between Williams and Bank One Trust Company, National Association, as Trustee (filed as Exhibit 4.1 to Form 8-K filed January 23, 2002). 4.13* -- Seventh Supplemental Indenture dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed as Exhibit 4.1 to Form 10-Q filed May 9, 2002). 4.14* -- Form of Senior Debt Indenture between Williams and The Chase Manhattan Bank (formerly Chemical Bank), as Trustee (filed as Exhibit 4.1 to Form S-3 filed February 2, 1990). 4.15* -- Indenture dated May 1, 1990, between Transco Energy Company and The Bank of New York, as Trustee (filed as an Exhibit to Transco Energy Company's Form 8-K dated June 25, 1990). 4.16* -- First Supplemental Indenture dated June 20, 1990, between Transco Energy Company and The Bank of New York, as Trustee (filed as an Exhibit to Transco Energy Company's Form 8-K dated June 25, 1990). 4.17* -- Second Supplemental Indenture dated November 29, 1990, between Transco Energy Company and The Bank of New York, as Trustee (filed as an Exhibit to Transco Energy Company's Form 8-K dated December 7, 1990). 4.18* -- Third Supplemental Indenture dated April 23, 1991, between Transco Energy Company and The Bank of New York, as Trustee (filed as an Exhibit to Transco Energy Company's Form 8-K dated April 30, 1991). 4.19* -- Fourth Supplemental Indenture dated August 22, 1991, between Transco Energy Company and The Bank of New York, as Trustee (filed as an Exhibit to Transco Energy Company's Form 8-K dated August 27, 1991). 4.20* -- Fifth Supplemental Indenture dated May 1, 1995, among Transco Energy Company, Williams and The Bank of New York, as Trustee (filed as Exhibit 4(l) to Form 10-K for the fiscal year ended December 31, 1998).
EXHIBIT NO. DESCRIPTION ------- ----------- 4.21* -- Form of Senior Debt Indenture between Williams Holdings of Delaware, Inc. and Citibank, N.A., as Trustee (filed as Exhibit 4.1 to Williams Holdings of Delaware, Inc.'s Form 10-Q filed October 18, 1995). 4.22* -- First Supplemental Indenture dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Citibank, N.A., as Trustee (filed as Exhibit 4(o) to Form 10-K for the fiscal year ended December 31, 1999). 4.23* -- Indenture dated March 31, 1990, between MAPCO Inc. and Bankers Trust Company, as Trustee (filed as Exhibit 4.0 to MAPCO Inc.'s Form 8-K filed February 19, 1991). 4.24* -- First Supplemental Indenture dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bankers Trust Company, as Trustee (filed as Exhibit 4(f) to Williams Holdings of Delaware, Inc.'s Form 10-K for the fiscal year ended December 31, 1998). 4.25* -- Second Supplemental Indenture dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Bankers Trust Company, as Trustee (filed as Exhibit 4(p) to Form 10-K for the fiscal year ended December 31, 1999). 4.26* -- Senior Indenture dated February 25, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.5.1 to MAPCO Inc.'s Amendment No. 1 to Form S-3 dated February 25, 1997). 4.27* -- Supplemental Indenture No. 1 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.(o) to MAPCO Inc.'s Form 10-K for the fiscal year ended December 31, 1997). 4.28* -- Supplemental Indenture No. 2 dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4.(p) to MAPCO Inc.'s Form 10-K for the fiscal year ended December 31, 1997). 4.29* -- Supplemental Indenture No. 3 dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(j) to Williams Holdings of Delaware, Inc.'s Form 10-K for the fiscal year ended December 31, 1998). 4.30* -- Supplemental Indenture No. 4 dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., Williams and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed as Exhibit 4(q) to Form 10-K for the fiscal year ended December 31, 1999). 4.31* -- Revised Form of Indenture between Barrett Resources Corporation, as Issuer, and Bankers Trust Company, as Trustee, with respect to Senior Notes including specimen of 7.55% Senior Notes (filed as Exhibit 4.1 to Barrett Resources Corporation's Amendment No. 2 to Registration Statement on Form S-3 filed February 10, 1997). 4.32* -- First Supplemental Indenture dated 2001, between Barrett Resources Corporation, as Issuer, and Bankers Trust Company, as Trustee (filed as Exhibit 4.3 to Form 10-Q filed November 13, 2001). 4.33* -- Second Supplemental Indenture dated as of August 2, 2001, among Barrett Resources Corporation, as Issuer, Resources Acquisition Corp., The Williams Companies, Inc. and Bankers Trust Company, as Trustee (filed as Exhibit 4.4 to Form 10-Q filed November 13, 2001). 4.34* -- Rights Agreement dated as of February 6, 1996, between Williams and First Chicago Trust Company of New York (filed as Exhibit 4 to Form 8-K filed January 24, 1996). 4.35* -- Certificate of Increase of Authorized Number of Shares of Series A Junior Participating Preferred Stock (filed as Exhibit 3(f) to Form 10-K for the fiscal year ended December 31, 1995). 4.36* -- Certificate of Increase of Authorized Number of Shares of Series A Junior Participating Preferred Stock (filed as Exhibit 3(g) to Form 10-K for the fiscal year ended December 31, 1997). 4.37* -- Form of Note (filed as Exhibit 4.2 and included in Exhibit 4.1 to Form 8-K filed January 23, 2002). 4.38* -- Purchase Contract Agreement dated January 14, 2002, between Williams and JPMorgan Chase Bank, as Purchase Contract Agent (filed as Exhibit 4.3 to Form 8-K filed January 23, 2002). 4.39* -- Form of Income PACS Certificate (filed as Exhibit 4.4 and included in Exhibit 4.3 to Form 8-K filed January 23, 2002).
EXHIBIT NO. DESCRIPTION ------- ----------- 4.40* -- Pledge Agreement dated January 14, 2002, among Williams, JPMorgan Chase Bank, as Collateral Agent, and JPMorgan Chase Bank, as Purchase Contract Agent (filed as Exhibit 4.5 to Form 8-K filed January 23, 2002). 4.41* -- Remarketing Agreement dated January 14, 2002, among Williams, JPMorgan Chase Bank, as Purchase Contract Agent, and Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Remarketing Agent (filed as Exhibit 4.6 to Form 8-K filed January 23, 2002). 4.42* -- Indenture dated as of March 28, 2001, among WCG Note Trust, Issuer, WCG Note Corp., Inc., Co-Issuer, and United States Trust Company of New York, Indenture Trustee and Securities Intermediary (filed as Exhibit 10.8 to Form 10-Q filed November 13, 2001). 4.43* -- First Supplemental Indenture dated as of March 5, 2002, among WCG Note Trust (the "Issuer"), WCG Note Corp., Inc., (the "Co-Issuer") and Bank of New York, as Indenture Trustee (filed as Exhibit 10.4 to Form 10-Q filed May 9, 2002). 10.1* -- Credit Agreement dated as July 25, 2000, among Williams and certain of its subsidiaries, the banks named therein and Citibank, N.A., as agent (filed as Exhibit 4.1 to Form 10-Q filed August 11, 2000). 10.2* -- Waiver and First Amendment to Credit Agreement dated as of January 31, 2001, to Credit Agreement dated July 25, 2000, among Williams and certain of its subsidiaries, the banks named therein and Citibank, N.A., as agent (filed as Exhibit 4(jj) to Form 10-K for the fiscal year ended December 31, 2000). 10.3* -- Second Amendment to Credit Agreement dated as of February 7, 2002, among Williams and certain of its subsidiaries, the Banks named therein and Citibank, N.A., as agent (filed as Exhibit 10(c) to Form 10-K for the fiscal year ended December 31, 2001). 10.4* -- Third Amendment to Credit Agreement dated as of March 11, 2002, by and among Williams and certain of its subsidiaries, as Borrowers, 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 (filed as Exhibit 10.1 to Form 10-Q filed May 9, 2002). 10.5* -- 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 (filed as Exhibit 10.12 to Form 10-Q filed August 14, 2002). 10.6* -- First Amended and Restated Credit Agreement dated as of October 31, 2002, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation and Texas Gas Transmission Corporation, as Borrowers, the Banks named therein, JPMorgan Chase Bank and Commerzbank AG, as Co-Syndication Agents, Credit Lyonnais New York Branch, as Documentation Agent, Citicorp USA, Inc. as Agent, and Salomon Smith Barney Inc., as Arranger (filed as Exhibit 10.2 to Form 10-Q filed November 13, 2002). 10.7* -- Credit Agreement dated as of July 25, 2000, among Williams, the banks named therein and Citibank, N.A., as agent (filed as Exhibit 4.2 to Form 10-Q filed August 11, 2000). 10.8* -- Waiver and First Amendment to Credit Agreement dated as of January 31, 2001, to Credit Agreement dated July 25, 2000, among Williams, the banks named therein and Citibank, N.A., as agent (filed as Exhibit 4(jj) to form 10-K for the fiscal year ended December 31, 2000). 10.9* -- Limited Waiver and Second Amendment to Credit Agreement Dated July 24, 2001, among Williams, the banks named therein and Citibank, N.A., as agent (filed as Exhibit 10(f) to Form 10-K for the fiscal year ended December 31, 2001). 10.10* -- Third Amendment to Credit Agreement dated as of February 7, 2002, among Williams, the banks named therein and Citibank, N.A., as agent (filed as Exhibit 10(g) to Form 10-K filed March 7, 2002). 10.11* -- Fourth Amendment to Credit Agreement dated as of March 11, 2002 By and among Williams, as Borrower, the Banks from time to time party to the Credit Agreement, the Co-Syndication Agents as named therein and Citibank, N.A., as agent for the Banks (filed as Exhibit 10.2 to Form 10-Q filed May 9, 2002).
EXHIBIT NO. DESCRIPTION ------- ----------- 10.12* -- U.S. $400,000,000 Term Loan Agreement dated April 7, 2000, among Williams, the lenders named therein and Credit Lyonnais New York Branch, as administrative agent (filed as Exhibit 4(r) to Form 10-K for the fiscal year ended December 31, 1999). 10.13* -- First Amendment dated as of August 21, 2000, to Term Loan Agreement dated April 7, 2000, among Williams, the lenders named therein and Credit Lyonnais New York Branch, as administrative agent (filed as Exhibit 4(nn) to Form 10-K for the fiscal year ended December 31, 2000). 10.14* -- Form of Waiver and Second Amendment dated as of January 31, 2001, to Term Loan Agreement dated April 7, 2000, among Williams, the lenders named therein and Credit Lyonnais New York Branch, as administrative agent (filed as Exhibit 4(oo) to Form 10-K for the fiscal year ended December 31, 2000). 10.15* -- Third Amendment dated as of February 7, 2002, to Term Loan Agreement dated April 7, 2000, among Williams, the lenders named therein and Credit Lyonnais New York Branch, as administrative agent (filed as Exhibit 10(k) to Form 10-K for the fiscal year ended December 31, 2001). 10.16* -- Fourth Amendment to Term Loan Agreement effective as of March 11, 2002, among Williams, Credit Lyonnais New York New York Branch, as Administrative Agent and certain Lenders of the Term Loan Agreement (filed as Exhibit 10.3 to Form 10-Q filed May 9, 2002). 10.17 -- Fifth Amendment to Term Loan Agreement effective as of July 31, 2002, among Williams, Credit Lyonnais New York New York Branch, as Administrative Agent and certain Lenders Of the Term Loan Agreement. 10.18* -- First Amended and Restated Term Loan Agreement dated as of October 31, 2002 among The Williams Companies, Inc., as Borrower, Credit Lyonnais New York Branch, as Administrative Agent, Commerzbank AG New York and Grand Cayman Branches, As Syndication Agent, The Bank of Nova Scotia, as Documentation Agent, and the Lenders named therein (filed as Exhibit 10.10 to Form 10-Q filed November 14, 2002). 10.19* -- Participation Agreement among Williams, Williams Communications Group, Inc., Williams Communications, LLC, WCG Note Trust, WCG Note Corp., Inc., Williams Share Trust, United States Trust Company of New York and Wilmington Trust Company dated as of March 22, 2001 (filed as Exhibit 10(a) to Form 10-Q filed May 15, 2001). 10.20* -- Williams Preferred Stock Remarketing, Registration Rights and Support Agreement among Williams, Williams Share Trust, WCG Note Trust, United States Trust Company of New York and Credit Suisse First Boston Corporation dated as of March 28, 2001 (filed as Exhibit 10(b) to Form 10-Q filed May 15, 2001). 10.21* -- Intercreditor Agreement dated as of September 8, 1999, among Williams, Williams Communications Group, Inc., Williams Communications, LLC and Bank of America N.A. (filed as Exhibit 10.7 to Form 10-Q filed November 13, 2001). 10.22* -- Amendment and Consent dated as of August 17, 2000, to the Amended and Restated Participation Agreement, attaching as Exhibit A the Second Amended and Restated Guaranty Agreement dated as of August 17, 2000, between Williams, State Street Bank and Trust Company of Connecticut, National Association, State Street Bank and Trust Company and Citibank, N.A., as Agent (filed as Exhibit 10(q) to Form 10-K for the fiscal year ended December 31, 2001). 10.23* -- Amendment, Waiver and Consent dated as of January 31, 2001, to Second Amended and Restated Guaranty Agreement between Williams, State Street Bank and Trust Company of Connecticut, National Association, State Street Bank and Trust Company and Citibank, N.A., as Agent (filed as Exhibit 10(r) to Form 10-K for the fiscal year ended December 31, 2001). 10.24* -- Amendment and Consent dated as of February 7, 2002, to Second Amended and Restated Guaranty Agreement between Williams, State Street Bank and Trust Company of Connecticut, National Association, State Street Bank and Trust Company and Citibank, N.A., as Agent (filed as Exhibit 10(s) to Form 10-K for the fiscal year ended December 31, 2001). 10.25* -- The Williams Companies, Inc. Supplemental Retirement Plan effective as of January 1, 1988 (filed as Exhibit 10(iii)(c) to Form 10-K for the fiscal year ended December 31, 1987). 10.26* -- Form of The Williams Companies, Inc. Change in Control Protection Plan among Williams and employees (filed as Exhibit 10(iii)(e) to Form 10-K for the fiscal year ended December 31, 1989).
EXHIBIT NO. DESCRIPTION ------- ----------- 10.27* -- The Williams Companies, Inc. 1985 Stock Option Plan (filed as Exhibit A to the Proxy Statement dated March 13, 1985). 10.28* -- The Williams Companies, Inc. 1988 Stock Option Plan for Non-Employee Directors (filed as Exhibit A to the Proxy Statement dated March 14, 1988). 10.29* -- The Williams Companies, Inc. 1990 Stock Plan (filed as Exhibit A to the Proxy Statement dated March 12, 1990). 10.30* -- The Williams Companies, Inc. Stock Plan for Non-Officer Employees (filed as Exhibit 10(iii)(g) to Form 10-K for the fiscal year ended December 31, 1995). 10.31* -- The Williams Companies, Inc. 1996 Stock Plan (filed as Exhibit A to the Proxy Statement dated March 27, 1996). 10.32* -- The Williams Companies, Inc. 1996 Stock Plan for Non-Employee Directors (filed as Exhibit B to the Proxy Statement dated March 27, 1996). 10.33* -- Indemnification Agreement effective as of August 1, 1986, among Williams, members of the Board of Directors and certain officers of Williams (filed as Exhibit 10(iii)(e) to Form 10-K for the year ended December 31, 1986). 10.34* -- The Williams International Stock Plan (filed as Exhibit 10(iii)(l) to Form 10-K for the fiscal year ended December 31, 1998). 10.35* -- Form of Stock Option Secured Promissory Note and Pledge Agreement among Williams and certain employees, officers and non-employee directors (filed as Exhibit 10(iii)(m) to Form 10-K for the fiscal year ended December 31, 1998). 10.36* -- The Williams Companies, Inc. 2001 Stock Plan (filed as Exhibit 4.1 to Form S-8 filed August 1, 2001). 10.37* -- Amended and Restated Separation Agreement dated April 23, 2001, between Williams and Williams Communications Group, Inc. (filed as Exhibit 99.1 to Form 8-K filed May 3, 2001). 10.38 -- Second Amended Joint Chapter 11 Plan dated August 12, 2002, of Williams Communications Group, Inc. and CG Austria, Inc. 10.39 -- Modifications to Second Amended Joint Chapter 11 Plan dated as of September 30, 2002, of Williams Communications Group, Inc. and CG Austria, Inc. 10.40 -- Settlement Agreement dated as of July 26, 2002, among Williams, Williams Communications Group, Inc., CG Austria, Inc., the Official Committee of Unsecured Creditors of Williams Communications Group, Inc., and Leucadia National Corporation. 10.41 -- First Amendment to Settlement Agreement dated as of August 13, 2002, among Williams, Williams Communications Group, Inc., CG Austria, Inc., the Official Committee of Unsecured Creditors of Williams Communications Group, Inc., and Leucadia National Corporation. 10.42 -- Second Amendment to Settlement Agreement dated as of September 30, 2002, among Williams, Williams Communications Group, Inc., CG Austria, Inc., the Official Committee of Unsecured Creditors of Williams Communications Group, Inc., and Leucadia National Corporation. 10.43 -- Purchase and Sale Agreement dated as of July 26, 2002, by and between Williams and Leucadia National Corporation. 10.44 -- Amendment to Purchase and Sale Agreement dated as of October 15, 2002, by and between Williams and Leucadia National Corporation. 10.45 -- Agreement for the Resolution of Continuing Contract Disputes dated July 26, 2002, among Williams, Williams Communications Group, Inc., and Williams Communications, LLC. 10.46 -- Amendment to Agreement for the Resolution of Continuing Contract Disputes dated October 15, 2002, among Williams, Williams Communications Group, Inc., and Williams Communications, LLC. 10.47 -- Tax Cooperation Agreement dated July 26, 2002, by and between Williams and Williams Communications Group, Inc. 10.48 -- Guaranty Indemnification Agreement dated July 26, 2002, by and between Williams and Williams Communications Group, Inc.
EXHIBIT NO. DESCRIPTION ------- ----------- 10.49 -- Real Property Purchase and Sale Agreement dated as of July 26, 2002, by and between Williams Headquarters Building Company, Williams Technology Center, LLC, Williams Communications, LLC, Williams Communications Group, Inc., and Williams Aircraft Leasing, LLC. 10.50 -- First Amendment to Real Property Purchase and Sale Agreement dated October 15, 2002, by and between Williams Headquarters Building Company, Williams Technology Center, LLC, Williams Communications, LLC, Williams Communications Group, Inc., WilTel Communications Group, Inc., Williams Aircraft, Inc., and CG Austria, Inc. 10.51 -- Second Amendment to Real Property Purchase and Sale Agreement dated October 23, 2002, by and between Williams Headquarters Building Company, Williams Technology Center, LLC, Williams Communications, LLC, Williams Communications Group, Inc., WilTel Communications Group, Inc., Williams Aircraft, Inc., and CG Austria, Inc. 10.52* -- Underwriting Agreement dated January 7, 2002, between Williams and the several underwriters named therein (filed as Exhibit 1.1 to Form 8-K filed January 23, 2002). 10.53* -- Purchase Agreement between E-Birchtree, LLC and Enterprise Products Operating L.P. dated as of July 31, 2002 (filed as Exhibit 10.1 to Form 10-Q filed August 14, 2002). 10.54* -- Purchase Agreement between E-Birchtree, LLC and E-Cypress, LLC dated as of July 31, 2002 (filed as Exhibit 10.2 to Form 10-Q filed August 14, 2002). 10.55* -- $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 (filed as Exhibit 10.3 to Form 10-Q filed August 14, 2002). 10.56* -- Amendment No. 1 dated as of October 31, 2002, to Credit Agreement dated as 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, and 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 (filed as Exhibit 10.1 to Form 10-Q filed November 14, 2002). 10.57* -- 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 (filed as Exhibit 10.4 to Form 10-Q filed August 14, 2002). 10.58* -- Termination Agreement between The Williams Companies, Inc. and Keith E. Bailey dated May 1, 2002 (filed as Exhibit 10.5 to Form 10-Q filed August 14, 2002). 10.59* -- Security Agreement dated as of July 31, 2002, among The Williams Companies, Inc. and each of the Subsidiaries which is a signatory thereto or which subsequently becomes a party thereto in favor of Citibank, N.A., as collateral trustee for the benefit of the holders of the Secured Obligations (filed as Exhibit 10.6 to Form 10-Q filed August 14, 2002). 10.60* -- First Amendment dated as of October 31, 2002, to Security Agreement dated as of July 31, 2002, among the Williams Companies, Inc., and each of the Subsidiaries which is or subsequently becomes a party to the Security Agreement in favor of Citibank, N.A., as collateral trustee for the benefit of the holders of the Secured Obligations (filed As Exhibit 10.4 to Form 10-Q filed November 14, 2002). 10.61* -- Pledge Agreement dated as of July 31, 2002, among The Williams Companies, Inc. and each of the Subsidiaries which is a signatory thereto or which subsequently becomes a party thereto in favor of Citibank, N.A., as collateral trustee for the benefit of the holders of the Secured Obligations (filed as Exhibit 10.7 to Form 10-Q filed August 14, 2002).
EXHIBIT NO. DESCRIPTION ------- ----------- 10.62* -- First Amendment dated as of October 31, 2002, to Pledge Agreement dated as of July 31, 2002, among The Williams Companies, Inc. and each of the Subsidiaries which is or subsequently becomes a party to the Pledge Agreement in favor of Citibank, N.A., as collateral trustee for the benefit of the holders of the Secured Obligations (filed as Exhibit 10.5 to Form 10-Q filed November 14, 2002). 10.63* -- Guaranty dated as of July 31, 2002, by Williams Gas Pipeline Company, L.L.C. in favor of the Financial Institutions as defined therein (filed as Exhibit 10.8 to Form 10-Q filed August 14, 2002). 10.64* -- First Amendment dated as of October 31, 2002, to Guaranty dated as of July 31, 2002, by Williams Gas Pipeline Company, L.L.C. in favor of the Financial Institutions as defined therein (filed as Exhibit 10.6 to Form 10-Q filed November 14, 2002). 10.65* -- 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 (filed as Exhibit 10.9 to Form 10-Q filed August 14, 2002). 10.66* -- First Amendment dated as of October 31, 2002, to Collateral Trust Agreement dated as of July 31, 2002, among The Williams Companies, Inc. and certain of its Subsidiaries, as Debtors, and Citibank, N.A., as Collateral Trustee (filed as Exhibit 10.7 to Form 10-Q filed November 14, 2002). 10.67* -- Form of Guaranty dated July 31, 2002, by each of the entities named on the signature pages thereto in favor of Citibank, N.A., as surety administrative agent for the holders of the Secured Obligations (filed as Exhibit 10.10 to Form 10-Q filed August 14, 2002). 10.68* -- First Amendment to Guaranty by Midstream Entities dated as of October 31, 2002, to Guaranty dated as of July 31, 2002, by certain Midstream Subsidiaries, as defined therein, in favor of Citibank, N.A., as surety administrative agent for the holders of the Secured Obligations (filed as Exhibit 10.8 to Form 10-Q filed November 14, 2002). 10.69* -- Form of Subordinated Guaranty dated as of July 31, 2002, by Williams Production Holdings LLC in favor of the Financial Institutions (filed as Exhibit 10.11 to Form 10-Q filed August 14, 2002). 10.70* -- Amended and Restated Subordinated Guaranty dated as of October 31, 2002, by Williams Production Holdings LLC in favor of the Financial Institutions as defined herein (filed as Exhibit 10.9 to Form 10-Q filed November 14, 2002). 10.71* -- 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 therein, as Banks, and Salomon Smith Barney Inc., as Arranger (filed as Exhibit 10.13 to Form 10-Q filed August 14, 2002). 10.72* -- Amended and Restated Credit Agreement dated as of October 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., Bank of America N.A. and The Bank of Nova Scotia, as Issuing Banks, the Banks named therein, as Banks, and Salomon Smith Barney Inc., as Arranger (filed as Exhibit 10.3 to Form 10-Q filed November 14, 2002). 10.73* -- Settlement and Retention Agreement dated August 7, 2002, between The Williams Companies, Inc. and William G. von Glahn (filed as Exhibit 10.11 to Form 10-Q filed November 14, 2002). 10.74* -- Form of Change in Control Severance Agreement between the Company and certain executive officers (filed as Exhibit 10.12 to Form 10-Q filed November 14, 2002). 10.75 -- Settlement and Retention Agreement dated December 18, 2002, between The Williams Companies, Inc. and Jack D. McCarthy. 10.76 -- Contribution Agreement between and among Williams Energy Services, LLC, Williams GP LLC, The Williams Companies, Inc. and Williams Energy Partners L.P. dated April 11, 2002. 10.77 -- Purchase Agreement by and between The Williams Companies, Inc., Williams Gas Pipeline Company, LLC, Williams Western Pipeline Company LLC, and Kern River Acquisition, LLC, as Sellers, and MidAmerican Energy Holdings Company, KR Holdings, LLC, KR Acquisition 1, LLC, and KR Acquisition 2, LLC, as Buyers, dated March 7, 2002. 10.78 -- Purchase Agreement by and between Williams Gas Pipeline Company, LLC, as Seller, and Southern Star Central Corp., as Buyer, dated September 13, 2002.
EXHIBIT NO. DESCRIPTION ------- ----------- 10.79 -- Settlement Agreement, by and among the Governor of the State of California and the several other parties named therein and The Williams Companies, Inc. and Williams Energy Marketing & Trading Company dated November 11, 2002. 10.80 -- Asset Purchase and Sale Agreement between Williams Refining & Marketing L.L.C., Williams Generating Memphis, L.L.C., Williams Memphis Terminal, Inc., Williams Petroleum Pipeline Systems, Inc. and Williams Mid-South Pipelines, LLC and The Williams Companies, Inc., and The Premcor Refining Group, Inc. and Premcor Inc. dated November 25, 2002. 10.81 -- Stock Purchase Agreement by and among The Williams Companies, Inc, MEHC Investment, Inc. and MidAmerican Energy Holdings Company dated March 7, 2002. 12 -- Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements. 20* -- Definitive Proxy Statement of Williams for 2003 (to be filed with the Securities and Exchange Commission on or before March 31, 2003). 21 -- Subsidiaries of the registrant. 23.1 -- Consent of Independent Auditors, Ernst & Young LLP. 23.2 -- Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc. 23.3 -- Consent of Independent Petroleum Engineers, Ryder Scott Company, L.P. 23.4 -- Consent of Independent Petroleum Engineers and Geologists, Miller and Lents, LTD. 24 -- Power of Attorney together with certified resolution.
--------------- * Each such exhibit has heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and is incorporated herein by reference. ** Williams agrees upon request to furnish each such exhibit to the Securities and Exchange Commission. The total amount of the securities authorized under each such exhibit does not exceed ten percent of the total assets of Williams and its subsidiaries taken as a whole.