S-4/A 1 file001.txt AMENDMENT NO. 1 TO FORM S-4 REGISTRATION STATEMENT AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON DECEMBER 20, 2002 REGISTRATION NO. 333-101699 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ------------------------ AMENDMENT NO. 1 TO FORM S-4 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 ------------------------ MIDAMERICAN ENERGY HOLDINGS COMPANY (Exact name of registrant as specified in its charter)
IOWA 4900 94-2213782 (State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer incorporation or organization) Classification Code Number) Identification No.)
666 GRAND AVENUE DES MOINES, IOWA 50309 (515) 242-4300 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices) DOUGLAS L. ANDERSON GENERAL COUNSEL MIDAMERICAN ENERGY HOLDINGS COMPANY 302 SOUTH 36TH STREET SUITE 400 OMAHA, NE 68131 (402) 341-4500 (Name, address, including zip code, and telephone number, including area code, of agent for service) ------------------------ Copy to: PETER J. HANLON, ESQ. WILLKIE FARR & GALLAGHER 787 SEVENTH AVENUE NEW YORK, NY 10019 (212) 728-8000 APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after the effective date of this Registration Statement. If any of the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. [ ] If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] ------------------------ THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF THE SECURITIES ACT OF 1933, AS AMENDED, OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A), MAY DETERMINE. ================================================================================ [SIDEBAR] THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT AN OFFER TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN OFFER TO BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED. [END SIDEBAR] SUBJECT TO COMPLETION, DATED DECEMBER 20, 2002 PROSPECTUS [GRAPHIC OMITTED] --------------------- OFFER TO EXCHANGE --------------------- UP TO $200,000,000 4.625% SENIOR NOTES DUE 2007 FOR ALL OUTSTANDING 4.625% SENIOR NOTES DUE 2007 AND UP TO $500,000,000 5.875% SENIOR NOTES DUE 2012 FOR ALL OUTSTANDING 5.875% SENIOR NOTES DUE 2012 --------------------- o We are offering to exchange new registered 4.625% senior notes due 2007 for all of our outstanding unregistered 4.625% senior notes due 2007 and new registered 5.875% senior notes for all of our outstanding 5.875% senior notes. o The exchange offer expires at 5:00 p.m., New York City time, on January 23, 2003, unless extended. o The exchange offer is subject to customary conditions that may be waived by us. o All original notes outstanding that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer will be exchanged for the exchange notes. o Tenders of original notes may be withdrawn at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer. o The exchange of notes will not be a taxable exchange for U.S. federal income tax purposes. o We will not receive any proceeds from the exchange offer. o The terms of the exchange notes to be issued are substantially identical to the terms of the original notes, except that the exchange notes will not have transfer restrictions, and you will not have registration rights. o There is no established trading market for the exchange notes, and we do not intend to apply for listing of the exchange notes on any securities exchange or market quotation system. SEE "RISK FACTORS" BEGINNING ON PAGE 14 FOR A DISCUSSION OF MATTERS YOU SHOULD CONSIDER BEFORE YOU PARTICIPATE IN THE EXCHANGE OFFER. --------------------- Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense. --------------------- The date of this Prospectus is December , 2002 TABLE OF CONTENTS
PAGE PAGE ----- ----- SUMMARY ................................. 1 REGULATION .............................. 77 RISK FACTORS ............................ 14 LEGAL PROCEEDINGS ....................... 90 FORWARD-LOOKING STATEMENTS .............. 24 MANAGEMENT .............................. 93 USE OF PROCEEDS ......................... 25 DESCRIPTION OF THE NOTES ................ 102 THE EXCHANGE OFFER ...................... 26 CERTAIN UNITED STATES FEDERAL INCOME CAPITALIZATION .......................... 34 TAX CONSIDERATIONS ................... 117 SELECTED CONSOLIDATED FINANCIAL AND PLAN OF DISTRIBUTION .................... 121 OPERATING DATA ....................... 35 NOTICE TO CANADIAN RESIDENTS ............ 122 MANAGEMENT'S DISCUSSION AND ANALYSIS LEGAL MATTERS ........................... 122 OF FINANCIAL CONDITION AND RESULTS OF EXPERTS ................................. 122 OPERATIONS ........................... 38 WHERE YOU CAN FIND MORE INFORMATION...... 122 QUANTITATIVE AND QUALITATIVE FINANCIAL STATEMENTS .................... F-1 DISCLOSURE ABOUT MARKET RISK ......... 55 BUSINESS ................................ 56
------------ In this prospectus, references to "U.S. dollars," "dollars," "US $," "$" or "cents" are to the currency of the United States and references to " (pounds sterling)," "sterling," "pence" or "p" are to the currency of the United Kingdom. In this prospectus, MW means megawatts, MWh means megawatt hours, Bcf means billion cubic feet, mmcf means million cubic feet, MMBtus means million British thermal units, GWh means gigawatts per hour, kV means 1000 volts, and Tcf means trillion cubic feet. ------------ This prospectus incorporates important business and financial information about us that is not included or delivered with this prospectus. We will provide this information to you at no charge upon written or oral request directed to Douglas L. Anderson, General Counsel MidAmerican Energy Holdings Company, 302 South 36th Street, Suite 400, Omaha, Nebraska 68131, (402) 341-4500. In order to ensure timely delivery of the information, any request should be made by January 13, 2003. No dealer, salesperson or other individual has been authorized to give any information or to make any representations not contained in this prospectus in connection with the exchange offer. If given or made, such information or representations must not be relied upon as having been authorized by us. Neither the delivery of this prospectus nor any sale made hereunder shall, under any circumstances, create any implications that there has not been any change in the facts set forth in this prospectus or in our affairs since the date hereof. Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. The letter of transmittal accompanying this prospectus states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of the exchange notes received in exchange for original notes where such original notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 120 days after the expiration of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resales. See "Plan of Distribution." ii NOTICE TO NEW HAMPSHIRE RESIDENTS NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE THAT ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER, OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH. iii SUMMARY This section contains a general summary of the information contained in this prospectus. It may not include all of the information that is important to you. You should read this entire prospectus, including the "Risk Factors" section and the financial statements and notes to those statements, before making an investment decision. MIDAMERICAN ENERGY HOLDINGS COMPANY OVERVIEW We are a United States-based global energy company. Our principal businesses are regulated electric and natural gas utilities, regulated interstate natural gas transmission and electric power generation. Our operations are organized and managed on seven distinct platforms which we refer to as: MidAmerican Energy, Northern Natural Gas, Kern River, CE Electric UK (which includes Northern Electric and Yorkshire Electricity), CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and HomeServices. Through six of these platforms, we own and operate a combined electric and natural gas utility company in the United States, two natural gas pipeline companies in the United States, two electricity distribution companies in the United Kingdom and a diversified portfolio of domestic and international electric power projects. We also own the second largest residential real estate brokerage firm in the United States. The following is a chart of our operating platforms and the principal lines of business in which they are engaged:
+-------------------------+ | | | MidAmerican Energy | | Holdings Company | | | +-------------------------+ | | +------------------+----------------+--------------------+--------------------+-----------------+------------------+ | | | | | | | | | | | | | | +-------------+ +-------------+ +------------+ +----------------------+ +-------------+ +-------------+ +--------------+ | | | | | | | CE ELECTRIC UK | | CalEnergy | | CalEnergy | | | | MidAmerican | | Northern | | Kern River | +----------+-----------+ | Generation- | | Generation- | | HomeServices | | Energy | | Natural Gas | | | | Northern |Yorkshire | | Domestic | | Foreign | | | | | | | | | | Electric |Electricity| | | | | | | +-------------+ +-------------+ +------------+ +----------+-----------+ +-------------+ +-------------+ +--------------+ Regulated gas Regulated natural Regulated natural Regulated Non-utility Non-utility Real estate and electric gas transmission gas transmission electricity power generation power generation brokerage and utility distribution related services
Our principal subsidiaries generate, transmit, store, distribute and supply energy. Our electric and natural gas utility subsidiaries currently serve approximately 4.3 million electricity customers and approximately 653,000 natural gas customers. Our natural gas pipeline subsidiaries operate interstate natural gas transmission systems with approximately 17,500 miles of pipeline in operation and peak delivery capacity of 5.3 Bcf of natural gas per day. We have interests in 6,185 net owned megawatts of power generation facilities in operation and construction, including 4,618 net owned megawatts in facilities that are part of the regulated return asset base of our electric utility business (as further described in "Business--MidAmerican Energy--Electric Operations") and 1,567 net owned megawatts in non-utility power generation facilities. Substantially all of the non-utility power generation facilities have long-term contracts for the sale of energy and/or capacity from the facilities. We have recently achieved significant growth in our asset base, while expanding and diversifying our underlying revenue and earnings base. In the past four years, we have consummated the four significant acquisitions described below. In March 1999, our predecessor, CalEnergy Company, Inc., acquired a publicly traded company which owned the largest combined electric and gas utility in Iowa. The primary asset of this company consisted of the MidAmerican Energy platform. 1 In September 2001, we acquired the electricity distribution business of Yorkshire Power Group Ltd., or Yorkshire Electricity, which was one of the twelve original regional electric companies in the United Kingdom, and simultaneously sold the electricity and gas supply business of Northern Electric plc, or Northern Electric, to the former owner of Yorkshire Electricity. In March 2002, we acquired Kern River Gas Transmission Company, or Kern River, which owns a 926-mile interstate natural gas pipeline extending from Wyoming to markets in California, Nevada and Utah and accesses natural gas supplies from large producing regions in the Rocky Mountains and Canada. In August 2002, we acquired Northern Natural Gas Company, or Northern Natural Gas, for $928 million in cash (subject to adjustment for working capital). We used the proceeds from a $950 million investment in our subsidiary trust's preferred securities by Berkshire Hathaway Inc., or Berkshire Hathaway, to finance this acquisition. Northern Natural Gas owns a 16,600-mile interstate natural gas pipeline extending from southwest Texas to the upper Midwest region of the United States with a design capacity of 4.4 Bcf of natural gas per day. Northern Natural Gas also operates three natural gas storage facilities and two liquefied natural gas peaking units with a total storage capacity of 59 Bcf and peak delivery capability of over 1.3 Bcf of natural gas per day. Northern Natural Gas accesses natural gas supply from many of the larger producing regions in North America, including the Rocky Mountains, Hugoton, Permian, Anadarko and Western Canadian basins. The pipeline system provides transportation and storage services to utilities, municipalities, other pipeline companies, gas marketers and industrial and commercial users. Our revenues for the year ended December 31, 2001 were $5.3 billion and our total assets were $12.6 billion as of December 31, 2001. Our revenues for the nine months ended September 30, 2002 (which includes Kern River for the period from March 27, 2002 and Northern Natural Gas for the period from August 16, 2002) were $3.5 billion and our total assets were $17.0 billion as of September 30, 2002. As of September 30, 2002, the total consolidated assets of our four utility platforms, MidAmerican Energy, Northern Natural Gas, Kern River and CE Electric UK, aggregated approximately 82% of our total assets. We are a privately owned company with publicly held fixed income securities. Since March 14, 2000, our sole shareholders have consisted of a private investor group comprised of Berkshire Hathaway, Walter Scott, Jr. and members of his family, David L. Sokol, our Chairman and Chief Executive Officer, and Gregory E. Abel, our President and Chief Operating Officer. Prior to that time, our common stock was publicly traded on the New York Stock Exchange. STRATEGY Our business strategy is focused upon the successful operation, management and growth of our diversified portfolio of energy assets and on the pursuit of strategic utility acquisitions and selected other investment opportunities, principally in the United States. As a privately owned company, we are able to focus on long-term risk-adjusted cash flow returns from our businesses. We seek to manage and operate our energy assets such that their cost structure makes us a low-cost provider of energy and energy services. In order to implement this strategy, we plan to: PURSUE OPERATING EFFICIENCIES AND INTERNAL INVESTMENT OPPORTUNITIES IN OUR BUSINESSES, WHILE MAINTAINING QUALITY AND RELIABILITY OF SERVICE. Our management philosophy emphasizes the efficient operation of our businesses through strict attention to the operational performance of our assets, continuous review and implementation of cost reduction initiatives and the active pursuit of opportunities to earn reasonable returns by making incremental capital investments within our existing operations. Following each of our utility acquisitions, we have implemented operational improvements and cost reductions that have enhanced asset performance and service reliability. These and other initiatives have helped us to pursue our goal of being a low-cost provider of energy and energy services to our customers and have strengthened our competitive position in the marketplace, while also increasing the returns on 2 our investments. In addition, we have worked closely and successfully with customers and with regulatory and legislative authorities to ensure that our business initiatives are consistent with our obligations to serve customers and with the requirements of the regulatory regimes under which we operate. We have identified and are proceeding with a number of significant capital investment opportunities that we believe offer attractive risk-adjusted returns. These opportunities include a $1.2 billion program to expand MidAmerican Energy's base of electric generation facilities in Iowa and a $1.2 billion expansion to approximately double the design delivery capacity of our Kern River pipeline by 2003, which we refer to as the 2003 Expansion Project. GROW AND DIVERSIFY THROUGH ACQUISITIONS OF HIGH QUALITY REGULATED UTILITY BUSINESSES. We believe that well managed regulated utility businesses can provide a stable cash flow profile and a reasonable risk-adjusted equity return to their owners. Our acquisitions of Northern Electric in 1997 and MidAmerican Energy in 1999 provided us with specialized skills and expertise, particularly in operations and regulatory affairs, which have enhanced our competitive position and positioned us favorably for future growth in our targeted sectors. In the past fifteen months, we completed three acquisitions of utility operating companies, Yorkshire Electricity, Kern River and Northern Natural Gas, each of which has added substantially to our base of utility operating assets and cash flows. We believe that these acquisitions helped us achieve additional diversification of our utility business with respect to sources of cash flow, types of utility operations, geography and regulatory regimes. CAPITALIZE ON CHANGE IN OUR INDUSTRY AND ON OUR SUPERIOR ACCESS TO CAPITAL IN ORDER TO MAKE ATTRACTIVE INVESTMENTS. The global energy markets, particularly those in the United States, are experiencing a period of significant change due to various factors, including the macroeconomic environment, fluctuating commodity prices, regulatory and legislative developments and financial restructurings by many market participants. We and our shareholders believe that such an environment provides opportunities for disciplined companies with access to investment capital to achieve reasonable risk-adjusted returns by acquiring high quality companies and assets at reasonable prices. Warren Buffett, Chairman of the Board and Chief Executive Officer of Berkshire Hathaway, has publicly stated that we are a core holding of Berkshire Hathaway and are expected to be its principal vehicle for investments in the energy sector. In 2002 to date, we completed two acquisitions of interstate natural gas transmission pipelines, which we funded with a majority of the proceeds of Berkshire Hathaway's investment in $1.273 billion of our trust preferred securities and $402 million of our zero coupon convertible preferred stock, all of which is subordinated to our senior indebtedness. We believe that our ability to successfully negotiate and complete these acquisitions was facilitated by our access to capital from Berkshire Hathaway and that there will continue to be opportunities in the current environment to make additional acquisitions that further enhance our business mix, risk profile, capitalization and investment returns. ENHANCE OUR INVESTMENT GRADE CREDIT PROFILE AND THAT OF OUR SUBSIDIARIES. Our financing strategy is focused on capitalizing and managing our utility subsidiaries in a manner consistent with maintenance of strong credit ratings, thereby supporting our credit profile with more predictable underlying cash flows from these subsidiaries. This strategy is driven by our belief that strong credit ratings allow us to minimize our financing costs over the long term and to optimize our investment returns, while also retaining the financial flexibility to pursue attractive capital investment opportunities as and when they are available. Our strategy is to finance our operating subsidiaries with debt that in almost all cases is non-recourse to us, which has allowed us to reduce financing costs by taking advantage of the stable, investment grade characteristics of our subsidiaries' utility assets. MAINTAIN PRUDENT FINANCIAL AND RISK MANAGEMENT POLICIES AND PRACTICES. Through our focus on regulated utility businesses, we strive to minimize the underlying risks of our portfolio of assets. Substantially all of our net owned megawatts in our non-utility power generation business have long-term (greater than one year) contracts for the sale of their energy and/or capacity, and substantially all of these assets are financed by non-recourse project finance debt. We seek to limit our exposure to movements in the commodity prices of energy products and are not a significant trader of energy commodities. Our activities in the marketing and supply of energy to customers outside of our regulated utility customer 3 base are not a material part of our business and are conducted pursuant to closely monitored risk management policies and practices that are intended to minimize our exposure to fluctuations in energy commodity prices and to counterparty credit risk. A core tenet of our acquisition and investment philosophy is that we will only pursue opportunities that meet our strict requirements for an acceptable risk profile and attractive potential cash flow returns. If we do not believe that such opportunities are available, we prefer to reduce our acquisition activities and focus on the optimization of our existing portfolio rather than pursue growth by accepting greater risks or inferior returns. ---------------- Our principal executive offices are located at 666 Grand Avenue, Des Moines, Iowa 50309, and our telephone number is (515) 242-4300. 4 THE EXCHANGE OFFER On October 4, 2002, we privately placed $200,000,000 aggregate principal amount of 4.625% senior notes due 2007 and $500,000,000 aggregate principal amount of 5.875% senior notes due 2012, which we refer to collectively as the original notes, in a transaction exempt from registration under the Securities Act. In connection with the private placement, we entered into a registration rights agreement, dated as of October 1, 2002, with the initial purchasers of the original notes. In the registration rights agreement, we agreed to offer our new 4.625% senior notes due 2007 and 5.875% senior notes due 2012, which will be registered under the Securities Act and which we refer to collectively as the exchange notes, in exchange for the applicable original notes. The exchange offer is intended to satisfy our obligations under the registration rights agreement. We also agreed to deliver this prospectus to the holders of the original notes. In this prospectus we refer to the original notes and the exchange notes as the notes. You should read the discussion under the headings "Summary--Terms of the Notes" and "Description of Notes" for information regarding the notes. THE EXCHANGE OFFER.......... This is an offer to exchange $1,000 in principal amount of exchange notes for each $1,000 in principal amount of original notes. The exchange notes are substantially identical to the original notes, except that the exchange notes will generally be freely transferable. We believe that you can transfer the exchange notes without complying with the registration and prospectus delivery provisions of the Securities Act if you: o acquire the exchange notes in the ordinary course of your business; o are not and do not intend to become engaged in a distribution of the exchange notes; o are not an "affiliate" (within the meaning of the Securities Act) of ours; o are not a broker-dealer (within the meaning of the Securities Act) that acquires the original notes from us or our affiliates; o are not a broker-dealer (within the meaning of the Securities Act) that acquired the original notes in a transaction as part of its market-making or other trading activities. If any of these conditions are not satisfied and you transfer any exchange note without delivering a proper prospectus or without qualifying for a registration exemption, you may incur liability under the Securities Act. See "The Exchange Offer--Terms of the Exchange." REGISTRATION RIGHTS AGREEMENT................... Under the registration rights agreement, we have agreed to use our reasonable best efforts to consummate the exchange offer or cause the original notes to be registered under the Securities Act to permit resales. If we are not in compliance with our obligations under the registration rights agreement, liquidated damages will accrue on the original notes in addition to the interest that is otherwise due on the original notes. If the exchange offer is completed on the terms and within the time period contemplated by this prospectus, no liquidated damages will be payable on the notes. The exchange notes will not contain any provisions regarding the payment of liquidated damages. See "The Exchange Offer--Liquidated Damages." 5 MINIMUM CONDITION........... The exchange offer is not conditioned on any minimum aggregate principal amount of original notes being tendered for exchange. EXPIRATION DATE............. The exchange offer will expire at 5:00 p.m., New York City time, on January 23, 2003, unless we extend it. EXCHANGE DATE............... Original notes will be accepted for exchange at the time when all conditions of the exchange offer are satisfied or waived. The exchange notes will be delivered promptly after we accept the original notes. CONDITIONS TO THE EXCHANGE OFFER.............. Our obligation to complete the exchange offer is subject to certain conditions. See "The Exchange Offer--Conditions to the Exchange Offer." We reserve the right to terminate or amend the exchange offer at any time prior to the expiration date upon the occurrence of certain specified events. WITHDRAWAL RIGHTS........... You may withdraw the tender of your original notes at any time before the expiration of the exchange offer on the expiration date. Any original notes not accepted for any reason will be returned to you without expense as promptly as practicable after the expiration or termination of the exchange offer. PROCEDURES FOR TENDERING ORIGINAL NOTES.............. See "The Exchange Offer--How to Tender." UNITED STATES FEDERAL INCOME TAX CONSEQUENCES........... The exchange of the original notes for exchange notes by U.S. Holders (as defined below) will not be a taxable exchange for federal income tax purposes, and U.S. Holders should not recognize any taxable gain or loss as a result of such exchange. EFFECT ON HOLDERS OF ORIGINAL NOTES...................... If the exchange offer is completed on the terms and within the period contemplated by this prospectus, holders of original notes will have no further registration or other rights under the registration rights agreement, except under limited circumstances. See "The Exchange Offer--Other." HOLDERS OF ORIGINAL NOTES WHO DO NOT TENDER THEIR ORIGINAL NOTES WILL CONTINUE TO HOLD THOSE ORIGINAL NOTES. ALL UNTENDERED, AND TENDERED BUT UNACCEPTED, ORIGINAL NOTES WILL CONTINUE TO BE SUBJECT TO THE TRANSFER RESTRICTIONS PROVIDED FOR IN THE ORIGINAL NOTES AND THE INDENTURE UNDER WHICH THE ORIGINAL NOTES HAVE BEEN ISSUED. To the extent that original notes are tendered and accepted in the exchange offer, the trading market, if any, for the original notes could be adversely affected. See "Risk Factors-- Risks Associated with the Exchange Offer--You may not be able to sell your original notes if you do not exchange them for registered exchange notes in the exchange offer."; "--Your ability to sell your original notes may be significantly 6 more limited and the price at which you may be able to sell your original notes may be significantly lower if you do not exchange them for registered exchange notes in the exchange offer."; and "The Exchange Offer--Other." USE OF PROCEEDS............. We will not receive any proceeds from the issuance of exchange notes in the exchange offer. EXCHANGE AGENT.............. The Bank of New York is serving as the exchange agent in connection with the exchange offer. 7 TERMS OF THE NOTES GENERAL..................... $200,000,000 aggregate principal amount of 4.625% senior notes due October 1, 2007, and $500,000,000 aggregate principal amount of 5.875% senior notes due October 1, 2012. INTEREST PAYMENT DATES...... January 31 and July 31 of each year, commencing January 31, 2003. OPTIONAL REDEMPTION......... We may redeem the notes of each series, at our option, in whole or in part, at any time, at a redemption price equal to the greater of: (1) 100% of the principal amount of the notes to be redeemed; or (2) the sum of the present values of the remaining scheduled payments of principal of and interest on the series of notes to be redeemed discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at a discount rate equal to the yield on equivalent Treasury securities plus 37.5 basis points, plus, for (1) or (2) above, whichever is applicable, accrued and unpaid interest, if any, on such notes to the date of redemption. SINKING FUND................ The notes are not subject to a mandatory sinking fund. CHANGE OF CONTROL........... Upon the occurrence of a Change of Control each holder of the notes will have the right, at the holder's option, to require us to repurchase all or any part of the holder's notes at a purchase price in cash equal to 101% of the principal thereof, plus accrued and unpaid interest, if any, to the date of such purchase in accordance with the procedures set forth in the indenture for the notes. A Change of Control means the occurrence of both of the following: (1) a transaction pursuant to which Berkshire Hathaway ceases to own, on a diluted basis, at least a majority of our common stock, assuming conversion of all convertible securities then owned by Berkshire Hathaway, without regard to whether then presently convertible, or we or our subsidiaries dispose of all or substantially all of our property and that of our subsidiaries to any entity which is not so majority owned by Berkshire Hathaway, and (2) within 90 days after the earlier of the announcement or occurrence of any such transaction, a downgrade in the ratings for the notes (generally to below investment grade by both Moody's Investors Service, Inc. and Standard & Poor's Rating Service) occurs. See "Description of the Notes--Covenants--Purchase of Notes Upon a Change of Control." RANKING..................... The notes are our general, unsecured senior obligations and rank pari passu in right of payment with all our other existing and future senior unsecured obligations and senior in right of 8 payment to all our existing and future subordinated obligations. The notes are effectively subordinated to all our existing and future secured obligations and to all existing and future obligations of our subsidiaries. COVENANTS................... The indenture for the notes contains covenants that, among other things, restrict our ability to grant liens on our assets and our ability to merge, consolidate or transfer or lease all or substantially all of our assets. See "Description of the Notes--Covenants." EVENTS OF DEFAULT........... Events of default with respect to the notes of any series under the indenture include, among other things: (1) default in the payment of any interest on any notes of that series for 30 days after payment is due; (2) default in the payment of principal of, or premium, if any, on any note of that series or as to any payment required in connection with a Change of Control as described above; (3) our failure to perform, or breach by us of, any covenant contained in the indenture or the notes of that series, which failure continues for 30 days after written notice thereof is provided to us pursuant to the indenture; (4) our failure or the failure of any of our significant subsidiaries (as defined later in this prospectus) to pay when due beyond any applicable grace period, or the acceleration of, debt (other than debt that is non-recourse to us) in excess of $100,000,000; (5) the entry by a court of one or more judgments against us or any of our significant subsidiaries (other than a judgment that is non-recourse to us) requiring payment by us in an aggregate amount in excess of $100,000,000 which has not been vacated, discharged, satisfied or stayed pending appeal within 60 days from entry; and (6) the occurrence of certain events of bankruptcy, insolvency or reorganization with respect to us or any of our significant subsidiaries. See "Description of the Notes--Definitions" and "--Events of Default." RATINGS..................... The notes were initially assigned ratings of Baa3 by Moody's, BBB-- by S&P and BBB by Fitch, Inc. However, these ratings are subject to change at any time. DENOMINATION AND FORM....... The original notes were, and the exchange notes will be, issued in denominations of $1,000 and any integral multiple of $1,000. The original notes were, and the exchange notes will be, represented by one or more global securities registered in the name of The Depository Trust Company or its nominee. 9 Beneficial interests in the global securities representing the original notes are, and the exchange notes will be, shown on, and transfers of the beneficial interests in the global securities representing the original notes are, and transfers of the beneficial interests in the global securities representing the exchange notes will be, effected only through, records maintained by DTC and its participants. Except as described later in this prospectus, notes in certificated form will not be issued. See "Description of the Notes--Global Notes; Book-Entry System." TRUSTEE..................... The Bank of New York is the trustee for the holders of the notes. GOVERNING LAW............... The notes, the indenture and the other documents for the offering of the notes are governed by the laws of the State of New York. RISK FACTORS This investment involves risks. Before you invest in the notes, you should carefully consider the matters set forth under the heading "Risk Factors" and all other information in this prospectus. 10 SUMMARY SELECTED HISTORICAL CONSOLIDATED FINANCIAL AND OPERATING DATA The following table presents our summary historical consolidated financial and operating data as of and for the years ended December 31, 2001, 2000, and 1999, and as of September 30, 2002 and for the nine months ended September 30, 2002 and 2001. Our unaudited consolidated financial statements as of September 30, 2002 and for the nine months ended September 30, 2002 and 2001 reflect all adjustments necessary in the opinion of our management (consisting of normal recurring accruals) for a fair presentation of such data. The financial data set forth below should be read in conjunction with our historical consolidated financial statements and the notes thereto appearing elsewhere in this prospectus. All data (except for ratios) is presented in thousands.
YEAR ENDED DECEMBER 31, 2001 (1) -------------------------- STATEMENT OF OPERATIONS DATA: Operating revenues ........................... $ 5,060,605 Total revenues ............................... 5,336,804 Interest expense, net of capitalized interest ................................... 412,794 Income before provision for income taxes ...................................... 503,884 Net income ................................... 142,669 (4) OTHER FINANCIAL DATA: Depreciation and amortization ................ $ 538,702 Capital expenditures ......................... 576,752 Ratio of earnings to fixed charges (7) ....... 1.8 Net cash flows from operating activities ..... 846,998 EBITDA (8) ................................... 1,455,380 Adjusted EBITDA (8) .......................... 1,275,887 EBIT (9) ..................................... 916,678 Adjusted EBIT (9) ............................ 737,185 AS OF SEPTEMBER 30, 2002 ---------------- BALANCE SHEET DATA: Property, plant, contracts and equipment, net ............................. $ 9,168,940 Total assets ................................. 16,984,050 Short-term debt .............................. 642,031 Current portion of long-term debt ............ 483,106 Parent company debt .......................... 1,623,178 Subsidiary and project debt .................. 6,388,169 Total liabilities ............................ 12,247,784 Parent company-obligated mandatorily redeemable preferred securities held by Berkshire Hathaway ...................... 1,727,772 Parent company-obligated mandatorily redeemable preferred securities held by others .................................. 335,043 Total shareholders' equity ................... 2,491,515 OUR PREDECESSOR MARCH 14, 2000 ----------------------------------------- THROUGH JANUARY 1, 2000 YEAR ENDED DECEMBER 31, THROUGH DECEMBER 31, 2000 (2) MARCH 13, 2000 1999 (3) --------------- ------------------ ---------------------- STATEMENT OF OPERATIONS DATA: Operating revenues ........................... $4,147,867 $ 1,087,125 $ 4,184,546 Total revenues ............................... 4,242,749 1,106,609 4,466,425 Interest expense, net of capitalized interest ................................... 311,404 85,814 426,173 Income before provision for income taxes ...................................... 219,204 91,170 357,069 Net income ................................... 81,257 51,312 (5) 167,230 (6) OTHER FINANCIAL DATA: Depreciation and amortization ................ $ 383,351 $ 97,278 $ 427,690 Capital expenditures ......................... 538,729 123,541 603,640 Ratio of earnings to fixed charges (7) ....... 1.3 1.7 1.6 Net cash flows from operating activities ..... 246,407 171,083 554,959 EBITDA (8) ................................... 913,959 274,262 1,210,932 Adjusted EBITDA (8) .......................... 913,959 281,867 1,126,637 EBIT (9) ..................................... 530,608 176,984 783,242 Adjusted EBIT (9) ............................ 530,608 184,589 698,947 OUR PREDECESSOR ---------------------- AS OF DECEMBER 31, 2001 2000 1999 ----------- ----------- ---------------- BALANCE SHEET DATA: Property, plant, contracts and equipment, net ............................. $6,527,448 $ 5,348,647 $ 5,463,329 Total assets ................................. 12,615,333 11,610,939 10,766,352 Short-term debt .............................. 256,012 261,656 379,523 Current portion of long-term debt ............ 317,180 438,978 235,202 Parent company debt .......................... 1,834,498 1,829,971 1,856,318 Subsidiary and project debt .................. 4,754,811 3,388,696 3,642,703 Total liabilities ............................ 9,767,438 8,911,349 8,978,924 Parent company-obligated mandatorily redeemable preferred securities held by Berkshire Hathaway ...................... 454,772 454,772 -- Parent company-obligated mandatorily redeemable preferred securities held by others .................................. 333,379 331,751 450,000 Total shareholders' equity ................... 1,708,167 1,576,401 994,588
11
NINE MONTHS ENDED SEPTEMBER 30, 2002 2001 ------------------ ----------------- STATEMENT OF OPERATIONS DATA: Operating revenues .................................... $3,404,533 $3,756,931 Total revenues ........................................ 3,549,744 4,043,075 Interest expense, net of capitalized interest ......... 438,870 290,153 Income before provision for income taxes .............. 492,192 502,729 Net income ............................................ 306,800 (10) 122,085 (11) OTHER FINANCIAL DATA: Depreciation and amortization ......................... $ 386,531 $ 395,253 Capital expenditures .................................. 778,750 376,962 Ratio of earnings to fixed charges (7) ................ 1.9 2.1 Net cash flows from operating activities .............. 682,782 790,990 EBITDA (8) ............................................ 1,317,593 1,188,135 Adjusted EBITDA (8) ................................... 1,263,253 967,027 EBIT (9) .............................................. 931,062 792,882 Adjusted EBIT (9) ..................................... 876,722 571,774
---------- (1) Reflects the acquisition of the Yorkshire Electricity electricity distribution business and the simultaneous sale of the Northern Electric electricity and gas supply business on September 21, 2001. (2) Reflects our acquisition by a private investor group on March 14, 2000. (3) Reflects our acquisition of MidAmerican Energy on March 12, 1999, our disposition of the Coso Joint Ventures on February 26, 1999, and our disposition of a 50% ownership interest in CE Generation, LLC, or CE Gen, on March 3, 1999. (4) Includes $15.2 million of non-recurring net income related to the sale of the Northern Electric electricity and gas supply business, the sale of the Telephone Flat Project, the sale of Western States Geothermal, the transfer of Bali Energy Ltd. shares, and the Teesside Power Limited, or TPL, asset valuation impairment charge. (5) Includes $7.6 million of net non-recurring expenses for the costs related to our acquisition by a private investor group on March 14, 2000. (6) Includes $81.5 million of non-recurring net income related to the settlement of political risk insurance proceeds related to our investment in Indonesia, gains on sales of shares of McLeodUSA, our disposition of the Coso Joint Ventures, our disposition of a 50% ownership interest in CE Gen, CE Electric UK restructuring charges and transaction costs related to our acquisition by a private investor group. (7) For purposes of calculating the ratio of earnings to fixed charges, earnings are divided by fixed charges. Earnings represent the aggregate of (a) our pre-tax income and (b) fixed charges, less capitalized interest. Fixed charges represent interest (whether expensed or capitalized), amortization of deferred financing and bank fees, and the estimated interest component of rentals. (8) EBITDA represents earnings before interest, taxes, depreciation, and amortization. Adjusted EBITDA represents EBITDA adjusted for non-recurring income and expense items as follows: (a) items discussed in (4), which are $179.4 million before tax; (b) item discussed in (5); (c) items discussed in (6), which are $84.3 million before tax; (d) items discussed in (10), which are $54.3 million before tax; and (e) items discussed in (11), which are $221.1 million before tax. Information concerning EBITDA and adjusted EBITDA is presented not as a measure of operating results, but rather as a measure of our ability to service debt. EBITDA and adjusted EBITDA 12 should not be construed as an alternative to either (a) operating income (determined in accordance with generally accepted accounting principles, or GAAP) or (b) cash flow from operating activities (determined in accordance with GAAP) . Since EBITDA and adjusted EBITDA are not defined by GAAP, they may not be calculated on the same basis as similarly titled measures of other companies. (9) EBIT represents earnings before interest and taxes. Adjusted EBIT represents EBIT adjusted for non-recurring income and expense items. Information concerning EBIT and adjusted EBIT is presented not as a measure of operating results, but rather as a measure of our ability to service debt. EBIT and adjusted EBIT should not be construed as an alternative to either (a) operating income (determined in accordance with GAAP) or (b) cash flow from operating activities (determined in accordance with GAAP). Since EBIT and adjusted EBIT are not defined by GAAP, they may not be calculated on the same basis as similarly titled measures of other companies. (10) Includes $41.3 million of non-recurring net income related to the sale of assets by CalEnergy Gas (Holdings) Limited, or CE Gas Holdings. (11) Includes $13.7 million of non-recurring net income related to the sale of Western States Geothermal and the sale of the Northern Electric electricity and gas supply business, or Northern Supply. 13 RISK FACTORS An investment in the notes is subject to numerous risks, including, but not limited to, those set forth below. In addition to the information contained elsewhere in this prospectus, you should carefully consider the following risk factors when evaluating an investment in the notes, including participation in the exchange offer. RISK ASSOCIATED WITH OUR CORPORATE AND FINANCIAL STRUCTURE WE ARE A HOLDING COMPANY THAT DEPENDS ON DISTRIBUTIONS FROM OUR SUBSIDIARIES AND JOINT VENTURES TO MEET OUR NEEDS. We are a holding company and derive substantially all of our income and cash flow from our subsidiaries and joint ventures. We expect that future development and acquisition efforts will be similarly structured to involve operating subsidiaries and joint ventures. We are dependent on the earnings and cash flows of, and dividends, loans, advances or other distributions from, our subsidiaries and joint ventures to generate the funds necessary to meet our obligations, including the payment of principal of, or interest and premium, if any, on, the notes. All required payments on debt and preferred stock at subsidiary levels will be made before funds from our subsidiaries are available to us. The availability of distributions from such entities is also subject to: o their earnings and capital requirements, o the satisfaction of various covenants and conditions contained in financing documents by which they are bound or in their organizational documents, and o in the case of our regulated utility subsidiaries, regulatory restrictions which restrict their ability to distribute profits to us. Our subsidiaries and joint ventures are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due pursuant to the notes or to make any funds available, whether by dividends, loans or other payments, for payment of the notes, and do not guarantee the payment of interest or premium, if any, on or principal of the notes. WE ARE SUBSTANTIALLY LEVERAGED AND THE NOTES ARE STRUCTURALLY SUBORDINATED TO THE INDEBTEDNESS OF OUR SUBSIDIARIES. Our substantial leverage level presents the risk that we might not generate sufficient cash to service our indebtedness, including the notes, or that our leveraged capital structure could limit our ability to finance future acquisitions, develop additional projects, compete effectively and operate successfully under adverse economic conditions. At September 30, 2002, our outstanding indebtedness was approximately $2.0 billion (excluding $2.1 billion in aggregate principal amount of our trust preferred securities, our guarantees and letters of credit in respect of subsidiary indebtedness aggregating approximately $235 million and our completion guarantee issued in favor of the lenders under Kern River's $875 million construction loan facility in connection with Kern River's 2003 Expansion Project). In addition, our subsidiaries have significant amounts of indebtedness. At September 30, 2002, our consolidated subsidiaries' and joint ventures' total outstanding indebtedness was approximately $7.1 billion, which does not include $453 million, representing our share of outstanding indebtedness of CE Generation, LLC, or CE Gen. This amount also does not include trade debt of our subsidiaries. The terms of the notes do not limit our ability or the ability of our subsidiaries or joint ventures to incur additional debt or issue additional preferred stock. Claims of creditors of our subsidiaries and joint ventures have priority over your claims with respect to the assets and earnings of our subsidiaries and joint ventures. In addition, the stock or assets of substantially all of our operating subsidiaries and joint ventures is directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of the notes. 14 RISKS ASSOCIATED WITH OUR BUSINESS OUR RECENT GROWTH HAS BEEN ACHIEVED, IN PART, THROUGH STRATEGIC ACQUISITIONS, AND ADDITIONAL ACQUISITIONS MAY NOT BE SUCCESSFUL. Because our industry is rapidly changing, there are opportunities for acquisitions of assets and businesses, as well as for business combinations. We investigate opportunities that may increase shareholder value and build on existing businesses. We have participated in the past and our security holders may assume that at any time we may be participating in bidding or other negotiations for such transactions. This participation may or may not result in a transaction for us. Any transaction that does take place may involve consideration in the form of cash, debt or equity securities. In the past six years, we have completed several significant acquisitions, including the acquisitions of Northern Electric, Yorkshire Electricity, MidAmerican Energy, Kern River and Northern Natural Gas. We have successfully integrated Northern Electric, Yorkshire Electricity, MidAmerican Energy and Kern River. We closed on the Northern Natural Gas acquisition in August 2002 and are in the process of integrating its operations. We intend to continue to actively pursue acquisitions in the energy industry to complement and diversify our existing business for the foreseeable future. The successful integration of Northern Natural Gas and any businesses we may acquire in the future will entail numerous risks, including, among others, the risk of diverting management's attention from day-to-day operations, the risk that the acquired businesses will require substantial capital and financial investments and the risk that the investments will fail to perform in accordance with expectations. Any substantial diversion of management attention and any substantial difficulties encountered in the transition and integration process could have a material adverse effect on the revenues, levels of expenses and operating results of the combined company. In addition, it has been publicly reported over the past year that many of the participants in the United States energy industry, including the prior owners of Kern River and Northern Natural Gas and potentially including other industry participants from whom we may choose to purchase additional businesses in the future, have recently had or may have liquidity, creditworthiness and other financial difficulties. As a consequence, there can be no assurance that any such sellers will not enter into bankruptcy or insolvency proceedings or that they will otherwise be able, required or willing to perform on their indemnification obligations to us if we should elect to pursue any such claims we may have against any of them under our acquisition agreements in the future. If our due diligence efforts were or are unsuccessful in identifying and analyzing all material liabilities relating to acquired companies and if there were to be any material undisclosed liabilities, or if there were to be other unexpected consequences from any such bankruptcy or insolvency proceeding, such as a successful challenge as to whether the prices paid by us constituted reasonably equivalent value within the meaning of the relevant bankruptcy laws, then any such bankruptcy or insolvency, or failure by any of these sellers to perform their indemnification obligations to us, could have a material adverse effect on our business, financial condition, results of operations and the market prices and rates for our securities. We cannot assure you that future acquisitions, if any, or any related integration efforts will be successful, or that our ability to repay the notes will not be adversely affected by any future acquisitions. WE ARE ACTIVELY PURSUING, DEVELOPING AND CONSTRUCTING NEW OR EXPANDED FACILITIES, THE COMPLETION AND EXPECTED COST OF WHICH IS SUBJECT TO SIGNIFICANT RISK. Through our operating subsidiaries, we are continuing to develop, construct, own and operate new or expanded facilities, including Kern River's 2003 Expansion Project, the Zinc Recovery Project and two planned electric generating plants in Iowa, and in the future we expect to pursue the development, construction, ownership and operation of additional new or expanded energy projects (including, without limitation, generation, distribution, transmission, exploration/production, storage and supply projects and related activities, infrastructure and services), both domestically and internationally, the completion of any of which, including any future projects, is subject to substantial risk and may expose us to significant costs. We cannot assure you that our development or construction efforts on any particular project, or our efforts generally, will be successful. 15 Also, a proposed expansion or project may cost more than planned to complete, and such excess costs, if related to a regulated asset and found to be imprudent, may not be recoverable in rates. The inability to successfully and timely complete a project or avoid unexpected costs may require us to perform under guarantees (such as the Kern River completion guarantee), and the inability to avoid unsuccessful projects or to recover any excess costs may materially affect our ability to service our obligations under the notes. Our Kern River completion guarantee also contains a potential acceleration event based on our credit ratings and certain other potential acceleration events which are more fully described elsewhere in this prospectus. OUR SUBSIDIARIES ARE SUBJECT TO CERTAIN OPERATING UNCERTAINTIES WHICH MAY ADVERSELY AFFECT REVENUES, EXPENSES OR DISTRIBUTIONS. The operation of complex electric and gas utility (including transmission and distribution systems), pipeline or power generating facilities involves many operating uncertainties and events beyond our control. Operating risks include the breakdown or failure of power generation equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, fuel interruption, performance below expected levels of output, capacity or efficiency, operator error and catastrophic events such as severe storms, fires, earthquakes or explosions. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Revenues, expenses and distributions may also be adversely affected by general economic, business, regulatory and weather conditions. The realization of any of these risks could significantly reduce or eliminate our affiliates' revenues or significantly increase our affiliates' expenses, thereby adversely affecting the ability to receive distributions from subsidiaries and joint ventures. We currently possess property, business interruption, catastrophic and general liability insurance, but proceeds from such insurance coverage may not be adequate for all liabilities incurred, lost revenue or increased expenses. Moreover, such insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks have made it more difficult for us to obtain certain types of coverage. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or that it will otherwise cover all potential losses. ACTS OF SABOTAGE AND TERRORISM AIMED AT OUR FACILITIES COULD ADVERSELY EFFECT OUR BUSINESS. Since the September 11, 2001 terrorist attacks, the United States government has issued warnings that energy assets, specifically our nation's pipeline and utility infrastructure, may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future acts of sabotage or terrorism aimed at our facilities, or those of our customers, could have a material adverse effect on our business, financial condition, results of operations and ability to service the notes. Any resulting acts of war or the threat of war as a result of such terrorist attacks could adversely affect the economy and energy consumption. Instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability to raise capital. WE ARE SUBJECT TO COMPREHENSIVE ENERGY REGULATION AND CHANGES IN REGULATION AND RATES MAY ADVERSELY AFFECT OUR BUSINESS, FINANCIAL CONDITION, RESULTS OF OPERATIONS AND ABILITY TO SERVICE THE NOTES. We are subject to comprehensive governmental regulation, including regulation in the United States by various federal, state and local regulatory agencies, regulation in the United Kingdom and regulation in the Philippines, all of which significantly influences our operating environment, our rates, our capital structure, our costs and our ability to recover our costs from customers. These regulatory agencies include, among others, the Federal Energy Regulatory Commission, or the FERC, the Environmental Protection Agency, or the EPA, the Nuclear Regulatory Commission, the United States Department of Transportation, the Iowa Utilities Board, or the IUB, the Illinois Commerce Commission, other state utility boards, numerous local agencies, the Gas and Electricity Markets Authority, or GEMA, which in discharging certain of its powers acts through its staff within the Office of Gas and Electricity Markets, or Ofgem, in 16 the United Kingdom, and various other governmental agencies in the United Kingdom and the Philippines. The FERC has jurisdiction over, among other things, wholesale rates for electric transmission service and electric energy sold in interstate commerce, interstate natural gas transportation and storage rates, the siting and construction of interstate natural gas transportation facilities and certain other activities of our utility subsidiaries. United States federal, state and local agencies also have jurisdiction over many of our other activities. The utility commissions in the states where our utility subsidiaries operate regulate many aspects of our utility operations including siting and construction of facilities, customer service and the rates that we can charge customers. The revenues of our United Kingdom distribution businesses are subject to review and adjustment by GEMA and many other aspects of our subsidiaries' United Kingdom operations are subject to the jurisdiction of GEMA and other regulators and agencies in the United Kingdom. The structure of federal and state energy regulation is currently undergoing change and has in the past, and may in the future, be the subject of various challenges, initiatives and restructuring proposals by policy makers, utilities and other industry participants. In addition to Congressional initiatives, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power generation industry and increase access to electric utilities' transmission and distribution systems for independent power producers and electricity consumers. The implementation of regulatory changes in response to such challenges, initiatives and restructuring proposals could result in the imposition of more comprehensive or stringent requirements on us or our subsidiaries or other industry participants, which would result in increased compliance costs and could have a material adverse effect on our business, financial condition, results of operations and ability to service the notes. We are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies or the Securities and Exchange Commission, or SEC, under the Public Utility Holding Company Act of 1935, as amended, or PUHCA. Changes in regulations or the imposition of additional regulations could have a material adverse impact on our results of operations. Recent developments, events and uncertainties which have impacted or could impact our businesses are described below. On July 31, 2002, the FERC issued a notice of proposed rulemaking with respect to Standard Market Design for the electric industry. The FERC has characterized the proposal as portending "sweeping changes" to the use and expansion of the interstate transmission and wholesale bulk power systems in the United States. The proposal includes numerous proposed changes to the current regulation of transmission and generation facilities designed "to promote economic efficiency" and replace the "obsolete patchwork we have today," according to the FERC Chairman. The final rule, if adopted as currently proposed, would require all public utilities operating transmission facilities subject to the FERC jurisdiction to file revised open access transmission tariffs that would require changes to the basic services these public utilities currently provide. The proposed rule may impact the pricing of MidAmerican Energy's electricity and transmission products. The FERC does not envision that a final rule will be fully implemented until September 30, 2004. We are still evaluating the proposed rule, and we believe that the final rule could vary considerably from the initial proposal. Accordingly, we are presently unable to quantify the likely impact of the proposed rule on us. The state utility regulatory environment has to date, in general, given MidAmerican Energy an exclusive right to serve retail electricity customers within its primary service territory in Iowa and, in turn, the obligation to provide electric service to those customers. There can be no assurance that there will not be a change in legislation or regulation in Iowa or in any of the other states in which we operate to allow retail competition in MidAmerican Energy's service territory. Because our Kern River and Northern Natural Gas pipeline systems are interstate natural gas pipelines subject to regulation as natural gas companies under the Natural Gas Act, as amended, the rates we can charge our customers and other terms and conditions of service are subject to review by the FERC and the possibility of modification in periodic rate proceedings or at any time in response to a complaint proceeding initiated by a customer or on the FERC's own initiative. The rates we can charge are required to be just and reasonable. The objective of the rate setting process is to allow us to recover our costs to 17 construct, own, operate and maintain our pipelines which are actually and prudently incurred and to afford us an opportunity to earn a reasonable rate of return. Under the terms of our transportation service contracts and in accordance with the FERC's rate making principles, our current maximum tariff rates are designed to recover costs included in our pipeline systems' regulatory cost of service that are associated with the construction and operation of our pipeline systems that are actually, reasonably and prudently incurred. All costs incurred may not be recoverable through existing or future rates. Failure to recover material costs may have a material adverse effect on our business, financial condition, results of operations and ability to service the notes. Revenue from Northern Electric's and Yorkshire Electricity's distribution business is controlled by a distribution price control formula which determines the maximum average price per unit of electricity that a distribution network operator in Great Britain may charge. The distribution price control formula is expected to have a five-year duration and is subject to review by the British regulatory body for the energy sector, GEMA, at the end of each five-year period and at other times in the discretion of GEMA. At each review, GEMA can propose adjustments to the distribution price control formula. In December 1999, a review resulted in a reduction in allowed revenue of 24% for Northern Electric's distribution business and 23% for Yorkshire Electricity's distribution business, in real terms, with effect from and after April 1, 2000. The next review of the distribution price control formula is expected to become effective in April 2005. Any further price reviews by GEMA, including those it may elect to conduct at any time in its discretion, may have a material adverse effect on our results of operations. The Philippine Congress has passed the Electric Power Reform Act of 2001, which is aimed at restructuring the power industry, including privatization of the National Power Corporation, or the NPC, and introduction of a competitive electricity market, among other initiatives. The implementation of the bill may have an adverse impact on our future operations in the Philippines and the Philippines power industry as a whole. WE ARE SUBJECT TO ENVIRONMENTAL, SAFETY AND OTHER LAWS AND REGULATIONS WHICH MAY ADVERSELY IMPACT US. Through our subsidiaries and joint ventures, we are subject to a number of environmental, safety and other laws and regulations affecting many aspects of our present and future operations, both domestic and foreign, including air emissions, water quality, wastewater discharges, solid wastes, hazardous substances and safety matters. We may incur substantial costs and liabilities in connection with our operations as a result of these regulations. In particular, the cost of future compliance with federal, state and local clean air laws, such as those that require certain generators, including some of our subsidiaries' electric generating facilities, to limit nitrogen oxide emissions and potential other pollutants, may require us to make significant capital expenditures which may not be recoverable through future rates. In addition, these costs and liabilities may include those relating to claims for damages to property and persons resulting from our operations. The implementation of regulatory changes imposing more comprehensive or stringent requirements on us, to the extent such changes would result in increased compliance costs or additional operating restrictions, could have a material adverse effect on our business, financial condition, results of operations and ability to service the notes. In addition, regulatory compliance for existing facilities and the construction of new facilities is a costly and time-consuming process, and intricate and rapidly changing environmental regulations may require major expenditures for permitting and create the risk of expensive delays or material impairment of value if projects cannot function as planned due to changing regulatory requirements or local opposition. Potential pipeline safety legislation and an increase in public expectations on pipeline safety may also require replacement of some of our pipeline segments, addition of monitoring equipment, and more frequent inspection or testing of our pipeline facilities. These requirements coupled with increases in state and federal agency oversight, if adopted, would necessitate additional testing and reporting which may result in higher operating costs and/or capital costs. Our FERC-approved tariffs or competition from other natural gas sources may not allow us to recover these increased costs of compliance. 18 In addition to operational standards, environmental laws also impose obligations to clean up or remediate contaminated properties or to pay for the cost of such remediation, often upon parties that did not actually cause the contamination. Accordingly, we may become liable, either contractually or by operation of law, for remediation costs even if the contaminated property is not presently owned or operated by us, or if the contamination was caused by third parties during or prior to our ownership or operation of the property. Given the nature of the past industrial operations conducted by us and others at our properties, there can be no assurance that all potential instances of soil or groundwater contamination have been identified, even for those properties where an environmental site assessment or other investigation has been conducted. Although we have accrued reserves for our known remediation liabilities, future events, such as changes in existing laws or policies or their enforcement, or the discovery of currently unknown contamination, may give rise to additional remediation liabilities which may be material. Any failure to recover increased environmental or safety costs incurred by us may have a material adverse effect on our business, financial condition, results of operations and ability to service the notes. INCREASED COMPETITION RESULTING FROM LEGISLATIVE, REGULATORY AND RESTRUCTURING EFFORTS COULD HAVE A SIGNIFICANT FINANCIAL IMPACT ON US AND OUR UTILITY SUBSIDIARIES AND CONSEQUENTLY DECREASE OUR REVENUE. The energy market continues to move towards a competitive environment and is characterized by numerous strong and capable competitors, many of which have more extensive operating experience and greater financial resources than we and our subsidiaries. Retail competition and the unbundling of regulated energy and gas service could have a significant adverse financial impact on us and our subsidiaries due to an impairment of assets, a loss of customers, lower profit margins and/or increased costs of capital. The total impacts of restructuring may have a significant financial impact on our financial position, results of operations and cash flows. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impacts of these changes on our financial position, results of operations or cash flows. The generation segment of the electric industry has been and will be significantly impacted by competition. The introduction of competition in the wholesale market has resulted in a proliferation of power marketers and a substantial increase in market activity. Many of these marketers have experienced financial difficulties and the market continues to be volatile. As retail competition continues to evolve, margins will be pressured by competition from other utilities, power marketers and self-generation. Many states and the federal government are implementing or considering regulatory initiatives that would increase access to electric utilities' transmission and distribution systems for independent power producers, utilities, power marketers and electricity customers. Although the recent and anticipated changes in the United States electric utility industry may create opportunities, they will also create additional challenges and risks for utilities. Competition will put pressure on margins for traditional electric services. Illinois recently enacted a law that provides for full retail customer choice in 2002. While introduction of retail competition in Iowa is not presently expected, depending upon the terms of any such legislation, if introduced it could have a material adverse effect on us. These types of restructurings and other industry restructuring efforts could materially impact our results of operations in a manner which is difficult to predict, since such efforts will depend on the terms and timing of such restructuring. As a result of the FERC orders, including Order 636, the FERC's policies favoring competition in gas markets, the expansion of existing pipelines and the construction of new pipelines, the interstate pipeline industry has begun to experience some failure to renew, or turn back, of firm capacity, as existing transportation service agreements expire and are terminated. Local distribution companies and end-use customers have more choices in the new, more competitive environment and may be able to obtain service from more than one pipeline to fulfill their natural gas delivery requirements. If a pipeline experiences capacity turn back and is unable to remarket the capacity, the pipeline or its remaining customers may have to bear the costs associated with the capacity that is turned back. Any new pipelines that are constructed could compete with our pipeline subsidiaries for customers' service needs. Increased 19 competition could reduce the volumes of gas transported by our pipeline subsidiaries or, in cases where they do not have long-term fixed rate contracts, could force our pipeline subsidiaries to lower their rates to meet competition. This could adversely affect our pipeline subsidiaries' financial results. A SIGNIFICANT DECREASE IN DEMAND FOR NATURAL GAS IN THE MARKETS SERVED BY OUR SUBSIDIARIES' PIPELINE AND DISTRIBUTION SYSTEMS WOULD SIGNIFICANTLY DECREASE OUR REVENUE AND THEREBY ADVERSELY AFFECT OUR BUSINESS, FINANCIAL CONDITION, RESULTS OF OPERATIONS AND ABILITY TO SERVICE THE NOTES. A sustained decrease in demand for natural gas in the markets served by our subsidiaries' pipeline and distribution systems would significantly reduce our revenues. Factors that could lead to a decrease in market demand include: o a recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on natural gas; o an increase in the market price of natural gas or a decrease in the price of other competing forms of energy, including electricity, coal and fuel oil; o higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or that limit the use of natural gas; o a shift by consumers to more fuel-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, pending legislation proposing to mandate higher fuel economy, or otherwise; and o a shift by our pipeline and distribution customers to the use of alternate fuels, such as fuel oil, due to price differentials or other incentives. FAILURE OF OUR SIGNIFICANT POWER PURCHASERS AND PIPELINE CUSTOMERS TO PAY AMOUNTS DUE UNDER THEIR CONTRACTS COULD REDUCE OUR REVENUES MATERIALLY. Our subsidiaries' non-utility generating facilities and both of our pipeline subsidiaries are dependent upon a relatively small number of customers for a significant portion of their revenues. As a result, our profitability and ability to make payments under the notes generally will depend upon the continued financial performance and creditworthiness of these customers. Accordingly, failure of one or more of our most significant customers to pay for contracted electric generating capacity or pipeline capacity reservation charges, for reasons related to financial distress or otherwise, could reduce our revenues materially if we were not able to make adequate alternate arrangements and therefore could have a material adverse effect on our business, financial condition, results of operations and ability to service the notes. OUR PIPELINE SUBSIDIARIES MAY NOT BE ABLE TO MAINTAIN OR REPLACE LONG-TERM GAS TRANSPORTATION SERVICE AGREEMENTS AT FAVORABLE RATES AS EXISTING CONTRACTS EXPIRE. Our business, financial condition, results of operations and ability to service the notes are dependent in significant part on the ability of Kern River and Northern Natural Gas to maintain long-term transportation service agreements with customers subject to favorable transportation rates. Many of our long-term transportation service agreements will expire before the maturity of the notes. Upon expiration, existing customers may elect not to extend their contracts at rates favorable to our subsidiaries or on a long-term basis, or at all. Our pipeline subsidiaries may also be unable to obtain favorable replacement agreements with other customers. The extension or replacement of the existing long-term contracts depends on a number of factors beyond our control, including: o the availability of economically deliverable natural gas for transport through our pipeline system, including in particular continued availability of adequate supplies from the Rocky Mountains, Hugoton, Permian, Anadarko and Western Canadian supply basins currently accessible to our pipeline subsidiaries; o existing competition to deliver natural gas to the upper Midwest and southern California; 20 o new pipelines or expansions potentially serving the same markets as our pipelines; o the growth in demand for natural gas in the upper Midwest and southern California; o whether transportation of natural gas pursuant to long-term contracts continues to be market practice; and o whether our business strategy, including our expansion strategy, continues to be successful. Any failure to extend or replace a significant portion of these contracts may have a material adverse effect on our business, financial condition, results of operations and ability to service the notes. OUR UTILITY AND NON-UTILITY BUSINESSES ARE SUBJECT TO MARKET AND CREDIT RISK. We are exposed to market and credit risks in our subsidiaries' generation, retail distribution and pipeline operations. Specifically, such risks include commodity price changes, market supply shortages, interest rate changes and counterparty default. In Iowa, MidAmerican Energy does not have an ability to pass through fuel price increases in its rates (an energy adjustment clause), so any significant increase in fuel costs or purchased power costs could have a negative impact on MidAmerican Energy. To minimize these risks, we require collateral to be posted if the creditworthiness of counterparties deteriorates below established levels and enter into financial derivative instrument contracts to hedge purchase and sale commitments, fuel requirements and inventories of natural gas, electricity, coal and emission allowances. However, financial derivative instrument contracts do not eliminate the risk. The impact of these risks could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales contracts or increased interest expense. WE HAVE SIGNIFICANT OPERATIONS OUTSIDE THE UNITED STATES WHICH MAY BE SUBJECT TO INCREASED RISK BECAUSE OF THE ECONOMIC OR POLITICAL CONDITIONS OF THE COUNTRY IN WHICH THEY OPERATE. We have a number of operations outside of the United States. The acquisition, ownership and operation of businesses outside the United States entail significant political and financial risks (including, without limitation, uncertainties associated with privatization efforts, inflation, currency exchange rate fluctuations, currency repatriation restrictions, changes in law or regulation, changes in government policy, political instability, civil unrest and expropriation) and other risk/structuring issues that have the potential to cause material impairment of the value of the business being operated, which we may not be capable of fully insuring against. The risk of doing business outside of the United States could be greater than in the United States because of specific economic or political conditions of each country. The uncertainty of the legal environment in certain foreign countries in which we operate or may acquire projects or businesses could make it more difficult for us to enforce our rights under agreements relating to such projects or businesses. In addition, the laws and regulations of certain countries may limit our ability to hold a majority interest in some of the projects or businesses that we may acquire. Furthermore, the central bank of any such country may have the authority in certain circumstances to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to restrict distributions to foreign investors. Although we may structure certain project revenue and other agreements to provide for payments to be made in, or indexed to, United States dollars or a currency freely convertible into United States dollars, there can be no assurance that we will be able to obtain sufficient dollars or other hard currency or that available dollars will be allocated to pay such obligations. Our international projects may be subject to the risk of being delayed, suspended or terminated by the applicable foreign governments or may be subject to the risk of contract abrogation, expropriations or other uncertainties resulting from changes in government policy or personnel or changes in general political or economic conditions affecting the country. In this regard, reference is made to the substantial uncertainties associated with one of our non-utility power projects in the Philippines, which is referred to as the Casecnan Project, where certain payments under the primary project agreement are currently not being made by the government of the Philippines and are presently the subject of international arbitration. Specifically, under the terms of a Casecnan Project agreement between CE Casecnan Water and Energy Company, Inc., or CE Casecnan, and the Philippine National Irrigation Administration, or NIA, NIA has the option of timely reimbursing CE Casecnan directly for certain taxes CE Casecnan has 21 paid. If NIA does not so reimburse CE Casecnan, the taxes paid by CE Casecnan result in an increase in the Water Delivery Fee under the Casecnan Project agreement. The payment of certain other taxes by CE Casecnan results automatically in an increase in the Water Delivery Fee. As of June 30, 2002, CE Casecnan has paid approximately $54.4 million in taxes which as a result of the foregoing provisions had resulted in an increase in the Water Delivery Fee. NIA has failed to pay the portion of the Water Delivery Fee each month which relates to the payment of these taxes by CE Casecnan. As a result of this non-payment, on August 19, 2002, CE Casecnan filed a Request for Arbitration against NIA, seeking payment of such portion of the Water Delivery Fee and enforcement of the relevant provision of the Casecnan Project agreement going forward. The arbitration will be conducted in accordance with the rules of the International Chamber of Commerce. WE FACE EXCHANGE RATE RISK. Payments from some of our foreign investments, including without limitation Northern Electric and Yorkshire Electricity, are made in a foreign currency and any dividends or distributions of earnings in respect of such investments may be significantly affected by fluctuations in the exchange rate between the United States dollar and the British pound or other applicable foreign currency. Although we may enter into certain transactions to hedge risks associated with exchange rate fluctuations, there can be no assurance that such transactions will be successful in reducing such risks. RISKS ASSOCIATED WITH THE EXCHANGE OFFER YOU MAY NOT BE ABLE TO SELL YOUR ORIGINAL NOTES IF YOU DO NOT EXCHANGE THEM FOR REGISTERED EXCHANGE NOTES IN THE EXCHANGE OFFER. If you do not exchange your original notes for exchange notes in the exchange offer, your original notes will continue to be subject to the restrictions on transfer as stated in the legends on the original notes. In general, you may not offer, sell or otherwise transfer the original notes in the United States unless they are: o registered under the Securities Act; o offered or sold under an exemption from the Securities Act and applicable state securities laws; or o offered or sold in a transaction not subject to the Securities Act and applicable state securities laws. We do not currently anticipate that we will register the original notes under the Securities Act. Except for limited instances involving the initial purchasers or holders of original notes who are not eligible to participate in the exchange offer or who receive freely transferable exchange notes in the exchange offer, we will not be under any obligation to register the original notes under the Securities Act under the registration rights agreement or otherwise. Also, if the exchange offer is completed on the terms and within the time period contemplated by this prospectus, no liquidated damages will be payable on your original notes. YOUR ABILITY TO SELL YOUR ORIGINAL NOTES MAY BE SIGNIFICANTLY MORE LIMITED AND THE PRICE AT WHICH YOU MAY BE ABLE TO SELL YOUR ORIGINAL NOTES MAY BE SIGNIFICANTLY LOWER IF YOU DO NOT EXCHANGE THEM FOR REGISTERED EXCHANGE NOTES IN THE EXCHANGE OFFER. To the extent that original notes are exchanged in the exchange offer, the trading market for the original notes that remain outstanding may be significantly more limited. As a result, the liquidity of the original notes not tendered for exchange could be adversely affected. The extent of the market for original notes would depend upon a number of factors, including the number of holders of original notes remaining outstanding and the interest of securities firms in maintaining a market in the original notes. An issue of securities with a similar outstanding market value available for trading, which is called the "float," may command a lower price than would be comparable to an issue of securities with a greater float. As a result, the market price for original notes that are not exchanged in the exchange offer may be affected adversely to the extent that original notes exchanged in the exchange offer reduce the float. The reduced float also may make the trading price of the original notes that are not exchanged more volatile. 22 THERE ARE STATE SECURITIES LAW RESTRICTIONS ON THE RESALE OF THE EXCHANGE NOTES. In order to comply with the securities laws of certain jurisdictions, the exchange notes may not be offered or resold by any holder unless they have been registered or qualified for sale in such jurisdictions or an exemption from registration or qualification is available and the requirements of such exemption have been satisfied. We do not currently intend to register or qualify the resale of the exchange notes in any such jurisdictions. However, an exemption is generally available for sales to registered broker-dealers and certain institutional buyers. Other exemptions under applicable state securities laws may also be available. WE WILL NOT ACCEPT YOUR ORIGINAL NOTES FOR EXCHANGE IF YOU FAIL TO FOLLOW THE EXCHANGE OFFER PROCEDURES AND, AS A RESULT, YOUR ORIGINAL NOTES WILL CONTINUE TO BE SUBJECT TO EXISTING TRANSFER RESTRICTIONS AND YOU MAY NOT BE ABLE TO SELL YOUR ORIGINAL NOTES. We will issue exchange notes as part of the exchange offer only after a timely receipt of your original notes, a properly completed and duly executed letter of transmittal and all other required documents. Therefore, if you want to tender your original notes, please allow sufficient time to ensure timely delivery. If we do not receive your original notes, letter of transmittal and other required documents by the expiration date of the exchange offer, we will not accept your original notes for exchange. We are under no duty to give notification of defects or irregularities with respect to the tenders of original notes for exchange. If there are defects or irregularities with respect to your tender of original notes, we will not accept your original notes for exchange. See "The Exchange Offer." 23 FORWARD-LOOKING STATEMENTS This prospectus contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as "may", "will", "could", "project", "believe", "anticipate", "expect", "estimate", "continue", "potential", "plan", "forecast" and similar terms. These statements represent our intentions, plans, expectations and beliefs and are subject to risks, uncertainties and other factors. Many of these factors are outside our control and could cause actual results to differ materially from such forward-looking statements. These factors include, among others: o general economic and business conditions in the jurisdictions in which our facilities are located; o governmental, statutory, regulatory or administrative initiatives or ratemaking actions affecting us or the electric or gas utility, pipeline or power generation industries; o weather effects on sales and revenues; o general industry trends; o increased competition in the power generation, electric utility or pipeline industries; o fuel and power costs and availability; o continued availability of accessible gas reserves; o changes in business strategy, development plans or customer or vendor relationships; o availability, term and deployment of capital; o availability of qualified personnel; o risks relating to nuclear generation; o financial or regulatory accounting principles or policies imposed by the Public Company Accounting Oversight Board, the Financial Accounting Standards Board, the SEC, the FERC and similar entities with regulatory oversight; and o other business or investment considerations that may be disclosed from time to time in our SEC filings or in other publicly disseminated written documents. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exclusive. 24 USE OF PROCEEDS We will not receive any proceeds from the issuance of the exchange notes in the exchange offer. The exchange notes will evidence the same debt as the original notes tendered in exchange for exchange notes. Accordingly, the issuance of the exchange notes will not result in any change in our indebtedness. The net proceeds of the private placement of the original notes were approximately $694 million after deducting the initial purchasers' discount and expenses related to the offering of the original notes. We used these net proceeds for general corporate purposes, including to repay our short term debt in the amount of $167 million; and to make up to $300 million of funds available for an equity contribution to Kern River, to be applied by Kern River to fund a portion of the costs of its 2003 Expansion Project. We also used the net proceeds to make an equity contribution of $150 million to Northern Natural Gas and a loan of $300 million to Northern Natural Gas. Northern Natural Gas used these amounts to repay an equal amount of its outstanding indebtedness under its bank credit agreement. Northern Natural Gas repaid the loan to us from the proceeds of its offering of $300 million of 5.375% Senior Notes due 2012, which was completed on October 15, 2002. 25 THE EXCHANGE OFFER PURPOSE OF THE EXCHANGE OFFER On October 4, 2002, we privately placed the original notes in a transaction exempt from registration under the Securities Act. Accordingly, the original notes may not be reoffered, resold or otherwise transferred in the United States unless so registered or unless an exemption from the Securities Act registration requirements is available. Pursuant to a registration rights agreement with the initial purchasers of the original notes, we agreed, for the benefit of holders of the notes, to: o prepare and file an exchange offer registration statement with the SEC with respect to a registered offer to exchange each series of original notes for a series of exchange notes that will be issued under the same indenture, in the same aggregate principal amount as and with terms that are substantially identical in all material respects to the original notes except that they will not contain terms with respect to transfer restrictions; o use our reasonable best efforts to cause the exchange offer registration statement to become effective under the Securities Act within 270 days after the date on which we issued the original notes; and o promptly after the exchange offer registration statement is declared effective, offer the exchange notes in exchange for surrender of the original notes. We will be entitled to consummate the exchange offer on the expiration date provided that we have accepted all original notes previously validly tendered in accordance with the terms set forth in this prospectus and the applicable letter of transmittal. In addition, under certain circumstances described below, we may be required to file a shelf registration statement to cover resales of the notes. If we do not comply with certain of our obligations under the registration rights agreement, we must pay liquidated damages on the original notes in addition to the interest that is otherwise due on the notes. See "--Liquidated Damages." The purpose of the exchange offer is to fulfill our obligations with respect to the registration rights agreement. If you are a broker-dealer that receives exchange notes for its own account in exchange for original notes, where you acquired such original notes as a result of market-making activities or other trading activities, you must acknowledge that you will deliver a prospectus in connection with any resale of such exchange notes. See "Plan of Distribution." TERMS OF THE EXCHANGE Upon the terms and subject to the conditions contained in this prospectus and in the letters of transmittal that accompany this prospectus, with respect to each series of original notes, we are offering to exchange $1,000 in principal amount of exchange notes for each $1,000 in principal amount of original notes. The terms of the exchange notes are substantially identical to the terms of the original notes for which they may be exchanged in the exchange offer, except that the exchange notes will generally be freely transferrable. The exchange notes will evidence the same debt as the original notes and will be entitled to the benefits of the indenture. Any original notes of a series that remain outstanding after the consummation of the exchange offer, together with all exchange notes of that series issued in connection with the exchange offer, will be treated as a single class of securities under the indenture. See "Description of Notes." The exchange offer is not conditioned on any minimum aggregate principal amount of original notes being tendered for exchange. Based on existing interpretations of the Securities Act by the staff of the SEC set forth in several no-action letters to third parties, and subject to the immediately following sentence, we believe that you may offer for resale, resell and otherwise transfer the exchange notes without further compliance with the 26 registration and prospectus delivery provisions of the Securities Act. However, if you are an "affiliate" (within the meaning of the Securities Act) of ours or you intend to participate in the exchange offer for the purpose of distributing the exchange notes or you are a broker-dealer (within the meaning of the Securities Act) that acquired notes in a transaction other than as part of its market-making or other trading activities and who has arranged or has an understanding with any person to participate in the distribution of the exchange notes, you: (1) will not be able to rely on the interpretations by the staff of the SEC set forth in the above-mentioned no-action letters; (2) will not be able to tender your notes in the exchange offer; and (3) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of your notes unless such sale or transfer is made pursuant to an exemption from such requirements. Subject to exceptions for certain holders, to participate in the exchange offer you will be required to represent to us at the time of the consummation of the exchange offer, among other things, that (1) you are not an affiliate of ours; (2) any exchange notes to be received by you will be acquired in the ordinary course of your business; and (3) at the time of commencement of the exchange offer, you have no arrangement or understanding with any person to participate in the distribution (within the meaning of the Securities Act) of the notes. In addition, in connection with any resales of exchange notes, any broker-dealer who acquired exchange notes for its own account as a result of market-making activities or other trading activities must deliver a prospectus meeting the requirements of the Securities Act. The SEC has taken the position that such a broker-dealer may fulfill its prospectus delivery requirements with respect to the exchange notes (other than a resale of an unsold allotment from the initial sale of the original notes) with this prospectus. Under the registration rights agreement, we are required to allow a broker-dealer and other persons with similar prospectus delivery requirements, if any, to use this prospectus connection with the resale of such exchange notes for a period of time not less than 120 days following the consummation of the exchange offer. If you are a broker-dealer that receives exchange notes for its own account in exchange for original notes, where you acquired such original notes as a result of market-making activities or other trading activities, you must acknowledge that you will deliver a prospectus in connection with any resale of such exchange notes. See "Plan of Distribution." You will not be required to pay brokerage commissions or fees or, subject to the instructions in the applicable letter of transmittal, transfer taxes relating to your exchange of original notes for exchange notes in the exchange offer. SHELF REGISTRATION STATEMENT If: o we are not permitted to effect the exchange offer because of any change in law or in applicable interpretations of such law by the staff of the SEC; o the exchange offer is not consummated by the 40th day after the date on which the exchange offer registration statement was declared effective; o any of the initial purchasers of the original notes so requests with respect to the original notes not eligible to be exchanged for exchange notes in the exchange offer and held by it following the consummation of exchange offer; o any holder of notes (other than a broker-dealer electing to exchange original notes acquired for its own account as a result of market-making or other trading activities for exchange securities) is not eligible to participate in the exchange offer and any such holder so requests for any reason other than the failure by such holder to make a timely and valid tender in accordance with the terms of exchange offer; or o any holder of notes (other than a broker-dealer electing to exchange original notes acquired for its own account as a result of market-making or other trading activities for exchange securities) 27 participates in the exchange offer but does not receive freely tradeable exchange notes on the date of the exchange and any such holder so requests for any reason other than the failure by such holder to make a timely and valid tender in accordance with the terms of exchange offer, we will: o as promptly as practicable prepare and file with the SEC a shelf registration statement relating to the offer and sale of notes that are not otherwise freely tradable; and o use our reasonable best efforts to cause the shelf registration statement to be declared effective not later than the later to occur of the date that is 150 days after the date on which our obligation to file the shelf registration arises or 270 days after the date on which we issued the original notes; and o use our reasonable best efforts to keep the shelf registration statement continuously effective until the earlier of two years from the date on which we issued the original notes (subject to extension under certain circumstances) and such shorter period ending when all the notes covered by the shelf registration statement have been sold pursuant to the shelf registration statement or are no longer restricted securities (as defined in Rule 144 under the Securities Act). You will not be entitled, except if you were an initial purchaser of the original notes, to have your notes registered under the shelf registration statement, unless you agree in writing to be bound by the applicable provisions of the registration rights agreement. In order to sell your notes under the shelf registration statement, you generally must be named as a selling security holder in the related prospectus and must deliver a prospectus to purchasers. Consequently, you will be subject to the civil liability provisions under the Securities Act in connection with those sales and indemnification obligations under the registration rights agreements. LIQUIDATED DAMAGES A registration default will be deemed to have occurred if: (1) the exchange offer registration statement is not declared effective within 270 days after the date on which we issued the original notes; (2) the shelf registration statement is not declared effective by the later to occur of the date that is 150 days after the date on which our obligation to file the shelf registration arises or 270 days after the date on which we issued the original notes; or (3) after either the exchange offer registration statement or the shelf registration statement is declared effective, such registration statement or the related prospectus thereafter ceases to be effective or usable (subject to certain exceptions) in connection with resales of original notes or exchange notes for the periods specified and in accordance with the registration rights agreement. Additional interest will accrue on the notes subject to such registration default at a rate of 0.5% from and including the date on which any such registration default occurs to but excluding the date on which all such registration defaults have ceased to be continuing. In each case, such additional interest is payable in addition to any other interest payable from time to time with respect to the original notes and the exchange notes. The exchange notes will not contain any provisions regarding the payment of liquidated damages. EXPIRATION DATE; EXTENSIONS; TERMINATION; AMENDMENTS The exchange offer expires on the expiration date. The expiration date is 5:00 p.m., New York City time, on January 23, 2003, unless we in our sole discretion extend the period during which the exchange offer is open, in which event the expiration date is the latest time and date on which the exchange offer, as so extended by us, expires. We reserve the right to extend the exchange offer at any time and from time to time prior to the expiration date by giving written notice to The Bank of New York, as the exchange agent, and by timely public announcement communicated in accordance with applicable law or regulation. During any extension of the exchange offer, all original notes previously tendered pursuant to the exchange offer and not validly withdrawn will remain subject to the exchange offer. 28 The exchange date will occur promptly after the expiration date. We expressly reserve the right to (i) terminate the exchange offer and not accept for exchange any original notes for any reason, including if any of the events set forth below under "--Conditions to the Exchange Offer" shall have occurred and shall not have been waived by us and (ii) amend the terms of the exchange offer in any manner, whether before or after any tender of the original notes. If any such termination or amendment occurs, we will notify the exchange agent in writing and will either issue a press release or give written notice to the holders of the original notes as promptly as practicable. Unless we terminate the exchange offer prior to 5:00 p.m., New York City time, on the expiration date, we will exchange the exchange notes for the original notes on the exchange date. If we waive any material condition to the exchange offer, or amend the exchange offer in any other material respect, and if at the time that notice of such waiver or amendment is first published, sent or given to holders of original notes in the manner specified above, the exchange offer is scheduled to expire at any time earlier than the expiration of a period ending on the fifth business day from, and including, the date that such notice is first so published, sent or given, then the exchange offer will be extended until the expiration of such period of five business days. This prospectus and the related letters of transmittal and other relevant materials will be mailed by us to record holders of original notes and will be furnished to brokers, banks and similar persons whose names, or the names of whose nominees, appear on the lists of holders for subsequent transmittal to beneficial owners of original notes. HOW TO TENDER The tender to us of original notes by you pursuant to one of the procedures set forth below will constitute an agreement between you and us in accordance with the terms and subject to the conditions set forth herein and in the applicable letter of transmittal. General Procedures. A holder of an original note may tender the same by (i) properly completing and signing the applicable letter of transmittal or a facsimile thereof (all references in this prospectus to the letter of transmittal shall be deemed to include a facsimile thereof) and delivering the same, together with the certificate or certificates representing the original notes being tendered and any required signature guarantees (or a timely confirmation of a book-entry transfer, which we refer to as a Book-Entry Confirmation, pursuant to the procedure described below), to the exchange agent at its address set forth on the back cover of this prospectus on or prior to the expiration date or (ii) complying with the guaranteed delivery procedures described below. If tendered original notes are registered in the name of the signer of the letter of transmittal and the exchange notes to be issued in exchange therefor are to be issued (and any untendered original notes are to be reissued) in the name of the registered holder, the signature of such signer need not be guaranteed. In any other case, the tendered original notes must be endorsed or accompanied by written instruments of transfer in form satisfactory to us and duly executed by the registered holder and the signature on the endorsement or instrument of transfer must be guaranteed by a firm, which we refer to as an Eligible Institution, that is a member of a recognized signature guarantee medallion program, which we refer to as an Eligible Program, within the meaning of Rule 17Ad-15 under the Exchange Act. If the exchange notes and/or original notes not exchanged are to be delivered to an address other than that of the registered holder appearing on the note register for the original notes, the signature on the letter of transmittal must be guaranteed by an Eligible Institution. Any beneficial owner whose original notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and who wishes to tender original notes should contact such holder promptly and instruct such holder to tender original notes on such beneficial owner's behalf. If such beneficial owner wishes to tender such original notes himself, such beneficial owner must, prior to completing and executing the letter of transmittal and delivering such original notes, either make appropriate arrangements to register ownership of the original notes in such beneficial owner's name or follow the procedures described in the immediately preceding paragraph. The transfer of record ownership may take considerable time. 29 Book-Entry Transfer. The exchange agent will make a request to establish an account with respect to the original notes at The Depository Trust Company, which we refer to as the Book-Entry Transfer Facility, for purposes of the exchange offer within two business days after receipt of this prospectus, and any financial institution that is a participant in the Book-Entry Transfer Facility's systems may make book-entry delivery of original notes by causing the Book-Entry Transfer Facility to transfer such original notes into the exchange agent's account at the Book-Entry Transfer Facility in accordance with the Book-Entry Transfer Facility's procedures for transfer. However, although delivery of original notes may be effected through book-entry transfer at the Book-Entry Transfer Facility, the letter of transmittal, with any required signature guarantees and any other required documents, must, in any case, be transmitted to and received by the exchange agent at the address specified on the back cover page of this prospectus on or prior to the expiration date or the guaranteed delivery procedures described below must be complied with. THE METHOD OF DELIVERY OF ORIGINAL NOTES AND ALL OTHER DOCUMENTS IS AT YOUR ELECTION AND RISK. IF SENT BY MAIL, WE RECOMMEND THAT YOU USE REGISTERED MAIL, RETURN RECEIPT REQUESTED, OBTAIN PROPER INSURANCE, AND COMPLETE THE MAILING SUFFICIENTLY IN ADVANCE OF THE EXPIRATION DATE TO PERMIT DELIVERY TO THE EXCHANGE AGENT ON OR BEFORE THE EXPIRATION DATE. Unless an exemption applies under the applicable law and regulations concerning "backup withholding" of federal income tax, the exchange agent will be required to withhold, and will withhold, 31% of the gross proceeds otherwise payable to a holder pursuant to the exchange offer if the holder does not provide its taxpayer identification number (social security number or employer identification number) and certify that such number is correct. Each tendering holder should complete and sign the main signature form and the Substitute Form W-9 included as part of the letter of transmittal, so as to provide the information and certification necessary to avoid backup withholding, unless an applicable exemption exists and is proved in a manner satisfactory to us and the exchange agent. Guaranteed Delivery Procedures. If a holder desires to accept the exchange offer and time will not permit a letter of transmittal or original notes to reach the exchange agent before the expiration date, a tender may be effected if the exchange agent has received at its office listed on the back cover hereof on or prior to the expiration date a letter, telegram or facsimile transmission from an Eligible Institution setting forth the name and address of the tendering holder, the names in which the original notes are registered, the principal amount of the original notes and, if possible, the certificate numbers of the original notes to be tendered, and stating that the tender is being made thereby and guaranteeing that within three New York Stock Exchange trading days after the date of execution of such letter, telegram or facsimile transmission by the Eligible Institution, the original notes, in proper form for transfer, will be delivered by such Eligible Institution together with a properly completed and duly executed letter of transmittal (and any other required documents). Unless original notes being tendered by the above-described method (or a timely Book-Entry Confirmation) are deposited with the exchange agent within the time period set forth above (accompanied or preceded by a properly completed letter of transmittal and any other required documents), we may, at our option, reject the tender. Copies of a Notice of Guaranteed Delivery which may be used by Eligible Institutions for the purposes described in this paragraph are being delivered with this prospectus and the related letter of transmittal. A tender will be deemed to have been received as of the date when the tendering holder's properly completed and duly signed letter of transmittal accompanied by the original notes (or a timely Book-Entry Confirmation) is received by the exchange agent. Issuances of exchange notes in exchange for original notes tendered pursuant to a Notice of Guaranteed Delivery or letter, telegram or facsimile transmission to similar effect (as provided above) by an Eligible Institution will be made only against deposit of the letter of transmittal (and any other required documents) and the tendered original notes (or a timely Book-Entry Confirmation). All questions as to the validity, form, eligibility (including time of receipt) and acceptance for exchange of any tender of original notes will be determined by us and our determination will be final and binding. We reserve the absolute right to reject any or all tenders not in proper form or the acceptances for exchange of which may, in the opinion of our counsel, be unlawful. We also reserve the absolute right 30 to waive any of the conditions of the exchange offer or any defect or irregularities in tenders of any particular holder whether or not similar defects or irregularities are waived in the case of other holders. None of us, the exchange agent or any other person will be under any duty to give notification of any defects or irregularities in tenders or shall incur any liability for failure to give any such notification. Our interpretation of the terms and conditions of the exchange offer (including the letters of transmittal and the instructions thereto) will be final and binding. TERMS AND CONDITIONS OF THE LETTERS OF TRANSMITTAL The letters of transmittal contain, among other things, the following terms and conditions, which are part of the exchange offer. The party tendering original notes for exchange, to whom we refer to as the Transferor, exchanges, assigns and transfers the original notes to us and irrevocably constitutes and appoints the exchange agent as the Transferor's agent and attorney-in-fact to cause the original notes to be assigned, transferred and exchanged. The Transferor represents and warrants that it has full power and authority to tender, exchange, assign and transfer the original notes and to acquire exchange notes issuable upon the exchange of such tendered original notes, and that, when the same are accepted for exchange, we will acquire good and unencumbered title to the tendered original notes, free and clear of all liens, restrictions, charges and encumbrances and not subject to any adverse claim. The Transferor also warrants that it will, upon request, execute and deliver any additional documents deemed by us to be necessary or desirable to complete the exchange, assignment and transfer of tendered original notes. The Transferor further agrees that acceptance of any tendered original notes by us and the issuance of exchange notes in exchange therefor shall constitute performance in full by us of our obligations under the registration rights agreement and that we shall have no further obligations or liabilities thereunder (except in certain limited circumstances). All authority conferred by the Transferor will survive the death or incapacity of the Transferor and every obligation of the Transferor shall be binding upon the heirs, legal representatives, successors, assigns, executors and administrators of such Transferor. See "--Terms of the Exchange." WITHDRAWAL RIGHTS Original notes tendered pursuant to the exchange offer may be withdrawn at any time prior to the expiration date. For a withdrawal to be effective, a written or facsimile transmission notice of withdrawal must be timely received by the exchange agent at its address set forth on the back cover of this prospectus. Any such notice of withdrawal must specify the person named in the letter of transmittal as having tendered original notes to be withdrawn, the certificate numbers of original notes to be withdrawn, the principal amount of original notes to be withdrawn (which must be an authorized denomination), a statement that such holder is withdrawing his election to have such original notes exchanged, and the name of the registered holder of such original notes, and must be signed by the holder in the same manner as the original signature on the letter of transmittal (including any required signature guarantees) or be accompanied by evidence satisfactory to us that the person withdrawing the tender has succeeded to the beneficial ownership of the original notes being withdrawn. The exchange agent will return the properly withdrawn original notes promptly following receipt of notice of withdrawal. All questions as to the validity of notices of withdrawals, including time of receipt, will be determined by us, and our determination will be final and binding on all parties. ACCEPTANCE OF ORIGINAL NOTES FOR EXCHANGE; DELIVERY OF EXCHANGE NOTES Upon the terms and subject to the conditions of the exchange offer, the acceptance for exchange of original notes validly tendered and not withdrawn and the issuance of the exchange notes will be made on the exchange date. For the purposes of the exchange offer, we shall be deemed to have accepted for exchange validly tendered original notes when, as and if we have given written notice thereof to the exchange agent. The exchange agent will act as agent for the tendering holders of original notes for the purposes of receiving exchange notes from us and causing the original notes to be assigned, transferred and 31 exchanged. Upon the terms and subject to the conditions of the exchange offer, delivery of exchange notes to be issued in exchange for accepted original notes will be made by the exchange agent promptly after acceptance of the tendered original notes. Original notes not accepted for exchange by us will be returned without expense to the tendering holders (or in the case of original notes tendered by book-entry transfer into the exchange agent's account at the Book-Entry Transfer Facility pursuant to the procedures described above, such non-exchanged original notes will be credited to an account maintained with such Book-Entry Transfer Facility) promptly following the expiration date or, if we terminate the exchange offer prior to the expiration date, promptly after the exchange offer is so terminated. CONDITIONS TO THE EXCHANGE OFFER We are not required to accept for exchange, or to issue exchange notes in exchange for, any outstanding original notes. We may terminate or extend the exchange offer by oral or written notice to the exchange agent and by timely public announcement communicated in accordance with applicable law or regulation, if: o any federal law, statute, rule, regulation or interpretation of the staff of the SEC has been proposed, adopted or enacted that, in our judgment, might impair our ability to proceed with the exchange offer or otherwise make it inadvisable to proceed with the exchange offer; o an action or proceeding has been instituted or threatened in any court or by any governmental agency that, in our judgement might impair our ability to proceed with the exchange offer or otherwise make it inadvisable to proceed with the exchange offer; o there has occurred a material adverse development in any existing action or proceeding that might impair our ability to proceed with the exchange offer or otherwise make it inadvisable to proceed with the exchange offer; o any stop order is threatened or in effect with respect to the registration statement of which this prospectus is a part or the qualification of the indenture under the Trust Indenture Act of 1939; o all governmental approvals that we deem necessary for the consummation of the exchange offer have not been obtained; o there is a change in the current interpretation by the staff of the SEC which permits holders who have made the required representations to us to resell, offer for resale, or otherwise transfer exchange notes issued in the exchange offer without registration of the exchange notes and delivery of a prospectus; or o a material adverse change shall have occurred in our business, condition, operations or prospects. The foregoing conditions are for our sole benefit and may be asserted by us with respect to all or any portion of the exchange offer regardless of the circumstances (including any action or inaction by us) giving rise to such condition or may be waived by us in whole or in part at any time or from time to time in our sole discretion. The failure by us at any time to exercise any of the foregoing rights will not be deemed a waiver of any such right, and each right will be deemed an ongoing right which may be asserted at any time or from time to time. In addition, we have reserved the right, notwithstanding the satisfaction of each of the foregoing conditions, to terminate or amend the exchange offer. Any determination by us concerning the fulfillment or non-fulfillment of any conditions will be final and binding upon all parties. EXCHANGE AGENT The Bank of New York has been appointed as the exchange agent for the exchange offer. Letters of transmittal must be addressed to the exchange agent at its address set forth on the back cover page of this prospectus. Delivery to an address other than as set forth herein, or transmissions of instructions via a facsimile or telex number other than the ones set forth herein, will not constitute a valid delivery. 32 SOLICITATION OF TENDERS; EXPENSES We have not retained any dealer-manager or similar agent in connection with the exchange offer and will not make any payments to brokers, dealers or others for soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and will reimburse it for reasonable out-of-pocket expenses in connection therewith. We will also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding tenders for their customers. The expenses to be incurred in connection with the exchange offer, including the fees and expenses of the exchange agent and printing, accounting and legal fees, will be paid by us and are estimated at approximately $250,000. No dealer, salesperson or other individual has been authorized to give any information or to make any representations not contained in this prospectus in connection with the exchange offer. If given or made, such information or representations must not be relied upon as having been authorized by us. Neither the delivery of this prospectus nor any exchange made hereunder shall, under any circumstances, create any implication that there has been no change in our affairs since the respective dates as of which information is given herein. The exchange offer is not being made to (nor will tenders be accepted from or on behalf of) holders of original notes in any jurisdiction in which the making of the exchange offer or the acceptance thereof would not be in compliance with the laws of such jurisdiction. However, we may, at our discretion, take such action as we may deem necessary to make the exchange offer in any such jurisdiction and extend the exchange offer to holders of original notes in such jurisdiction. In any jurisdiction the securities laws or blue sky laws of which require the exchange offer to be made by a licensed broker or dealer, the exchange offer is being made on behalf of us by one or more registered brokers or dealers which are licensed under the laws of such jurisdiction. APPRAISAL RIGHTS You will not have dissenters' rights or appraisal rights in connection with the exchange offer. FEDERAL INCOME TAX CONSEQUENCES The exchange of original notes for exchange notes by holders should not be a taxable exchange for federal income tax purposes, and holders should not recognize any taxable gain or loss or any interest income as a result of such exchange. See "Certain United States Federal Income Tax Considerations." OTHER Participation in the exchange offer is voluntary and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decisions on what action to take. As a result of the making of, and upon acceptance for exchange of all validly tendered original notes pursuant to the terms of this exchange offer, we will have fulfilled a covenant contained in the terms of the original notes and the registration rights agreement. Holders of the original notes who do not tender their original notes in the exchange offer will continue to hold such original notes and will be entitled to all the rights, and limitations applicable thereto, under the indenture, except for any such rights under the registration rights agreement which by their terms terminate or cease to have further effect as a result of the making of this exchange offer. See "Description of Notes." All untendered original notes will continue to be subject to the restriction on transfer set forth in the indenture. To the extent that original notes are tendered and accepted in the exchange offer, the trading market, if any, for the original notes could be adversely affected. See "Risk Factors -- Your ability to sell your original notes may be significantly more limited and the price at which you may be able to sell your original notes may be significantly lower if you do not exchange them for registered exchange notes in the exchange offer." We may in the future seek to acquire untendered original notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plan to acquire any original notes which are not tendered in the exchange offer. 33 CAPITALIZATION The following table sets forth our consolidated capitalization at September 30, 2002 and our pro forma consolidated capitalization at September 30, 2002 as if (a) all of the original notes had been issued on September 30, 2002, and (b) our $300 million loan to Northern Natural Gas and the subsequent repayment to us from the proceeds of its offering of $300 million of 5.375% Senior Notes due 2012 was completed on September 30, 2002. The table should be read in conjunction with our historical consolidated financial statements and the notes hereto appearing elsewhere in this prospectus.
SEPTEMBER 30, 2002 ------------------- PRO FORMA ACTUAL ADJUSTMENTS PRO FORMA -------------- ------------------- -------------- (ALL DATA IN THOUSANDS) Indebtedness: Parent company short-term debt ...................... $ 167,000 $ (167,000) $ -- Subsidiary short-term debt .......................... 475,031 (450,000) 25,031 Parent company long-term debt (2) ................... 1,838,178 700,000(1) 2,538,178 Subsidiary long-term debt (3) (4) ................... 6,656,275 300,000 6,956,275 ----------- ---------- ----------- Total consolidated indebtedness ..................... 9,136,484 383,000 9,519,484 Parent company-obligated mandatorily redeemable preferred securities of subsidiary trusts held by Berkshire Hathaway ................................. 1,727,772 1,727,772 Parent company-obligated mandatorily redeemable preferred securities of subsidiary trusts held by others ............................................. 335,043 335,043 Preferred securities of subsidiaries ................ 93,619 93,619 Shareholders' equity: Zero-coupon convertible preferred stock--authorized 50,000 shares, no par value, 41,263 shares issued and outstanding .................................... -- -- Common stock--authorized 60,000 shares, no par value, 9,281 shares issued and outstanding ......... -- -- Additional paid-in capital .......................... 1,956,509 1,956,509 Retained earnings ................................... 510,766 510,766 Accumulated other comprehensive income .............. 24,240 24,420 ----------- ---------- ----------- Total shareholders' equity .......................... 2,491,515 2,491,515 ----------- ---------- ----------- Total capitalization ................................ $13,784,433 $ 383,000 $14,167,433 =========== ========== ===========
---------- (1) Represents the notes being registered hereby. (2) Includes approximately $215 million current portion of parent long-term debt. (3) Represents debt for which the repayment obligation is at our subsidiary level and that is non-recourse to us except as it relates to our guarantee of approximately $47 million of the Cordova Funding Corporation Senior Secured Bonds, our guarantee of approximately $139 million for the Salton Sea Funding Series F Bonds, our letters of credit of approximately $49 million for our geothermal facilities located on the island of Leyte in the Philippines, and our completion guarantee as it potentially relates to Kern River's $875 million construction loan facility, of which approximately $385 million was drawn as of September 30, 2002. (4) Includes approximately $268 million current portion of subsidiary long-term debt. 34 SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA The following tables set forth selected historical consolidated financial and operating data, which should be read in conjunction with our financial statements and the related notes to those statements included in this prospectus and with "Management's Discussion and Analysis of Financial Condition and Results of Operations" appearing elsewhere in this prospectus. The selected consolidated data as of and for each of the five years in the period ended December 31, 2001 have been derived from our audited historical consolidated financial statements. The selected consolidated data as of September 30, 2002 and for the nine months ended September 30, 2002 and 2001 have been derived from our unaudited historical consolidated financial statements and reflect all adjustments necessary in the opinion our management (consisting of normal recurring accruals) for a fair presentation of such data. All data (except for ratios) is presented in thousands.
MARCH 14, YEAR ENDED 2000 THROUGH DECEMBER 31, DECEMBER 31, 2001 (1) 2000 (2) ------------------ --------------- STATEMENT OF OPERATIONS DATA: Operating revenues ........................ $ 5,060,605 $ 4,147,867 Total revenue ............................. 5,336,804 4,242,749 Cost of sales and operating expenses ................................. 3,881,424 3,328,790 Depreciation and amortization ............. 538,702 383,351 Interest expense, net of capitalized interest ................................. 412,794 311,404 Provision for income taxes ................ 250,064 53,277 Minority interest ......................... 106,547 84,670 Income before extraordinary item and cumulative effect of change in accounting principle .................. 147,273 81,257 Extraordinary item, net of tax ............ -- -- Cumulative effect of change in accounting principle, net of tax ......... (4,604) -- Net income (loss) ......................... 142,669 (5) 81,257 OTHER FINANCIAL DATA: Capital expenditures ...................... $ 398,165 $ 301,948 Ratio of earnings to fixed charges (9) .............................. 1.8 1.3 Net cash flows from operating activities ............................... 846,998 246,407 Net cash flows from investing activities ............................... (238,544) (2,389,160) Net cash flows from financing activities ............................... (258,467) 1,878,849 EBITDA (10) ............................... 1,455,380 913,959 Adjusted EBITDA (10) ...................... 1,275,887 913,959 EBIT (11) ................................. 916,678 530,608 Adjusted EBIT (11) ........................ 737,185 530,608 OUR PREDECESSOR ------------------------------------------------------------------------- JANUARY 1, 2000 THROUGH MARCH 13, YEAR ENDED DECEMBER 31, 2000 1999 (3) 1998 (4) 1997 ----------------- ------------------ --------------- -------------------- STATEMENT OF OPERATIONS DATA: Operating revenues ........................ $1,087,125 $ 4,184,546 $ 2,555,206 $ 2,166,338 Total revenue ............................. 1,106,609 4,466,425 2,682,711 2,270,911 Cost of sales and operating expenses ................................. 824,742 3,201,084 1,729,944 1,453,733 Depreciation and amortization ............. 97,278 427,690 333,422 276,041 Interest expense, net of capitalized interest ................................. 85,814 426,173 347,292 251,305 Provision for income taxes ................ 31,008 93,475 93,265 99,044 Minority interest ......................... 8,850 46,923 41,276 45,993 Income before extraordinary item and cumulative effect of change in accounting principle .................. 51,312 216,671 137,512 51,823 Extraordinary item, net of tax ............ -- (49,441) (7,146) (135,850) Cumulative effect of change in accounting principle, net of tax ......... -- -- (3,363) -- Net income (loss) ......................... 51,312 (6) 167,230 (7) 127,003 (84,027) (8) OTHER FINANCIAL DATA: Capital expenditures ...................... $ 44,355 $ 360,898 $ 227,071 $ 194,224 Ratio of earnings to fixed charges (9) .............................. 1.7 1.6 1.5 1.5 Net cash flows from operating activities ............................... 171,083 554,959 361,546 336,548 Net cash flows from investing activities ............................... (54,874) (1,960,820) (1,007,780) (1,066,061) Net cash flows from financing activities ............................... (128,501) 115,875 797,338 1,741,906 EBITDA (10) ............................... 274,262 1,210,932 952,767 724,206 Adjusted EBITDA (10) ...................... 281,867 1,126,637 952,767 811,206 EBIT (11) ................................. 176,984 783,242 619,345 448,165 Adjusted EBIT (11) ........................ 184,589 698,947 619,345 535,165
35
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------------------- 2002 2001 -------------------- -------------------- STATEMENT OF OPERATIONS DATA: Operating revenues ...................................................... $ 3,404,533 $ 3,756,931 Total revenue ........................................................... 3,549,744 4,043,075 Cost of sales and operating expenses .................................... 2,232,151 2,854,940 Depreciation and amortization ........................................... 386,531 395,253 Interest expense, net of capitalized interest ........................... 438,870 290,153 Provision for income taxes .............................................. 80,226 296,088 Minority interest ....................................................... 105,166 79,952 Income before cumulative effect of change in accounting principle ....... 306,800 126,689 Cumulative effect of change in accounting principle, net of tax ......... -- (4,604) Net income .............................................................. 306,800 (12) 122,085 (13) OTHER FINANCIAL DATA: Capital expenditures .................................................... $ 778,750 $ 376,962 Ratio of earnings to fixed charges (9) .................................. 1.9 2.1 Net cash flows from operating activities ................................ 682,782 790,990 Net cash flows from investing activities ................................ (2,263,656) (48,697) Net cash flows from financing activities ................................ 1,814,900 (197,961) EBITDA (10) ............................................................. 1,317,593 1,188,135 Adjusted EBITDA (10) .................................................... 1,263,253 967,027 EBIT (11) ............................................................... 931,062 792,882 Adjusted EBIT (11) ...................................................... 876,722 571,774
AS OF SEPTEMBER 30, 2002 -------------------- BALANCE SHEET DATA: Property, plant, contracts and equipment, net ........................... $ 9,168,940 Total assets .............................. 16,984,050 Short-term debt ........................... 642,031 Parent company debt ....................... 1,623,178 Subsidiary and project debt ............... 6,388,169 Current portion of long-term debt ......... 483,106 Total liabilities ......................... 12,247,784 Parent company-obligated mandatorily redeemable preferred securities held by Berkshire Hathaway ................................. 1,727,772 Parent company-obligated mandatorily redeemable preferred securities held by others ................ 335,043 Total shareholders' equity ................ 2,491,515 OUR PREDECESSOR ----------------------------------------- AS OF DECEMBER 31, 2001 2000 1999 1998 1997 ------------- ------------- ------------- ------------- ------------- BALANCE SHEET DATA: Property, plant, contracts and equipment, net ........................... $ 6,527,448 $ 5,348,647 $ 5,463,329 $4,236,039 $3,528,910 Total assets .............................. 12,615,333 11,610,939 10,766,352 9,103,524 7,487,626 Short-term debt ........................... 256,012 261,656 379,523 -- -- Parent company debt ....................... 1,834,498 1,829,971 1,856,318 2,645,991 1,303,845 Subsidiary and project debt ............... 4,754,811 3,388,696 3,642,703 2,712,319 2,189,007 Current portion of long-term debt ......... 317,180 438,978 235,202 381,491 -- Total liabilities ......................... 9,767,438 8,911,349 8,978,924 7,598,040 5,282,162 Parent company-obligated mandatorily redeemable preferred securities held by Berkshire Hathaway ................................. 454,772 454,772 -- -- -- Parent company-obligated mandatorily redeemable preferred securities held by others ................ 333,379 331,751 450,000 553,930 553,930 Total shareholders' equity ................ 1,708,167 1,576,401 994,588 827,053 765,326
---------- (1) Reflects the acquisition of the Yorkshire Electricity electricity distribution business and the simultaneous sale of the Northern Electric electricity and gas supply business on September 21, 2001. (2) Reflects our acquisition by a private investor group on March 14, 2000. (3) Reflects our acquisition of MidAmerican Energy on March 12, 1999, our disposition of the Coso Joint Ventures on February 26, 1999, and our disposition of a 50% ownership interest in CE Gen on March 3, 1999. (4) Reflects the acquisition from Kiewit Diversified Group on January 2, 1998. (5) Includes $15.2 million of non-recurring net income related to the sale of the Northern Electric electricity and gas supply business, the sale of the Telephone Flat Project, the sale of Western States Geothermal, the transfer of Bali Energy Ltd. shares, and the TPL asset valuation impairment charge. 36 (6) Includes $7.6 million of net non-recurring expenses for the costs related to our acquisition by a private investor group on March 14, 2000. (7) Includes $81.5 million of non-recurring net income related to the settlement of political risk insurance proceeds related to our investment in Indonesia, gains on sales of shares of McLeodUSA, our disposition of the Coso Joint Ventures, our disposition of a 50% ownership interest of CE Gen, CE Electric UK restructuring charges and transaction costs related to our acquisition by a private investor group. (8) Includes an $87 million non-recurring Indonesia asset impairment charge. (9) For purposes of computing the ratio of earnings to fixed charges, earnings are divided by fixed charges. Earnings represent the aggregate of (a) our pre-tax income and (b) fixed charges, less capitalized interest. Fixed charges represent interest (whether expensed or capitalized), amortization of deferred financing and bank fees, and the estimated interest component of rentals. (10) EBITDA represents earnings before interest, taxes, depreciation, and amortization. Adjusted EBITDA represents EBITDA adjusted for non-recurring income and expense items as follows: (a) items discussed in (5), which are $179.4 million before tax; (b) item discussed in (6); (c) items discussed in (7), which are $84.3 million before tax; (d) item discussed in (8). (e) items discussed in (12), which are $54.3 million before tax; and (f) items discussed in (13), which are $221.1 million before tax. Information concerning EBITDA and adjusted EBITDA is presented not as a measure of operating results, but rather as a measure of our ability to service debt. EBITDA and adjusted EBITDA should not be construed as an alternative to either (a) operating income (determined in accordance with GAAP) or (b) cash flow from operating activities (determined in accordance with GAAP). Since EBITDA and adjusted EBITDA are not defined by GAAP, they may not be calculated on the same basis as similarly titled measures of other companies. (11) EBIT represents earnings before interest and taxes. Adjusted EBIT represents EBIT adjusted for non-recurring income and expense items. Information concerning EBIT and adjusted EBIT is presented not as a measure of operating results, but rather as a measure of our ability to service debt. EBIT and adjusted EBIT should not be construed as an alternative to either (a) operating income (determined in accordance with GAAP) or (b) cash flow from operating activities (determined in accordance with GAAP). Since EBIT and adjusted EBIT are not defined by GAAP, they may not be calculated on the same basis as similarly titled measures of other companies. (12) Includes $41.3 million of non-recurring net income related to the sale of assets by CE Gas Holdings. (13) Includes $13.7 million of non-recurring net income related to the sale of Western States Geothermal and the sale of Northern Supply. 37 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is management's discussion and analysis of certain significant factors which have affected the financial condition and results of operations of MidAmerican Energy Holdings Company, or the Company, during the periods included in the accompanying statements of operations. This discussion should be read in conjunction with "Selected Consolidated Financial and Operating Data" and the Company's historical financial statements and the notes to those statements included elsewhere in this prospectus. As a result of the recent acquisitions of Northern Natural Gas and Kern River, the acquisition of the electricity distribution business of Yorkshire Electricity and the simultaneous sale of the electricity and gas supply business of Northern Electric to the former owner of Yorkshire Electricity, which together are referred to as the Northern Electric/Yorkshire Electricity swap, and the acquisition by a private investor group on March 14, 2000, the Company's future results will differ from the Company's historical results. GENERAL The Company is a United States-based privately owned global energy company with publicly held fixed income securities that generates, distributes and supplies energy to utilities, government entities, retail customers and other customers located throughout the world. Through the Company's subsidiaries, the Company's operations are organized and managed on seven distinct platforms: MidAmerican Energy, Northern Natural Gas, Kern River, CE Electric UK (which includes Northern Electric and Yorkshire Electricity), CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and HomeServices. These platforms, with the exception of Northern Natural Gas and Kern River, are discussed in detail in the notes to the Company's financial statements included in this prospectus. NORTHERN NATURAL GAS COMPANY On August 16, 2002, the Company acquired all of the outstanding capital stock of Northern Natural Gas from Dynegy, Inc. and its affiliates for $899 million, net of cash acquired of $1.4 million, subject to adjustment for working capital. The Company used the proceeds from a $950 million investment in its subsidiary trust's preferred securities by Berkshire Hathaway to finance this acquisition. Northern Natural Gas owns a 16,600-mile interstate natural gas pipeline extending from southwest Texas to the upper Midwest region of the United States with a design capacity of 4.4 Bcf of natural gas per day. Northern Natural Gas also operates three natural gas storage facilities and two liquefied natural gas peaking units with a total storage capacity of 59 Bcf and peak delivery capability of over 1.3 Bcf of natural gas per day. Northern Natural Gas accesses natural gas supply from many of the larger producing regions in North America, including the Rocky Mountains, Hugoton, Permian, Anadarko and Western Canadian basins. The pipeline system provides transportation and storage services to utilities, municipalities, other pipeline companies, gas marketers and industrial and commercial users. KERN RIVER GAS TRANSMISSION COMPANY On March 27, 2002, the Company acquired Kern River from a subsidiary of The Williams Companies, Inc., or Williams. Kern River owns and operates a 926-mile interstate natural gas pipeline extending from Wyoming to markets in California, Nevada and Utah and accessing natural gas supply from large producing regions in the Rocky Mountains and Canada. The Company paid $420 million, net of cash acquired of $7.7 million, including transaction costs and working capital adjustments, for Kern River. At the time of the acquisition, Kern River had $505 million of indebtedness, the unamortized portion of which remains outstanding. The design capacity of the existing Kern River pipeline is 100% contracted through 2011 and 84% contracted through 2016. In connection with the Kern River acquisition, the Company issued $323 million of 11% mandatorily redeemable preferred securities of a subsidiary trust due March 12, 2012 with scheduled principal payments beginning in 2005, and $127 million of no par, zero coupon convertible preferred stock to 38 Berkshire Hathaway. Each share of such preferred stock is convertible at the option of the holder into one share of Company common stock subject to certain adjustments as described in the Company's amended and restated articles of incorporation. CRITICAL ACCOUNTING POLICIES The preparation of financial statements and related documents in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Note 2 to the consolidated financial statements for the year ended December 31, 2001 included in this prospectus describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Estimates are used for, but not limited to, the accounting for revenue, the effects of certain types of regulation, impairment of long-lived assets, and contingent liabilities. Actual results could differ from these estimates. The following critical accounting policies are impacted significantly by judgments, assumptions and estimates used in the preparation of the consolidated financial statements. REVENUE RECOGNITION Revenues are recorded based upon services rendered and electricity, gas and steam delivered, distributed or supplied to the end of the period. Where there is an over recovery of United Kingdom distribution business revenues against the maximum regulated amount, revenues are deferred in an amount equivalent to the over recovered amount. The deferred amount is deducted from revenue and included in other liabilities. Where there is an under recovery, no anticipation of any potential future recovery is made. MidAmerican Energy records unbilled revenues representing the estimated amounts customers will be billed for services rendered between the meter reading dates in a particular month and the end of that month. The unbilled revenues estimate is reversed in the following month. To the extent the estimated amount differs from that amount subsequently billed, the timing of revenues will be affected. Accrued unbilled revenues are included in accounts receivable on the consolidated balance sheets. Revenues from the transportation and storage of gas are recognized based on contractual terms and the related volumes. Northern Natural Gas and Kern River are subject to the FERC's regulations and, accordingly, certain revenues collected may be subject to possible refunds upon final orders in pending rate cases. Northern Natural Gas and Kern River record rate refund liabilities considering their regulatory proceedings 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. SFAS NO. 71--ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION MidAmerican Energy, Kern River and Northern Natural Gas prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards No. 71, which differs in certain respects from the application of generally accepted accounting principles by non-regulated businesses. In general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, MidAmerican Energy, Kern River and Northern Natural Gas have deferred certain costs, which will be amortized over various future periods. To the extent that collection of such costs or payment of obligations is no longer probable as a result of changes in regulation, the associated regulatory asset or liability is charged or credited to income. A possible consequence of deregulation of the regulated energy industry is that SFAS No. 71 may no longer apply. If portions of the Company's subsidiaries' regulated energy operations no longer meet the criteria of SFAS No. 71, the Company could be required to write off the related regulatory assets and liabilities from its balance sheet, and thus a material adjustment to earnings in that period could result if regulatory assets are not recovered in transition provisions of any deregulation legislation. 39 The Company continues to evaluate the applicability of SFAS No. 71 to its regulated energy operations and the recoverability of these assets and liabilities through rates as there are on-going changes in the regulatory and economic environment. IMPAIRMENT OF LONG-LIVED ASSETS The Company's long-lived assets consist primarily of property, plant and equipment, goodwill and intangible assets that were acquired in business acquisitions. The Company believes the useful lives assigned to the depreciable assets, which generally range from 1 to 87 years, are reasonable. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Triggering events include a significant change in the extent or manner in which long-lived assets are being used or in their physical condition, in legal factors, or in the business climate that could affect the value of the long-lived assets, including changes in regulation. The interpretation of such events requires judgment from management as to whether such an event has occurred and is required. If an event occurs that could affect the carrying value of the asset and management does not identify it as triggering event, future results of operations could be significantly affected. Upon the occurrence of a triggering event, the carrying amount of a long-lived asset is reviewed to assess whether the recoverable amount has declined below its carrying amount. The recoverable amount is the estimated net future cash flows that the Company expects to recover from the future use of the asset, undiscounted and without interest, plus the asset's residual value on disposal. Where the recoverable amount of the long-lived asset is less than the carrying value, an impairment loss would be recognized to write down the asset to its fair value which is based on discounted estimated cash flows from the future use of the asset. The estimate of cash flows arising from future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from future use of the asset. Any changes in the estimates of cash flows arising from future use of the asset or the residual value of the asset on disposal based on changes in the market conditions, changes in the use of the asset, management's plans, the determination of the useful life of the asset and technology changes in the industry could significantly change the calculation of the fair value or recoverable amount of the asset and the resulting impairment loss, which could significantly affect the results of operations. Effective January 1, 2002, the Company adopted Statement of Financial Accounting Standard No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 requires that amortization of goodwill and indefinite-lived intangible assets be discontinued and that these assets be tested for impairment annually. During the second quarter of 2002, the Company completed its initial impairment testing of goodwill primarily using a discounted cash flow methodology. No impairment was indicated as a result of the initial testing. CONTINGENT LIABILITIES The Company establishes reserves 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 different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Reserves for contingent liabilities are based upon management's assumptions and estimates, and advice of legal counsel or other third parties regarding the probable outcomes of any matters. Should the outcomes differ from the assumptions and estimates, revisions to the estimated reserves for contingent liabilities would be required. RESULTS OF OPERATIONS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2002 AND 2001 Operating revenue for the three months ended September 30, 2002, was $1,238.5 million compared with $1,076.8 million for the same period in 2001, an increase of 15.0%. MidAmerican Energy operating 40 revenue increased for the three months ended September 30, 2002, to $538.7 million from $507.7 million for the same period in 2001, primarily due to higher volumes for regulated electricity. CE Electric UK Funding operating revenue decreased for the three months ended September 30, 2002, to $193.4 million from $316.3 million for the same period in 2001, primarily due to the sale of Northern Supply in September 2001 of $209 million, partially offset by Yorkshire Electricity distribution revenue of $103 million. The remaining change in operating revenue primarily relates to (1) the increase of revenue at HomeServices of $147.6 million primarily due to acquisitions in 2002 and late 2001, (2) the acquisition of Kern River in March 2002, which accounted for $39.9 million of operating revenue and (3) the acquisition of Northern Natural Gas in August 2002, which accounted for $39.1 million of operating revenue. Operating revenue for the nine months ended September 30, 2002, was $3,404.5 million compared with $3,756.9 million for the same period in 2001, a decrease of 9.4%. MidAmerican Energy operating revenue decreased for the nine months ended September 30, 2002, to $1,582.6 million from $1,897.8 million for the same period in 2001, primarily due to lower volumes and rates for regulated and non-regulated gas. CE Electric UK Funding operating revenues decreased for the nine months ended September 30, 2002, to $597.0 million from $1,222.3 million for the same period in 2001, primarily due to the sale of Northern Supply in September 2001 of $889 million, partially offset by Yorkshire Electricity distribution revenue of $276 million. The remaining change in operating revenue primarily relates to (1) the increase of revenue at HomeServices of $382.5 million primarily due to acquisitions in 2002 and late 2001, (2) the acquisition of Kern River in March 2002, which accounted for $87.0 million of operating revenue and (3) the acquisition of Northern Natural Gas in August 2002, which accounted for $39.1 million of operating revenue. The following data represents sales from MidAmerican Energy:
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, 2002 2001 2002 2001 Electricity Retail Sales (GWh) ............. 4,987 4,679 13,254 12,502 Electricity Sales for Resale (GWh) ......... 2,506 1,772 7,485 6,341 Regulated and Non-Regulated Gas Supplied (Thousands of MMBtus) ........... 38,936 53,605 169,200 198,789
MidAmerican Energy's electric retail sales and electric sales for resale increased for three months ended September 30, 2002, from the same period in 2001 due to higher temperatures in the third quarter of 2002. Retail gas supplied decreased due to decreased non-regulated activity for the three months ended September 30, 2002, compared to the same period in 2001. MidAmerican Energy electric retail sales increased for the nine months ended September 30, 2002 from the same period in 2001 due primarily to higher temperatures in 2002, primarily in the third quarter of 2002. Electric sales for resale increased for the nine months ended September 30, 2002 from the same period in 2001 due to availability of Cordova Energy Company LLC, or Cordova Energy, an indirect wholly owned subsidiary of the Company, and lower retail usage in the first quarter of 2002, allowing for more energy to be sold in the wholesale markets. Regulated and non-regulated gas supplied decreased due to colder temperatures during the first quarter of 2001 and decreased non-regulated activity. CE Electric UK Funding distributed 9,473 GWh of electricity in the three months ended September 30, 2002, compared with 4,457 GWh of electricity in the same period in 2001. CE Electric UK Funding distributed 30,252 GWh of electricity in the nine months ended September 30, 2002, compared with 13,016 GWh of electricity in the same period in 2001. The increase in electricity distributed for both periods ended September 30, 2002, is primarily due to the acquisition of Yorkshire Electricity distribution. Kern River transported 90,532,000 MMBtus in the three months ended September 30, 2002, and 190,195,000 MMBtus since the Company acquired Kern River on March 27, 2002. 41 Northern Natural Gas transported 121,028,500 MMBtus since the Company acquired Northern Natural Gas on August 16, 2002. Income on equity investments for the three months ended September 30, 2002, was $10.9 million compared with $6.3 million for the same period in 2001. The increase was primarily due to higher earnings at CE Gen as a result of higher energy prices in 2002 and the allowance for doubtful accounts accrual in 2001, and income from a HomeServices' joint venture which was fully consolidated in 2001, partially offset by lower equity earnings due to impairment of alternative energy project funds in 2002. Income on equity investments for the nine months ended September 30, 2002, was $29.9 million compared with $23.6 million for the same period in 2001. The increase was primarily due to income from a HomeServices' joint venture that was fully consolidated in 2001. Interest and other income for the three months ended September 30, 2002, was $32.7 million compared with $223.9 million for the same period in 2001. The decrease was primarily due to the $200.3 million gain on the sale of Northern Supply in September 2001. Interest and other income for the nine months ended September 30, 2002, was $115.3 million compared with $262.5 million for the same period in 2001. The decrease was primarily due to the gain on sale of Northern Supply in September 2001, partially offset by the $54.3 million gain on the sale of various CE Gas Holdings assets in May 2002. Cost of sales for the three months ended September 30, 2002, was $443.1 million compared with $473.0 million for the same period in 2001, a decrease of 6.3%. Cost of sales for the nine months ended September 30, 2002, was $1,283.2 million compared with $2,010.2 million for the same period in 2001, a decrease of 36.2%. The decreases for both periods relates primarily to the sale of Northern Supply and decreased gas revenue at MidAmerican Energy, partially offset by increase cost of sales at HomeServices due to higher commission on the higher revenues as a result of acquisitions. Operating expenses for the three months ended September 30, 2002, were $343.3 million compared with $293.9 million for the same period in 2001. The increase was primarily due to higher costs at HomeServices of $32.3 million as a result of acquisitions and operating expenses due to the acquisition of Northern Natural Gas of $26.6 million, partially offset by lower costs at MidAmerican Energy of $23.4 million due to the restructuring of the Cooper Nuclear Station contract with the Nebraska Public Power District, or NPPD, and lower energy efficiency expenses. Operating expenses for the nine months ended September 30, 2002, were $948.9 million compared with $844.8 million for the same period in 2001. The increase was primarily due to higher costs at HomeServices of $77.5 million as a result of acquisitions and operating expenses due to the acquisitions of Northern Natural Gas of $26.6 million and Kern River of $18.2 million, partially offset by lower costs at MidAmerican Energy of $22.0 million due to the restructuring of the Cooper Nuclear Station contract and lower energy efficiency expenses. Depreciation and amortization for the three months ended September 30, 2002, was $129.4 million compared with $122.7 million for the same period in 2001. The increase was primarily due to higher depreciation at MidAmerican Energy of $12.5 million primarily due to higher Iowa revenue sharing accruals, the commencement of commercial operation at CE Casecnan of $5.8 million, and depreciation expense due to the acquisitions of Northern Natural Gas of $5.8 million and Kern River of $4.9 million, partially offset by the discontinuance of amortizing goodwill beginning January 1, 2002 of $24.8 million. Depreciation and amortization for the nine months ended September 30, 2002, was $386.5 million compared with $395.3 million for the same period in 2001. The decrease was primarily due to discontinuance of amortizing goodwill beginning January 1, 2002 of $74.7 million, partially offset by the commencement of commercial operations at CE Casecnan of $17.6 million, higher depreciation at MidAmerican Energy of $17.3 million primarily due to higher Iowa revenue sharing accruals, depreciation expense due to the acquisitions of Kern River of $12.2 million and Northern Natural Gas of $5.8 million and increased amortization at HomeServices of $8.9 million due to intangible assets amortization related to acquisitions. 42 Interest expense, less amounts capitalized, for the three months ended September 30, 2002, was $159.3 million compared with $99.9 million for the same period in 2001, an increase of 59.5%. The increase was due primarily to the increase of interest expense at CE Electric UK Funding of $24.4 million predominantly due to the debt related to the Yorkshire Electricity acquisition, the discontinuance of capitalizing interest related to the Casecnan Project of $13.0 million, and interest expense due to the acquisitions of Kern River and Northern Natural Gas of $12.9 million and $8.1 million, respectively. Interest expense, less amounts capitalized, for the nine months ended September 30, 2002, was $438.9 million compared with $290.2 million for the same period in 2001, an increase of 51.2%. The increase was primarily due to the increase of interest expense at CE Electric UK Funding of $68.4 million predominantly due to the debt related to the Yorkshire Electricity acquisition, the discontinuance of capitalizing interest related to the Casecnan Project and the Cordova Project of $37.7 million and $9.7 million, respectively, and interest expense due to debt related to the acquisitions of Kern River and Northern Natural Gas of $22.4 million and $8.1 million, respectively. Tax expense for the three months ended September 30, 2002, was $26.8 million compared with $241.9 million for the same period in 2001. The decrease is due primarily to the tax expense of $199.9 million related to the sale of the Northern Supply business in September 2001 and the recognition of a tax benefit of $21.1 million in connection with the sale of the CE Gas Holdings assets in May 2002. Tax expense for the nine months ended September 30, 2002, was $80.2 million compared to $296.1 million for the same period in 2001. The decrease is due primarily to the tax expense related to the sale of the Northern Supply business in September 2001, the release of the tax obligation of $35.7 million in connection with the execution of the TPL restructuring agreement in the U.K., and the recognition of a tax benefit in connection with the sale of the CE Gas Holdings assets in 2002. Minority interest for the three months ended September 30, 2002, was $45.3 million compared with $27.8 million for the same period in 2001. Minority interest for the nine months ended September 30, 2002, was $105.2 million compared with $80.0 million for the same periods in 2001. Minority interest includes the dividends on the Company-obligated mandatorily redeemable preferred securities of subsidiary trusts. The increases in minority interest for both periods is primarily due to the issuance of Company-obligated mandatorily redeemable preferred securities of subsidiary trusts relating to the Kern River and Northern Natural Gas acquisitions. Effective January 1, 2001, the Company changed its accounting policy regarding major maintenance and repairs for nonregulated gas projects, nonregulated plant overhaul costs and geothermal well rework costs to the direct expense method from the former policy of monthly accruals based on long-term scheduled maintenance plans for the gas projects and deferral and amortization of plant overhaul costs and geothermal well rework costs over the estimated useful lives. The cumulative effect of the change in accounting principle for 2001 was $4.6 million, net of taxes of $0.7 million. RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2001 AND THE PERIODS MARCH 14, 2000 THROUGH DECEMBER 31, 2000, AND JANUARY 1, 2000 THROUGH MARCH 13, 2000 The following is a discussion of the historical results of the Company for the year ended December 31, 2001 and the period March 14, 2000 through December 31, 2000, and of the Company's predecessor, MEHC (Predecessor), for the period January 1, 2000 through March 13, 2000. Results for the Company include the impact of the Company's acquisition by a private investor group beginning March 14, 2000 which are predominately the minority interest costs on issuance of Company-obligated mandatorily redeemable preferred securities of a subsidiary trust and the effects of purchase accounting, including goodwill amortization and fair value adjustments to the carrying value of assets and liabilities. In order to provide comparability between periods, the Company has prepared pro forma results as if the Company's acquisition by a private investor group had occurred at the beginning of each year after giving effect to pro forma adjustments related to the acquisition, including the issuance of the 11% trust preferred securities. The discussion therefore will highlight any significant variances on a pro forma basis from the year ended December 31, 2000 to the year ended December 31, 2001. 43 Pro forma operating revenue for the year ended December 31, 2001 was $5,060.6 million compared with $5,235.0 million for the same period in 2000, a decrease of 3.3%. MidAmerican Energy operating revenue increased for the year ended December 31, 2001 to $2,752.5 million from $2,576.9 million for the same period in 2000, primarily due to increases in volumes of non-regulated gas sold and increases in volumes and prices on off-system electricity sales. CE Electric UK operating revenue decreased for the year ended December 31, 2001 to $1,444.0 million from $1,997.9 million for the same period in 2000, primarily due to the Northern Electric/Yorkshire Electricity swap and changes in foreign exchange rates. The supply business that was sold is generally a high volume business that tends to operate at lower profitability levels than the distribution business. The remaining increase primarily relates to the increase of revenue at HomeServices due to acquisitions and the inclusion of a joint venture which was previously accounted for as an equity investment and the commencement of operations of the Cordova project in June 2001. The following data represents sales from MidAmerican Energy:
YEAR ENDED DECEMBER 31, ----------------------- 2001 2000 ---------- ---------- Electricity Retail Sales (GWh) ............ 17,207 16,715 Electricity Wholesale Sales (GWh) ......... 7,755 6,941 Regulated and Non-Regulated Gas Supplied (Thousands of MMBtus) .................... 264,338 174,385
MidAmerican Energy electric retail sales increased for the year ended December 31, 2001 from the same period in 2000 due to the more extreme temperatures substantially offset by a decrease in non-weather related sales. Electric wholesale sales increased for the year ended December 31, 2001 from the same period in 2000 due to higher production at the Cooper and Neal power plants and favorable market conditions. Regulated and non-regulated gas supplied increased due principally to growth in the non-regulated markets for the year ended December 31, 2001 compared to the same period in 2000. The following data represents the supply and distribution operations in the United Kingdom:
YEAR ENDED DECEMBER 31, ----------------------- 2001 2000 ---------- ---------- Electricity Supplied (GWh) ................. 12,745 19,925 Gas Supplied (Thousands of MMBtus) ......... 40,738 51,035 Electricity Distributed (GWh) .............. 23,770 16,350
The decrease in electricity and gas supplied for the year ended December 31, 2001 is due to the sale of Northern Electric's electricity and gas supply business in September 2001. The increase in electricity distributed for the year ended December 31, 2001 was due to the addition of Yorkshire Electricity and changes in demand in the distribution area. Pro forma interest and other income for the year ended December 31, 2001 was $96.7 million compared with $114.4 million for the same period in 2000. The decrease was due primarily to reduced interest income and lower income from equity investments. The non-recurring gains in 2001 are comprised mainly of the pre-tax gain on the sale of Northern Electric's electricity and gas supply business of $196.7 million, the loss on the impairment of TPL of $58.8 million, the gain on the sale of Telephone Flat, a geothermal development project, of $20.7 million, the gain on the transfer of shares of Bali, an indirect wholly owned subsidiary of the Company, of $10.4 million, and the gain on the sale of Western States Geothermal Company, an indirect wholly owned subsidiary of the Company, of $9.8 million. The after-tax gains and (losses) for the sale of Northern Electric's electricity and gas supply business, the TPL impairment, the Telephone Flat sale, the transfer of the Bali shares, and the Western States Geothermal sale were $10.8 million, ($20.7) million, $12.2 million, $6.5 million and $6.4 million, respectively. 44 Pro forma cost of sales for the year ended December 31, 2001 was $2,705.0 million compared with $3,029.7 million for the same period in 2000, a decrease of 10.7%. The decrease relates primarily to decreased cost of sales at CE Electric UK due to the sale of Northern Electric's electricity and gas supply business, lower foreign exchange rates and lower electricity volumes and prices, partially offset by increased volumes and prices for both regulated and non-regulated gas at MidAmerican Energy, and acquisitions at HomeServices. Pro forma operating expenses for the year ended December 31, 2001 were $1,176.4 million compared with $1,123.6 million for the same period in 2000. The increase was primarily due to higher costs at HomeServices due to acquisitions and the inclusion of a joint venture which was previously accounted for as an equity investment and higher costs at MidAmerican Energy due to costs related to Cooper Nuclear Station, accounts receivable discounts and bad debts, partially offset by lower costs at CE Electric UK due to the sale of Northern Electric's electricity and gas supply business, lower pension costs and a lower exchange rate, partially offset by the addition of Yorkshire Electricity. Pro forma depreciation and amortization for the year ended December 31, 2001 was $538.7 million compared with $479.6 million for the same period in 2000. This increase was due to higher depreciation at MidAmerican Energy due to inclusion of an Iowa revenue sharing accrual and an increase in depreciation rates implemented in 2001 and amortization of intangible assets related to the HomeServices acquisitions, partially offset by lower depreciation at CE Electric UK due to lower amortization of operational assets and a lower exchange rate, partially offset by the addition of Yorkshire Electricity. Pro forma interest expense, less amounts capitalized, for the year ended December 31, 2001 was $412.8 million compared with $398.1 million for the same period in 2000, an increase of 3.7%. This increase is due to increased interest expense associated with the debt acquired with Yorkshire Electricity and lower capitalized interest on the mineral extraction process, partially offset by lower average outstanding debt balances and lower foreign exchange rates at Northern Electric. The loss on non-recurring items of $7.6 million in the period from January 1, 2000 through March 13, 2000 represents the costs incurred related to the Company's acquisition by a private investor group. Pro forma tax expense for the year ended December 31, 2001 was $250.1 million compared with $81.6 million for the same period in 2000. The increase is due primarily to the tax on the gain related to the sale of Northern Electric's electricity and gas supply business and higher pre-tax income. Pro forma minority interest for the year ended December 31, 2001 was $106.5 million compared with $104.3 million for the same period in 2000. The increase is primarily due to increased minority interest at HomeServices. The cumulative effect of change in accounting principle of $4.6 million in 2001 represents the change in accounting for major maintenance and overhauls. Pro forma net income for the year ended December 31, 2001 was $142.7 million compared with $124.9 million for the same period in 2000. RESULTS OF OPERATIONS FOR THE PERIODS MARCH 14, 2000 THROUGH DECEMBER 31, 2000, JANUARY 1, 2000 THROUGH MARCH 13, 2000 AND FOR THE YEAR ENDED DECEMBER 31, 1999 The following is a discussion of the historical results of the Company for the period March 14, 2000 through December 31, 2000, and of MEHC (Predecessor) for the period January 1, 2000 through March 13, 2000, and for the year ended December 31, 1999. Results for the Company include the results of MEHC (Predecessor) beginning March 14, 2000, in conjunction with the Company's acquisition by a private investor group. The impact of the transaction is reflected in the Company's results of operations, predominately minority interest costs on issuance of Company-obligated mandatorily redeemable preferred securities of a subsidiary trust and the effects of purchase accounting, including goodwill amortization and fair value adjustments to the carrying value of assets and liabilities. In order to provide comparability between periods, the Company has prepared pro forma results as if the Company's acquisition by a private investor group and the MidAmerican Energy acquisition had occurred at the 45 beginning of each year after giving effect to pro forma adjustments related to the acquisitions, including the sales of the qualified facilities, the redemption of limited recourse notes, the redemption of the senior discount notes and the issuance of the 11% trust preferred securities. The discussion therefore will highlight any significant variances on a pro forma basis from the year ended December 31, 1999 to the year ended December 31, 2000. Pro forma operating revenue for the year ended December 31, 2000 was $5,235.0 million compared with $4,572.8 million for the same period in 1999, an increase of 14.5%. MidAmerican Energy operating revenue increased for the year ended December 31, 2000 to $2,576.9 million from $1,871.9 million for the same period in 1999, primarily due to increases in non-regulated gas sales and higher prices in regulated gas. CE Electric UK operating revenue decreased for the year ended December 31, 2000 to $1,997.9 million from $2,072.2 million for the same period in 1999, primarily due to lower volumes of electricity supplied in the franchise area and lower foreign exchange rates partially offset by higher volumes of electricity supplied out of the franchise area and distribution revenue from access charges. The remaining increase primarily related to the increase of revenue at HomeServices due to acquisitions in late 1999. The following data represents sales from MidAmerican Energy:
YEAR ENDED DECEMBER 31, ----------------------- 2000 1999 ---------- ---------- Electricity Retail Sales (GWh) ............ 16,715 16,007 Electricity Wholesale Sales (GWh) ......... 6,941 7,168 Regulated and Non-Regulated Gas Supplied (Thousands of MMBtus) .................... 174,385 138,387
MidAmerican Energy electricity retail sales increased for the year ended December 31, 2000 from the same period in 1999 due to increased customers and non-weather related sales partially offset by more moderate temperatures. Electricity wholesale sales decreased for the year ended December 31, 2000 from the same period in 1999 due to a lower power plant output primarily from the Cooper Nuclear Station which results in lower energy available for resale. Gas supplied increased due to an increase in customers, an increase in heating degree days and an increase in trading activity of non-regulated sales. The following data represents the supply and distribution operations in the United Kingdom:
YEAR ENDED DECEMBER 31, ---------------------- 2000 1999 ---------- --------- Electricity Supplied (GWh) ................. 19,925 17,984 Electricity Distributed (GWh) .............. 16,350 15,943 Gas Supplied (Thousands of MMBtus) ......... 51,035 48,435
The increase in electricity supplied for the year ended December 31, 2000 was due primarily to the increase in volumes for customers outside of the franchise area. The increase in electricity distributed for the year ended December 31, 2000 was due to changes in demand in the franchise area. The increase in gas supplied in 2000 from 1999 reflected higher volume in the industrial and commercial markets. Pro forma interest and other income for the year ended December 31, 2000 was $114.4 million compared with $145.4 million for the same period in 1999. The decrease was due primarily to the reduced interest income resulting from lower cash balances, lower dividends from TPL and gains on other asset sales in 1999, partially offset by proceeds of Company-owned life insurance of $7.5 million received in 2000. The 1999 gain on non-recurring items resulted from the sale of approximately 6.74 million shares of McLeodUSA Class A common stock, through a secondary offering by McLeodUSA, at $55.625 per share. Proceeds from the sale exceeded $375 million, with a resulting after-tax gain to the Company of approximately $47.1 million. 46 As a result of the sales of the Coso Joint Ventures geothermal projects previously owned by the Company, and an interest in CE Gen, the Company recorded a gain of $20.2 million in the first quarter of 1999. In the fourth quarter of 1999, the Company recorded a pre-tax gain of $40.3 million relating to insurance proceeds received from an arbitration settlement between Himpurna California Energy Ltd. and Patuha Power Ltd., former subsidiaries of the Company, and P.T. PLN (Persero), an Indonesian national electric utility. Pro forma cost of sales for the year ended December 31, 2000 was $3,029.7 million compared with $2,398.6 million for the same period in 1999, an increase of 26.3%. The increase related to increased sales at MidAmerican Energy and HomeServices. Pro forma operating expense for the year ended December 31, 2000 was $1,123.6 million compared with $1,115.8 million for the same period in 1999. The increase primarily relates to the increase of operating expenses at HomeServices due to acquisitions in late 1999. Pro forma depreciation and amortization for the year ended December 31, 2000 was $479.6 million compared with $462.0 million for the same period in 1999. The increase was primarily due to higher depreciation at CE Electric UK primarily due to higher production at CE Gas Holdings, the Company's United Kingdom gas exploration subsidiary. Pro forma interest expense, less amounts capitalized, for the year ended December 31, 2000 was $398.1 million compared with $447.0 million for the same period in 1999, a decrease of 10.9%. This decrease was due to the repayment of the 9.5% Senior Notes in 1999 and other reduced indebtedness and an increase in capitalized interest related to the construction of the Casecnan, Cordova and Zinc projects. The loss on non-recurring items of $7.6 million in the period from January 1, 2000 through March 13, 2000 represents the costs related to the Company's acquisition by a private investor group. Pro forma tax expense for the year ended December 31, 2000 was $81.6 million compared with $89.4 million for the same period in 1999. The decrease was due primarily to lower pretax income in 2000. Pro forma minority interest for the year ended December 31, 2000 was $104.3 million compared with $101.9 million for the same period in 1999. Minority interest included the dividends on the $455 million of Company-obligated mandatorily redeemable preferred securities of subsidiary trusts. Pro forma net income for the year ended December 31, 2000 was $124.9 million compared with $138.3 million for the same period in 1999. LIQUIDITY AND CAPITAL RESOURCES The Company has available a variety of sources of liquidity and capital resources, both internal and external. These resources provide funds required for current operations, construction expenditures, debt retirement and other capital requirements. The Company may from time to time seek to retire its outstanding debt through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. The Company's cash and cash equivalents were $662 million at September 30, 2002, compared to $387 million at December 31, 2001. Each of the Company's direct or indirect subsidiaries is organized as a legal entity separate and apart from the Company and its other subsidiaries. Pursuant to separate financing agreements at each subsidiary, the assets of each subsidiary may be pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should not be assumed that any asset of any subsidiary of the Company will be available to satisfy the obligations of the Company or any of its other subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to the Company or affiliates thereof. 47 The Company generated cash flows from operations of $683 million for the nine months ended September 30, 2002, compared with $791 million for the same period in 2001. The decrease was primarily due to timing of changes in working capital activities, partially offset by positive impacts of the Kern River and real estate companies acquisitions. The remaining increase to cash and cash equivalents is primarily due to the issuances of convertible preferred stock, trust preferred securities and subsidiary and project debt and cash proceeds from sale of assets, partially offset by the Kern River and Northern Natural Gas acquisitions, purchase of convertible preferred securities, repayment of subsidiary and project debt and capital expenditures for operating and construction projects. In addition, the Company recorded separately restricted cash and investments of $63.9 million and $54.8 million at September 30, 2002, and December 31, 2001, respectively. The restricted cash balance as of September 30, 2002, is comprised primarily of amounts deposited in restricted accounts which is reserved for the service of debt obligations. OTHER INVESTMENTS On March 27, 2002, a newly formed subsidiary of the Company invested $275 million in Williams in exchange for shares of 97/8% cumulative convertible preferred stock of Williams. In connection with this investment, the Company issued $275 million of no par, zero coupon convertible preferred stock to Berkshire Hathaway. Dividends on the Williams' preferred stock are scheduled to be received quarterly, and commenced on July 1, 2002. This investment is accounted for under the cost method. The Company is aware that there have been public announcements that Williams' financial condition has deteriorated as a result of, among other factors, reduced liquidity. The Company had not recorded an impairment on this investment as of September 30, 2002, and is monitoring the situation. DEBT ISSUANCES AND REDEMPTIONS On February 8, 2002, MidAmerican Energy issued $400 million of 6.75% medium-term notes due in 2031. The proceeds were used to refinance existing debt and preferred securities and for other corporate purposes. On March 11, 2002, MidAmerican Energy redeemed all $100 million of its 7.98% MidAmerican Energy-obligated preferred securities of a subsidiary trust at 100% of the principal amount plus accrued interest. On May 1, 2002, MidAmerican Energy reacquired all $26.7 million of its $7.80 series of preferred securities. Of this amount, $13.3 million of preferred securities were redeemed at 100% of the principal amount plus accrued dividends, and the remaining $13.4 million was redeemed at 103.9% of the principal amount plus accrued dividends. On June 21, 2002, Kern River closed on a bank loan facility providing for aggregate loans of up to $875 million to be used for the construction of the Kern River 2003 Expansion Project. The facility, which matures 15 years after the 2003 Expansion Project commences operation, has a variable interest rate which increases over the term of the facility from 1.375% to 4.5% over LIBOR. Kern River had drawn $385 million on this facility as of September 30, 2002. In connection with this facility, the Company guaranteed the completion of the 2003 Expansion Project as described below in "Kern River's 2003 Expansion Project Financing." On March 1, 2001, MidAmerican Funding, LLC retired $200 million of 5.85% senior secured notes due 2001. On March 19, 2001, MidAmerican Funding, LLC issued $200 million of 6.75% senior secured notes due March 1, 2011. YORKSHIRE ELECTRICITY In August 2002, CE Electric UK Funding acquired the remaining 5.25% of Yorkshire Electricity that it did not already own from Xcel Energy International, an affiliate of Xcel Energy Inc., for $33.3 million. 48 REAL ESTATE COMPANIES 2002 ACQUISITIONS In 2002, HomeServices separately acquired three real estate companies for an aggregate purchase price of approximately $100.0 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2001, these real estate companies had combined revenue of approximately $356.0 million on 42,000 closed sides representing $13.7 billion of sales volume. Additionally, HomeServices is obligated to pay a maximum earnout of $18.5 million calculated based on 2002 financial performance measures. These purchases were financed using HomeServices' $65.0 million revolving credit facility and the Company's corporate revolver for $40.0 million, which was contributed to HomeServices as equity. The Company is in the process of completing the allocation of the purchase prices to the assets and liabilities acquired. CALENERGY GAS HOLDING DISPOSAL In May 2002, CE Gas Holdings, an indirect wholly owned subsidiary of the Company, completed the sale of several of its U.K. natural gas assets to Gaz de France for (pounds sterling)137.0 million (approximately $200.0 million). CE Gas Holdings sold four natural gas-producing fields located in the southern basin of the U.K. North Sea including Anglia, Johnston, Schooner and Windermere. The transaction also included the sale of rights in four gas fields in development and construction and three exploration blocks owned by CE Gas Holdings. ACCOUNTS RECEIVABLE SOLD In 1997, MidAmerican Energy entered into a revolving agreement, which expired on October 29, 2002, to sell all of its right, title and interest in the majority of its billed accounts receivable to MidAmerican Energy Funding Corporation, a special purpose entity established to purchase accounts receivable from MidAmerican Energy. MidAmerican Energy Funding Corporation in turn sold receivable interests to outside investors. In consideration for the sale, MidAmerican Energy received cash and a subordinated note, bearing interest at 8%, from MidAmerican Energy Funding Corporation. As of September 30, 2002, the revolving cash balance was $36.0 million and the amount outstanding under the subordinated note was $89.2 million. The agreement was structured as a true sale, under which the creditors of MidAmerican Energy Funding Corporation were entitled to be satisfied out of the assets of MidAmerican Energy Funding Corporation prior to any value being returned to MidAmerican Energy or its creditors. Therefore, the accounts receivable sold are not reflected on the Company's consolidated balance sheets. As of September 30, 2002, $126.0 million of accounts receivable, net of reserves, were sold under the agreement. MidAmerican Energy did not extend or replace this agreement. CONSTRUCTION MIDAMERICAN ENERGY MidAmerican Energy's primary need for capital is for utility construction expenditures. For the first nine months of 2002, utility construction expenditures totaled $228.8 million, including allowance for funds used during construction, or capitalized financing costs, and Quad Cities Station nuclear fuel purchases. All such expenditures were met with cash generated from utility operations. Forecasted MidAmerican Energy utility construction expenditures, including allowances for funds used during construction are $382.0 million for 2002 and $1.614 billion for 2003 through 2006. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. MidAmerican Energy has announced plans to construct an electric generating plant, the Greater Des Moines Energy Center, in Iowa. The plant will provide service to regulated retail electricity customers and be included in MidAmerican Energy's regulated rate base in Iowa, Illinois and South Dakota. Wholesale sales may also be made from the plant to the extent the power is not needed for regulated retail service. The plant will be a 540 MW (500 MW based on expected accreditation) natural gas-fired plant with an estimated cost of $415.0 million. MidAmerican Energy will own 100% of the plant and will operate it. The 49 plant will be operated in simple cycle mode during 2003 and 2004, with combined cycle operation commencing in 2005. MidAmerican Energy commenced construction of the plant in 2002 following receipt of two orders from the IUB. The first order authorized construction of the plant. The second order, issued May 29, 2002, specified the principles that will apply to the plant over its life for purposes of Iowa ratemaking and was sought by MidAmerican Energy to limit regulatory risk. MidAmerican Energy presently expects that all utility construction expenditures through 2007 will be met with the issuance of long-term debt and cash generated from utility operations, net of dividends. The actual level of cash generated from utility operations is affected by, among other things, economic conditions in the utility service territory, weather and federal and state legislation and regulatory actions. KERN RIVER'S 2003 EXPANSION PROJECT FINANCING On July 17, 2002, Kern River received approval from the FERC to construct, own and operate the 2003 Expansion Project. The 2003 Expansion Project will loop most of Kern River's existing mainline, construct three new compressor stations and upgrade or modify Kern River's six existing compressor stations. The 2003 Expansion Project, which is expected to be completed and operational by May 2003, will increase Kern River's capacity by approximately 900mmcf/day. Service will be provided under long-term contracts subject to incremental rates. The estimated cost of the expansion is approximately $1.2 billion, which will be financed with 70% debt and 30% equity, consistent with Kern River's existing capital structure, the application for the FERC approval described above and the limitations contained in the indenture for Kern River's existing secured senior notes. Construction will initially be funded with the proceeds of an $875.0 million credit facility entered into by Kern River on June 21, 2002, until 70% of the projected capitalized costs of the 2003 Expansion Project has been spent. The final 30% of the capitalized costs of the 2003 Expansion Project will be funded with equity from the Company. The credit facility is structured as a two-year construction facility followed by a term loan with a final maturity 15 years after completion of the 2003 Expansion Project. However, Kern River presently intends to refinance the credit facility through a bond offering or other capital markets transaction following completion of the 2003 Expansion Project. Prior to completion of the 2003 Expansion Project, the credit facility lenders will have limited recourse to Kern River and its assets and cash flow, and will have recourse to the Company's completion guarantee described below. Following completion of the 2003 Expansion Project, until such time as the Kern River credit facility is refinanced, the lenders under the credit facility will share equally and ratably with the existing Kern River senior secured noteholders in all of the collateral pledged to such senior secured noteholders. Pursuant to the Company's completion guarantee, it has guaranteed that "completion" of the 2003 Expansion Project will occur on or prior to the earliest of any abandonment by Kern River of the project, the occurrence of certain other acceleration events and June 30, 2004. The potential acceleration events include any downgrading of the Company's public debt rating to below investment grade by either S&P or Moody's unless a satisfactory substitute guarantor assumes the Company's obligations under the completion guarantee within 60 days after any such downgrade; Berkshire Hathaway ceasing to own at least a majority of the outstanding capital stock of the Company; and certain other customary events of default by the Company. In the completion guarantee, the Company has also agreed to cause capital contributions to be made to Kern River in a minimum aggregate amount of at least $375 million by June 30, 2004 or upon any earlier event of abandonment of the project. For purposes of the Company's completion guarantee, the term "completion" is defined in the Kern River credit agreement to mean satisfaction of a number of conditions, the most significant of which include the requirements that the 2003 Expansion Project be substantially complete and operable and able to permit Kern River to perform its obligations under all of the long-term firm gas transportation service agreements entered into in connection with the 2003 Expansion Project; that the shippers under such agreements shall have begun to incur the obligation to pay reservation fees thereunder; and that the FERC shall have authorized Kern River to begin collecting rates under its tariff and its shipper agreements; provided that the 2003 Expansion Project shall still be deemed to have been completed if it is less than substantially complete but it demonstrates at least 80% design capacity and Kern River's debt service coverage ratios as defined in its senior secured note indenture are not less than 1:55 to 1:0. There are a number of other conditions to 50 completion, including requirements that all conditions to completion of the expansion contained in Kern River's senior secured note indenture be satisfied and all of Kern River's obligations under its credit agreement then share pari passu in all collateral available to Kern River's senior secured noteholders. The Company's completion guarantee shall terminate upon the earlier of completion of the 2003 Expansion Project or repayment in full of all obligations under the Kern River credit facility. ZINC RECOVERY PROJECT CalEnergy Minerals LLC, our indirect wholly owned subsidiary, is constructing the Zinc Recovery Project. The Zinc Recovery Project is designed to have a capacity of approximately 30,000 metric tons per year, and commenced initial commercial operations in 2002. We expect the Zinc Recovery Project to be at 100% production in mid-2003. Total project costs of the Zinc Recovery Project are expected to be approximately $244.0 million, net of settlement proceeds from a dispute with the contractor, which is being funded by $140.5 million of debt and the balance from funds provided by the Company. The Zinc Recovery Project has incurred $213.9 million, net of settlement proceeds from a dispute with the contractor, of such costs through September 30, 2002. DEVELOPMENT ACTIVITY MidAmerican Energy has announced plans to develop a 750 MW super-critical-temperature, coal-fired plant fueled with Powder River low-sulfur coal in Pottawattamie County, Iowa. If constructed, MidAmerican Energy will operate the plant and expects to own 450 MW of the plant. Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large baseload plants in Iowa. MidAmerican Energy's investment in the plant is projected to be approximately $785.0 million, including the cost of related transmission facilities, taxes and allowance for funds used during construction. The plant will provide service to regulated customers and be included in MidAmerican Energy's regulated rate base in Iowa, Illinois and South Dakota. Wholesale sales may also be made from the plant to the extent the power is not needed for regulated retail service. MidAmerican Energy has made a filing with the IUB for a certificate to construct this plant and has made a filing with the IUB for approval of ratemaking principles for this plant during the fourth quarter of 2002. The development of this plant is subject to obtaining environmental and other required permits, as well as to receiving orders from the IUB approving construction of the plant and associated transmission facilities and establishing ratemaking principles which are satisfactory to MidAmerican Energy. The Company's subsidiary, Fox Energy Company LLC, is developing a 635 net MW gas fired power generating facility in Kaukanna, Outagamie County, Wisconsin. A subsidiary of TransAlta Corporation has agreed to participate in the development of this project at a level of 50% and has an option to own 50% of the project. The Company's subsidiary, CE Obsidian Energy LLC, or Obsidian, is developing a 185 net MW geothermal facility in Imperial Valley, California, known as Salton Sea VI. An affiliate of El Paso Corporation, or El Paso, has elected to participate in the ownership and development of this project at a level of 50%. The Company is actively seeking to develop, construct, own and operate additional new energy projects, both domestically and internationally, the completion of any of which is subject to substantial risk. Development can require the Company to expend significant sums for preliminary engineering, permitting, fuel supply, resource exploration, legal and other expenses in preparation for competitive bids which the Company may not win or before it can be determined whether a project is feasible, economically attractive or capable of being financed. Successful development and construction is contingent upon, among other things, negotiation on terms satisfactory to the Company of engineering, construction, fuel supply, sales contracts and, if the Company intends to own less than 100% of the project, joint venture or similar agreements, with other project participants, receipt of required governmental permits and consents and timely implementation of construction. There can be no assurance that development efforts on any particular project, or the Company's development efforts generally, will be successful. See "Risk Factors." 51 COOPER NUCLEAR STATION CONTRACT RESTRUCTURING On July 31, 2002, MidAmerican Energy and the NPPD signed an agreement on the restructuring of the power purchase contract for Cooper Nuclear Station. Under the terms of the restructured contract, MidAmerican Energy will pay NPPD through December 31, 2004, a scheduled amount per unit for 380 MW of the accredited capacity of Cooper Nuclear Station and a minimum of approximately 1.2 million MWh in the last five months of 2002 and approximately 2.5 million MWh in each of 2003 and 2004. NPPD also paid MidAmerican Energy $39.1 million on August 1, 2002. In December 2000, MidAmerican Energy ceased contributing decommissioning funds to NPPD and maintained a separate fund for estimated Cooper Nuclear Station decommissioning costs. Through July 31, 2002, $18.3 million had been accrued and retained by MidAmerican Energy in this separate fund. In conjunction with the power purchase contract restructuring, MidAmerican Energy is recognizing the $39.1 million cash payment and the $18.3 million previously accrued for decommissioning into income based on the estimated energy expected to be received for the remainder of the contract. Finally, both parties agreed to release each other from any and all claims, past or present, each might have under the power purchase contract prior to being restructured and file to dismiss the litigation currently pending in U.S. District Court. Under the terms of MidAmerican Energy's power purchase contract with NPPD prior to its restructuring, MidAmerican Energy paid NPPD one-half of the fixed and operating costs of Cooper Nuclear Station, excluding depreciation but including debt service, and MidAmerican Energy's share of the nuclear fuel cost, including Department of Energy disposal fees, based on energy delivered. In addition, prior to December 2000, MidAmerican Energy contributed toward payment of one-half of Cooper Nuclear Station's project decommissioning costs based on an assumed 2004 shutdown of the plant. These obligations ceased pursuant to the restructuring of the power purchase contract for Cooper Nuclear Station. OBLIGATIONS AND COMMITMENTS The Company has contractual obligations and commercial commitments that may affect its financial condition. Based on management's assessment of the underlying provisions and circumstances of the material contractual obligations and commercial commitments of the Company, including material off-balance sheet and structured finance arrangements, there is no known trend, demand, commitment, event or uncertainty that is reasonably likely to occur which would have a material effect on the Company's financial condition or results of operations. The following tables identify material obligations and commitments as of December 31, 2001:
PERIOD PAYMENTS ARE DUE ---------------------------------------------------------------------- TOTAL 2002 2003-2004 2005-2006 AFTER 2006 CONTRACTUAL CASH OBLIGATIONS (IN MILLIONS) ------------- ---------- ----------- ----------- ------------- Parent company long-term debt (1) ................. $ 1,850.0 $ -- $ 215.0 $ 260.0 $ 1,375.0 Subsidiary and project debt (1) ................... 5,078.3 317.2 571.6 620.9 3,568.6 Company-obligated mandatorily redeemable preferred securities of subsidiary trusts ........ 880.3 -- -- 136.4 743.9 Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts (2)..... 100.0 100.0 -- -- -- Mandatorily redeemable preferred securities of subsidiaries .................................. 26.7 6.7 13.3 6.7 -- Power purchase contract (3) ....................... 25.9 17.4 8.5 -- -- Coal, electricity and natural gas contract commitments (4) .................................. 479.4 163.9 207.3 67.9 40.3 Operating leases (4) .............................. 135.6 31.2 46.7 24.2 33.5 ---------- ------ --------- --------- ---------- Total ............................................ $ 8,576.2 $ 636.4 $ 1,062.4 $ 1,116.1 $ 5,761.3 ========== ======= ========= ========= ==========
---------- (1) Excludes unamortized debt premiums and discounts. (2) These subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts were redeemed on March 11, 2002. 52 (3) This liability was eliminated with the execution of the Settlement Agreement and Release related to the restructured Cooper Nuclear Station power purchase agreement effective August 1, 2002. (4) The fuel and energy commitments and operating leases are not reflected on the consolidated balance sheets.
COMMITMENT EXPIRATION PER PERIOD ------------------------------------------------------------------ TOTAL 2002 2003-2004 2005-2006 AFTER 2006 OTHER COMMERCIAL COMMITMENTS (IN MILLIONS) ----------- ---------- ----------- ----------- ----------- Unused parent company revolving lines of credit ........................................ $ 200.7 $ 86.5 $ 114.2 $ -- $ -- Parent company letters of credit ............... 45.8 -- 45.8 -- -- Unused subsidiary lines of credit .............. 541.8 511.3 30.5 -- -- Parent company guarantee of subsidiary debt..... 176.9 2.1 3.2 3.6 168.0 Subsidiary lines of credit from parent company ....................................... 10.0 -- -- -- 10.0 -------- ------- -------- ---- ------ Total ......................................... $ 975.7 $ 599.9 $ 193.7 $ 3.6 $ 178.0 ======== ======= ======== ===== =======
As of September 30, 2002, Northern Natural Gas had $13.8 million of obligations to deliver 4.0 Bcf of natural gas in 2002 and $46.0 million of obligations to deliver 12.2 Bcf of natural gas in 2003. The obligations are revalued based on market prices for natural gas, with changes in value included in the statement of operations. In 2002, Northern Natural Gas entered into natural gas commodity price swaps and index basis swaps to effectively fix the deferred obligation balance. Any further changes in the market value of the deferred obligations will be offset by a corresponding change in the opposite direction in the market value of the swaps. Other than the delivery of natural gas issue described above, the issuance of Company-obligated mandatorily redeemable preferred securities of subsidiary trust in connection with the Northern Natural Gas and Kern River acquisitions as described in note 2 in the notes to the consolidated financial statements for the nine months ended September 30, 2002, and the issuance of long-term debt as described in note 8 in the notes to the consolidated financial statements for the nine months ended September 30, 2002, there have been no other material changes to the obligations and commitments as described in the Annual Report on Form 10-K for the year ended December 31, 2001. OFF-BALANCE SHEET ARRANGEMENTS The Company has certain investments that are accounted for under the equity method in accordance with GAAP. Accordingly, an amount is recorded on the Company's balance sheet as an equity investment and is increased or decreased for the Company's pro-rata share of earnings or losses, respectively, less any dividend distribution from such investments. As of September 30, 2002, the Company's investments which are accounted for under the equity method had an aggregate $1,060.2 million of debt and $70.3 million in outstanding letters of credit. As of September 30, 2002, the Company's pro-rata share of the debt was $524.9 million and was non-recourse to the Company, except for $138.8 million of such debt which the Company has guaranteed on the Salton Sea Funding Series F Bonds and which was included in the Company's consolidated balance sheet at September 30, 2002. (See note 8 to the notes to the consolidated financial statements for the year ended December 31, 2001 included in this prospectus for further discussion). The Company's pro-rata share of the outstanding letters of credit was $35.1 million as of September 30, 2002. The Company is generally not required to support the debt service obligations of these investments. However, default with respect to this non-recourse debt could result in a loss of invested equity. STANDARD ELECTRICITY MARKET DESIGN On July 31, 2002, the FERC issued a notice of proposed rulemaking with respect to Standard Market Design for the electric industry. The FERC has characterized the proposal as portending "sweeping changes" to the use and expansion of the interstate transmission and the wholesale bulk power systems in the United States. The proposal includes numerous proposed changes to the current regulation of 53 transmission and generation facilities designed "to promote economic efficiency" and replace the "obsolete patchwork we have today," according to the FERC Chairman. The final rule, if adopted as currently proposed, would require all public utilities operating transmission facilities subject to the FERC jurisdiction to file revised open access transmission tariffs that would require changes to the basic services these public utilities currently provide. The proposed rule may impact the pricing of MidAmerican Energy's electricity and transmission products. The FERC does not envision that a final rule will be fully implemented until September 30, 2004. The Company is still evaluating the proposed rule and the Company believes that the final rule could vary considerably from the initial proposal. Accordingly, the Company is presently unable to quantify the likely impact of the proposed rule on the Company and its subsidiaries. DOMESTIC GAS RATES MATTERS On March 15, 2002, MidAmerican Energy made a filing with the IUB requesting an increase in rates of approximately $26.6 million for its Iowa retail natural gas customers. As part of the filing, MidAmerican Energy requested an interim rate increase of approximately $20.4 million annually. On June 12, 2002, the IUB issued an order granting an interim rate increase of approximately $13.8 million annually, effective immediately and subject to refund with interest. On July 15, 2002, MidAmerican Energy and the Office of Consumer Advocate filed a proposed settlement agreement with the IUB. The settlement agreement, which was approved by the IUB on November 8, 2002, provides for an increase in rates of $17.7 million annually for MidAmerican Energy's Iowa retail natural gas customers and freezes such rates for two years after the date the IUB approves tariffs implementing the settlement agreement. MidAmerican Energy implemented the new rates effective November 25, 2002. PHILIPPINES REGULATORY MATTERS The Philippine Congress has passed the Electric Power Industry Reform Act of 2001, which is aimed at restructuring the Philippine power industry, privatization of the NPC and introduction of a competitive electricity market, among other initiatives. The implementation of the bill may have an impact on the Company's future operations in the Philippines and the Philippines power industry as a whole, the effect of which is not yet determinable and estimable. In connection with an interagency review of approximately 40 independent power project contracts in the Philippines, the Casecnan Project (along with four other unrelated projects) has reportedly been identified as raising legal and financial questions and, with those projects, has been prioritized for renegotiation. The Company's subsidiaries' Upper Mahiao, Malitbog, and Mahanagdong projects, which, together with the Casecnan Project, collectively referred to as the Philippine Projects, have also reportedly been identified as raising financial questions. No written report has yet been issued with respect to the interagency review, and the timing and nature of steps, if any, that the Philippine Government may take in this regard are not known. To the extent disputes arise under the Philippine Projects' agreements with respect to the Philippines Projects' obligations, rights and remedies thereunder, such disputes will be determined by international arbitration in a neutral forum conducted in accordance with the rules of the International Chamber of Commerce or UNCITRAL, as applicable. Representatives of CE Casecnan together with certain current and former Philippine government officials, also have been requested to appear, and have appeared, before a Philippine Senate committee which has independently raised questions and made allegations with respect to the Casecnan Project's tariff structure and implementation. No further hearings are scheduled at this time. UK PENSION LIABILITY Under the Electric Supply Pension Scheme retirement plan in the United Kingdom, subsidiaries of the Company provide defined benefits for eligible retired employees. SFAS 87 requires recognition of an additional minimum liability when the accumulated benefit obligation exceeds the fair value of the plan assets. Due to a decline in the fair value of plan assets, the Company anticipates recording a liability and a charge to other comprehensive income, net of tax, at December 31, 2002 of approximately $300 million. This amount is subject to estimates and fair values as of December 31, 2002 and will not be known until the first quarter of 2003. This charge will not impact net income or cash flow. 54 NEW ACCOUNTING PRONOUNCEMENTS AND REPORTING ISSUES In August 2001, the Financial Accounting Standards Board, or FASB, issued SFAS No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143 requires recognition on the balance sheet of legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of such assets. Additionally, at the time an asset retirement obligation, or ARO, is recognized, an ARO asset of the same amount is recorded and depreciated. This pronouncement is effective for fiscal years beginning after June 15, 2002. The Company is evaluating the impact that adoption of this standard will have on its consolidated financial statements. In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. The adoption of SFAS No. 144 on January 1, 2002, did not have any impact on the Company's consolidated financial statements. The Emerging Issues Task Force, or EITF, recently issued EITF Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under Issues No. 98-10 and 00-17." In accordance with EITF No. 02-3, all gains and losses on energy trading contracts must be reported net on the income statement, effective for reporting periods ending after July 15, 2002, with all prior periods presented being reclassified to a consistent presentation. MidAmerican Energy's nonregulated wholesale gas and electric marketing activities qualify as "energy trading" contracts under the guidance of EITF No. 98-10. In accordance with EITF Issue No. 02-3, effective September 30, 2002, for MidAmerican Energy, all trading revenues are reported net of the cost of such sales. Previously, such amounts were recorded gross. All prior periods have been reclassified to conform to the net presentation. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The Company is exposed to market risk, including changes in the market price of certain commodities and interest rates. To manage the price volatility relating to these exposures, the Company enters into various financial derivative instruments. Senior management provides the overall direction, structure, conduct and control of the Company's risk management activities, including the use of financial derivative instruments, authorization and communication of risk management policies and procedures, strategic hedging program guidelines, appropriate market and credit risk limits, and appropriate systems for recording, monitoring and reporting the results of transactional and risk management activities. During the nine months ended September 30, 2002, the Company issued long-term debt as described in note 8 of our notes to the consolidated financial statements for the nine months ended September 30, 2002 and assumed additional debt with the acquisitions of Northern Natural Gas and Kern River. However, the Company does not believe it has any material change in regard to exposure to interest rate risk. Refer to note 16 of our notes to the consolidated financial statements for the year ended December 31, 2001 included in this prospectus for discussion on derivatives used to hedge price risk. The Company's exposure to commodity price risk has not changed materially from December 31, 2001. 55 BUSINESS GENERAL MidAmerican Energy Holdings Company is a United States-based privately owned global energy company. Our subsidiaries' principal businesses are regulated electric and natural gas utilities, regulated interstate natural gas transmission and electric power generation. Our operations are organized on seven distinct platforms which we refer to as: MidAmerican Energy, Northern Natural Gas, Kern River, CE Electric UK (which includes Northern Electric and Yorkshire Electricity), CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and HomeServices. Through six of these platforms, we own and operate a combined electric and natural gas utility company in the United States, two natural gas pipeline companies in the United States, two electricity distribution companies in the United Kingdom, and a diversified portfolio of domestic and international independent power projects. We also own the second largest residential real estate brokerage firm in the United States. Financial information for each of our seven operating platforms is contained in note 22 to our consolidated financial statements for the year ended December 31, 2001 and note 14 to our consolidated financial statements for the nine month period ended September 30, 2002 included in this prospectus. Financial information for Kern River and Northern Natural Gas is included in note 14 to our consolidated financial statements for the nine month period ended September 30, 2002, from their respective dates of acquisition. Financial information for our utility platforms may differ from the amounts included in the notes to the financial statements due to the effects of fair value adjustments associated with our acquisition of these entities. The following is a chart of our operating platforms and the principal lines of business in which they are engaged: [GRAPHIC OMITTED]
+-------------------------+ | | | MidAmerican Energy | | Holdings Company | | | +-------------------------+ | | +------------------+----------------+--------------------+--------------------+-----------------+------------------+ | | | | | | | | | | | | | | +-------------+ +-------------+ +------------+ +----------------------+ +-------------+ +-------------+ +--------------+ | | | | | | | CE ELECTRIC UK | | CalEnergy | | CalEnergy | | | | MidAmerican | | Northern | | Kern River | +----------+-----------+ | Generation- | | Generation- | | HomeServices | | Energy | | Natural Gas | | | | Northern |Yorkshire | | Domestic | | Foreign | | | | | | | | | | Electric |Electricity| | | | | | | +-------------+ +-------------+ +------------+ +----------+-----------+ +-------------+ +-------------+ +--------------+ Regulated gas Regulated natural Regulated natural Regulated Non-utility Non-utility Real estate and electric gas transmission gas transmission electricity power generation power generation brokerage and utility distribution related services
Our senior unsecured obligations have received investment grade ratings of Baa3, BBB- and BBB from Moody's Investors Service Inc., Standard & Poors Ratings Services and Fitch, Inc., respectively. Our utility subsidiaries also have investment grade ratings by Moody's, S&P and Fitch, respectively: MidAmerican Energy (A3, A- and A-), Northern Natural Gas (Baa2, A- and BBB+), Kern River (A3, A- and A-), Northern Electric (A3, A- and A) and Yorkshire Electricity (A3, A- and A), respectively. However, these ratings are subject to change. We initially incorporated in 1971 under the laws of the State of Delaware. We were reincorporated in 1999 in Iowa, at which time we changed our name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company. STRATEGY Our business strategy is focused upon the successful operation, management and growth of our diversified portfolio of energy assets and on the pursuit of strategic utility acquisitions and selected other investment opportunities, principally in the United States. As a privately owned company, we are able to focus on long-term risk-adjusted cash flow returns from our businesses. We seek to manage and operate our energy assets such that their cost structure makes us a low-cost provider of energy and energy services. 56 In order to implement this strategy, we plan to: PURSUE OPERATING EFFICIENCIES AND INTERNAL INVESTMENT OPPORTUNITIES IN OUR BUSINESSES, WHILE MAINTAINING QUALITY AND RELIABILITY OF SERVICE. Our management philosophy emphasizes the efficient operation of our businesses through strict attention to the operational performance of our assets, continuous review and implementation of cost reduction initiatives and the active pursuit of opportunities to earn reasonable returns by making incremental capital investments within our existing operations. Following each of our utility acquisitions, we have implemented operational improvements and cost reductions that have enhanced asset performance and service reliability. These and other initiatives have helped us to pursue our goal of being a low-cost provider of energy and energy services to our customers and have strengthened our competitive position in the marketplace, while also increasing the returns on our investments. In addition, we have worked closely and successfully with customers and with regulatory and legislative authorities to ensure that our business initiatives are consistent with our obligations to serve customers and with the requirements of the regulatory regimes under which we operate. We have identified and are proceeding with a number of significant capital investment opportunities that we believe offer attractive risk-adjusted returns. These opportunities include a $1.2 billion program to expand MidAmerican Energy's base of electric generation facilities in Iowa and a $1.2 billion investment in Kern River's 2003 Expansion Project. GROW AND DIVERSIFY THROUGH ACQUISITIONS OF HIGH QUALITY REGULATED UTILITY BUSINESSES. We believe that well managed regulated utility businesses can provide a stable cash flow profile and a reasonable risk-adjusted equity return to their owners. Our acquisitions of Northern Electric in 1997 and MidAmerican Energy in 1999 provided us with specialized skills and expertise, particularly in operations and regulatory affairs, which have enhanced our competitive position and positioned us favorably for future growth in our targeted sectors. In the past fifteen months, we completed three acquisitions of utility operating companies, Yorkshire Electricity, Kern River and Northern Natural Gas, each of which has added substantially to our base of utility operating assets and cash flows. We believe that these acquisitions helped us achieve additional diversification of our utility business with respect to sources of cash flow, types of utility operations, geography and regulatory regimes. CAPITALIZE ON CHANGE IN OUR INDUSTRY AND ON OUR SUPERIOR ACCESS TO CAPITAL IN ORDER TO MAKE ATTRACTIVE INVESTMENTS. The global energy markets, particularly those in the United States, are experiencing a period of significant change due to various factors, including the macroeconomic environment, fluctuating commodity prices, regulatory and legislative developments and financial restructurings by many market participants. We and our shareholders believe that such an environment provides opportunities for disciplined companies with access to investment capital to achieve reasonable risk-adjusted returns by acquiring high quality companies and assets at reasonable prices. Warren Buffett, Chairman of the Board and Chief Executive Officer of Berkshire Hathaway, has publicly stated that we are a core holding of Berkshire Hathaway and are expected to be its principal vehicle for investments in the energy sector. In 2002 to date, we completed two acquisitions of interstate natural gas transmission pipelines, which we funded with a majority of the proceeds of Berkshire Hathaway's investment in $1.273 billion of our trust preferred securities and $402 million of our zero coupon convertible preferred stock, all of which is subordinated to our senior indebtedness. We believe that our ability to successfully negotiate and complete these acquisitions was facilitated by our access to capital from Berkshire Hathaway and that there continue to be opportunities in the current environment to make additional acquisitions that further enhance our business mix, risk profile, capitalization and investment returns. ENHANCE OUR INVESTMENT GRADE CREDIT PROFILE AND THAT OF OUR SUBSIDIARIES. Our financing strategy is focused on capitalizing and managing our utility subsidiaries in a manner consistent with maintenance of strong credit ratings, thereby supporting our credit profile with more predictable underlying cash flows from these subsidiaries. This strategy is driven by our belief that strong credit ratings allow us to minimize our financing costs over the long term and to optimize our investment returns, while also retaining the financial flexibility to pursue attractive capital investment opportunities as and when they are available. Our strategy is to finance our operating subsidiaries with debt that in almost all cases is non-recourse to us, which has allowed us to reduce financing costs by taking advantage of the stable, investment grade characteristics of our subsidiaries' utility assets. 57 MAINTAIN PRUDENT FINANCIAL AND RISK MANAGEMENT POLICIES AND PRACTICES. Through our focus on regulated utility businesses, we strive to minimize the underlying risks of our portfolio of assets. Substantially all of our net owned MW in our non-utility power generation business have long-term (greater than one year) contracts for the sale of their energy and/or capacity, and substantially all of these assets are financed by non-recourse project finance debt. We seek to limit our exposure to movements in the commodity prices of energy products and are not a significant trader of energy commodities. Our activities in the marketing and supply of energy to customers outside of our regulated customer base are not a material part of our business and are conducted pursuant to closely monitored risk management policies and practices that are intended to minimize our exposure to fluctuations in energy commodity prices and to counterparty credit risk. A core tenet of our acquisition and investment philosophy is that we will only pursue opportunities that meet our strict requirements for an acceptable risk profile and attractive potential cash flow returns. If we do not believe that such opportunities are available, we prefer to reduce our acquisition activities and focus on the optimization of our existing portfolio rather than pursue growth by accepting greater risks or inferior returns. MIDAMERICAN ENERGY MidAmerican Energy is the largest energy company headquartered in Iowa. MidAmerican Energy is principally engaged in the business of generating, transmitting, distributing and selling electric energy and in distributing, selling and transporting natural gas. MidAmerican Energy distributes electricity at retail in Iowa, Illinois and South Dakota. It also distributes natural gas at retail in Iowa, Illinois, South Dakota and Nebraska. MidAmerican Energy's utility operations are providing regulated retail electric service to approximately 678,000 customers and regulated retail natural gas service to approximately 653,000 customers. MidAmerican Energy also provides competitive natural gas service in several Midwestern states and competitive electric service in Illinois and Ohio. In addition to retail sales, MidAmerican Energy sells electric energy and natural gas to other utilities, marketers and municipalities outside of MidAmerican Energy's delivery system. These sales are referred to as wholesale sales. It also transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. MidAmerican Energy's electric and gas utility operations are conducted under franchises, certificates, permits and licenses obtained from state and local authorities. The franchises, with various expiration dates, are typically for 25-year terms. MidAmerican Energy has a residential, agricultural, commercial and diversified industrial customer group, in which no single industry or customer accounted for more than 4% of its total 2001 electric operating revenues or 4% of its total 2001 gas operating margin. Among the primary industries served by MidAmerican Energy are those which are concerned with food products, the manufacturing, processing and fabrication of primary metals, real estate, farm and other non-electrical machinery, and cement and gypsum products. For the nine months ended September 30, 2002, MidAmerican Energy derived approximately 67% of its gross operating revenues from its electric utility business, 28% from its gas utility business and 5% from its non-regulated business activities. For 2001, 2000 and 1999, the corresponding percentages were 56% electric, 37% gas and 7% non-regulated, 53% electric, 41% gas and 6% non-regulated and 67% electric, 32% gas and 1% non-regulated, respectively. The change in revenue mix is principally driven by changes in natural gas prices and seasonality. There are seasonal variations in MidAmerican Energy's electric and gas businesses, which are principally related to the use of energy for air conditioning and heating. In 2001, 38% of MidAmerican Energy's electric utility revenues were reported in the months of June, July, August and September, and 59% of MidAmerican Energy's gas utility revenues were reported in the months of January, February, March and December. ELECTRIC OPERATIONS The electric utility industry continues to undergo regulatory change. Traditionally, prices charged by electric utility companies have been regulated by federal and state commissions and have been based on 58 cost of service. In recent years, changes have been occurring that move the electric utility industry toward a more competitive, market-based pricing environment. These changes may have a significant impact on the way MidAmerican Energy does business. MidAmerican Energy manages its operations as four separate business units: generation, energy delivery, transmission, and marketing and sales. The generation segment derives most of its revenue from the sale of regulated wholesale electricity and non-regulated wholesale and retail natural gas. The energy delivery segment derives its revenue principally from the delivery of regulated electricity and natural gas, while the transmission segment obtains most of its revenue from the sale of transmission capacity. The marketing and sales segment receives its revenue principally from non-regulated sales of natural gas and electricity. For the year ended December 31, 2001, regulated electric sales by MidAmerican Energy by customer class were as follows: 20.6% were to residential customers, 15.3% were to small general service customers, 25.8% were to large general service customers, 7.3% were to other customers, and 31.0% were wholesale sales. For the year ended December 31, 2001, regulated electric sales by MidAmerican Energy by jurisdiction were as follows: 88.6% to Iowa, 10.6% to Illinois and 0.8% to South Dakota. The annual hourly peak demand on MidAmerican Energy's electric system occurs principally as a result of air conditioning use during the cooling season. In July 2002, MidAmerican Energy recorded an hourly peak demand of 3,887 MW, which is 54 MW greater than MidAmerican Energy's previous record hourly peak of 3,833 MW set in 1999. The following table sets out information concerning MidAmerican Energy's power generation facilities as of November 1, 2002:
FACILITY NET CAPACITY NET MW COMMERCIAL OPERATING PROJECT (1) (MW) (2) OWNED (2) FUEL LOCATION OPERATION ---------------------------------------------- ---------- ----------- --------- ---------- ----------- Council Bluffs Energy Center units 1 & 2 ..... 133 133 Coal Iowa 1954, 1958 Council Bluffs Energy Center unit 3 .......... 690 546 Coal Iowa 1978 Louisa Generation Station .................... 700 616 Coal Iowa 1983 Neal Generation Station units 1 & 2 .......... 435 435 Coal Iowa 1964, 1972 Neal Generation Station unit 3 ............... 515 371 Coal Iowa 1975 Neal Generation Station unit 4 ............... 624 261 Coal Iowa 1979 Ottumwa Generation Station ................... 708 368 Coal Iowa 1981 Quad Cities Generating Station ............... 1,636 409 Nuclear Illinois 1972 Riverside Generation Station ................. 135 135 Coal Iowa 1925-61 Combustion Turbines .......................... 785 785 Gas/Oil Iowa 1969-95 Moline Water Power ........................... 3 3 Hydro Illinois 1970 Portable Power Modules ....................... 56 56 Oil Iowa 2000 ----- --- Total Operating Power Generation Facilities .................................. 6,420 4,118 PROJECTS UNDER CONSTRUCTION: ---------------------------- Greater Des Moines Energy Center ............. 500 500 Gas Iowa 2003-05 ----- ----- Total Power Generation Facilities ............ 6,920 4,618 ===== =====
---------- (1) We operate all such power generation facilities other than Quad Cities Generating Station and Ottumwa Generation Station. (2) Represents accredited net generating capability. Actual MW may vary depending on operating conditions and plant design. Net MW owned indicates ownership of accredited capacity for the summer of 2002 as approved by the Mid-Continent Area Power Pool (MAPP). MidAmerican Energy's accredited net generating capability in the summer of 2002 was 4,724 MW, which included its 4,118 net MW owned and its accredited net MW capability pursuant to the restructured Cooper Nuclear Station power purchase agreement for a minimum guaranteed amount of energy from 59 any source and the Cordova power purchase agreement. Accredited net generating capability represents the amount of generation available to meet the requirements on MidAmerican Energy's energy system, including the net amount of capacity purchases less capacity sales from company-owned generation and generation under power purchase contracts. The net generating capability at any time may be less than it would otherwise be due to regulatory restrictions, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling or modifications. MidAmerican Energy has announced plans regarding two electric generating plants in Iowa. Both plants would provide service to regulated retail electricity customers and be included in regulated rate base in Iowa, Illinois and South Dakota. Wholesale sales may also be made from the plants to the extent the power is not needed for regulated retail service. The first plant, which is the Greater Des Moines Energy Center described above, will be a 540 MW (500 MW based on expected accreditation) natural gas-fired plant with an estimated cost of $415 million. MidAmerican Energy will own 100% of the plant and will operate it. The plant will be operated in simple cycle mode during 2003 and 2004, with combined cycle operation commencing in 2005. MidAmerican Energy commenced construction of the plant in 2002 following receipt of two orders from the IUB. The first order authorized construction of the plant. The second order, issued May 29, 2002, specified the principles that will apply to the plant over its life for purposes of Iowa ratemaking and was sought by MidAmerican Energy to limit regulatory risk. The second plant is currently under development and is expected to be a 750 MW super-critical-temperature, coal-fired plant fueled with Powder River low-sulfur coal in Pottawattamie County, Iowa. If constructed, MidAmerican Energy will operate the plant and expects to own 450 MW of the plant. Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large baseload plants in Iowa. MidAmerican Energy has made a filing with the IUB for a certificate to construct this plant and has made a filing with the IUB for approval of ratemaking principles for this second plant during the fourth quarter of 2002. The development of this plant is subject to obtaining environmental and other required permits, as well as to receiving orders from the IUB approving construction of the plant and associated transmission facilities and establishing ratemaking principles which are satisfactory to MidAmerican Energy. MidAmerican Energy presently expects that all utility construction expenditures through 2007 will be met with the issuance of long-term debt and cash generated from utility operations, net of dividends. The actual level of cash generated from utility operations is affected by, among other things, economic conditions in the utility service territory, weather and federal and state legislation and regulatory actions. MidAmerican Energy is interconnected with Iowa utilities and utilities in neighboring states and is involved in an electric power pooling agreement known as Mid-Continent Area Power Pool, or MAPP. MAPP is a voluntary association of electric utilities doing business in Minnesota, Nebraska, North Dakota and the Canadian provinces of Saskatchewan and Manitoba and portions of Iowa, Montana, South Dakota and Wisconsin. Its membership also includes power marketers, regulatory agencies and independent power producers. MAPP facilitates operation of the transmission system and is responsible for the safety and reliability of the bulk electric system. In November 2001, MAPPCOR, the contractor to MAPP, sold its transmission-related assets to the Midwest Independent Transmission System Operator, Inc., or Midwest ISO. The Midwest ISO now has responsibility for administration of MAPP's Open-Access Transmission Tariff. Each MAPP participant is required to maintain for emergency purposes a net generating capability reserve of at least 15% above its system peak demand. MidAmerican Energy's reserve margin at peak demand for 2002 was approximately 22%. However, significantly higher-than-normal temperatures during the cooling season could cause MidAmerican Energy's reserve to fall below the 15% minimum. If MidAmerican Energy fails to maintain the appropriate reserve, significant penalties could be contractually imposed by MAPP. MidAmerican Energy's transmission system connects its generating facilities with distribution substations and interconnects with 14 other transmission providers in Iowa and five adjacent states. Under 60 normal operating conditions, MidAmerican Energy's transmission system is unconstrained and has adequate capacity to deliver energy to MidAmerican Energy's distribution system and to export and import energy with other interconnected systems. In December 1999, the FERC issued Order No. 2000 establishing, among other things, minimum characteristics and functions for regional transmission organizations. Public utilities that were not a member of an independent system operator at the time of the order were required to submit a plan by which its transmission facilities would be transferred to a regional transmission organization. On September 28, 2001, MidAmerican Energy and five other electric utilities filed with the FERC a plan to create TRANSLink Transmission Company LLC, or TRANSLink, and to integrate their electric transmission systems into a single, coordinated system operating as a for-profit independent transmission company in conjunction with a FERC-approved regional transmission organization. On April 25, 2002, the FERC issued an order approving the transfer of control of MidAmerican Energy's and other utilities' transmission assets to TRANSLink in conjunction with TRANSLink's participation in the Midwest ISO. Additional state regulatory approval is required from states in which TRANSLink will be operating and those applications have not yet been filed. Once filed, MidAmerican Energy does not anticipate rulings in the state proceedings until some time in 2003. Transferring operation and control of MidAmerican Energy's transmission assets to other entities could increase costs for MidAmerican Energy; however, the actual impact of TRANSLink on MidAmerican Energy's future transmission costs is not yet known. GAS OPERATIONS For the year ended December 31, 2001, regulated gas sales by MidAmerican Energy, excluding transportation throughput, by customer class were as follows: 34.5% were to residential customers, 18.2% were to small general service customers, 1.5% were to large general service customers, 1.7% were to other customers, and 44.1% were wholesale sales. For the year ended December 31, 2001, regulated gas sales by MidAmerican Energy, excluding transportation throughput, by jurisdiction were as follows: 78.9% to Iowa, 10.5% to South Dakota, 9.8% to Illinois, and 0.8% to Nebraska. MidAmerican Energy purchases gas supplies from producers and third party marketers. To ensure system reliability, a geographically diverse supply portfolio with varying terms and contract conditions is utilized for the gas supplies. MidAmerican Energy has rights to firm pipeline capacity to transport gas to its service territory through direct interconnects to the pipeline systems of Northern Natural Gas, Natural Gas Pipeline Company of America, Northern Border Pipeline Company and ANR Pipeline Company. Firm capacity in excess of MidAmerican Energy's system needs, resulting from differences between the capacity portfolio and seasonal system demand, can be resold to other companies to achieve optimum use of the available capacity. Past IUB, and South Dakota Public Utilities Commission rulings have allowed MidAmerican Energy to retain 30% of Iowa and South Dakota margins, respectively, earned on the resold capacity, with the remaining 70% being returned to customers through a purchased gas adjustment clause as described below. MidAmerican Energy's cost of gas is recovered from customers through purchased gas adjustment clauses. In 1995, the IUB gave initial approval of MidAmerican Energy's Incentive Gas Supply Procurement Program. Under the program, as amended, MidAmerican Energy is required to file with the IUB every six months a comparison of its gas procurement costs to an index-based and historical reference price. If MidAmerican Energy's costs of gas for the period are less or greater than an established tolerance band around the reference price, then MidAmerican Energy shares a portion of the savings or costs with customers. In October 2002, the IUB approved a one year extension of the program through October 31, 2003. A similar program is currently in effect in South Dakota through October 31, 2005. Since the implementation of the program, MidAmerican Energy has successfully achieved and shared savings with its natural gas customers. MidAmerican Energy utilizes leased gas storage to meet peak day requirements and to manage the daily changes in demand due to changes in weather. The storage gas is typically replaced during the summer months. In addition, MidAmerican Energy also utilizes three liquefied natural gas plants and two propane-air plants to meet peak day demands. 61 MidAmerican Energy has strategically built multiple pipeline interconnections into several of its larger communities. Multiple pipeline interconnects create competition among pipeline suppliers for transportation capacity to serve those communities, thus reducing costs. In addition, multiple pipeline interconnects give MidAmerican Energy the ability to optimize delivery of the lowest cost supply from the various pipeline supply basins into these communities and increase delivery reliability. Benefits to MidAmerican Energy's system customers are shared with all jurisdictions through a consolidated purchased gas adjustment clause. NORTHERN NATURAL GAS COMPANY EXISTING FACILITIES AND BUSINESS Northern Natural Gas is one of the largest interstate natural gas pipeline systems in the United States. It reaches from Texas to Michigan's Upper Peninsula and is engaged in the transmission and storage of natural gas for utilities, municipalities, other pipeline companies, gas marketers, industrial and commercial users and other end users. Northern Natural Gas' revenues are derived from the interstate transportation and storage of natural gas for third parties. Except for small quantities of natural gas owned for system operations, Northern Natural Gas does not own the natural gas that is transported through its system. Northern Natural Gas' transportation and storage operations are subject to a FERC-regulated tariff that is designed to allow it an opportunity to recover its costs together with a regulated return on equity. Northern Natural Gas' system is comprised of two distinct areas, its traditional end-use and distribution market area at the northern end of the system, including delivery points in Michigan, Illinois, Iowa, Minnesota, Kansas, Nebraska, Wisconsin and South Dakota, which we refer to as the Market Area, and the natural gas supply and market area at the southern end of the system, including Kansas, Oklahoma, Texas and New Mexico, which we refer to as the Field Area. Northern Natural Gas' Field Area is interconnected with many interstate and intrastate pipelines in the national grid system. A majority of Northern Natural Gas' capacity in both the Market Area and the Field Area is dedicated to Market Area customers under long-term firm transportation contracts. Approximately 49% of Northern Natural Gas' capacity subject to firm transportation contracts is under contracts which extend beyond 2005. Northern Natural Gas' strategic plan is focused on taking advantage of the system's bi-directional and relatively flexible natural gas transportation capabilities and its storage assets to maximize economic returns. A key component of this strategic plan is to build upon Northern Natural Gas' asset base located in the center of the North American natural gas grid by increasing flexibility through additional pipeline interconnects. Through existing interconnections, Northern Natural Gas' shippers have supply access to Canadian, Rocky Mountain, Hugoton, Anadarko and Permian supplies. Northern Natural Gas also expects to pursue selective pipeline expansions, storage service enhancement and improved utilization of existing systems. In addition, Northern Natural Gas is focused on utilizing its ability to transport both dry natural gas and processable natural gas to take advantage of opportunities presented by natural gas processing facility consolidations in the Mid-continent. Northern Natural Gas expects to be able to meet the expected demand growth in its Market Area with only modest investment in new facilities as a result of the flexibility in Northern Natural Gas' system. Furthermore, Northern Natural Gas' access to supply diversity is expected to provide it with a significant competitive advantage because of the ability of the system to provide shippers access to many sources of low cost natural gas. Northern Natural Gas operates approximately 16,600 miles of natural gas pipelines which deliver approximately 5.0% of the total natural gas consumed in the United States. The Northern Natural Gas system is believed to be the largest in the United States as measured by pipeline miles and the eighth largest as measured by throughput. The pipeline system is powered by 92 transmission compressor stations with an aggregate of approximately 840,000 horsepower. Northern Natural Gas operates three natural gas storage facilities and two liquefied natural gas, or LNG, storage peaking units for a total storage capacity of 59 Bcf and peak delivery capability of over 1.3 Bcf/day. Northern Natural Gas' pipeline system is configured with approximately 3,500 receipt and delivery points (excluding farm taps) which are 62 integrated with the facilities of local distribution companies, or LDCs. Natural gas deliveries from Northern Natural Gas to the Market Area and Field Area totaled approximately 1.4 Tcf in 2001. The northern portion of Northern Natural Gas' pipeline system transports natural gas primarily to end-user and local distributor markets in the Market Area. Customers consist of LDCs, municipalities, other pipeline companies, gas marketers and end-users. While approximately ten large LDCs account for the majority of Market Area volumes, Northern Natural Gas also serves numerous small communities through these large LDCs as well as municipalities or smaller LDCs and directly serves several large end-users. In 2001, approximately 85% of Northern Natural Gas' revenues were from capacity charges under firm transportation and storage contracts and approximately 85% of those revenues were from LDCs. In 2001, approximately 69% of Northern Natural Gas' revenues were generated from Market Area customer contracts. The following customers, all of whom were utility LDCs located in the Market Area, each accounted for approximately 10% or more of Northern Natural Gas' transportation revenues for the year ended December 31, 2001: Reliant Energy Minnegasco (18%); UtiliCorp United Inc., now Aquila, Inc. (12%); Northern States Power Company--Minnesota (10%); and MidAmerican Energy (10%). As noted above, the Field Area of Northern Natural Gas' system provides access to natural gas supply from key production areas such as the Hugoton, Permian and Anadarko Basins. In each of these areas, Northern Natural Gas has numerous interconnecting receipt and delivery points, with volumes received in the Field Area consisting of both directly connected supply and volumes from interconnections with other pipeline systems. In addition, Northern Natural Gas has the ability to aggregate processable natural gas for deliveries to various gas processing facilities. In the Field Area, customers holding transportation capacity consist of LDCs, marketers, producers, and end-users. The majority of Northern Natural Gas' Field Area firm transportation is provided to Northern Natural Gas' Market Area firm customers under long-term firm transportation contracts with such volumes supplemented by volumes transported on an interruptible basis or pursuant to short-term firm contracts. In 2001, approximately 20% of Northern Natural Gas' revenues were generated from Field Area customer transportation contracts. Northern Natural Gas' system is characterized by significant seasonal swings in demand, which provide opportunities to deliver high value-added services. Because of its location and multiple interconnections with other interstate and intrastate pipelines, Northern Natural Gas is able to access natural gas both from traditional production areas, such as the Hugoton, Permian and Anadarko Basins, as well as growing supply areas such as the Rocky Mountains through Trailblazer Pipeline Company, Pony Express Pipeline and Colorado Interstate Gas Company, and from Canadian production areas through Northern Border Pipeline Company, Great Lakes Gas Transmission Limited Partnership and Viking Gas Transmission Company. As a result of Northern Natural Gas' geographic location in the middle of the United States and its many interconnections with other pipelines, Northern Natural Gas augments its steady end-user and LDC revenues by taking advantage of opportunities to provide intermediate transportation through pipeline interconnections for customers in other markets including Chicago, other parts of the Midwest, Texas and California. Northern Natural Gas' storage services are provided through the operation of three underground storage fields (one in Iowa and two in Kansas) and two LNG storage peaking units. The three underground natural gas storage facilities and Northern Natural Gas' two LNG storage peaking units have a total storage capacity of approximately 59 Bcf and over 1.3 Bcf/day of peak day deliverability. These storage facilities provide Northern Natural Gas with operational flexibility for daily balancing of its system and providing services to customers for meeting their year-round loadswing requirements. In 2001, approximately 11% of Northern Natural Gas' revenues were generated from storage services. COMPETITION Pipelines compete on the basis of cost, flexibility, reliability of service and overall customer service. Historically, Northern Natural Gas has been able to provide competitive cost service because of its access to a variety of low cost supply basins, its cost control measures and its relatively high load factor through-put, which lowers the cost per unit of transportation. Although Northern Natural Gas has 63 experienced pipeline system bypass affecting a small percentage of its market, to date Northern Natural Gas has been able to more than offset any load lost to bypass in the Market Area through expansion projects such as the Peak Day 2000 project (described below). Major competitors in the Market Area include ANR Pipeline Company and Natural Gas Pipeline Company of America. Other competitors include Northern Border Pipeline Company, Great Lakes Gas Transmission Limited Partnership and Viking Gas Transmission Company. In the Field Area, Northern Natural Gas competes with a large number of other competitors. Particularly in the Field Area, a significant amount of Northern Natural Gas' capacity is used on an interruptible or short-term basis. In summer months, Northern Natural Gas's Market Area customers often release significant amounts of their unused firm capacity to other shippers, which competes with Northern Natural Gas' short-term or interruptible services. Natural gas competes with other forms of energy, including electricity, coal and fuel oil, primarily on the basis of price. The price of natural gas is influenced by legislation and governmental regulations, the weather, the futures market, production costs, and other factors beyond the control of Northern Natural Gas. Industrial end-users often have the ability to choose from alternative fuel sources in addition to natural gas, such as fuel oil and coal. Northern Natural Gas attempts to maintain its competitive position through discounting transportation to keep delivered natural gas prices in line with prices for alternative fuels and by using flexible short-term and interruptible transportation services that are contracted for on an as needed basis. Northern Natural Gas believes that current and anticipated changes in its competitive environment have created opportunities to serve existing customers more efficiently and to meet certain growing supply needs. While LDCs provide peak day delivery growth driven by population growth and alternative fuel replacement, new off-peak demand growth is being driven primarily by power and ethanol plant expansion. Off-peak demand growth is important to Northern Natural Gas as this demand can generally be satisfied with little or no requirement for the construction of new facilities. Approximately 3,000 MW of natural gas-fired electric power plants in development have been announced in close proximity to Northern Natural Gas' system. Northern Natural Gas has been successful in competing for a significant amount of the increased demand related to the construction of new power and ethanol plants. Over the last five years, Northern Natural Gas has contracted approximately 528 mmcf/day of volume on its system from such new facilities, of which approximately 346 mmcf/day is currently in service and approximately 182 mmcf/day is scheduled to begin service between 2002 and 2005. PIPELINE EXPANSIONS Northern Natural Gas expects to continue evaluating potential additional pipeline expansions on an opportunistic basis. Northern Natural Gas recently completed the final year of its $110 million Peak Day 2000 Project. The Peak Day 2000 Project was designed to serve incremental load over a five-year period beginning in 1997. The Peak Day 2000 Project consists of pipeline expansion that added approximately 267 mmcf/day of capacity to serve a portion of the 528 mmcf/day of volume Northern Natural Gas has added to its system in the Market Area. Northern Natural Gas is currently negotiating precedent agreements with respect to an approximately $11 million Market Area expansion project, which we refer to as Project Max. Project Max is projected to provide Northern Natural Gas with an incremental 135 mmcf/day of capacity, primarily beginning service in 2003, including service to the MidAmerican Energy Greater Des Moines Energy Center that is currently under construction. Northern Natural Gas has a firm transportation service agreement with MidAmerican Energy to provide 96 mmcf/day of capacity to transport volumes to this plant. The plant is capable of taking up to 180 mmcf/day, all of which can be transported on Northern Natural Gas. OVERVIEW OF REGULATION AND CONTRACTS The FERC regulates Northern Natural Gas under the Natural Gas Act, the Natural Gas Policy Act of 1978 and other applicable statutes and regulations. The Natural Gas Act grants the FERC authority over the construction and operation of pipelines and related facilities utilized in the transportation, 64 storage and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. The FERC also has authority to regulate rates for natural gas in interstate commerce. Northern Natural Gas holds several Certificates of Public Convenience and Necessity issued by the FERC authorizing Northern Natural Gas to construct, operate and maintain its pipeline and related facilities and services and to transport and store natural gas in interstate commerce. Northern Natural Gas' rates and terms and conditions of service are regulated by the FERC. FERC regulations and Northern Natural Gas' tariff allow Northern Natural Gas to charge up to maximum approved rates for particular services as set forth in its tariff. Northern Natural Gas' rates are designed to provide it with the ability to recover prudently incurred operations and maintenance costs, taxes, interest, depreciation and amortization and a regulated return on equity. Natural gas companies may not grant any undue preference to any person, or maintain any unreasonable difference in their rates or other terms of service. On August 1, 2002, the FERC issued an Order to Respond to Northern Natural Gas related to Northern Natural Gas' existing $450 million revolving credit facility and to cash management record keeping by Northern Natural Gas. Pursuant to a Stipulation and Consent Agreement dated August 8, 2002, Northern Natural Gas agreed to comply with the FERC's cash management practices and to not include the costs associated with its existing $450 million revolving credit facility in any future rate proceeding. See "Regulation--Northern Natural Gas and Kern River." TRANSITION SERVICES FROM DYNEGY When Dynegy Inc. assumed ownership of Northern Natural Gas from Enron Corp. on February 1, 2002, Enron Operations Services Corp., or EOS, agreed to temporarily continue to provide certain services which it had previously provided to operate Northern Natural Gas through a transition services agreement. These services initially included physical operations, gas logistics, engineering, financial, accounting and other corporate services required to maintain and operate the system. Certain of these services, including the physical operation of the pipeline, were provided through June 30, 2002. Through January 31, 2003, EOS, pursuant to an assignment of the transition services agreement from Dynegy to us, is continuing to provide services necessary to operate the pipeline, including gas logistics, which involves gas nominations, gas scheduling and gas control and other required services, including information technology services. Additionally, on July 1, 2002, Dynegy assumed responsibility for the operations, engineering and corporate functions of Northern Natural Gas. In connection with our purchase of Northern Natural Gas from Dynegy on August 16, 2002, Dynegy has agreed to continue to provide limited support services to Northern Natural Gas pursuant to a new transition services agreement for a period ending January 31, 2003. KERN RIVER GAS TRANSMISSION COMPANY EXISTING FACILITIES AND BUSINESS Kern River's principal asset is a 926-mile interstate natural gas transmission pipeline system, with an original approximate capacity of 700 mmcf/day, extending from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. Following the completion of several recent expansion projects, including the 2002 expansion project and the California Action Project, the design capacity of the pipeline is currently 845.5 mmcf/day. Construction of the original pipeline began on January 2, 1991 and was completed in early 1992. Kern River's pipeline is comprised of two distinguishable sections: the mainline and the common facilities. The 707-mile mainline section extends from the pipeline's point of origination in Opal, Wyoming through the Central Rocky Mountains area into Daggett, California and is owned entirely by Kern River. The common facilities consist of the 219-mile section of pipeline that extends from Daggett to Bakersfield, California. The common facilities are jointly owned by Kern River (currently approximately 67.9%) and Mojave Pipeline Company (currently approximately 32.1%), as tenants-in-common. Kern River's ownership percentage in the common facilities will increase or decrease pursuant to subsequently completed expansions by the respective joint owners. 65 COMPETITION Generally, Kern River competes on a similar basis as other pipelines as is discussed above under the heading "Business--Northern Natural Gas Company." Pipelines compete on the basis of cost, flexibility, reliability of service and overall customer service. More specifically, Kern River competes with various interstate pipelines and its shippers in serving the southern California, Las Vegas and Salt Lake City market areas, in order to market any unsubscribed capacity and expansion capacity. Kern River provides customers with supply diversity through pipeline interconnects with Northwest pipeline, the Colorado Interstate Gas pipeline, the Overland Trail pipeline, and Questar pipeline. These interconnects allow Kern River to access natural gas reserves in Colorado, northwestern New Mexico, Wyoming, Utah and the Western Canadian Sedimentary Basin. Approximately 100% of Kern River's original pipeline capacity is contractually committed with 14 extended term rate shippers until September 30, 2011. Beyond that, approximately 84% of the original pipeline capacity is contractually committed until September 30, 2016. Nearly 100% of the additional permanent capacity constructed in connection with the 2002 expansion and to be constructed for the 2003 Expansion Project is contractually committed under 10- and 15-year agreements. Even though Kern River does not market natural gas supply, in each market area the purchaser evaluates the total cost of natural gas supply, including transportation rates, from each alternative supplier/transporter. Based on published rates and fuel percentages, we believe Kern River currently has the lowest transportation costs from well-head to burner tip of any interstate pipeline serving our direct markets in southern California, with gas transportation costs of approximately $0.39-0.44/MMBtu compared to approximately $0.77-$1.10/MMBtu on competing pipelines. There can be no assurance that our competitors do not or will not charge rates which are discounted to these published rates, particularly on a short-term basis. The 2003 Expansion Project shippers' initial tariff rates in the original FERC filing were $0.57-$0.70/MMBtu. These rates are expected to be reduced in a FERC compliance filing Kern River is required to make 60 days prior to placing the 2003 Expansion Project in service. Kern River is the only interstate pipeline that presently delivers natural gas directly from a gas supply basin into the intrastate California market, which enables its customers to avoid paying a "rate stack" (i.e., additional transportation costs attributable to the movement from an interstate system to an intrastate system within California). We believe that Kern River's rate structure and access to downstream pipelines/storage facilities and to low-cost Rocky Mountain gas reserves increases its competitiveness and attractiveness to end-users. Kern River believes it is advantaged relative to other competing interstate pipelines because its relatively new pipeline can be expanded at lower costs than those that apply to other systems. Its levelized rate structures under expansion rates and settlement rates also provide Kern River's customers with future rate certainty. OVERVIEW OF REGULATION AND CONTRACTS The FERC regulates Kern River under the Natural Gas Act, the Natural Gas Policy Act of 1978 and other applicable FERC regulations. The Natural Gas Act grants the FERC authority over the construction and operation of pipelines and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement, or abandonment of such facilities, as well as the transportation and wholesale sales of natural gas. The FERC also has authority to regulate rates for natural gas in interstate commerce. Kern River holds several Certificates of Public Convenience and Necessity issued by the FERC authorizing Kern River to construct, operate and maintain its pipeline and related facilities and to transport natural gas in interstate commerce. Kern River's rates, charges and terms and conditions of service are regulated by the FERC. FERC regulations and Kern River's tariff allow Kern River to charge up to maximum approved rates for particular services as set forth in its tariff. Kern River's rates are designed to provide it with the ability to recover prudently incurred operations and maintenance costs, taxes, interest, depreciation and amortization and a regulated return on equity. Natural gas companies may not grant any undue preference to any person, or maintain any unreasonable difference in their rates or other terms of service. 66 Kern River's rates are set using a "levelized cost-of-service" methodology so that the rate is constant over the contract period. This is achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expenses decrease. When Kern River commenced service in 1992, shippers signed 15-year long-term firm transportation contracts that were to expire in 2007. Under terms of a 1995 rate settlement, Kern River agreed that new rates would be filed by May 1, 1999. Instead of filing a rate case, Kern River negotiated a "pre-settlement" of the rate case with its shippers. This was approved by the FERC pursuant to a 1999 rate settlement in Docket No. RP99-274, which included an agreement for a moratorium on rate cases until May 1, 2002 under which Kern River may be required to file a rate case by May 1, 2004. In order to reduce transportation rates further and extend contract terms beyond 2007, Kern River initiated an open season in October 1998 to measure interest in lower, extended term rates for extended term contracts. Shippers were offered the choice of new 10- or 15-year contracts (4-9 year extensions of their existing contracts) with both options starting on October 1, 2001 and expiring on either September 30, 2011 or September 30, 2016. On February 8, 2001 the FERC approved implementation of the extended term rates. All existing shippers have signed up under the extended term rates program. See "Regulation--Northern Natural Gas and Kern River." KERN RIVER'S 2003 EXPANSION PROJECT The 2003 Expansion Project includes the primary 2003 Expansion Project and the High Desert Lateral. Kern River filed for FERC approval of the primary 2003 Expansion Project on August 1, 2001 and the High Desert Lateral on July 18, 2001. Primary 2003 Expansion Project. Construction commenced on August 6, 2002, and the primary 2003 Expansion Project is expected to be completed and operational by May 1, 2003 at a total cost of approximately $1.2 billion. The primary 2003 Expansion Project is a new parallel 717-mile loop pipeline that will begin in Lincoln County, Wyoming and terminate in Kern County, California. The project is designed to more than double the amount of natural gas transported on the Kern River system. The pipeline will include 36- and 42-inch diameter pipe, most of which will be laid in the existing Kern River right-of-way at a 25-foot offset from the existing pipeline, and new above ground facilities. Three segments along the right-of-way, approximately 205 miles in Utah, Nevada and California, will not require additional pipeline but will instead be areas where the gas will be compressed and transported through the existing pipeline. The existing pipeline rights-of-way, compressor facilities and receipt/delivery facilities will all be utilized by the 2003 Expansion Project, streamlining the permitting, acquisition of rights-of-way and ultimately the construction and operations of the 2003 Expansion Project. The primary 2003 Expansion Project includes the construction of three new compressor stations and the installation of additional compression and other modifications at six existing facilities. When completed, the Kern River system will have a summer day design capacity of approximately 1.73 Bcf/day, an increase of approximately 900 mmcf/day. Kern River has 18 long-term firm transportation service agreements with 17 shippers for 100% of the primary 2003 Expansion Project's capacity. The term for all these service agreements is either 10 or 15 years from the date on which transportation services on the 2003 Expansion Project commence. In addition to the FERC certificate process discussed above, Kern River requires several federal and state land use, air, water and other environmental permits in order to construct and ultimately operate the 2003 Expansion Project. All required permits have been applied for and have been obtained. High Desert Lateral. High Desert Power Project, LLC, or High Desert LLC, has commenced construction of a natural gas-fired 750 MW power plant owned by a subsidiary of Constellation Energy Group in Victorville, California. High Desert LLC has advised us that the plant is scheduled to start commercial operation by July 1, 2003. The High Desert Lateral is a 32-mile lateral and associated meter stations designed to transport up to 282 mmcf/day of natural gas to the High Desert power plant for High Desert LLC's affiliate, Victorville Gas, LLC, from interconnects with the common facilities and PG&E Corporation near Kramer Junction. 67 Victorville Gas, LLC will be seeking to acquire gas supply and/or upstream transportation capacity from shippers on the common facilities. Kern River began construction on the High Desert Lateral in May 2002 and placed the facilities in service on August 31, 2002. 2003 Expansion Project Financing. The 2003 Expansion Project will be financed with 70% debt and 30% equity, consistent with Kern River's existing capital structure, the application for FERC approval of the 2003 Expansion Project and the limitations contained in the indenture for Kern River's existing secured senior notes. On June 21, 2002, Kern River entered into an $875 million credit facility to fund a portion of the costs of the 2003 Expansion Project and we issued a completion guarantee in favor of the lenders under that credit facility. For a more complete description of the Kern River credit facility and our completion guarantee, see "Management's Discussion and Analysis of Financial Condition and Results of Operations--Construction--Kern River's 2003 Expansion Project Financing." CE ELECTRIC UK The business of CE Electric UK consists primarily of the distribution of electricity in the United Kingdom by Northern Electric and Yorkshire Electricity. In February 1997, CE Electric UK Ltd., an indirect wholly owned subsidiary of CE Electric UK, acquired Northern Electric. Northern Electric was one of the twelve original United Kingdom regional electric companies which came into existence in 1990 as a result of the restructuring and subsequent privatization of the electricity industry that occurred in the United Kingdom. On September 21, 2001, CE Electric UK Ltd. acquired 94.75% of Yorkshire Electricity from Innogy Holdings plc, or Innogy, and simultaneously sold Northern's electricity and gas supply and metering businesses to Innogy. We sometimes refer to these transactions as the Northern Electric/Yorkshire Electricity swap. In August 2002, CE Electric UK acquired the remaining 5.25% of Yorkshire Electricity that it did not already own from Xcel Energy International, an affiliate of Xcel Energy Inc. With the acquisition of Yorkshire Electricity and the disposal of the electricity and gas supply and metering businesses of Northern Electric and certain other recent or pending strategic disposals, CE Electric UK is positioned to continue to bring together the skills and resources of two neighboring distribution businesses to create one of the largest distribution companies in the United Kingdom, serving more than 3.6 million customers in an area of approximately 10,000 square miles. CE Electric UK has also implemented a number of initiatives which have produced savings in ongoing operating and capital costs at its businesses. BUSINESS OF CE ELECTRIC UK Descriptions of the functional business units of each of Northern Electric's and Yorkshire Electricity's distribution businesses are set forth below. For a summary description of the deregulated energy market in the United Kingdom, see "Regulation--CE Electric UK." ELECTRICITY DISTRIBUTION Northern Electric's and Yorkshire Electricity's operations consist primarily of the distribution of electricity and other auxiliary businesses in the United Kingdom. Northern Electric's and Yorkshire Electricity's distribution licensee companies, Northern Electric Distribution Limited, or NED, and Yorkshire Electricity Distribution plc, or YED, receive electricity from the national grid transmission system and distribute it to their customers' premises using their network of transformers, switchgear and cables. Substantially all of the customers in NED's and YED's distribution service areas are connected to the NED and YED networks and electricity can only be delivered through their distribution system, thus providing NED and YED with distribution volume that is relatively stable from year to year. NED and YED charge fees for the use of the distribution system to the suppliers of electricity. The suppliers, which purchase electricity from generators and sell the electricity to end-user customers, use NED's and YED's distribution networks pursuant to an industry standard "Uses of System Agreement" which NED and YED separately entered into with the various suppliers of electricity in their respective distribution areas. 68 The fees that may be charged by NED and YED for use of their distribution systems are controlled by a prescribed formula that limits increases (and may require decreases) based upon the rate of inflation in the United Kingdom and other regulatory action. For a more detailed description of this pricing formula, see "Regulation--CE Electric UK." At September 30, 2002, NED's and YED's electricity distribution network (excluding service connections to consumers) on a combined basis included approximately 31,000 kilometers of overhead lines and approximately 65,000 kilometers of underground cables. In addition to the circuits referred to above, at September 30, 2002, NED's and YED's distribution facilities also included approximately 56,600 transformers and approximately 58,000 substations. Substantially all substations are owned in freehold, and most of the balance are held on leases which will not expire within 10 years. UTILITY SERVICES Integrated Utility Services Limited, or IUS, a subsidiary of Northern Electric, is an engineering contracting company whose main business is providing electrical connection services on behalf of NED's and YED's distribution businesses and providing electrical infrastructure contracting services to third parties. The acquisition of Yorkshire Electricity by CE Electric UK Ltd. in 2001 has given IUS the opportunity to integrate Yorkshire Electricity's engineering contracting activities into IUS. GENERATION Northern Electric Generation Limited, or Northern Generation, a CE Electric UK subsidiary, presently maintains ownership interests in TPL. Teesside Power Limited. TPL owns and operates a 1,875 net MW combined cycle gas-fired power plant at Wilton in northeast England. Northern Generation owns a 15.4% interest in TPL, but does not operate the plant. The project was initiated in the early 1990s by Enron and at the time of the Enron bankruptcy filing in December 2001, Enron, through its subsidiaries, owned a 42.5% interest in the plant, operated the plant, and contracted to purchase 668 MW of capacity from the plant. In May 2002, TPL executed a restructuring and stabilization agreement with its lenders. It is anticipated that there will be no further dividends arising from this investment and, as a result, Northern Generation wrote off its equity investment in TPL as of December 31, 2001. Viking. In October 2002, Northern Generation sold its 50% interest in a 50MW gas fired mid-merit power plant known as Viking, located at Seal Sands in northeast England, to a subsidiary of Rolls-Royce plc. RETAIL DISPOSAL In August 2002, Northern Electric disposed of its non-core business of selling electrical and gas appliances which had been conducted through Northern Electric Retail Limited, a subsidiary of CE Electric UK. GAS EXPLORATION AND PRODUCTION CE Gas Holdings is a gas exploration and production company which is focused on developing integrated upstream gas projects. Its upstream gas business consists of the exploration, development and production, including transportation and storage, of gas for delivery to a point of sale into either a gas supply market or a power generation facility. In May 2002, CE Gas Holdings completed the sale of most of its United Kingdom natural gas assets to Gaz de France for approximately $200 million ( (pounds sterling)137.0 million). As part of the sale, CE Gas Holdings disposed of all of its interest in the natural gas-producing fields of Anglia, Johnston, Schooner and Windermere, each of which is located in the southern basin of the United Kingdom North Sea. The sale also included all of CE Gas Holdings' rights in four gas fields in development/construction and three exploration blocks owned by CE Gas Holdings. CE Gas Holdings retained its 5% working interest in the Victor Field and its 25% interest in the ETS gas pipeline. During 2001, the Victor Field produced on average 3.5 mmcf/day of gas, and CE Gas Holdings' share of the estimated remaining gas reserves in the Victor Field is 7 Bcf. 69 In addition to retaining its interest in the Victor Field and the ETS pipeline, CE Gas Holdings retained certain development interests in Poland (Polish Trough) and Australia (Perth, Bass and Otway Basins). CE Gas Holdings' interest in the retained fields is estimated to equal approximately 150 Bcf of gas. CALENERGY GENERATION--DOMESTIC OPERATING PROJECTS We own interests in 15 operating non-utility power projects in the United States. The following table sets out certain information concerning our domestic non-utility power projects in operation as of November 1, 2002:
FACILITY NET CONTRACT CAPACITY NET MW EXPIRATION PROJECT (MW)(1) OWNED(1) FUEL LOCATION DATE POWER PURCHASER(2) ---------------------------------- ---------- ---------- ------ ------------ -------------- ------------------- Cordova .......................... 537 537 Gas Illinois 2019 El Paso/MEC Salton Sea I ..................... 10 5 Geo California 2017 Edison Salton Sea II .................... 20 10 Geo California 2020 Edison Salton Sea III ................... 50 25 Geo California 2019 Edison Salton Sea IV .................... 40 20 Geo California 2026 Edison Salton Sea V ..................... 49 25 Geo California Year-to-year El Paso/Zinc(3) Vulcan ........................... 34 17 Geo California 2016 Edison Elmore ........................... 38 19 Geo California 2018 Edison Leathers ......................... 38 19 Geo California 2019 Edison Del Ranch ........................ 38 19 Geo California 2019 Edison CE Turbo ......................... 10 5 Geo California Year-to-year El Paso/Zinc(3) Saranac .......................... 240 90 Gas New York 2009 NYSEG Power Resources .................. 200 100 Gas Texas 2003 TXU Yuma ............................. 50 25 Gas Arizona 2024 SDG&E Roosevelt Hot Springs(4) ......... 23 17 Geo Utah 2020 UP&L --- --- Total CalEnergy Generation-- Domestic Operations ............. 1,377 933 ===== ===
---------- (1) Actual MW may vary depending on operating and reservoir conditions and plant design. Facility Net Capacity (in MW) represents facility gross capacity (in MW) less parasitic load. Parasitic load is electrical output used by the facility and not made available for sale to utilities or other outside purchasers. Net MW owned indicates current legal ownership, but, in some cases, does not reflect the current allocation of partnership distributions. (2) Southern California Edison Company; San Diego Gas & Electric Company; Utah Power & Light Company; New York State Electric & Gas Corporation; TXU Generation Company LP; Zinc Recovery Project; El Paso Corporation; and MidAmerican Energy. (3) Each contract governing power purchases by the Zinc Recovery Project will expire 33 years from the date of the initial power delivery under such contract. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Construction--Zinc Recovery Project" and "Business--CalEnergy Generation--Domestic--Zinc Recovery Project." (4) Our subsidiary owns an approximately 70% indirect interest in this project which supplies geothermal steam to a power plant owned by UP&L. We obtained a cash prepayment under a pre-sale agreement with UP&L whereby UP&L paid in advance for the steam produced by this steam field. Cordova Project. Cordova Energy owns a 537 MW gas-fired power plant in the Quad Cities, Illinois area which we refer to as the Cordova Project. CalEnergy Generation Operating Company, our indirect wholly owned subsidiary, operates the Cordova Project. The Cordova Project commenced commercial operations in June 2001. Cordova Energy entered into a power purchase agreement with a unit of El Paso, under which El Paso will purchase all of the capacity and energy from the project until December 31, 2019. Cordova Energy has exercised an option to recall from El Paso 50% of the output through May 14, 2004, reducing El Paso's purchase obligation to 50% of the output during such period. The recalled output 70 is being sold to MidAmerican Energy. We are aware there have been public announcements that El Paso's financial condition has deteriorated as a result of, among other things, reduced liquidity. We will continue to monitor the situation. We have a 50% ownership interest in CE Gen, which has interests in ten geothermal plants in the Imperial Valley in California (commonly referred to as the Salton Sea I, Salton Sea II, Salton Sea III, Salton Sea IV, Salton Sea V, Vulcan, Elmore, Leathers, Del Ranch and CE Turbo projects), and three natural gas-fired cogeneration plants (Saranac, Power Resources and Yuma). A subsidiary of El Paso owns the other 50% ownership interest in CE Gen. An indirect wholly owned subsidiary of CE Gen operates each of the ten Imperial Valley geothermal plants and each of the three natural gas-fired cogeneration plants. Each plant possesses an operating margin that allows for production in excess of the facility net MW amount listed in the table above. Utilization of this operating margin is based upon a variety of factors and can be expected to vary between calendar quarters, under normal operating conditions. Imperial Valley Projects. Six of the Imperial Valley geothermal plants sell electricity to Southern California Edison Company, or Edison, under 30-year Standard Offer No. 4 Agreements, which we refer to as the SO4 Agreements. Under the SO4 Agreements, Edison is obligated to pay capacity payments, capacity bonus payments and energy payments. The price for contract capacity payments is fixed for the life of such SO4 Agreement. The energy payments are based on the cost Edison avoids by purchasing energy from the projects instead of obtaining the energy from other sources. This cost is referred to as the Avoided Cost of Energy. In June and November 2001, six of these projects entered into agreements that provide for amended energy payments under the SO4 Agreements. The amendments provide for fixed energy payments of 5.37 cents per kWh commencing May 1, 2002 for a five year period in lieu of Edison's Avoided Cost of Energy. Following the five year period, the energy payments revert to Edison's Avoided Cost of Energy. Two of the Imperial Valley projects have negotiated contracts with Edison. The Salton Sea I contract provides for a capacity payment and energy payment for the life of the contract. Both payments are based upon an initial value that is subject to quarterly adjustment by reference to various inflation-related indices. The Salton Sea IV contract also provides for fixed price capacity payments for the life of the contract and fixed energy prices, which are subject, in part, to quarterly adjustment by reference to various inflation-related indices, through June 20, 2017 (and at Edison's Avoided Cost of Energy thereafter), and, in part, to Edison's Avoided Cost of Energy. The Salton Sea V and Turbo projects began operations in 2000 and, when the Zinc Recovery Project achieves 100% production, the Salton Sea V Project and the Turbo Project would expect to sell approximately 20 MW to the Zinc Recovery Project at a price based on market transactions. The remainder is being sold through other market transactions. Saranac Project. The Saranac Project is a 240 net MW natural gas-fired cogeneration facility located in Plattsburgh, New York. The Saranac Project has entered into a 15-year power purchase agreement with New York State Electric & Gas Company expiring in 2009. The Saranac Project is a qualifying facility, or QF, and has entered into 15-year steam purchase agreements with Georgia-Pacific Corporation and Pactiv Corporation. The Saranac Project has a 15-year natural gas supply agreement with Shell Canada Limited, to supply 100% of the Saranac Project's fuel requirements. Each of the Saranac power purchase agreement, the Saranac steam purchase agreements and the Saranac gas supply agreement contains rates that are fixed for their respective contract terms. Revenues escalate at a higher rate than fuel costs. The Saranac partnership is indirectly owned by subsidiaries of CE Gen, ArcLight Capital Partners LLC and General Electric Capital Corporation. Power Resources Project. The Power Resources Project is a 200 net MW natural gas-fired cogeneration project located near Big Spring, Texas, which has a 15-year power purchase agreement with TXU Generation Company LP, formerly known as Texas Utilities Electric Company expiring in 2003. The Power Resources Project is a QF and has a steam purchase agreement with Alon USA, L.P. 71 Yuma Project. The Yuma Project is a 50 net MW natural gas-fired cogeneration project in Yuma, Arizona providing 50 MW of electricity to San Diego Gas & Electric Company under an existing 30-year power purchase agreement which expires in 2024. The Yuma project is a QF and has executed steam sales contracts with an adjacent industrial entity to act as its thermal host. Roosevelt Hot Springs. One of our subsidiaries operates and owns an approximately 70% indirect interest in a geothermal steam field which supplies geothermal steam to a 23 net MW power plant owned by Utah Power & Light Company, or UP&L, located on the Roosevelt Hot Springs property under a 30-year steam sales contract expiring in 2020. We obtained a cash prepayment under a pre-sale agreement with UP&L whereby UP&L paid in advance for the steam produced by the steam field. We guarantee the performance of this subsidiary. We must make certain penalty payments to UP&L if the steam produced does not meet certain quantity and quality requirements. Zinc Recovery Project. CalEnergy Minerals LLC is constructing the Zinc Recovery Project which will recover zinc from the geothermal brine. Facilities are being installed near the Imperial Valley project's sites to extract a zinc chloride solution from the geothermal brine through an ion exchange process. This solution will be transported to a central processing plant where zinc ingots will be produced through solvent extraction, electrowinning and casting processes. The Zinc Recovery Project is operated by an indirect wholly owned subsidiary of CE Gen, is designed to have a capacity of approximately 30,000 metric tons per year, and has commenced initial commercial operations in 2002. The Zinc Recovery Project is expected to be at 100% production in mid- 2003. DEVELOPMENT PROJECTS Fox Energy. Our subsidiary, Fox, is developing a 635 net MW gas fired power generating facility in Kaukanna, Outagamie County, Wisconsin. A subsidiary of TransAlta Corporation has agreed to participate in the development of this project at a level of 50% and has an option to own 50% of the project. A Certificate of Public Convenience and Necessity was issued by the Public Service Commission of Wisconsin on November 8, 2002. An air permit for construction and initial operations was issued by the Wisconsin Department of Natural Resources on November 4, 2000 and such application was deemed complete on April 25, 2002. A final environmental impact statement was issued by the Wisconsin Department of Natural Resources on August 19, 2002. Electrical and natural gas interconnection agreements and a water supply agreement have also been executed for this project. Salton Sea VI. Our subsidiary, Obsidian, is developing a 185 net MW geothermal facility in Imperial Valley, California. Substantially all the output of the facility will be sold to the Imperial Irrigation District pursuant to a power purchase agreement. An affiliate of El Paso has elected to participate in the ownership and development of this project at a level of 50%. On July 29, 2002, Obsidian filed an application for certification seeking approval from the California Energy Commission to construct and operate the facility. CALENERGY GENERATION--FOREIGN The following table sets out information concerning CalEnergy Generation's principal foreign non-utility power projects in operation as of November 1, 2002:
FACILITY NET POLITICAL CAPACITY NET MW COMMERCIAL U.S. $ POWER PURCHASER/ RISK PROJECT (MW)(1) OWNED(1) FUEL LOCATION OPERATION PAYMENTS GUARANTOR(2) INSURANCE ------------------- ---------- ------------ ------- ------------- ------------ ---------- ------------------ ---------- Mahanagdong ....... 165 149 Geo Philippines 1997 Yes PNOC-EDC/ROP Yes Malitbog .......... 216 216 Geo Philippines 1996-97 Yes PNOC-EDC/ROP Yes Upper Mahiao ...... 119 119 Geo Philippines 1996 Yes PNOC-EDC/ROP Yes Casecnan .......... 150 150(3) Hydro Philippines 2001 Yes NIA/ROP Yes --- --- Total CalEnergy Generation-- Foreign Operations ....... 650 634 === ===
72 ---------- (1) Actual MW may vary depending on operating and reservoir conditions and plant design. Facility Net Capacity (in MW) represents the contract capacity for the facility. Net MW owned indicates current legal ownership, but, in some cases, does not reflect the current allocation of distributions. (2) PNOC--Energy Development Corporation, or PNOC-EDC, Republic of the Philippines, or ROP, and NIA (NIA also purchases water from this facility). The government of the Philippines undertaking supports PNOC-EDC's and NIA's respective obligations. (3) Subject to repurchase rights of up to 15% of the project by an initial minority shareholder and a dispute with the other initial minority shareholder regarding an additional 15% of the project. Also see "Legal Proceedings--Casecnan Shareholder Litigation" and note 20 to our consolidated financial statements for the year ended December 31, 2001 for a discussion of legal proceedings regarding this ownership interest. We indirectly own the Upper Mahiao, Malitbog and Mahanagdong projects, which are geothermal power plants located on the island of Leyte in the Philippines, and the Casecnan Project, a combined irrigation and hydroelectric power generation project, which is located in the central part of Island of Luzon in the Philippines. One of our indirect wholly owned subsidiaries operates each of these projects. Each plant possesses an operating margin that allows for production in excess of the amount listed above. Utilization of this operating margin is based upon a variety of factors and can be expected to vary between calendar quarters, under normal operating conditions. Mahanagdong. The Mahanagdong Project is a 165 net MW geothermal power project owned and operated by CE Luzon Geothermal Power Company, Inc., or CE Luzon, a Philippine corporation of which we indirectly own 100% of the common stock. Another industrial company owns an approximate 10% preferred equity interest in the Mahanagdong Project. The Mahanagdong Project has been in commercial operation since July 25, 1997. The Mahanagdong Project sells 100% of its capacity on a similar basis as described above for the Upper Mahiao Project to PNOC-EDC, which in turn sells the power to the NPC for distribution on the island of Luzon. The terms of the Mahanagdong energy conversion agreement are substantially similar to those of the Upper Mahiao agreement. The Mahanagdong agreement provides for a ten-year cooperation period. At the end of the cooperation period, the facility will be transferred to PNOC-EDC at no cost. All of PNOC-EDC's obligations under the Mahanagdong agreement are supported by the Republic of the Philippines through a performance undertaking. The capacity fees are approximately 97% of total revenues at the design capacity levels and the energy fees are approximately 3% of such total revenues. PNOC-EDC's payment requirements, and its other obligations under the Mahanagdong agreement, are supported by the Republic of the Philippines through a performance undertaking. Malitbog. The Malitbog Project is a 216 net MW geothermal project owned and operated by Visayas Geothermal Power Company, or VGPC, a Philippine general partnership that is wholly owned, indirectly, by us. The three units of the Malitbog facility were put into commercial operation on July 25, 1996 (for Unit I) and July 25, 1997 (for Units II and III). VGPC sells 100% of its capacity on substantially the same basis as described above for the Upper Mahiao Project to PNOC-EDC, which sells the power to the NPC for distribution on the islands of Cebu and Luzon. The electrical energy produced by the facility is sold to PNOC-EDC on a take-or-pay basis. These capacity payments equal approximately 100% of total revenues. A substantial majority of the capacity payments are required to be made by PNOC-EDC in dollars. The portion of capacity payments payable to PNOC-EDC in pesos is expected to vary over the term of the Malitbog energy conversion agreement from 10% of VGPC's revenues in the early years of the 10-year cooperation period to 23% of VGPC's revenues at the end of the cooperation period. Payments made in pesos will generally be made to a peso-dominated account and will be used to pay peso-denominated operation and maintenance expenses with respect to the Malitbog Project and Philippine withholding taxes, if any, on the Malitbog Project's debt service. The government of the Philippines has entered into a performance undertaking, which provides that all of PNOC-EDC's obligations pursuant to the Malitbog energy conversion agreement carry the full faith and credit of, and are affirmed and guaranteed by, the Republic of the Philippines. 73 The Malitbog energy conversion agreement cooperation period expires ten years after the date of commencement of commercial operation of Unit III. At the end of this cooperation period, the facility will be transferred to PNOC-EDC at no cost, on an "as is" basis. See "Legal Proceedings" for a description of legal proceedings related to the Malitbog Project. Upper Mahiao. The Upper Mahiao facility is a 119 net MW geothermal power project owned and operated by CE Cebu Geothermal Power Company, Inc., or CE Cebu, a Philippine corporation that is 100% indirectly owned by us. The Upper Mahiao facility has been in commercial operation since June 17, 1996. Under the terms of the Upper Mahiao energy conversion agreement, CE Cebu owns and operates the Upper Mahiao Project during the ten-year cooperation period, which commenced in June 1996, after which ownership will be transferred to PNOC-Energy Development Corporation, or PNOC-EDC, at no cost. The Upper Mahiao Project is located on land provided by PNOC-EDC at no cost. The project takes geothermal steam and fluid, also provided by PNOC-EDC at no cost, and converts its thermal energy into electrical energy which is sold to PNOC-EDC on a "take-or-pay" basis, which in turn sells the power to the NPC, for distribution on the island of Cebu. PNOC-EDC pays to CE Cebu a fee based on the plant capacity nominated to PNOC-EDC in any year (which, at the plant's design capacity, is approximately 95% of total contract revenues) and a fee based on the electricity actually delivered to PNOC-EDC (approximately 5% of total contract revenues). Payments under the Upper Mahiao agreement are denominated in U.S. dollars, or computed in U.S. dollars and paid in Philippine pesos at the then-current exchange rate, except for the energy fee. PNOC-EDC's payment requirements, and its other obligations under the Upper Mahiao agreement, are supported by the Republic of the Philippines through a performance undertaking. Casecnan. CE Casecnan, our indirectly majority owned subsidiary, operates the Casecnan Project, a combined irrigation and 150 net MW hydroelectric power generation project. The Casecnan Project consists generally of diversion structures in the Casecnan and Taan Rivers that captures and diverts excess water in the Casecnan watershed by means of concrete, in-stream diversion weirs and transfers that water through a transbasin tunnel of approximately 23 kilometers (including the intake audit from the Taan to the Casecnan River), with a diameter of approximately 6.5 meters to an existing underutilized water storage reservoir at Pantabangan. During the water transfer, the elevation differences between the two watersheds allows electrical energy to be generated at a 150 net MW rated capacity power plant, which is located in an underground powerhouse cavern at the end of the water tunnel. A tailrace discharge tunnel of approximately three kilometers delivers water from the water tunnel and the powerhouse to the Pantabangan Reservoir, providing additional water for irrigation and increasing the potential electrical generation at two downstream existing hydroelectric facilities of the NPC, the government-owned and controlled corporation that is the primary supplier of electricity in the Philippines. CE Casecnan constructed the Casecnan Project under the terms of the project agreement between CE Casecnan and NIA. Under the project agreement, CE Casecnan developed, financed and arranged for the construction of the Casecnan Project, and will own and operate the Casecnan Project for 20 years. During this cooperation period, NIA is obligated to accept all deliveries of water and energy, and so long as the Casecnan Project is physically capable of operating and delivering in accordance with agreed levels set forth in the project agreement, NIA will pay CE Casecnan a fixed fee for the delivery of a minimum volume of water and a fixed fee for the delivery of a minimum amount of electricity. In addition, NIA will pay a fee for all electricity delivered in excess of a threshold amount up to a specified amount. NIA will sell the electricity it purchases to the NPC, although NIA's obligations to CE Casecnan under the project agreement are not dependent on the NPC's purchase of the electricity from NIA. All fees to be paid by NIA to CE Casecnan are payable in U.S. dollars. The fixed fees for the delivery of water and energy, regardless of the amount of electricity or water actually delivered, are expected to provide approximately 78% of CE Casecnan's revenues. At the end of the cooperation period, the Casecnan Project will be transferred to NIA and the NPC for no additional consideration on an "as is" basis. 74 The Republic of the Philippines has provided a performance undertaking under which NIA's obligations under the project agreement are guaranteed by the full faith and credit of the Republic of the Philippines. See "Legal Proceedings" for a description of legal proceedings related to the Casecnan Project. HOMESERVICES HomeServices of America, Inc., or HomeServices, our wholly owned subsidiary, is the second largest full-service independent residential real estate brokerage firm in the United States based on aggregate closed transaction sides. Closed transaction sides mean either the buy side or sell side of any closed home purchase and is the standard term used by industry participants and publications to rank real estate brokerage firms. In addition to providing traditional residential real estate brokerage services, HomeServices offers other integrated real estate services, including mortgage originations, title and closing services and other related services. HomeServices currently operates in 15 states under the following brand names: Carol Jones Realty, CBSHOME Real Estate, Champion Realty, Edina Realty, First Realty/GMAC, Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty, Prudential California Realty, Realty South, Reece & Nichols, Semonin REALTORS and Woods Bros. Realty. HomeServices generally occupies the number one or number two market share position in each of its major markets based on aggregate closed transaction sides. HomeServices' major markets consist of the following metropolitan areas: Minneapolis and St. Paul, Minnesota; Los Angeles and San Diego, California; Kansas City, Kansas; Des Moines, Iowa; Omaha and Lincoln, Nebraska; Birmingham, Alabama; Tucson, Arizona; Louisville, Kentucky; Annapolis, Maryland; Atlanta, Georgia and Springfield, Missouri. REAL ESTATE COMPANIES 2002 ACQUISITIONS In 2002, HomeServices separately acquired three real estate companies for an aggregate purchase price of approximately $100 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2001, these real estate companies had combined revenue of approximately $356 million on 42,000 closed sides representing $13.7 billion of sales volume. Additionally, HomeServices is obligated to pay a maximum earnout of $18.5 million calculated based on 2002 financial performance measures. These purchases were financed using HomeServices' $65 million revolving credit facility and our corporate revolver for $40 million, which was contributed to HomeServices as equity. We are in the process of completing the allocation of the purchase prices to the assets and liabilities acquired. PROPERTIES Our utility properties consist of physical assets necessary and appropriate to render electric and gas service in our service territories. Electric property consists primarily of generation, transmission and distribution facilities. Gas property consists primarily of distribution plants, natural gas pipelines, related rights-of-way, compressor stations and meter stations. It is the opinion of management that the principal depreciable properties owned by us are in good operating condition and well maintained. MIDAMERICAN ENERGY MidAmerican Energy's most significant properties are its electric generation facilities. For a discussion of these generation facilities, please see "Business--MidAmerican Energy." At September 30, 2002, the electric transmission system of MidAmerican Energy included approximately 900 miles of 345-kV lines, and 1,325 miles of 161-kV lines. The gas distribution facilities of MidAmerican Energy at September 30, 2002 included approximately 20,600 miles of gas mains and services. Substantially all of the former Iowa-Illinois Gas and Electric Company (predecessor to MidAmerican Energy Company) utility property and franchises, and substantially all of the former Midwest Power Systems Inc. (predecessor to MidAmerican Energy Company) electric utility property located in Iowa, or approximately 79% of gross utility plant, is pledged to secure mortgage bonds. In addition to the circuits referred to above, at September 30, 2002, MidAmerican Energy's delivery facilities also included approximately 218,000 distribution transformers and approximately 370 substations. 75 NORTHERN NATURAL GAS AND KERN RIVER At September 30, 2002, Northern Natural Gas' system was comprised of approximately 7,300 miles of mainline transmission pipes and approximately 9,300 miles of smaller diameter branch lines and laterals. Northern Natural Gas' storage services are provided through the operation of three underground storage fields, in Redfield, Iowa, and Lyons and Cunningham, Kansas. The three underground natural gas storage facilities and Northern Natural Gas' two liquefied natural gas storage peaking units have a total storage capacity of approximately 59 Bcf. Northern Natural Gas' two LNG liquefaction/vaporization facilities are located near Garner, Iowa and Wrenshall, Minnesota with storage capacity of 2 Bcf each. At September 30, 2002, Kern River's pipeline was comprised of two distinguishable sections: the mainline and the common facilities. The 707-mile mainline section extends from the pipeline's point of origination in Opal, Wyoming through the Central Rocky Mountains area into Daggett, California and is owned entirely by Kern River. The common facilities consist of the 219-mile section of pipeline that extends from Daggett to Bakersfield, California. The common facilities are jointly owned by Kern River (currently approximately 67.9%) and Mojave Pipeline Company (currently approximately 32.1%) as tenants-in-common. The right to construct and operate the pipelines across certain property was obtained through negotiations and through the exercise of the power of eminent domain, where necessary. Northern Natural Gas and Kern River continue to have the power of eminent domain in each of the states in which they operate their respective pipelines, but they do not have the power of eminent domain with respect to Native American tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management. With respect to real property, each of the pipelines falls into two basic categories: (1) parcels that are owned in fee, such as certain of the compressor stations, measurement stations and district office sites; and (2) parcels where the interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the pipelines. We believe that Northern Natural Gas and Kern River each have satisfactory title to all of the real property making up their respective pipelines in all material respects. CE ELECTRIC UK At September 30, 2002, Northern Electric's and Yorkshire Electricity's electricity distribution networks (excluding service connection to consumers) on a combined basis included approximately 31,000 kilometers of overhead lines and approximately 65,000 kilometers of underground cables. In addition to the circuits referred to above, at September 30, 2002, Northern Electric's and Yorkshire Electricity's distribution facilities also included approximately 56,600 transformers and approximately 58,000 substations. OTHER PROPERTIES At September 30, 2002, our most significant physical properties, other than those owned by MidAmerican Energy, Northern Natural Gas, Kern River and CE Electric UK, are our current interests in operating power facilities and our plants under construction and related real property interests, as well as leases of office space for our residential real estate brokerage operations. See "Business" for further detail. 76 REGULATION Our operating platforms are subject to a number of federal, state, local and international regulations. MIDAMERICAN ENERGY MidAmerican Energy is subject to comprehensive regulation by utility regulatory agencies in Iowa, Illinois and South Dakota that significantly influences the operating environment and the recoverability of costs from utility customers. Except for Illinois, that regulatory environment has to date, in general, given MidAmerican Energy an exclusive right to serve electricity customers within its service territory and, in turn, the obligation to provide electric service to those customers. In Illinois all customers are free to choose their electricity provider. MidAmerican Energy has an obligation to serve customers at regulated rates that leave MidAmerican Energy's system, but later choose to return. To date, there has been no significant loss of customers from MidAmerican Energy's existing regulated Illinois rates. In connection with the March 1999 approval by the IUB of the MidAmerican Energy acquisition and March 2000 affirmation as part of our acquisition by a private investor group, we agreed, among other things, to use all commercially reasonable efforts to maintain an investment grade credit rating for MidAmerican Energy's utility operations and its long-term debt and to seek the approval of the IUB of a reasonable utility capital structure if MidAmerican Energy's utility operations' common equity level decreases below 42%, excluding circumstances beyond its control, or below 39%, under any circumstances. MidAmerican Energy's utility operations' common equity level at December 31, 2001 and September 30, 2002 was above these levels. With the elimination of its energy adjustment clause in Iowa in 1997, MidAmerican Energy is financially exposed to movements in energy prices. Although MidAmerican Energy has sufficient low cost generation under typical operating conditions for its retail electric needs, a loss of adequate generation by MidAmerican Energy requiring the purchase of replacement power at a time of high market prices could subject MidAmerican Energy to losses on its energy sales. In December 1999, the FERC issued Order No. 2000 establishing among other things minimum characteristics and functions for regional transmission organizations. Public utilities that were not a member of an independent system operator at the time of the order were required to submit a plan by which their transmission facilities would be transferred to a regional transmission organization. On September 28, 2001, MidAmerican Energy and five other electric utilities filed with the FERC a plan to create TRANSLink Transmission Company LLC and to integrate their electric transmission systems into a single, coordinated system operating as a for-profit independent transmission company in conjunction with a FERC approved regional transmission organization. On April 25, 2002, the FERC issued an order approving the transfer of control of MidAmerican Energy's and other utilities' transmission assets to TRANSLink in conjunction with TRANSLink's participation in the Midwest ISO. Additionally, state regulatory approval is required from states in which TRANSLink will be operating and those applications have not yet been filed. Once filed, MidAmerican Energy does not anticipate rulings in the state proceedings until some time in 2003. Transferring operation and control of MidAmerican Energy's transmission assets to other entities could increase costs for MidAmerican Energy; however, the actual impact of TRANSLink on MidAmerican Energy's future transmission costs is not yet known. On July 31, 2002, the FERC issued a notice of proposed rulemaking with respect to Standard Market Design for the electric industry. The FERC has characterized the proposal as portending "sweeping changes" to the use and expansion of the interstate transmission and the wholesale bulk power systems in the United States. The proposal includes numerous proposed changes to the current regulation of transmission and generation facilities designed "to promote economic efficiency" and replace the "obsolete patchwork we have today," according to the FERC's chairman. The final rule, if adopted as currently proposed, would require all public utilities operating transmission facilities subject to the FERC jurisdiction to file revised open access transmission tariffs that would require changes to the basic services these public utilities currently provide. The proposed rule may impact the costs and/or pricing of MidAmerican Energy's electricity and transmission products. The FERC does not envision that a final rule will be fully implemented until September 30, 2004. We are still evaluating the proposed rule, and we 77 believe that the final rule could vary considerably from the initial proposal. Accordingly, we are presently unable to quantify the likely impact of the proposed rule on us. The structure of such federal and state energy regulations have in the past, and may in the future, be the subject of various challenges and restructuring proposals by utilities and other industry participants. The implementation of regulatory changes in response to such changes or restructuring proposals, or otherwise imposing more comprehensive or stringent requirements on us, which would result in increased compliance costs, could have a material adverse effect on our results of operations. Under a settlement agreement approved by the IUB on December 21, 2001, MidAmerican Energy's Iowa retail rates in effect on December 31, 2000 are frozen through December 31, 2005. Additionally, this settlement agreement reinstates, with modifications, the revenue sharing provisions of a 1997 pricing plan settlement agreement, which expired on December 31, 2000. The settlement agreement further provides that an amount equal to 50% of revenues associated with Iowa retail electric returns on equity between 12% and 14%, and 83.33% of revenues associated with Iowa retail electric returns on equity above 14%, in each year will be recorded as a regulatory liability to be used to offset a portion of the cost to Iowa customers of future generating plant investment. An amount equal to the regulatory liability will be recorded as a regulatory charge in depreciation and amortization expense when the liability is accrued. Interest expense is accrued on the portion of the regulatory liability related to prior years. Beginning in 2002, the liability is being reduced as it is credited against allowance for funds used during construction or capitalized financing costs associated with generating plant additions. As of September 30, 2002, the related regulatory liability was $95.0 million. In Iowa, MidAmerican Energy does not have an energy adjustment clause, so any significant increase in fuel costs or purchased power costs could have a negative impact on MidAmerican Energy. Under an Illinois restructuring law enacted in 1997, as amended in 2002, a sharing mechanism is in place for MidAmerican Energy's Illinois regulated retail electric operations whereby earnings above a computed level of return on common equity will be shared equally between customers and MidAmerican Energy. MidAmerican Energy's computed level of return on common equity is based on a rolling two-year average of the Monthly Treasury Long-Term Average Rate, as published by the Federal Reserve System, plus a premium of 8.5% for 2000 through 2004 and a premium of 12.5% for 2005 and 2006. The two-year average above which sharing must occur for 2001 was 14.34%. The law allows MidAmerican Energy to mitigate the sharing of earnings above the threshold return on common equity through accelerated recovery of regulatory assets. On September 21, 2001, MidAmerican Energy filed a petition with the South Dakota Public Utilities Commission, or SDPUC, to increase its South Dakota natural gas rates. On February 20, 2002, the SDPUC approved a settlement agreement allowing increased rates of $3.1 million annually. On October 19, 2001, MidAmerican Energy filed a petition with the Illinois Commerce Commission to increase its Illinois natural gas rates. On September 11, 2002, the Illinois Commerce Commission issued an order granting MidAmerican Energy a $2.2 million annual increase in rates. On March 15, 2002, MidAmerican Energy made a filing with the IUB requesting an increase in rates of approximately $26.6 million for its Iowa retail natural gas customers. As part of the filing, MidAmerican Energy requested an interim rate increase of approximately $20.4 million annually. On June 12, 2002, the IUB issued an order granting MidAmerican Energy an interim increase of approximately $13.8 million annually, effective immediately and subject to refund with interest. On July 15, 2002 MidAmerican Energy and the Office of Consumer Advocate filed a proposed settlement agreement with the IUB. The settlement agreement, which was approved by the IUB on November 8, 2002, provides for an increase in rates of $17.7 million annually for MidAmerican Energy's Iowa retail natural gas customers and freezes such rates for two years after the date the IUB approves tariffs implementing the settlement agreement. MidAmerican Energy implemented the new rates effective November 25, 2002. NORTHERN NATURAL GAS AND KERN RIVER Northern Natural Gas and Kern River are subject to regulation by various federal and state agencies as discussed below. 78 As owners of interstate natural gas pipelines, Northern Natural Gas' and Kern River's rates, services and operations are subject to regulation by the FERC. The FERC administers, among other things, the Natural Gas Act and the Natural Gas Policy Act. Additionally, interstate pipeline companies are subject to regulation by the Department of Transportation pursuant to the Natural Gas Pipeline Safety Act, which establishes safety requirements in the design, construction, operations and maintenance of interstate natural gas transmission facilities. The FERC has jurisdiction over, among other things, the construction and operation of pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. The FERC also has jurisdiction over the rates and charges and terms and conditions of service for the transportation of natural gas in interstate commerce. Our pipeline subsidiaries also are required to file with the FERC an annual report on Form 2, which is publicly available, disclosing general corporate information and financial statements regarding our pipeline subsidiaries. Northern Natural Gas has implemented a straight fixed variable rate design which provides that all fixed costs assignable to firm capacity customers, including a return on equity, are to be recovered through fixed monthly demand or capacity reservation charges which are not a function of throughput volumes. Northern Natural Gas' current tariff structure provides for: o seasonality in demand rates; o extension of the majority of firm storage and transport contracts through May 31, 2003 and October 31, 2003, respectively; o a rate moratorium through October 31, 2003, with limited re-openers based on the FERC's rulemaking changes; and o the right of Northern Natural Gas to file for term-differentiated rates, if allowed. Northern Natural Gas' tariff rates were designed to recover a cost of service that would reflect a 12.3% return on equity based upon the settlement reached in FERC Docket No. RP 98-203. Northern Natural Gas' last rate case was filed on May 1, 1998, and its next rate case may be filed no earlier than May 2003 and no later than May 2004. Northern Natural Gas' most likely next rate case filing date is May 1, 2003 with filed rates to be effective November 1, 2003. Kern River's tariff rates were designed to recover a cost of service that would reflect a 13.25% return on equity. Kern River's rates are set using a "levelized cost-of-service" methodology so that the rate is constant over the contract period. This is achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expense decreases. In 2000, the FERC issued new rules with respect to terms and conditions of interstate pipeline transportation service pursuant to Order No. 637. In Order No. 637, the FERC made changes to its regulatory model to enhance the effectiveness and efficiency of gas markets as they evolved since the series of FERC orders commonly referred to as Order No. 636, which were adopted beginning in the early 1990s and which provided for the restructuring of interstate pipeline sales and services. Specifically, in Order No. 637 the FERC: o addressed alternatives to traditional pipeline pricing by permitting peak/off-peak and term differentiated rate structures; o revised certain reporting requirements; and o made changes in regulations related to (1) scheduling equality for released capacity, (2) capacity segmentations, and (3) pipeline imbalance services, operational flow orders and penalties. On July 17, 2000, Northern Natural Gas made its initial compliance filing in accordance with the FERC's Order No. 637. Northern Natural Gas made a revised Order No. 637 compliance filing on March 4, 2002 and a supplemental filing on May 10, 2002. On November 21, 2002, the FERC issued an Order on Compliance with Order Nos. 637, 587-G and 587-L. In the November 21, 2002 Order, the FERC found that Northern Natural Gas generally complied with Order Nos. 637, 587-G and 587-L, subject to certain modifications, and ordered Northern Natural Gas to file compliance tariffs within 30 days. 79 On June 15, 2000, Kern River filed pro forma tariff sheets in Docket No. RP00-337 to comply with the FERC's directives in Order No. 637. In its May 30, 2002 "Order on Compliance with Order No. 637 and Second Order on Compliance with Order Nos. 587-G and 587-L," the FERC found that Kern River had generally complied with the requirements of Order Nos. 637, 587-G and 587-L, subject to the certain modifications. On October 31, 2002, the FERC issued an order that generally accepted Kern River's tariff filings to comply with Order Nos. 637, 587-G and 587-L. In the order, the FERC directed Kern River to provide a park and loan service and to make changes addressing segmentation as well as forward and backhaul nominations. On June 28, 2002, Kern River filed tariff sheets to comply with the FERC's order. These tariff sheets are pending action by the FERC. On September 30, 2002, the FERC issued an order on Kern River's compliance filing with Order No. 587-0. The FERC found that Kern River generally complied with the requirements of Order No. 587-0 and that Kern River should refile its title transfer tracking service. As a result of the FERC's policies favoring competition in gas markets and the expansion of existing pipelines and construction of new pipelines, the interstate pipeline industry has begun to experience some turnback of firm capacity as existing transportation service agreements expire and are terminated. LDCs and end-use customers have more choices in the new, more competitive environment and may be able to shift load from one pipeline to another. If a pipeline experiences capacity turnback and is unable to remarket the capacity, the pipeline or its other customers may have to bear the costs associated with the capacity that is turned back. These issues will be resolved in a pipeline's general rate case proceedings. The FERC also has authority over gas pipelines' accounting practices. The FERC recently issued a notice of proposed rulemaking regarding gas accounting issues which would limit the ability of gas pipelines to enter into cash management agreements with their parent companies. We are in the process of reviewing such proposed rule, but we do not believe the rule will have a material adverse impact on us and our pipeline subsidiaries. See "Business--Northern Natural Gas Company--Overview of Regulation and Contracts" and "Business--Kern River Gas Transmission Company--Overview of Regulation and Contracts." Additional proposals and proceedings that might affect the interstate pipeline industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. In some states various forms of restructuring legislation have been passed and in many states local utility regulatory agencies are overseeing the restructuring. As a result of restructuring, LDCs could unbundle their services and withdraw from all or part of their merchant function, and electric utilities could divest their generating function. This restructuring would result in the interstate pipelines having different customer profiles, including independent gas marketers and independent power generators and end-users. We cannot predict when or if any new proposals might be implemented or, if so, how Northern Natural Gas and Kern River might be affected. OTHER UNITED STATES REGULATION The Public Utility Regulatory Policies Act of 1978, as amended, or PURPA, and PUHCA are two of the laws (including the regulations thereunder) that affect our and certain of our subsidiaries' operations. PURPA provides to QFs certain exemptions from federal and state laws and regulations, including organizational, rate and financial regulation. PUHCA extensively regulates and restricts the activities of registered public utility holding companies and their subsidiaries. Congress is currently considering major changes to both PUHCA and PURPA in a House-Senate conference on a comprehensive energy bill (H.R. 4). The Senate version of the bill (S. 517) would repeal PUHCA and replace it with provisions giving state and federal regulators enhanced access to the books and records of all utility holding companies. The Senate bill would also prospectively repeal PURPA's mandatory purchase obligation for utilities, but this provision would not abrogate CalEnergy Generation-Domestic's existing QF contracts. Any such legislation, if adopted, could vary considerably from the terms contained in either or both of the House and Senate versions which are presently under consideration. We believe that if the current proposed legislation is passed, it would apply to new projects only and thus, although potentially 80 impacting our ability to develop new domestic projects, it would not affect our existing qualifying facilities. We cannot assure you, however, that legislation, if passed, or any other similar legislation proposed in the future, would not adversely impact our existing domestic projects. We are currently exempt from regulation under all provisions of PUHCA, except the provisions that regulate the acquisition of securities of public utility companies, based on the intrastate exemption in Section 3(a)(1) of PUHCA. In order to maintain this exemption, we and each of our public utility subsidiaries from which we derive a material part of our income (currently only MidAmerican Energy) must be predominantly intrastate in character and organized in and carry on our and their respective utility operations substantially in our state of organization (currently Iowa). Except for MidAmerican Energy's generating plant assets, the majority of our domestic power plants and all of our foreign utility operations are not public utilities within the meaning of PUHCA as a result of their status as QFs under PURPA (with our ownership interest therein limited to 50%), exempt wholesale generators or foreign utility companies, or are otherwise exempted from the definition of "public utility" under PUHCA. Although we believe that we will continue to qualify for exemption from additional regulation under PUHCA, it is possible that as a result of the expansion of our public utility operations, loss of exempt status by one or more of our domestic power plants or foreign utilities, or amendments to PUHCA or the interpretation of PUHCA, we could become subject to additional regulation under PUHCA in the future. There can be no assurances that such regulation would not have a material adverse effect on us. In the event we were unable to avoid the loss of QF status for one or more of our affiliate's facilities, such an event could result in termination of a given project's power sales agreement and a default under the project subsidiary's project financing agreements, which, in the event of the loss of QF status for one or more facilities, could have a material adverse effect on us. Regulatory requirements applicable in the future to nuclear generating facilities could adversely affect the results of operations of us and MidAmerican Energy, in particular. We are subject to certain generic risks associated with utility nuclear generation, including risks arising from the operation of nuclear facilities and the storage, handling and disposal of high-level and low-level radioactive materials; risks of a serious nuclear incident; limitations on the amounts and types of insurance commercially available in respect of losses that might arise in connection with nuclear operations; and uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. The Nuclear Regulatory Commission has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. Revised safety requirements promulgated by the Nuclear Regulatory Commission have, in the past, necessitated substantial capital expenditures at nuclear plants, including those in which MidAmerican Energy has an ownership interest, such as the Quad Cities units, and additional such expenditures could be required in the future. CE ELECTRIC UK Since 1990, the electricity generation, supply and distribution industries in Great Britain have been privatized, and competition has been introduced in generation and supply. Electricity is produced by generators, transmitted through the national grid transmission system by The National Grid Company plc (or in Scotland by Scottish Power or Scottish Hydro Electric) and distributed to customers by the fourteen Distribution License Holders, which we refer to as DLHs, in their respective distribution service areas. During the fourth quarter of 1998, the market for supplying electricity began to be opened to competition through a phased-in program. This program, which proceeded by geographic areas, was completed in 1999. Under the Utilities Act 2000, the public electricity supply license created pursuant to the Electricity Act 1989 was replaced by two separate licenses--the electricity distribution license and the electricity supply license. When the relevant provision of the Utilities Act 2000 became effective on October 1, 2001, the public electricity supply licenses formerly held by Northern Electric plc and Yorkshire Electricity Group plc were split so that separate subsidiaries held licenses for electricity distribution and electricity supply. In order to comply with the Utilities Act 2000 and to facilitate this license splitting, Northern Electric plc and Yorkshire Electricity Group plc (and each of the other holders of the former public 81 electricity supply licenses) each made a statutory transfer scheme that was approved by the Secretary of State for Trade and Industry. These schemes provided for the transfer of certain assets and liabilities to the licensed subsidiaries. This occurred on October 1, 2001, a date set by the Secretary of State for Trade and Industry. As a consequence of these schemes, the electricity distribution businesses of Northern Electric plc and Yorkshire Electricity Group plc were transferred to NED and YED, respectively. NED and YED are each holders of an electricity distribution license. The residual elements of the Electricity Supply licenses were transferred to Innogy in connection with the sale of Northern Electric's electricity and gas supply business to Innogy and the retention by Innogy of the electricity and gas supply business of Yorkshire Electricity, all as a part of the Northern Electric/Yorkshire Electricity Swap on September 21, 2001. Each of the DLHs is required to offer terms for connection to its distribution system and for use of its distribution system to any person. In providing the use of its distribution system, a DLH must not discriminate between users, nor may its charges differ except where justified by differences in cost. Most revenue of the DLHs is controlled by a distribution price control formula which is set out in the license of each DLH. It has been the practice of Ofgem (and its predecessor body, the Office of Electricity Regulation), to review the formula periodically and to reset it at intervals of five year duration. The formula may be varied with the consent of the DLH, or if the DLH does not consent, following a review by the U.K.'s competition authority. The periodic review during which the formula is reset is the process by which Ofgem determines its view of the future allowed revenue of DLHs. The procedure and methodology adopted at a price control review is at the reasonable discretion of Ofgem. At the last such review, concluded in 1999 and effective April 2000, Ofgem's judgment of the future allowed revenue of licensees was based upon, among other things: o the actual operating costs of each of the licensees; o the operating costs which each of the licensees would incur if it were as efficient as, in Ofgem's judgment, the most efficient licensee; o the regulatory value to be ascribed to each of the licensees' distribution network assets; o the allowance for depreciation of the distribution network assets of each of the licensees; o the rate of return to be allowed on investment in the distribution network assets by all licensees; and o the financial ratios of each of the licensees and the license requirement for each licensee to maintain an investment grade status. As a result of the most recent review, the allowed revenue of Northern Electric's distribution business was reduced by 24%, in real terms, and the allowed revenue of Yorkshire Electricity's distribution business was reduced by 23%, in real terms, with effect from April 1, 2000. The range of reductions for all licensees in Great Britain was between 4% and 33%. For the duration of the current regulatory period, the 1999 review also requires that regulated distribution revenue per unit be increased or decreased each year by RPI-Xd, where the factor "RPI" is the United Kingdom retail price index reflecting the average of the 12-month inflation rates recorded for each month in the previous July to December period and "Xd" is an adjustment factor which was established by Ofgem at the 1999 review (and continues to be set) at 3%. The formula also takes account of the changes in system electrical losses, the number of customers connected and the voltage at which customers receive the units of electricity distributed. This formula determines the maximum average price per unit of electricity distributed (in pence per kilowatt hour) which a DLH is entitled to charge. The distribution price control formula permits DLHs to receive additional revenues due to increased distribution of units and a predetermined increase in customer numbers. Once set, the price control formula does not, during its duration, seek to constrain the profits of a DLH from year to year. It is a control on revenue that operates independently of most of the DLH's costs. During the duration of the price control, additional cost savings or costs, if any, therefore directly impact profit. 82 The distribution prices allowable under the current distribution price control formula are expected to be reviewed by Ofgem in time for a revised formula to take effect from April 1, 2005. The formula may be further reviewed at other times in the discretion of the regulator. Ofgem has recently modified the licenses of all DLHs to implement an "Information and Incentives Project" under which up to 2% of a DLH's regulated income depends upon the performance of the DLH's distribution system as measured by the number and duration of customer interruptions and upon the level of customer satisfaction monitored by Ofgem. Under the Utilities Act 2000, GEMA is able to impose financial penalties on license holders who contravene (or have in the past contravened) any of their license duties or certain of their duties under the Electricity Act 1989 or who are failing (or have in the past failed) to achieve a satisfactory performance in relation to the individual standards of performance prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the licensee's revenue. CALENERGY GENERATION--DOMESTIC Each of the operating domestic power facilities owned through CE Gen meets the requirements promulgated under PURPA to be qualifying facilities, except for Cordova Energy. Qualifying facility or "QF" status under PURPA provides two primary benefits. First, regulations under PURPA exempt QFs from PUHCA, the FERC rate regulation under the Federal Power Act and the state laws concerning rates of electric utilities and financial and organization regulations of electric utilities. Second, the FERC's regulations promulgated under PURPA require that (1) electric utilities purchase electricity generated by QFs, the construction of which commenced on or after November 9, 1978, at a price based on the purchasing utility's Avoided Cost of Energy, (2) electric utilities sell back-up, interruptible, maintenance and supplemental power to QFs on a non-discriminatory basis, and (3) electric utilities interconnect with QFs in their service territories. There can be no assurance that the QF status of such CalEnergy Generation--Domestic facilities will be maintained. CORDOVA ENERGY Cordova Energy is exempt from regulation under PUHCA because it is an exempt wholesale generator. PUHCA provides that an exempt wholesale generator is not considered to be an electric utility company. An exempt wholesale generator is permitted to sell capacity and electricity in the wholesale markets, but not in the retail markets. If an exempt wholesale generator is subject to a "material change" in facts that might affect its continued eligibility for exempt wholesale generator status, within 60 days of such material change, the exempt wholesale generator must (1) file a written explanation of why the material change does not affect its exempt wholesale generator status, (2) file a new application for exempt wholesale generator status, or (3) notify the FERC that it no longer wishes to maintain exempt wholesale generator status. CALENERGY GENERATION--FOREIGN The Philippine Congress has passed the Electric Power Industry Reform Act of 2001, which is aimed at restructuring the Philippine power industry, privatization of the NPC and introduction of a competitive electricity market, among other initiatives. The implementation of the bill may have an adverse impact on the Company's future operations in the Philippines and the Philippines power industry as a whole, the effect of which is not yet determinable and estimable. In connection with an interagency review of approximately 40 independent power project contracts in the Philippines, the Casecnan Project (along with four other unrelated projects) has reportedly been identified as raising legal and financial questions and, with those projects, has been prioritized for renegotiation. The Philippine Projects, have also reportedly been identified as raising financial questions. No written report has yet been issued with respect to the interagency review, and the timing and nature of steps, if any, that the Philippine Government may take in this regard are not known. To the extent disputes arise under the Philippine Projects' agreements with respect to the Philippines Projects' 83 obligations, rights and remedies thereunder, such disputes will be determined by international arbitration in a neutral forum conducted in accordance with the rules of the International Chamber of Commerce or UNCITRAL, as applicable. Representatives of CE Casecnan, together with certain current and former Philippine government officials, also have been requested to appear, and have appeared, before a Philippine Senate committee which has independently raised questions and made allegations with respect to the Casecnan Project's tariff structure and implementation. No further hearings are scheduled at this time. HOMESERVICES The Department of Housing and Urban Development and the Federal Home Administration, or FHA, lender guidelines prohibit the collection of a broker-fee from FHA financed buyers where the FHA lender is affiliated with the real estate broker or where there is no buyer-broker agreement. The majority of HomeServices' subsidiaries have been charging a broker fee to their buyers and sellers, except in circumstances where the FHA guidelines prohibit it. Nonetheless, HomeServices is working with the FHA to change the lenders' guidelines to permit collection of these fees. PIPELINE SAFETY REGULATION Our pipeline operations are subject to regulation by the United States Department of Transportation under the Natural Gas Pipeline Safety Act of 1969, as amended, relating to design, installation, testing, construction, operation and management of our pipeline system. The Natural Gas Pipeline Safety Act requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain inspection and maintenance plans and to comply with such plans. We conduct internal audits of our facilities every four years, with more frequent reviews of those we deem higher risk. The United States Department of Transportation routinely audits our pipeline. Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis. The aging pipeline infrastructure in the United States has led to heightened regulatory and legislative scrutiny of pipeline safety and integrity practices. The Natural Gas Pipeline Safety Act was amended by the Pipeline Safety Act of 1992 to require the Department of Transportation's Office of Pipeline Safety to consider protection of the environment when developing minimum pipeline safety regulations. In addition, the amendments require that the Department of Transportation issue pipeline regulations concerning, among other things, the circumstances under which emergency flow restriction devices should be required, training and qualification standards for personnel involved in maintenance and operation, and requirements for periodic integrity inspections, as well as periodic inspection of facilities in navigable waters which could pose a hazard to navigation or public safety. In addition, the amendments narrowed the scope of our gas pipeline exemption pertaining to underground storage tanks under the Resource Conservation and Recovery Act. While the effect of new legislation, which has been passed by Congress but not yet signed by the President, on us is still being determined, we expect to spend the capital or make the operational changes necessary to comply with all pipeline integrity legislation. Northern Natural Gas and Kern River currently project that they will make significant expenditures to meet these new regulations. We believe our subsidiaries' pipeline operations comply in all material respects with the Natural Gas Pipeline Safety Act, but the industry, including our subsidiaries, could be required to incur additional capital expenditures and increased costs depending upon final regulations issued by the Department of Transportation under the Natural Gas Pipeline Safety Act. ENVIRONMENTAL REGULATION DOMESTIC We are subject to a number of federal, state and local environmental laws and health and other regulations affecting many aspects of our present and future operations in the United States. Such laws and regulations generally require us to obtain and comply with a wide variety of licenses, permits and 84 other approvals. No assurance can be given that in the future all necessary permits and approvals will be obtained or renewed and all applicable statutes and regulations complied with. In addition, regulatory compliance for the construction of new power facilities and gas pipeline operations is a costly and time-consuming process, and intricate and rapidly changing environmental regulations may require major expenditures for permitting or other compliance issues and may create the risk of expensive delays or material impairment of project value if projects cannot function as planned due to changing regulatory requirements or local opposition. We believe that our operating power facilities and gas pipeline operations are currently in material compliance with all applicable federal, state and local laws and regulations. However, we cannot assure you that existing regulations will not be revised or that new regulations will not be adopted or become applicable to us which could have an adverse impact on our operating costs and operations. In accordance with the requirements of Section 112 of the Clean Air Act Amendments of 1990, the EPA has performed a study of the hazards to public health reasonably anticipated to occur as a result of emissions of hazardous air pollutants by electric utility steam generating units. In December 2000, after research and monitoring of mercury emissions, the EPA concluded that it is appropriate and necessary to regulate mercury emissions from coal-fired generating units. It is anticipated that rules will be developed to regulate these emissions in 2003 or 2004 with reductions of mercury emissions effective in 2007. The cost to MidAmerican Energy of reducing its mercury emissions would depend on available technology at the time, but could be material. In July 1997, the EPA adopted revisions to the National Ambient Air Quality Standards for ozone and a new standard for fine particulate matter. Based on data to be obtained from monitors located throughout each state, the EPA will determine which states have areas that do not meet the air quality standards (i.e., areas that are classified as nonattainment). The standards were subjected to legal proceedings, and in February 2001, United States Supreme Court upheld the constitutionality of the standards, though remanding the issue of implementation of the ozone standard to the EPA. As a result of a decision rendered by the United States Circuit Court of Appeals for the District of Columbia, the EPA is moving forward in implementation of the ozone and fine particulate standards and is analyzing existing monitoring data to determine attainment status. The impact of the new standards on us is currently unknown. MidAmerican Energy's generating stations may be subject to emission reductions if the stations are located in nonattainment areas or contribute to nonattainment areas in other states. As part of state implementation plans to achieve attainment of the standards, MidAmerican Energy could be required to install control equipment on its generating stations or decrease the number of hours during which these stations operate. The ozone and fine particulate matter standards could also, in whole or in part, be superceded by one of a number of multi-pollutant emission reduction proposals currently under consideration at the federal level. In July 2002, legislation was introduced in Congress to implement the Administration's "Clear Skies Initiative," calling for the reduction in emissions of sulfur dioxide, nitrogen oxides and mercury through a cap-and-trade system. Reductions would begin in 2008 with additional emission reductions being phased in through 2018. While legislative action is necessary for this or other multi-pollutant emission reduction initiatives to become effective, MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions required to meet emissions reductions of this nature. Since the adoption of the United Nations Framework on Climate Change in 1992, there has been a worldwide effort to reduce greenhouse gas, or GHG, emissions to 1990 levels or below. In December 1997, the U.S. participated in the Kyoto, Japan negotiations, where the basis of a Climate Change treaty was formulated. Under the treaty, known as the Kyoto Protocols, the United States would have an overall reduction target of 7% in GHG emissions from 1990 levels by 2008-2012. To date, the Senate has not ratified the Kyoto Protocols. In addition, President Bush has recently indicated his opposition to the Kyoto Protocols. However, given the widespread international and public support for the reduction of GHG emissions, it is not unlikely that GHG reduction regulations will come to pass, even if not related to the Kyoto Protocols. At this time, we cannot estimate the potential impact of such regulations on us or our subsidiaries. 85 In 2001, the state of Iowa passed legislation that, in part, requires rate-regulated utilities to develop a multi-year plan and budget for managing regulated emissions from their generating facilities in a cost-effective manner. MidAmerican Energy's proposed plan and associated budget was filed with the IUB on April 1, 2002, in accordance with state law. MidAmerican Energy expects the IUB to rule on the prudence of such plan during the first or second quarter of 2003. MidAmerican Energy is required to file updates to such plan at least every two years. MidAmerican Energy's proposed plan provides its projected air emission reductions considering current proposals being debated at the federal level and describes a coordinated long-range plan to achieve these air emission reductions. MidAmerican Energy's proposed plan also provides specific actions to be taken at each coal-fired generating facility and related costs and timing for each action. MidAmerican Energy's proposed plan outlines $732.0 million in environmental investments to existing coal-fired generating units, some of which are jointly owned, over a nine-year period from 2002 through 2010. MidAmerican Energy's share of these investments is $546.6 million, $67.9 million of which is projected to be incurred during the 2002-2005 rate freeze period. Such plan also identifies expenses that will be incurred at the generating facilities to operate and maintain the environmental equipment installed as a result of such plan. Following the expiration on December 31, 2005 of the rate settlement agreement which was approved by the IUB on December 21, 2001, MidAmerican Energy's proposed plan suggests the use of an adjustment mechanism for recovery of such plan's costs, similar to the tracking mechanisms for cost recovery of renewable energy and energy efficiency expenditures that are presently part of MidAmerican Energy's regulated electric rates. See "Regulation--MidAmerican Energy" for a discussion of the settlement agreement. Federal, state and local environmental laws and regulations currently have, and future modifications may have, the effect of increasing the lead time for the construction of new facilities, significantly increasing the total cost of new facilities, requiring modification of our existing facilities, increasing the risk of delay on construction projects, increasing our cost of waste disposal and possibly reducing the reliability of service we provide and the amount of energy available from our facilities. Any of such items could have a substantial impact on amounts required to be expended by us in the future. Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate past releases or threatened releases of hazardous or toxic substances or petroleum products located at the facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by a party in connection with any releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict and joint and several. The cost of investigation, remediation or removal of substances may be substantial. In connection with the ownership and operation of facilities, we and our subsidiaries may be liable for such costs. Even at those sites where we are not presently aware of any contamination that currently requires remediation, given the use of hazardous substances at each facility and their locations, often within areas that have a long history of industrial use, it is possible that we will discover currently unknown contamination or that future spills or other causes of contamination will occur. As a result, it is possible that we may become liable for remediation. The EPA and state environmental agencies have determined that contaminated wastes remaining at decommissioned manufactured gas plant facilities may pose a threat to the public health or the environment if these contaminants are in sufficient quantities and at such concentrations as to warrant remedial action. MidAmerican Energy has evaluated or is evaluating 27 properties that were, at one time, sites of gas manufacturing plants in which it may be a potentially responsible party. The purpose of these evaluations 86 is to determine whether waste materials are present, whether the materials constitute an environmental or health risk, and whether MidAmerican Energy has any responsibility for remedial action. Investigations of the sites are at various stages, and MidAmerican Energy has conducted ten removal actions to date and is continuing to evaluate several of the sites to determine the appropriate site remedies, if any, necessary to obtain site closure from the agencies. MidAmerican Energy estimates the range of possible costs for investigation, remediation and monitoring for the sites discussed above to be $16 million to $30 million. MidAmerican Energy's estimate of the probable cost for these sites as of September 30, 2002 was $18 million. The estimate consists of $1 million for investigation costs, $6 million for remediation costs, $9 million for ground water treatment and monitoring costs and $2 million for closure and administrative costs. This estimate has been recorded as a liability and a regulatory asset for future recovery. MidAmerican Energy projects that these amounts will be paid or incurred over the next five years. Accruals for probable remediation costs are established based on site-specific estimates and are evaluated and revised quarterly as appropriate based on additional information obtained during investigation and remedial activities. The estimated recorded liability could change materially based on facts and circumstances derived from site investigations, changes in required remedial action and changes in technology relating to remedial alternatives. Insurance recoveries have been received for some of the sites under investigation. Those recoveries are intended to be used principally for accelerated remediation, as specified by the IUB, and are recorded as a regulatory liability. Additionally, as viable potentially responsible parties are identified, those parties are evaluated for potential contributions, and cost recovery is pursued when appropriate. Although the timing of potential incurred costs and recovery of costs in MidAmerican Energy's rates may affect the results of operations in individual periods, management believes that the outcome of issues related to the remediation of former manufactured gas plant facilities will not have a material adverse effect on our financial position, results of operations or cash flows. UNITED KINGDOM CE Electric UK's businesses are subject to numerous regulatory requirements with respect to the protection of the environment. The United Kingdom government introduced new contaminated land legislation in April 2000 that requires companies to: o put in place a program for investigating the company's history to identify problem sites for which it is responsible; o make a clear commitment to meeting responsibilities for cleaning up those sites; o provide funding to make sure that this can happen; and o make commitments public. CE Electric UK is in the process of completing the evaluation work on the three sites that may be subject to the legislation. Exploratory work with an environmental remediation company is in progress on these sites. The Environmental Protection Act (Disposal of PCB's and other Dangerous Substances) Regulations 2001 were introduced on May 5, 2000. The regulations required that transformers containing over 50 parts per million of PCB's and other dangerous substances be registered with the Environment Agency by July 31, 2000. Transformers containing 500 parts per million had to be de-contaminated by December 31, 2000. CE Electric UK has registered 380 items above 50 parts per million, decontaminated 120 items and informed the Environment Agency that it is continuing with its sampling, labeling and registration program. These regulations are not expected to have a material impact on us. The Groundwater Regulations seek to prevent listed hazardous substances from entering groundwater and strengthens the United Kingdom Environment Agency's powers to require additional 87 protective measures, especially in areas of important groundwater supplies. Mineral oils and hydrocarbons are included in the list of more tightly controlled substances, or List I substances. This affects the high voltage fluid filled electricity cable network incorporating an insulating fluid that is currently in List I. The existing voluntary Operating Code of Practice, as agreed between the Agency and the Electricity Supply Industries, is undergoing revision through the services of the Electricity Association to address the regulatory changes. The existing voluntary Operating Code of Practice is, and any revised Operating Code of Practice will be, incorporated into the operating practices of NED and YED. Any revisions which are made are not expected to have a material impact on us. The Oil Storage Regulations began to become effective in 2002 and require the introduction of secondary containment measures (bunding) for all above ground oil storage locations where the capacity is more than 200 liters. The primary containers must be in sound condition, leak free, and positioned away from vehicle traffic routes. The secondary containment must be impermeable to water and oil (without drainage valve) and be subject to routine maintenance. The capacity of the bund must be sufficient to hold up to 110% of the largest stored vessel or 25% of the maximum stored capacity, whichever is the greater. The full impact of the regulations is being phased in over the next three years. On March 1, 2002, these regulations came into effect for all new oil storage facilities. On September 1, 2003, the regulations become effective for existing storage facilities at "significant risk" (i.e. within 10 meters of a water course), and on September 1, 2005 the regulations come into effect for all remaining storage facilities. A detailed study of the impacts has been carried out and a plan of action prepared to ensure compliance. We expect that the cost of compliance with such regulations will not have a material adverse impact. The Electricity Act 1989 obligates either the United Kingdom Secretary of State or the Director General of Electric Supply to take into account the effect of electricity generation, transmission and supply activities on the physical environment when approving applications for the construction of overhead power lines. The Electricity Act requires CE Electric UK to consider the desirability of preserving natural beauty and the conservation of natural and man-made features of particular interest when it formulates proposals for development in connection with certain of its activities. CE Electric UK mitigates the effects its proposals have on natural and man-made features and administers an environmental assessment when it intends to lay cables, construct overhead lines or carry out any other development in connection with its licensed activities. We expect that the cost of compliance with these obligations and the mitigation thereof will not have a material adverse impact. CE Electric UK's policy is to carry out its activities in such a manner as to minimize the impact of its works and operations on the environment, and in accordance with environmental legislation and good practice. There have not been any significant regulatory environmental compliance issues and there are no material legal or administrative proceedings pending against CE Electric UK with respect to any environmental matter. Environmental laws and regulations in the United Kingdom currently have, and future modifications may have, the effect of requiring modification of CE Electric UK's facilities, increasing its cost of waste disposal and possibly reducing the reliability of service it provides and the amount of energy available from its facilities. Any of such items could have a substantial impact on amounts required to be expended by CE Electric UK in the future. PHILIPPINES On June 23, 1999, the Philippine Congress enacted the Philippine Clean Air Act of 1999. The related implementing rules and regulations were adopted in November 2000. The law as written would require the Upper Mahiao, Mahanagdong and Malitbog projects, which we collectively refer to as the Leyte Projects, to comply with a maximum discharge of 200 grams of hydrogen sulfide per gross megawatt hour of output by June 2004. On November 13, 2002, the Secretary of the Philippine Department of Environmental and Natural Resources issued Memorandum Circular, or MC, 2002-13 designating geothermal areas as "special airsheds." PNOC-EDC has advised us that the MC exempts the Upper Mahiao, Mahanagdong and Malitbog plants from the need to comply with the point-source emission standards of the Clean Air Act. The Leyte Projects intend to seek confirmation of the impact of the MC from PNOC-EDC and from the Philippine Department of Environmental and Natural Resources. 88 NUCLEAR REGULATION Each licensee of a nuclear facility is required to provide financial assurance for the cost of decommissioning its licensed nuclear facility. In general, decommissioning of a nuclear facility means the obligation to safely remove the facility from service and restore the property to a condition allowing unrestricted use by the operator. Based on information presently available, we expect to contribute approximately $41 million during the period 2002 through 2006 to an external trust established for the investment of funds for decommissioning the Quad Cities station. Approximately 55% of the fair value of the trust's funds are now invested in domestic corporate debt and common equity securities. The remainder is invested in investment grade municipal and United States Treasury bonds. The Quad Cities station decommissioning costs properly charged to Iowa customers are included in base rates, and recovery of any increases in those amounts must be sought through the normal ratemaking process. As a result of a July 31, 2002 Settlement Agreement and Release relating to a restructuring of the power purchase contract between MidAmerican Energy and NPPD, MidAmerican Energy will no longer be accruing for decommissioning costs for the Cooper Nuclear Station. Refer to note 12H of our notes to consolidated financial statements for the nine months ended September 30, 2002 contained in this prospectus for a discussion of the settlement and contract restructuring. MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in the Quad Cities station through a combination of insurance purchased by Exelon Generation Company, LLC (the operator and joint owner of the Quad Cities station), insurance purchased directly by MidAmerican Energy and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988. The general types of coverage are: nuclear liability, property coverage and nuclear worker liability. Exelon Generation purchased nuclear liability insurance for the Quad Cities station in the maximum available amount of $200 million. In accordance with the Price-Anderson Amendments Act of 1988, excess liability protection above that amount is provided by a mandatory industry-wide Secondary Financial Protection program under which the licensees of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the United States. Currently, MidAmerican Energy's aggregate maximum potential share of an assessment for the Quad Cities station is approximately $44 million per incident, payable in installments not to exceed $5 million annually. The property insurance covers property damage, stabilization and decontamination of the facility, disposal of the decontaminated material and premature decommissioning arising out of a covered loss. For the Quad Cities station, Exelon Generation purchased primary and excess property insurance protection for the combined interests in the Quad Cities station, with coverage limits totaling $2.1 billion. MidAmerican Energy also directly purchased extra expense/business interruption coverage for its share of replacement power and/or other extra expenses in the event of a covered accidental outage at the Quad Cities station. The property and related coverages purchased directly by MidAmerican Energy and by Exelon Generation, which includes the interests of MidAmerican Energy, are underwritten by an industry mutual insurance company and contain provisions for retrospective premium assessments should two or more full policy-limit losses occur in one policy year. Currently, the maximum aggregate retrospective amounts that could be assessed against MidAmerican Energy from industry mutual policies for its obligations associated with the Quad Cities station total $6.3 million. The master nuclear worker liability coverage, which was purchased by Exelon Generation for the Quad Cities station, is an industry-wide guaranteed-cost policy with an aggregate limit of $200 million for the nuclear industry as a whole, which is in effect to cover worker tort claims in nuclear-related industries. 89 LEGAL PROCEEDINGS In addition to the proceedings described below, we and our subsidiaries are currently parties to various items of litigation or arbitration, none of which are reasonably expected by us to have a material adverse effect on us. CASECNAN CONSTRUCTION ARBITRATION On February 12, 2001, the contractor for the Casecnan Project, a consortioum consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa., working together with Siemens A.G. and Sulzer Hydro Ltd., which we collectively refer to as the Contractor, filed a Request for Arbitration with the International Chamber of Commerce seeking an extension of the Guaranteed Substantial Completion Date by up to 153 days through August 31, 2001 resulting from various alleged force majeure events. In its March 20, 2001 Supplement to Request for Arbitration, the Contractor requested compensation for alleged additional costs of approximately $4 million it incurred from the claimed force majeure events to the extent it is unable to recover from its insurer. On April 20, 2001, the Contractor filed a further supplement seeking an additional compensation for damages of approximately $62 million for the alleged force majeure event (and geologic conditions) related to the collapse of the surge shaft. The Contractor also has alleged that the circumstances surrounding the placing of the Casecnan Project into commercial operation on December 11, 2001 amounted to a repudiation of the Construction Contract and has filed a claim for unspecified quantum meruit damages. CE Casecnan believes all such allegations and claims are without merit and is vigorously contesting the Contractor's claims. The arbitration is being conducted applying New York law and in accordance with the rules of the International Chamber of Commerce. Hearings have been held in connection with this arbitration in July 2001, September 2001, January 2002 and March 2002. As part of those hearings, on June 25, 2001, the arbitration tribunal temporarily enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di Roma in support of the Contractor's obligations to CE Casecnan for delay liquidated damages. As a result of the continuing nature of that injunction, on April 26, 2002, CE Casecnan and the Contractor mutually agreed that no demands would be made on the Banca di Roma demand guaranty except pursuant to an arbitration award. As of September 30, 2002, however, CE Casecnan has received approximately $6.0 million of liquidated damages from demands made on the demand guarantees posted by Commerzbank on behalf of the Contractor. In November 2002, hearings were held on the Contractor's claim with respect to the alleged unenforceability of the delay liquidated damages clause. On November 7, 2002, the International Chamber of Commerce issued the arbitration tribunal's partial award with respect to the Contractor's force majeure and geologic conditions claims. The arbitration panel awarded the Contractor 18 days of schedule relief in the aggregate for all of the force majeure events and awarded the Contractor $3.8 million with respect to the cost of the collapsed surge shaft. All of the Contractor's other claims that were heard by the arbitration tribunal were denied. Further hearings on the Contractor's repudiation and quantum meruit claims and certain other matters are scheduled for January 2003. These claims, and the alleged unenforceability of the delay liquidated damages clause, have not been ruled on by the arbitration tribunal. CASECNAN SHAREHOLDER LITIGATION Pursuant to the share ownership adjustment mechanism in the CE Casecnan shareholder agreement, which is based upon pro forma financial projections of the Casecnan Project prepared following commencement of commercial operations, in February 2002, CE Casecnan, through its indirect wholly owned subsidiary CE Casecnan Ltd., advised the minority shareholder LaPrairie Group Contractors (International) Ltd., or LPG, that our indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against, inter alia, CE Casecnan Ltd. and us. In the complaint, LPG seeks compensatory and punitive damages for alleged breaches of the shareholder agreement and alleged breaches of fiduciary duties allegedly owed by CE Casecnan Ltd. and us to LPG. The complaint also seeks injunctive relief against all defendants and a declaratory judgment that LPG is entitled to maintain its 15% interest in CE Casecnan. The impact, if any, of this litigation on us cannot be determined at this time. 90 CASECNAN NIA ARBITRATION Under the terms of an agreement between CE Casecnan and NIA regarding the Casecnan Project, NIA has the option of timely reimbursing CE Casecnan directly for certain taxes CE Casecnan has paid. If NIA does not so reimburse CE Casecnan, the taxes paid by CE Casecnan result in an increase in the Water Delivery Fee under the Casecnan Project agreement. The payment of certain other taxes by CE Casecnan results automatically in an increase in the Water Delivery Fee. As of September 30, 2002, CE Casecnan has paid approximately $54.4 million in taxes which as a result of the foregoing provisions had resulted in an increase in the Water Delivery Fee. NIA has failed to pay the portion of the Water Delivery Fee each month which relates to the payment of these taxes by CE Casecnan. As a result of this non-payment, on August 19, 2002, CE Casecnan filed a Request for Arbitration against NIA, seeking payment of such portion of the Water Delivery Fee and enforcement of the relevant provision of the Casecnan Project agreement going forward. The arbitration will be conducted in accordance with the rules of the International Chamber of Commerce. MALITBOG ARBITRATION On October 16, 2000, VGPC commenced arbitration against PNOC-EDC by serving it with a Notice of Arbitration and Statement of Claim alleging that PNOC-EDC breached the Malitbog energy conversion agreement by improperly characterizing certain No Fault Outages as Forced Outage Hours and then deducting them from the total number of hours each month for purposes of determining payments due to VGPC. On December 22, 2000, VGPC filed an Amended Statement of Claim pursuant to which VGPC added a claim that PNOC-EDC breached the Malitbog agreement by refusing to accept VGPC's specified Nominated Capacity for contract years July 25, 1999 to July 25, 2000, and July 25, 2000 to July 25, 2001. A Second Amended Statement of Claim was filed on March 9, 2001 to add an issue related to the proper duration of annual scheduled maintenance on the Malitbog plant. VGPC intends to vigorously pursue its claims in this proceeding. Hearings were conducted from June 24, 2002 to July 5, 2002 in Sydney, Australia. On November 27, 2002, the arbitration panel issued a unanimous award which states that PNOC-EDC is obligated to pay for all the hours that VGPC spent on Scheduled Maintenance in the year 2000 to the extent that the total number of days of Scheduled Outage has not exceeded 45 days. The award also orders PNOC-EDC to accept VGPC's Nominated Capacity for project years through 2002 and to pay all amounts owed to VGPC in this regard. Furthermore, the award declares that VGPC can only declare no fault outages if VGPC is not at fault, but places the burden of proof in this regard on PNOC-EDC. Also, the award orders VGPC to pay PNOC-EDC $1.6 million in costs. The award orders VGPC and PNOC-EDC to work together to attempt to agree on the amounts owed under the terms of the order and if the parties cannot reach an agreement, each party is to make submissions to the arbitration panel by the middle of January 2003. MAHANAGDONG ARBITRATION On September 25, 2002, CE Luzon commenced arbitration against PNOC-EDC alleging that PNOC-EDC breached the Mahanagdong energy conversion agreement by refusing to accept CE Luzon's Nominated Capacity for contract years July 25, 2001 to July 25, 2002 and July 25, 2002 to July 25, 2003. CE Luzon intends to vigorously pursue its claim in this proceeding. The arbitration will be conducted in accordance with the rules of the International Chamber of Commerce. PIPELINE LITIGATION In 1998, the United States Department of Justice informed the then current owners of Kern River and Northern Natural Gas 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 such entities and certain of their subsidiaries including Kern River and Northern Natural Gas. Mr. Grynberg has also filed claims against numerous 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, civil penalties, attorneys' fees and costs. On April 9, 1999, the United States Department of Justice announced that it 91 declined to intervene in any of the Grynberg qui tam cases, including the actions filed against Kern River and Northern Natural Gas in the United States District Court for the District of Colorado. On October 21, 1999, the Panel on Multi-District Litigation transferred the Grynberg qui tam cases, including the ones filed against Kern River and Northern Natural Gas, to the United States District Court for the District of Wyoming for pre-trial purposes. Motions to dismiss the complaint, filed by various defendants including Northern Natural Gas and Williams, which was the former owner of Kern River, were denied on May 18, 2001. In connection with the purchase of Kern River from Williams in March 2002, Williams agreed to indemnify us against any liability for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. No such indemnification was obtained in connection with the purchase of Northern Natural Gas in August 2002. We believe that the Grynberg cases filed against Kern River and Northern Natural Gas are without merit and Williams, on behalf of Kern River pursuant to its agreement to indemnify us, and Northern Natural Gas, intends to defend these actions vigorously. On June 8, 2001, a number of interstate pipeline companies, including Kern River and Northern Natural Gas, were named as defendants in a nationwide class action lawsuit which had been pending in the 26th Judicial District, District Court, Stevens County Kansas, Civil Department against other defendants, generally pipeline and gathering companies, since May 20, 1999. The plaintiffs allege that the 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 November 2001, Kern River and Northern Natural Gas, along with the coordinating defendants, filed a motion to dismiss under Rules 9B and 12B of the Kansas Rules of Civil Procedure. In January 2002, Kern River and most of the coordinating defendants filed a motion to dismiss for lack of personal jurisdiction. The court has yet to rule on these motions. The plaintiffs filed for certification of the plaintiff class on September 16, 2002. Williams has agreed to indemnify us against any liability associated with Kern River for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. Williams, on behalf of Kern River and other entities, anticipates joining with Northern Natural Gas and other defendants in contesting certification of the plaintiff class. Kern River and Northern Natural Gas believe that this claim is without merit and that Kern River's and Northern Natural Gas' gas measurement techniques have been in accordance with industry standards and its tariff. 92 MANAGEMENT OUR DIRECTORS AND EXECUTIVE OFFICERS Our current executive officers and directors and their positions are as follows:
NAME POSITION ------------------------ ------------------------------------------------------------ David L. Sokol Chairman of the Board, Chief Executive Officer and Director Gregory E. Abel President, Chief Operating Officer and Director Patrick J. Goodman Senior Vice President and Chief Financial Officer Douglas L. Anderson Senior Vice President and General Counsel Keith D. Hartje Senior Vice President and Chief Administrative Officer Warren E. Buffett Director Walter Scott, Jr. Director Marc D. Hamburg Director W. David Scott Director Edgar D. Aronson Director John K. Boyer Director Stanley J. Bright Director Richard R. Jaros Director
Executive officers are elected annually by the Board of Directors. There are no family relationships among the executive officers, nor any arrangements or understanding between any executive officer and any other person pursuant to which the executive officer was selected. Set forth below is certain information with respect to each of the foregoing executive officers and directors: DAVID L. SOKOL, 46, Chairman of the Board of Directors and Chief Executive Officer. Mr. Sokol has been CEO since April 19, 1993 and served as President of MEHC from April 19, 1993 until January 21, 1995. Mr. Sokol has been Chairman of the Board of Directors since May 1994 and a director since March 1991. Formerly, among other positions held in the independent power industry, Mr. Sokol served as President and Chief Executive Officer of Kiewit Energy Company, which at that time was a wholly owned subsidiary of Peter Kiewit Sons', Inc. GREGORY E. ABEL, 40, President, Chief Operating Officer and Director. Mr. Abel joined us in 1992 and initially served as Vice President and Controller. Mr. Abel is a Chartered Accountant and, from 1984 to 1992, he was employed by Price Waterhouse. As a Manager in the San Francisco office of Price Waterhouse, he was responsible for clients in the energy industry. PATRICK J. GOODMAN, 36, Senior Vice President and Chief Financial Officer. Mr. Goodman joined us in 1995, and previously served in various accounting positions including Senior Vice President and Chief Accounting Officer. Prior to joining us, Mr. Goodman was a financial manager for National Indemnity Company and a senior associate at Coopers & Lybrand. DOUGLAS L. ANDERSON, 44, Senior Vice President and General Counsel. Mr. Anderson joined us in February 1993 and has served in various legal positions including General Counsel of our independent power affiliates. From 1990 to 1993, Mr. Anderson was a corporate attorney with Fraser, Stryker, Meusey, Olson, Boyer & Bloch, P.C., a law firm in Omaha, Nebraska. Prior to that Mr. Anderson was a principal in the firm of Anderson and Anderson. 93 KEITH D. HARTJE, 52, Senior Vice President and Chief Administrative Officer. Mr. Hartje has been with MidAmerican Energy and its predecessor companies since 1973. In that time, he has held a number of positions, including General Counsel and Corporate Secretary, District Vice President for southwest Iowa operations, and Vice President, Corporate Communications. WARREN E. BUFFETT, 72, Director. Mr. Buffett has been one of our directors since March 2000. He is Chairman of the Board and Chief Executive Officer of Berkshire Hathaway. Mr. Buffett is a Director of the Coca-Cola Company, the Gillette Company and The Washington Post Company. WALTER SCOTT, JR., 71, Director. Mr. Scott has been one of our directors since June 1991. Mr. Scott was our Chairman and Chief Executive Officer from January 8, 1992 until April 19, 1993. For more than the past five years, he has been Chairman of the Board of Directors of Level 3 Communications, Inc., a successor to certain businesses of Peter Kiewit Sons', Inc. Mr. Scott is a director of Peter Kiewit Sons', Inc., Berkshire Hathaway, Burlington Resources, Inc., ConAgra, Inc., Valmont Industries, Inc., Kiewit Materials Co., Commonwealth Telephone Enterprises, Inc. and RCN Corporation. Mr. Walter Scott, Jr. is the father of Mr. W. David Scott. MARC D. HAMBURG, 53, Director. Mr. Hamburg has been one of our directors since March 2000. He has served as Vice President--Chief Financial Officer of Berkshire Hathaway since October 1, 1992 and Treasurer since June 1, 1987, his date of employment with Berkshire Hathaway. W. DAVID SCOTT, 41, Director. Mr. Scott has been one of our directors since March 2000. Mr. Scott formed Magnum Resources, Inc., a commercial real estate investment and management company, in October 1994, and has served as its President and Chief Executive Officer since its inception. Before forming Magnum Resources, Mr. Scott worked for America First Companies, Cornerstone Banking Group and Peter Kiewit Sons', Inc. Mr. Scott has been a director of America First Mortgage Investments, Inc., a mortgage REIT, since 1998. Mr. W. David Scott is the son of Mr. Walter Scott, Jr. EDGAR D. ARONSON, 68, Director. Mr. Aronson has been one of our directors since 1983. Mr. Aronson founded EDACO, Inc., a private venture capital company, in 1981 and has been President of EDACO, Inc. since that time. Prior to that, Mr. Aronson was Chairman of Dillon, Read International from 1979 to 1981 and a General Partner in charge of the International Department of Salomon Brothers Inc. from 1973 to 1979. Mr. Aronson served during 1962-1968 as Vice President consecutively in the International Departments of First National Bank of Chicago and Republic National Bank of New York. He founded the International Department of Salomon Brothers and Hutzler in 1968. JOHN K. BOYER, 58, Director. Mr. Boyer has been one of our directors since March 2000. From 1993 to date, he has been a partner with Fraser, Stryker, Meusey, Olson, Boyer & Bloch, P.C., a law firm with emphasis on corporate, commercial, federal, state and local taxation law. STANLEY J. BRIGHT, 62, Director. Mr. Bright is our Vice Chairman and was Chairman and Chief Executive Officer of MidAmerican Energy from July 1, 1995 until March 1999. Mr. Bright joined Iowa-Illinois Gas and Electric Company (a predecessor of MidAmerican Energy) as Vice President and Chief Financial Officer in 1986, became a director in 1987, President and Chief Operating Officer in 1990, and Chairman and Chief Executive Officer in 1991. RICHARD R. JAROS, 50, Director. Mr. Jaros has been one of our directors since March 1991. Mr. Jaros served as our President and Chief Operating Officer from January 8, 1992 to April 19, 1993 and as Chairman of the Board from April 19, 1993 to May 1994. Until July 1997, Mr. Jaros was Executive Vice President and Chief Financial Officer of Peter Kiewit Sons', Inc. and President of Kiewit Diversified Group, Inc., which is now Level 3 Communications, Inc. From 1990 until January 8, 1992, Mr. Jaros served as a Vice President of Peter Kiewit Sons', Inc. Mr. Jaros serves as director of Commonwealth Telephone Enterprises, Inc., RCN Corporation and Level 3 Communications, Inc. 94 EXECUTIVE COMPENSATION The following table sets forth the compensation of our Chief Executive Officer and our four other most highly compensated executive officers who were employed as of December 31, 2001, which we refer to as our Named Executive Officers. Information is provided regarding our Named Executive Officers for the last three fiscal years during which they were our executive officers, if applicable.
BONUS(1) NAME AND YEAR ENDED --------------------------- PRINCIPAL POSITIONS DEC. 31, SALARY CASH STOCK ----------------------------- ------------ ----------- ------------------- ------- David L. Sokol .............. 2001 $ 750,000 $ 2,400,000 $ -- Chairman and Chief 2000 $ 750,000 $ 4,250,000 $ -- Executive Officer 1999 $ 675,000 $ 3,276,049 $ -- Gregory E. Abel ............. 2001 $ 520,000 $ 1,150,000 $ -- President and Chief 2000 $ 500,000 $ 1,100,000 $ -- Operating Officer 1999 $ 357,933 $ 1,452,234 $ -- Ronald W. Stepien ........... President, 2001 $ 400,000 $ 275,000 $ -- MidAmerican 2000 $ 370,667 $ 641,938 $ -- Energy(4) 1999 $ 350,000 $ 1,052,069 $ -- Patrick J. Goodman .......... 2001 $ 240,000 $ 260,000 $ -- Chief Financial 2000 $ 230,000 $ 1,183,071(5) $ -- Officer 1999 $ 199,279 $ 334,374 $ -- Douglas L. Anderson ......... 2001 $ 154,427 $ 200,000 $ -- General Counsel and 2000 $ 120,000 $ 591,806(5) $ -- Corporate Secretary 1999 $ 110,000 $ 40,000 $ -- OTHER RESTRICTED SECURITIES ALL NAME AND ANNUAL STOCK UNDERLYING LTIP OTHER PRINCIPAL POSITIONS COMP(2) AWARDS OPTIONS PAYOUTS COMP(3) ----------------------------- --------- ------------ ------------ ----------- ---------- David L. Sokol .............. $ -- $ -- -- $ -- $33,037 Chairman and Chief $ -- $ -- 2,199,277 $ -- $40,430 Executive Officer $ -- $ -- -- $ -- $41,519 Gregory E. Abel ............. $ -- $ -- -- $ -- $23,657 President and Chief $ -- $ -- 649,052 $ -- $27,530 Operating Officer $ -- $ -- -- $ -- $27,803 Ronald W. Stepien ........... President, $7,270 $ -- -- $316,021 $ 6,630 MidAmerican $ -- $ -- -- $ -- $ 6,630 Energy(4) $ -- $ -- 56,203 $ -- $ 6,240 Patrick J. Goodman .......... $ -- $ -- -- $ -- $13,527 Chief Financial $ -- $ -- -- $ -- $14,891 Officer $ -- $ -- 60,000 $ -- $14,719 Douglas L. Anderson ......... $ -- $ -- -- $ -- $ 6,630 General Counsel and $ -- $ -- -- $ -- $ 6,630 Corporate Secretary $ -- $ -- 5,000 $ -- $ 3,654
---------- (1) Includes amounts voluntarily deferred by the executive, if applicable. Includes various expatriate compensation items, including expatriate allowances, company provided transportation, housing and tax benefits. (2) Includes payout of earnings on Long-Term Incentive Partnership Plan. (3) Consists of 401(k) Plan contributions for 2001 for each Executive Officer listed above in the amount of $6,630. To offset its obligations under the Company's Executive Split Dollar Plan for executives whose retirement benefit cannot be fully funded through the Company's Base Retirement Plan for Salaried Employees, the Company has agreed to pay the premiums for policies of split dollar life insurance on the lives of such executives. Included in this column is the value of premiums paid in 2001 for Mr. Sokol of $25,507, for Mr. Abel of $16,569, and for Mr. Goodman of $6,705. Also included are the insurance premiums in the following amounts paid by the Company with respect to the term life insurance portion of premiums paid in 2001 for Mr. Sokol of $900, for Mr. Abel of $457 and for Mr. Goodman of $192. (4) Mr. Stepien retired effective December 31, 2001. (5) Includes cash amounts received upon cash-out of equity in connection with our acquisition by a private investor group on March 14, 2000. OPTION GRANTS IN LAST FISCAL YEAR We did not grant any options during 2001. 95 AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR END OPTION VALUES The following table sets forth the option exercises and the number of securities underlying exercisable and unexercisable options held by each of our Named Executive Officers at December 31, 2001.
UNDERLYING UNEXERCISED VALUE OF UNEXERCISED OPTIONS HELD (#) IN-THE-MONEY OPTIONS ($)(1) SHARES ACQUIRED ON ----------------------------- ---------------------------- NAME EXERCISE (#) VALUE REALIZED ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE ----------------------------- ------------------- -------------------- ------------- --------------- ------------- -------------- David L. Sokol .............. -- -- 1,970,412 228,865 N/A N/A Gregory E. Abel ............. -- -- 584,864 64,188 N/A N/A Ronald W. Stepien ........... -- -- -- -- -- -- Patrick J. Goodman .......... -- -- -- -- -- -- Douglas L. Anderson ......... -- -- -- -- -- --
---------- (1) On March 14, 2000 we were acquired by a private investor group. As a privately held company, we have no publicly traded equity securities and, consequently, our management does not believe there is a reliable method of computing the present value of the stock options granted to Messrs. Sokol and Abel as shown on the foregoing table. LONG-TERM INCENTIVE PLANS--AWARDS IN LAST FISCAL YEAR
NUMBER OF PERFORMANCE OR SHARES, UNITS OTHER PERIOD UNTIL OR OTHER MATURATION NAME RIGHTS (#)(1) OR PAYOUT THRESHOLD ($) TARGET ($)(2) MAXIMUM(#)(3) ----------------------------- --------------- ------------------- --------------- --------------- -------------- Ronald W. Stepien ........... N/A December 31, 2005 56,106 N/A N/A(3) Patrick J. Goodman .......... N/A December 31, 2005 107,212 N/A 360,000 Douglas L. Anderson ......... N/A December 31, 2005 87,769 N/A 231,640.50
---------- (1) The awards shown in the foregoing table are made pursuant to the Long-Term Incentive Partnership Plan, or LTIP, which provides that awards vest equally over five years with any unvested balances forfeited upon termination of employment unless the participant retires at or above age 55 with at least 5 years of service in which case the participant will receive any unvested portion of the award. Vested balances are paid to the participant at the time of termination. Once an award is fully vested, the participant may elect to defer or receive payment of part or all of the award. Messrs. Sokol and Abel are not participants in the LTIP. Awards are credited or reduced with annual interest or loss based on a composite of funds or indices. (2) "Target" and "Threshold" payouts are equivalent with the LTIP. (3) Because Mr. Stepien is no longer our employee, the maximum payout does not apply. COMPENSATION OF DIRECTORS All directors, excluding Messrs. Sokol, Abel, Buffett and Walter Scott, are paid an annual retainer fee of $24,000 and a fee of $500 per day for attendance at Board and Committee meetings. Directors who are our employees are not entitled to receive such fees. All directors are reimbursed for their expenses incurred in attending Board meetings. RETIREMENT PLANS We maintain a Supplemental Retirement Plan for Designated Officers, which we refer to as the Supplemental Plan, to provide additional retirement benefits to designated participants, as determined by the Board of Directors. Messrs. Sokol, Abel, Stepien and Goodman are participants in the Supplemental Plan. The Supplemental Plan provides annual retirement benefits up to sixty-five percent of a participant's Total Cash Compensation in effect immediately prior to retirement, subject to a $1 million maximum retirement benefit. "Total Cash Compensation" means the highest amount payable to a participant as monthly base salary during the five years immediately prior to retirement multiplied by 12 plus the 96 average of the participant's last three years awards under an annual incentive bonus program and special, additional or non-recurring bonus awards, if any, that are required to be included in Total Cash Compensation pursuant to a participant's employment agreement or approved for inclusion by the Board. Participants must be credited with five years service in order to be eligible to receive benefits under the Supplemental Plan. Each of our Named Executive Officers has or will have five years of credited service with us as of their respective normal retirement age and will be eligible to receive benefits under the Supplemental Plan. A participant who elects early retirement is entitled to reduced benefits under the Supplemental Plan, however, in accordance with their respective employment agreements, Messrs. Sokol and Abel are eligible to receive the maximum retirement benefit at age 47. A survivor benefit is payable to a surviving spouse under the Supplemental Plan. Benefits from the Supplemental Plan will be paid out of general corporate funds; however, through a rabbi trust, we maintain life insurance on the participants in amounts expected to be sufficient to fund the after-tax cost of the projected benefits. Deferred compensation is considered part of the salary covered by the Supplemental Plan. The supplemental retirement benefit will be reduced by the amount of the participant's regular retirement benefit under the MidAmerican Energy Company Cash Balance Retirement Plan, which we refer to as the MidAmerican Retirement Plan, that became effective January 1, 1997, and by benefits under the Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan, which we refer to as the Iowa-Illinois Supplemental Plan, as applicable. The MidAmerican Retirement Plan replaced retirement plans of predecessor companies that were structured as traditional, defined benefit plans. Under the MidAmerican Retirement Plan, each participant has an account, for record keeping purposes only, to which credits are allocated each payroll period based upon a percentage of the participant's salary paid in the current pay period. In addition, all balances in the accounts of participants earn a fixed rate of interest that is credited annually. The interest rate for a particular year is based on the constant maturity Treasury yield plus seven-tenths of one percentage point. At retirement or other termination of employment, an amount equal to the vested balance then credited to the account is payable to the participant in the form of a lump sum or a form of annuity for the entire benefit under the MidAmerican Retirement Plan. Mr. Anderson is a participant in this plan. The table below shows the estimated aggregate annual benefits payable under the Supplemental Plan and the MidAmerican Retirement Plan. The amounts exclude Social Security and are based on a straight life annuity and retirement at ages 55, 60 and 65. Federal law limits the amount of benefits payable to an individual through the tax qualified defined benefit and contribution plans, and benefits exceeding such limitation are payable under the Supplemental Plan.
TOTAL CASH ESTIMATED ANNUAL BENEFIT AGE AT RETIREMENT COMPENSATION ------------------------------------------ RETIREMENT ($) 55 60 65 ------------------------------ ------------ ------------ ------------ $ 400,000 $ 220,000 $ 240,000 $ 260,000 500,000 275,000 300,000 325,000 600,000 330,000 360,000 390,000 700,000 385,000 420,000 455,000 800,000 440,000 480,000 520,000 900,000 495,000 540,000 585,000 1,000,000 550,000 600,000 650,000 1,250,000 687,500 750,000 812,500 1,500,000 825,000 900,000 975,000 1,750,000 962,500 1,000,000 1,000,000 2,000,000 and greater 1,000,000 1,000,000 1,000,000
EMPLOYMENT AGREEMENTS Pursuant to his employment agreement Mr. Sokol serves as Chairman of our Board of Directors and Chief Executive Officer. The employment agreement provides that Mr. Sokol is to receive an annual base 97 salary of not less than $750,000, senior executive employee benefits and annual bonus awards that shall not be less than $675,000. Subject to an annual renewal provision, such agreement is scheduled to expire on August 21, 2003. The employment agreement provides that we may terminate the employment of Mr. Sokol with cause, in which case we are to pay to him any accrued but unpaid salary and a bonus of not less than the minimum annual bonus, or due to death, permanent disability or other than for cause, including a change in control, in which case Mr. Sokol is entitled to receive an amount equal to three times the sum of his annual salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years, as well as three years of accelerated option vesting plus continuation of his senior executive employee benefits (or the economic equivalent thereof) for three years. If Mr. Sokol resigns, we are to pay to him any accrued but unpaid salary and a bonus of not less than the annual minimum bonus, unless he resigns for good reason in which case he will receive the same benefits as if he were terminated other than for cause. In the event Mr. Sokol has relinquished his position as Chief Executive Officer and is subsequently terminated as Chairman of the Board due to death, disability or other than for cause, he is entitled to any accrued but unpaid salary plus an amount equal to the aggregate annual salary that would have been paid to him through the fifth anniversary of the date he commenced his employment solely as Chairman of the Board, the immediate vesting of all of his options and the continuation of his senior executive employee benefits (or the economic equivalent thereof) through this fifth anniversary. If Mr. Sokol relinquishes his position as Chief Executive Officer but offers to remain employed as the Chairman of the Board, he is to receive a special achievement bonus equal to two times the sum of his annual salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years, as well as two years of accelerated option vesting. Under the terms of separate employment agreements between us and each of Messrs. Abel and Goodman, each of such executives is entitled to receive two years base salary continuation, payments in respect of average bonuses for the prior two years and two years continued option vesting in the event we terminate his employment other than for cause. If such persons were terminated without cause, Messrs. Sokol, Abel and Goodman would currently be entitled to be paid approximately $12,375,000, $3,330,000 and $1,006,000, respectively, without giving effect to any tax related provisions. 98 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth certain information regarding beneficial ownership of the shares of our common stock and certain information with respect to the beneficial ownership of each director, our Named Executive Officers and all directors and executive officers as a group as of November 1, 2002.
NUMBER OF SHARES PERCENTAGE NAME AND ADDRESS OF BENEFICIAL OWNER (1) BENEFICIALLY OWNED (2) OF CLASS (2) ---------------------------------------------- ------------------------ ------------- Common Stock: Gregory E. Abel (3) ................... 696,433 7.02% Douglas L. Anderson ................... -- -- Edgar D. Aronson ...................... -- -- Berkshire Hathaway (4) ................ 900,942 9.71% Stanley J. Bright ..................... -- -- John K. Boyer ......................... -- -- Warren E. Buffett (5) ................. -- -- Patrick J. Goodman .................... -- -- Marc D. Hamburg (5) ................... -- -- Richard R. Jaros ...................... -- -- W. David Scott (6) .................... 624,350 6.73% Walter Scott, Jr. (7) ................. 5,000,000 53.87% David L. Sokol (8) .................... 1,692,967 15.89% All directors and executive officers as a group (13 persons) ................. 8,914,692 78.96%
---------- (1) Unless otherwise indicated, each address is c/o us at 666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309. (2) Includes shares which the listed beneficial owner is deemed to have the right to acquire beneficial ownership of under Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days. (3) Includes options to purchase 640,493 shares of common stock which are exercisable within 60 days. (4) Such beneficial owner's address is 1440 Kiewit Plaza, Omaha, Nebraska 68131. (5) Excludes 900,942 shares of common stock held by Berkshire Hathaway of which beneficial ownership of such shares is disclaimed. (6) Includes shares held by trusts for the benefit of or controlled by W. David Scott. Such beneficial owner's address is 402 South 36th Street, Suite 800, Omaha, Nebraska 68131. (7) Excludes 3 million shares held by family members and family controlled trusts and corporations ("Scott Family Interests"), including the 624,350 shares shown as beneficially owned by W. David Scott in the table above, as to all of which shares Mr. Walter Scott disclaims beneficial ownership. Such beneficial owner's address is 1000 Kiewit Plaza, Omaha, Nebraska 68131. (8) Includes options to purchase 1,368,762 shares of common stock which are exercisable within 60 days. The terms of our Zero Coupon Convertible Preferred Stock held by Berkshire Hathaway entitle the holder thereof to elect two members of our Board of Directors. The Zero Coupon Convertible Preferred Stock does not vote as to the election of any other members of our Board of Directors. Mr. Sokol's employment agreement gives him the right during the term of his employment to serve as a member of the Board of Directors and to designate two additional directors. 99 Pursuant to a shareholders agreement, following March 14, 2003, Walter Scott, Jr. or any of the Scott Family Interests would be able to require Berkshire Hathaway to purchase, for an agreed value or an appraised value, any or all of Walter Scott, Jr.'s and the Scott Family Interests' shares of our common stock, provided that Berkshire Hathaway is then a purchaser of a type which is able to consummate such a purchase without causing it or any of its affiliates or us or any of our subsidiaries to become subject to regulation as a registered holding company or a subsidiary of a registered holding company under PUHCA. Berkshire Hathaway is not currently such a purchaser. The consummation of such a transaction could result in a change in control with respect to us. Our Amended and Restated Articles of Incorporation provide that each share of the Zero Coupon Convertible Preferred Stock is convertible at the option of the holder thereof into one conversion unit, which is one share of our common stock subject to certain adjustments as described in our articles, upon the occurrence of a Conversion Event. A "Conversion Event" includes (1) any conversion of Zero Coupon Convertible Preferred Stock that would not cause the holder of the shares of common stock issued upon conversion (or any affiliate of such holder) or us to become subject to regulation as a registered holding company or as a subsidiary of a registered holding company under PUHCA either as a result of the repeal or amendment of PUHCA, the number of shares involved or the identity of the holder of such shares and (2) a Company Sale. A "Company Sale" includes our involuntary or voluntary liquidation, dissolution, recapitalization, winding-up or termination and any merger, consolidation or sale of all or substantially all of our assets. The conversion by Berkshire Hathaway of its shares of Zero Coupon Convertible Preferred Stock into our common stock could result in a change in control with respect to beneficial owership of our voting securities as calculated pursuant to Rule 13d-3(d) under the Securities Exchange Act. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Under a subscription agreement with us, Berkshire Hathaway has agreed to purchase, under certain circumstances, additional 11% trust issued mandatorily redeemable preferred securities in the event preferred securities outstanding prior to the closing of our acquisition by a private investor group on March 14, 2000 are tendered for conversion to cash by the current holders. We provided a guarantee in favor of a third party lender in connection with a $1,663,998.75 loan from such lender to our President, Gregory E. Abel, in March of 2000. The loan matures on April 1, 2010. The proceeds of this loan were used by Mr. Abel to purchase 47,475 shares of our common stock. Such common stock (together with 8,465 additional shares of common stock owned by Mr. Abel) also secures the loan. The entire original principal amount of the loan and the guarantee remain presently outstanding. In order to finance our $275 million preferred stock investment in Williams, on March 7, 2002, we sold to Berkshire Hathaway shares of our zero coupon convertible preferred stock. In order to finance our acquisition of Kern River, on March 12, 2002, we sold to Berkshire Hathaway and/or its consolidated subsidiaries shares of our no par, zero coupon convertible preferred stock for $127 million and $323 million of 11% mandatorily redeemable preferred securities of our subsidiary trust due March 12, 2012 with scheduled principal payments beginning in 2005. In order to finance our acquisition of Northern Natural Gas, on August 16, 2002, we sold to Berkshire Hathaway and/or its consolidated subsidiaries $950 million of 11% mandatorily redeemable preferred securities of our subsidiary trust due August 31, 2012 with scheduled principal payments beginning in 2003. Messrs. Warren E. Buffett and Walter Scott, Jr. are members of the Board of Directors of Berkshire Hathaway. Messrs. Buffett and Marc D. Hamburg are executive officers of Berkshire Hathaway. Each of Messrs. Buffett, Hamburg and Walter Scott serves on our Board of Directors and participates in deliberations regarding executive officer compensation. On March 6, 2002, we purchased options to purchase shares of our common stock from Mr. David L. Sokol, our Chairman and Chief Executive Officer. The options purchased had exercise prices ranging from $18.50 to $24.22. We paid Mr. Sokol an aggregate amount of $27,122,550, which is equal to the difference between his option exercise prices and an agreed upon per share value. Mr. Sokol serves on our Board of Directors and participates in deliberations regarding executive officer compensation. 100 In July 2002, we purchased 557,686 options to purchase shares of HomeServices common stock from directors, officers and employees of HomeServices. The options purchased had exercise prices ranging from $11.3125 to $15.00. We paid an aggregate of $4,268,392, which is equal to the difference between the option exercise prices and an agreed upon per share value. We have not purchased any other options or securities from our stockholders, directors or executive officers since January 1, 2002. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION There is no compensation committee of the Board of Directors. All members of the Board of Directors participate in deliberations regarding executive officer compensation. Messrs. Sokol and Abel are current officers and employees. Mr. Walter Scott is a former officer. Mr. Jaros is a former officer and employee. See --"Certain Relationships and Related Transactions." 101 DESCRIPTION OF THE NOTES The original notes were, and the exchange notes will be, issued pursuant to an indenture, dated as of October 4, 2002, between the Company and The Bank of New York, as trustee. The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended. The following description is a summary of the material provisions of the indenture and the related registration rights agreement. It does not restate those agreements in their entirety. We urge you to read the indenture and the registration rights agreement because they, and not this description, define your rights as a holder of the notes. The definitions of certain capitalized terms used in the following summary are set forth below under "--Definitions." GENERAL The indenture does not limit the aggregate principal amount of the debt securities that may be issued thereunder and provides that debt securities may be issued from time to time in one or more series. The notes were initially offered in the aggregate principal amount of $700,000,000. We may, without the consent of the holders, increase such principal amount in the future on the same terms and conditions and with the same CUSIP number(s) as the notes. The notes were issued in two series. The 2007 notes were issued in an aggregate principal amount of $200,000,000. The 2007 notes bear interest at the rate of 4.625% per annum and will mature on October 1, 2007. The 2012 notes were issued in an aggregate principal amount of $500,000,000. The 2012 notes bear interest at the rate of 5.875% per annum and will mature on October 1, 2012. Interest on the notes is payable semi-annually in arrears on each January 31 and July 31, commencing January 31, 2003, to the holders thereof at the close of business on the preceding January 15 and July 15, respectively. Interest on the notes is computed on the basis of a 360-day year of twelve 30-day months. The original notes were, and the exchange notes will be, issued without coupons and in fully registered form only in denominations of $1,000 and any integral multiple of $1,000. The Company files certain reports and other information with the SEC in accordance with the requirements of Sections 13 and 15(d) under the Exchange Act. See "Where You Can Find More Information." In addition, at any time that Sections 13 and 15(d) cease to apply to the Company, the Company has covenanted in the indenture to file comparable reports and information with the trustee and the SEC, and mail such reports and information to holders of notes at their registered addresses, for so long as any notes remain outstanding. If (1) the registration statement of which this prospectus is a part is not declared effective by the SEC within 270 days after the date on which the original notes were issued, (2) a shelf registration statement with respect to the resale of the notes is not declared effective by the SEC within 150 days after the Company's obligation to file such shelf registration statement arises (but in any event not prior to 270 days after the date on which the original notes were issued) or (3) any of the foregoing registration statements (or the prospectuses related thereto) after being declared effective by the SEC cease to be so effective or usable (subject to certain exceptions) in connection with resales of the original notes or exchange notes for the periods specified and in accordance with the registration rights agreement, the interest rate on the notes that are then subject to such cessation or other registration default will increase by 0.5% from and including the date on which any such event occurs until such event ceases to be continuing. The registration rights are more fully described under "Exchange Offer--Liquidated Damages." Any 2007 original notes that remain outstanding after the consummation of the exchange offer, together with all 2007 exchange notes issued in connection with the exchange offer, will be treated as a single class of securities under the indenture. Any 2012 original notes that remain outstanding after the consummation of the exchange offer, together with all 2012 exchange notes issued in connection with the exchange offer, will be treated as a single class of securities under the indenture. 102 OPTIONAL REDEMPTION GENERAL The notes of each series are redeemable in whole or in part, at the option of the Company at any time, at a redemption price equal to the greater of: (1) 100% of the principal amount of the series of notes being redeemed; or (2) the sum of the present values of the remaining scheduled payments of principal of and interest on the series of notes being redeemed discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at a discount rate equal to the Treasury Yield plus 37.5 basis points, plus, for (1) or (2) above, whichever is applicable, accrued interest on such notes to the date of redemption. Notice of redemption shall be given not less than 30 days nor more than 60 days prior to the date of redemption. If fewer than all the notes are to be redeemed, selection of notes of a series for redemption will be made by the trustee in any manner the trustee deems fair and appropriate. Unless the Company defaults in payment of the Redemption Price (as defined below), from and after the date of redemption the notes or portions of notes called for redemption will cease to bear interest, and the holders of those notes will have no right in respect of those notes except the right to receive the applicable Redemption Price. OPTIONAL REDEMPTION PROVISIONS Under the procedures described above, the price payable upon the optional redemption at any time of a note (the "Redemption Price") is determined by calculating the present value (the "Present Value") at such time of each remaining payment of principal of or interest on such note and then totaling those Present Values. If the sum of those Present Values is equal to or less than 100% of the principal amount of such note, the Redemption Price of such note will be 100% of its principal amount (redemption at par). If the sum of those Present Values is greater than 100% of the principal amount of such note, the Redemption Price of such note will be such greater amount (redemption at a premium). In no event may a note be redeemed optionally at less than 100% of its principal amount. The Present Value at any time of a payment of principal of or interest on a note is calculated by applying to such payment the discount rate (the "Discount Rate") applicable to such payment. The Discount Rate applicable at any time to payment of principal of or interest on a note equals the equivalent yield to maturity at such time of a fixed rate United States treasury security having a maturity comparable to the maturity of such payment plus 37.5 basis points, such yield being calculated on the basis of the interest rate borne by such United States treasury security and the price at such time of such security. The United States treasury security employed in the calculation of a Discount Rate (a "Relevant Security") as well as the price and equivalent yield to maturity of such Relevant Security will be selected or determined by an Independent Investment Banker. Whether the sum of the Present Values of the remaining payments of principal of and interest on a note to be redeemed optionally will or will not exceed 100% of its principal amount and, accordingly, whether such note will be redeemed at par or at a premium will depend on the Discount Rate used to calculate such Present Values. Such Discount Rate, in turn, will depend upon the equivalent yield to maturity of a Relevant Security, which yield will itself depend on the interest rate borne by, and the price of, the Relevant Security. While the interest rate borne by the Relevant Security is fixed, the price of the Relevant Security tends to vary with interest rate levels prevailing from time to time. In general, if at a particular time the prevailing level of interest rates for a newly issued United States treasury security having a maturity comparable to that of a Relevant Security is higher than the level of interest rates for newly issued United States treasury securities having a maturity comparable to such Relevant Security prevailing at the time the Relevant Security was issued, the price of the Relevant Security will be lower than its issue price. Conversely, if at a particular time the prevailing level of interest rates for a newly 103 issued United States treasury security having a maturity comparable to that of a Relevant Security is lower than the level of interest rates prevailing for newly issued United States treasury securities having a maturity comparable to the Relevant Security at the time the Relevant Security was issued, the price of the Relevant Security will be higher than its issue price. Because the equivalent yield to maturity on a Relevant Security depends on the interest rate it bears and its price, an increase or a decrease in the level of interest rates for newly issued United States treasury securities with a maturity comparable to that of a Relevant Security above or below the levels of interest rates for newly issued United States treasury securities having a maturity comparable to the Relevant Security prevailing at the time of issue of the Relevant Security will generally result in an increase or a decrease, respectively, in the Discount Rate used to determine the Present Value of a payment of principal of or interest on a note. An increase or a decrease in the Discount Rate, and therefore an increase or a decrease in the levels of interest rates for newly issued United States treasury securities having a maturity comparable to the Relevant Security, will result in a decrease or an increase, respectively, of the Present Value of a payment of principal of or interest on a note. In other words, the Redemption Price varies inversely with the levels of interest rates for newly issued United States treasury securities having a maturity comparable to the Comparable Treasury Issue. As noted above, however, if the sum of the Present Values of the remaining payments of principal of and interest on a note proposed to be redeemed is less than its principal amount, such note may only be redeemed at par. SINKING FUND The notes are not subject to any mandatory sinking fund. RANKING The notes are general, unsecured senior obligations of the Company and rank pari passu in right of payment with all other existing and future senior unsecured obligations of the Company and senior in right of payment to all existing and future subordinated obligations of the Company. The notes are effectively subordinated to all existing and future secured obligations of the Company and to all existing and future obligations of the Company's Subsidiaries. At September 30, 2002, the Company's outstanding indebtedness was approximately $2.0 billion (excluding $2.1 billion in aggregate principal amount of the Company's trust preferred securities, the Company's guarantees and letters of credit in respect of subsidiary indebtedness aggregating approximately $235 million and the Company's completion guarantee issued in favor of the lenders under Kern River's $875 million construction loan facility in connection with Kern River's 2003 Expansion Project). In addition, the Company's subsidiaries have significant amounts of indebtedness. At September 30, 2002, the Company's consolidated subsidiaries' and joint ventures' total outstanding indebtedness was approximately $7.1 billion, which does not include $453 million, representing the Company's share of outstanding indebtedness of CE Gen. This amount also does not include trade debt of the Company's subsidiaries. See "Capitalization." COVENANTS Except as set forth under "--Defeasance and Discharge--Covenant Defeasance" below, for so long as any notes remain outstanding, the Company will comply with the terms of the covenants set forth below. RESTRICTIONS ON LIENS The Company is not permitted to pledge, mortgage, hypothecate or permit to exist any pledge, mortgage or other Lien upon any property or assets at any time directly owned by the Company to secure any indebtedness for money borrowed which is incurred, issued, assumed or guaranteed by the Company ("Indebtedness for Borrowed Money"), without making effective provisions whereby the outstanding notes will be equally and ratably secured with any and all such Indebtedness for Borrowed Money and with any other Indebtedness for Borrowed Money similarly entitled to be equally and ratably secured; provided however, that this restriction does not apply to or prevent the creation or existence of: 104 (1) any Liens existing prior to the issuance of the original notes; (2) purchase money Liens which do not exceed the cost or value of the purchased property or assets; (3) any Liens not to exceed 10% of Consolidated Net Tangible Assets; and (4) any Liens on property or assets granted in connection with extending, renewing, replacing or refinancing in whole or in part the Indebtedness for Borrowed Money (including, without limitation, increasing the principal amount of such Indebtedness for Borrowed Money) secured by Liens described in the foregoing clauses (1) through (3), provided that the Liens in connection with any such extension, renewal, replacement or refinancing will be limited to the specific property or assets that was subject to the original Lien. In the event that the Company proposes to pledge, mortgage or hypothecate or permit to exist any pledge, mortgage or other Lien upon any property or assets at any time directly owned by it to secure any Indebtedness for Borrowed Money, other than as permitted by clauses (1) through (4) of the previous paragraph, the Company will give prior written notice thereof to the trustee and the Company will, prior to or simultaneously with such pledge, mortgage or hypothecation, effectively secure all the notes equally and ratably with such Indebtedness for Borrowed Money. The foregoing covenant does not restrict the ability of the Company's Subsidiaries and affiliates to pledge, mortgage, hypothecate or permit to exist any mortgage, pledge or Lien upon their property or assets, in connection with project financings or otherwise. CONSOLIDATION, MERGER, CONVEYANCE, SALE OR LEASE The Company is not permitted to consolidate with or merge with or into any other person, or convey, transfer or lease its consolidated properties and assets substantially as an entirety to any person, or permit any person to merge into or consolidate with the Company, unless (1) the Company is the surviving or continuing corporation or the surviving or continuing corporation or purchaser or lessee is a corporation incorporated under the laws of the United States of America, one of the States thereof or the District of Columbia or Canada and assumes the Company's obligations under the notes and under the indenture and (2) immediately before and after such transaction, no event of default under the indenture shall have occurred and be continuing. Except for a sale of the consolidated properties and assets of the Company substantially as an entirety as provided above, and other than properties or assets required to be sold to conform with laws or governmental regulations, the Company is not permitted, directly or indirectly, to sell or otherwise dispose of any of its consolidated properties or assets (other than short-term, readily marketable investments purchased for cash management purposes with funds not representing the proceeds of other asset sales) if on a pro forma basis, the aggregate net book value of all such sales during the most recent 12-month period would exceed 10% of Consolidated Net Tangible Assets computed as of the end of the most recent quarter preceding such sale; provided, however, that (1) any such sales shall be disregarded for purposes of this 10% limitation if the net proceeds are invested in properties or assets in similar or related lines of business of the Company and its Subsidiaries, including, without limitation, any of the lines of business in which the Company or any of its Subsidiaries is engaged on the date of such sale or disposition, and (2) the Company may sell or otherwise dispose of consolidated properties and assets in excess of such 10% limitation if the net proceeds from such sales or dispositions, which are not reinvested as provided above, are retained by the Company as cash or Cash Equivalents or used to retire Indebtedness for Borrowed Money of the Company (other than Indebtedness for Borrowed Money which is subordinated to the notes) and its Subsidiaries. PURCHASE OF NOTES UPON A CHANGE OF CONTROL Upon the occurrence of a Change of Control, each holder of the notes will have the right to require that the Company repurchase all or any part of such holder's notes at a purchase price in cash equal to 101% of the principal thereof on the date of purchase plus accrued interest, if any, to the date of purchase. 105 The Change of Control provisions may not be waived by the trustee or by the board of directors of the Company, and any modification thereof must be approved by each holder. Nevertheless, the Change of Control provisions will not necessarily afford protection to holders, including protection against an adverse effect on the value of the notes of any series, in the event that the Company or its Subsidiaries incur additional Debt, whether through recapitalizations or otherwise. Within 30 days following a Change of Control, the Company will mail a notice to each holder of the notes of each series with a copy to the trustee, stating the following: (1) that a Change of Control has occurred and that such holder has the right to require the Company to purchase such holder's notes at the purchase price described above (the "Change of Control Offer"); (2) the circumstances and relevant facts regarding such Change of Control (including information with respect to pro forma historical income, cash flow and capitalization after giving effect to such Change of Control); (3) the purchase date (which will be not earlier than 30 days nor later than 60 days from the date such notice is mailed) (the "Purchase Date"); (4) that after the Purchase Date interest on such note will continue to accrue (except as provided in clause (5)); (5) that any note properly tendered pursuant to the Change of Control Offer will cease to accrue interest after the Purchase Date (assuming sufficient moneys for the purchase thereof are deposited with the trustee); (6) that holders electing to have a note of any series purchased pursuant to a Change of Control Offer will be required to surrender the note of such series, with the form entitled "Option of Holder To Elect Purchase" on the reverse of the note completed, to the paying agent at the address specified in the notice prior to the close of business on the fifth business day prior to the Purchase Date; (7) that a holder will be entitled to withdraw such holder's election if the paying agent receives, not later than the close of business on the third business day (or such shorter periods as may be required by applicable law) preceding the Purchase Date, a telegram, telex, facsimile transmission or letter setting forth the name of the holder, the principal amount of notes of such series the holder delivered for purchase, and a statement that such holder is withdrawing his election to have such notes of such series purchased; and (8) that holders that elect to have their notes of any series purchased only in part will be issued new notes having a principal amount equal to the portion of the notes of the series that were surrendered but not tendered and purchased. On the Purchase Date, the Company will (1) accept for payment all notes of any series or portions thereof tendered pursuant to the Change of Control Offer, (2) deposit with the trustee money sufficient to pay the purchase price of all notes of such series or portions thereof so tendered for purchase and (3) deliver or cause to be delivered to the trustee the notes of such series properly tendered together with an officer's certificate identifying the notes of such series or portions thereof tendered to the Company for purchase. The trustee will promptly mail, to the holders of the notes of such series properly tendered and purchased, payment in an amount equal to the purchase price, and promptly authenticate and mail to each holder a new note of the same series having a principal amount equal to any portion of such holder's notes of such series that were surrendered but not tendered and purchased. The Company will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Purchase Date. If the Company is prohibited by applicable law from making the Change of Control Offer or purchasing notes of any series thereunder, the Company need not make a Change of Control Offer pursuant to this covenant for so long as such prohibition is in effect. 106 The Company will comply with all applicable tender offer rules, including, without limitation, Rule 14e-1 under the Exchange Act, in connection with a Change of Control Offer. EVENTS OF DEFAULT An event of default with respect to the notes of any series is defined in the indenture as being any one of the following events: (1) default as to the payment of interest on any note of that series for 30 days after payment is due; (2) default as to the payment of principal of, or premium, if any, on any note of that series or as to any payment required in connection with a Change of Control; (3) failure to make a Change of Control Offer required under the covenants described under "Purchase of Notes Upon a Change of Control" above or a failure to purchase the notes of that series tendered in respect of such Change of Control Offer; (4) default in the performance, or breach, of any covenant, agreement or warranty of the Company contained in the indenture and the notes of that series and such failure continues for 30 days after written notice is given to the Company by the trustee or to the Company and the trustee by the holders of at least a majority in aggregate principal amount outstanding of the notes of that series, as provided in the indenture; (5) default on any other Debt of the Company or any Significant Subsidiary (other than Debt that is Non-Recourse to the Company) if either (x) such default results from failure to pay principal of such Debt in excess of $100 million when due after any applicable grace period or (y) as a result of such default, the maturity of such Debt has been accelerated prior to its scheduled maturity and such default has not been cured within the applicable grace period, and such acceleration has not been rescinded, and the principal amount of such Debt, together with the principal amount of any other Debt of the Company and its Significant Subsidiaries (not including Debt that is Non-Recourse to the Company) that is in default as to principal, or the maturity of which has been accelerated, aggregates $100 million or more; (6) the entry by a court of one or more judgments or orders against the Company or any Significant Subsidiary for the payment of money that in the aggregate exceeds $100 million (excluding (i) the amount thereof covered by insurance or by a bond written by a person other than an affiliate of the Company and (ii) judgments that are Non-Recourse to the Company), which judgments or orders have not been vacated, discharged or satisfied or stayed pending appeal within 60 days from the entry thereof, provided that such a judgment or order will not be an event of default if such judgment or order does not require any payment by the Company; and (7) certain events involving bankruptcy, insolvency or reorganization of the Company or any of its Significant Subsidiaries. The indenture provides that the trustee may withhold notice to the holders of any default (except in payment of principal of, premium, if any, or interest on any series of notes and any payment required in connection with a Change of Control) if the trustee considers it in the interest of holders to do so. The indenture provides that if an event of default with respect to the notes of any series at the time outstanding (other than an event of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary) has occurred and is continuing, either the trustee or (i) in the case of any event of default described in clause (1) or (2) above, the holders of at least 33% in aggregate principal amount of the notes of that series then outstanding, or (ii) in the case of any other event of default, the holders of at least a majority in aggregate principal amount of the notes of that series then outstanding, may declare the principal of and any accrued interest on all notes of that series to be due and payable immediately, but upon certain conditions such declaration may be annulled and past defaults (except, unless theretofore cured, a default in payment of principal of, premium, if any, or interest on the notes of that series or any payment required in connection with a Change of Control) may be waived by the holders of a majority in principal amount of the notes of that series then outstanding. If an event of default due to the 107 bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary occurs, the indenture provides that the principal of and interest on all notes of that series will become immediately due and payable without any action by the trustee, the holders of notes or any other person. The holders of a majority in principal amount of the notes of any series then outstanding will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee under the indenture with respect to the notes of such series, subject to certain limitations specified in the indenture, provided that the holders of notes of such series must have offered to the trustee reasonable indemnity against expenses and liabilities. The indenture requires the annual filing by the Company with the trustee of a written statement as to its knowledge of the existence of any default in the performance and observance of any of the covenants contained in the indenture. MODIFICATION OF THE INDENTURE The indenture contains provisions permitting the Company and the trustee, with the consent of the holders of not less than a majority in principal amount of the notes at the time outstanding, to modify the indenture or the rights of the holders of the series of notes, except that no such modification may (1) extend the stated maturity of the principal of or any installment of interest on the notes, reduce the principal amount thereof or the interest rate thereon, reduce any premium payable on redemption or purchase thereof, impair the right of any holder to institute suit for the enforcement of any such payment on or after the stated maturity thereof or make any change in the covenants regarding a Change of Control or the related definitions without the consent of the holder of each of the series of notes so affected, or (2) reduce the percentage of any series of notes, the consent of the holders of which is required for any such modification, without the consent of the holders of all series of notes then outstanding. DEFEASANCE AND DISCHARGE LEGAL DEFEASANCE The indenture provides that the Company will be deemed to have paid and will be discharged from any and all obligations in respect of the notes of any series on the 123rd day after the deposit referred to below has been made (or immediately if an opinion of counsel is delivered to the effect described in clause (B)(3)(y) below), and the provisions of the indenture will cease to be applicable with respect to such notes of such series (except for, among other matters, certain obligations to register the transfer or exchange of such notes of such series, to replace stolen, lost or mutilated notes of such series, to maintain paying agents and to hold monies for payment in trust) if, among other things: (A) the Company has deposited with the trustee, in trust, money and/or U.S. Government Obligations that through the payment of interest and principal in respect thereof in accordance with their terms will provide money in an amount sufficient to pay the principal of, premium, if any, and accrued and unpaid interest on the applicable notes, on the respective stated maturities of the notes or, if the Company makes arrangements satisfactory to the trustee for the redemption of the notes prior to their stated maturity, on any earlier redemption date in accordance with the terms of the indenture and the applicable notes; (B) the Company has delivered to the trustee: (1) either (x) an opinion of counsel to the effect that holders will not recognize income, gain or loss for federal income tax purposes as a result of such deposit, defeasance and discharge and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit, defeasance and discharge had not occurred and the Company had paid or redeemed such notes on the applicable dates, which opinion of counsel must be based upon a ruling of the Internal Revenue Service to 108 the same effect or a change in applicable federal income tax law or related Treasury regulations after the date of the indenture, or (y) a ruling directed to the trustee or the Company received from the Internal Revenue Service to the same effect as the aforementioned opinion of counsel; (2) an opinion of counsel to the effect that the creation of the defeasance trust does not violate the Investment Company Act of 1940; and (3) an opinion of counsel to the effect that either (x) after the passage of 123 days following the deposit referred to in clause (A) above, the trust fund will not be subject to the effect of Section 547 or 548 of the U.S. Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law or (y) based upon existing precedents, if the matter were properly briefed, a court should hold that the deposit of moneys and/or U.S. Government Obligations as provided in clause (A) above would not constitute a preference voidable under Section 547 or 548 of the U.S. Bankruptcy Code or Section 15 of the New York Debtor and Creditor Law; (C) immediately after giving effect to such deposit referred to in clause (A) above on a pro forma basis, no event of default under the indenture, or event that after the giving of notice or lapse of time or both would become an event of default, will have occurred and be continuing on the date of such deposit or (unless an opinion of counsel is delivered to the effect described in clause (B)(3)(y) above) during the period ending on the 123rd day after the date of such deposit, and such deposit and discharge will not result in a breach or violation of, or constitute a default under, any other material agreement or instrument to which the Company is a party or by which the Company is bound; and (D) if at such time the notes are listed on a national securities exchange, the Company has delivered to the trustee an opinion of counsel to the effect that the notes will not be delisted as a result of such deposit, defeasance and discharge. COVENANT DEFEASANCE The indenture further provides that the provisions of the covenants described herein under "Covenants--Restrictions on Liens", "--Consolidation, Merger, Conveyance, Sale or Lease" and "--Purchase of Notes Upon a Change of Control," clauses (3) and (4) under "Events of Default" with respect to such covenants, clause (2) under "Events of Default" with respect to offers to purchase upon a Change of Control as described above and clauses (5) and (6) under "Events of Default" will cease to be applicable to the Company and its Subsidiaries upon the satisfaction of the provisions described in clauses (A), (B), (C) and (D) of the preceding paragraph; provided, however, that with respect to such covenant defeasance, the opinion of counsel described in clause (B)(1)(x) above need not be based upon any ruling of the Internal Revenue Service or change in applicable federal income tax law or related Treasury regulations. DEFEASANCE AND CERTAIN OTHER EVENTS OF DEFAULT If the Company exercises its option to omit compliance with certain covenants and provisions of the indenture with respect to the notes of any series as described in the immediately preceding paragraph and any series of notes is declared due and payable because of the occurrence of an event of default that remains applicable, the amount of money and/or U.S. Government Obligations on deposit with the trustee will be sufficient to pay amounts due on such notes at the time of their stated maturity or scheduled redemption, but may not be sufficient to pay amounts due on such notes at the time of acceleration resulting from such event of default. The Company will remain liable for such payments. GOVERNING LAW The indenture and the notes are governed by, and construed in accordance with, the law of the State of New York, including Section 5-1401 of the New York General Obligations Law, but otherwise without regard to conflict of laws rules. 109 TRUSTEE The Bank of New York is the trustee under the indenture. An affiliate of the trustee was an initial purchaser in the offering of the original notes. The Bank of New York (or one of its affiliates) currently serves, and may in the future serve, as trustee under indentures evidencing other indebtedness of the Company and its affiliates. The Bank of New York (or one of its affiliates) is also, and may in the future be, a lender under credit facilities for the Company and its affiliates. The Bank of New York is also the exchange agent in the exchange offer. DEFINITIONS Set forth below is a summary of certain of the defined terms used in the covenants and other provisions of the indenture. Reference is made to the indenture for the full definitions of all such terms as well as any other capitalized terms used herein for which no definition is provided. "Attributable Value" means, as to a Capitalized Lease Obligation under which any person is at the time liable and at any date as of which the amount thereof is to be determined, the capitalized amount thereof that would appear on the face of a balance sheet of such person in accordance with GAAP. "Berkshire Hathaway" means Berkshire Hathaway Inc. and any Subsidiary of Berkshire Hathaway Inc. "Capital Stock" means, with respect to any person, any and all shares, interests, participations or other equivalents (however designated, whether voting or non-voting) in, or interests (however designated) in, the equity of such person that is outstanding or issued on or after the date of the indenture, including, without limitation, all common stock and preferred stock and partnership and joint venture interests in such person. "Capitalized Lease" means, as applied to any person, any lease of any property of which the discounted present value of the rental obligations of such person as lessee, in conformity with GAAP, is required to be capitalized on the balance sheet of such person, and "Capitalized Lease Obligation" means the rental obligations, as aforesaid, under such lease. "Cash Equivalent" means any of the following: (1) securities issued or directly and fully guaranteed or insured by the United States of America or any agency or instrumentality thereof (provided that the full faith and credit of the United States of America is pledged in support thereof); (2) time deposits and certificates of deposit of any commercial bank organized in the United States having capital and surplus in excess of $500,000,000 or any commercial bank organized under the laws of any other country having total assets in excess of $500,000,000 with a maturity date not more than two years from the date of acquisition; (3) repurchase obligations with a term of not more than 30 days for underlying securities of the types described in clauses (1) or (5) of this definition that were entered into with any bank meeting the qualifications set forth in clause (2) of this definition or another financial institution of national reputation; (4) direct obligations issued by any state or other jurisdiction of the United States of America or any other country or any political subdivision or public instrumentality thereof maturing, or subject to tender at the option of the holder thereof, within 90 days after the date of acquisition thereof and, at the time of acquisition, having a rating of at least A from S&P or A-2 from Moody's (or, if at any time neither S&P nor Moody's may be rating such obligations, then from another nationally recognized rating service acceptable to the trustee); (5) commercial paper issued by (a) the parent corporation of any commercial bank organized in the United States having capital and surplus in excess of $500,000,000 or any commercial bank organized under the laws of any other country having total assets in excess of $500,000,000, and (b) others having one of the two highest ratings obtainable from either S&P or Moody's (or, if at 110 any time neither S&P nor Moody's may be rating such obligations, then from another nationally recognized rating service acceptable to the trustee) and in each case maturing within one year after the date of acquisition; (6) overnight bank deposits and bankers' acceptances at any commercial bank organized in the United States having capital and surplus in excess of $500,000,000 or any commercial bank organized under the laws of any other country having total assets in excess of $500,000,000; (7) deposits available for withdrawal on demand with any commercial bank organized in the United States having capital and surplus in excess of $500,000,000 or any commercial bank organized under the laws of any other country having total assets in excess of $500,000,000; (8) investments in money market funds substantially all of whose assets comprise securities of the types described in clauses (1) through (6) and (9) of this definition; and (9) auction rate securities or money market preferred stock having one of the two highest ratings obtainable from either S&P or Moody's (or, if at any time neither S&P nor Moody's may be rating such obligations, then from another nationally recognized rating service acceptable to the trustee). "Change of Control" means the occurrence of one or more of the following events: (1) a transaction pursuant to which Berkshire Hathaway ceases to own, on a diluted basis (assuming conversion of all of the Company's convertible preferred stock and any other Capital Stock of the Company that is issued and outstanding, regardless of whether any such convertible preferred stock or other Capital Stock is then presently convertible), at least a majority of the issued and outstanding common stock of the Company; or (2) the Company or its Subsidiaries sell, convey, assign, transfer, lease or otherwise dispose of all or substantially all the property of the Company and its Subsidiaries taken as a whole to any person or entity other than an entity at least a majority of the issued and outstanding common stock of which is owned by Berkshire Hathaway, calculated on a diluted basis as described above; provided that with respect to the foregoing subparagraphs (1) and (2), a Change of Control will not be deemed to have occurred unless and until a Rating Decline has occurred as well. "Comparable Treasury Issue" means the United States Treasury security selected by an Independent Investment Banker as having a maturity comparable to the remaining term of such notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the notes. "Comparable Treasury Price" means, with respect to any Redemption Date, (1) the average of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) on the third business day preceding such Redemption Date, as set forth in the daily statistical release (or any successor release) published by the Federal Reserve Bank of New York and designated "Composite 3:30 p.m. Quotations for U.S. Government Securities" or (2) if such release (or any successor release) is not published or does not contain such prices on such business day, the Reference Treasury Dealer Quotation for such Redemption Date. "Consolidated Net Tangible Assets" means, as of the date of any determination thereof, the total amount of all assets of the Company determined on a consolidated basis in accordance with GAAP as of such date less the sum of (a) the consolidated current liabilities of the Company determined in accordance with GAAP and (b) assets properly classified as Intangible Assets. "Currency Protection Agreement" means, with respect to any person, any foreign exchange contract, currency swap agreement or other similar agreement or arrangement intended to protect such person against fluctuations in currency values to or under which such person is a party or a beneficiary on the date of the indenture or becomes a party or a beneficiary thereafter. "Debt" means, with respect to any person, at any date of determination (without duplication): 111 (1) all Indebtedness for Borrowed Money of such person; (2) all obligations of such person evidenced by bonds, debentures, notes or other similar instruments; (3) all obligations of such person in respect of letters of credit, bankers' acceptances, surety, bid, operating and performance bonds, performance guarantees or other similar instruments or obligations (or reimbursement obligations with respect thereto) (except, in each case, to the extent incurred in the ordinary course of business); (4) all obligations of such person to pay the deferred purchase price of property or services, except Trade Payables; (5) the Attributable Value of all obligations of such person as lessee under Capitalized Leases; (6) all Debt of others secured by a Lien on any Property of such person, whether or not such Debt is assumed by such person, provided that, for purposes of determining the amount of any Debt of the type described in this clause, if recourse with respect to such Debt is limited to such Property, the amount of such Debt will be limited to the lesser of the fair market value of such Property or the amount of such Debt; (7) all Debt of others Guaranteed by such person to the extent such Debt is Guaranteed by such person; (8) all Redeemable Stock valued at the greater of its voluntary or involuntary liquidation preference plus accrued and unpaid dividends; and (9) to the extent not otherwise included in this definition, all net obligations of such person under Currency Protection Agreements and Interest Rate Protection Agreements. For purposes of determining any particular amount of Debt that is or would be outstanding, Guarantees of, or obligations with respect to letters of credit or similar instruments supporting (to the extent the foregoing constitutes Debt), Debt otherwise included in the determination of such particular amount will not be included. For purposes of determining compliance with the indenture, in the event that an item of Debt meets the criteria of more than one of the types of Debt described in the above clauses, the Company, in its sole discretion, will classify such item of Debt and only be required to include the amount and type of such Debt in one of such clauses. "Guarantee" means any obligation, contingent or otherwise, of any person directly or indirectly guaranteeing any Debt of any other person and, without limiting the generality of the foregoing, any Debt obligation, direct or indirect, contingent or otherwise, of such person (1) to purchase or pay (or advance or supply funds for the purchase or payment of) such Debt of such other person (whether arising by virtue of partnership arrangements (other than solely by reason of being a general partner of a partnership), or by agreement to keep-well, to purchase assets, goods, securities or services or to take-or-pay, or to maintain financial statement conditions or otherwise) or (2) entered into for purposes of assuring in any other manner the obligee of such Debt of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part), provided that the term "Guarantee" will not include endorsements for collection or deposit in the ordinary course of business or the grant of a lien in connection with any Non-Recourse Debt. The term "Guarantee" used as a verb has a corresponding meaning. "Independent Investment Banker" means an independent investment banking institution of international standing appointed by the Company. "Intangible Assets" means, as of the date of determination thereof, all assets of the Company properly classified as intangible assets determined on a consolidated basis in accordance with GAAP. "Interest Rate Protection Agreement" means, with respect to any person, any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement intended to protect such person against fluctuations in interest rates to or under which such person or any of its Subsidiaries is a party or a beneficiary on the date of the indenture or becomes a party or a beneficiary thereafter. 112 "Investment Grade" means with respect to the notes, (1) in the case of S&P, a rating of at least BBB-, (2) in the case of Moody's, a rating of at least Baa3, and (3) in the case of a Rating Agency other than S&P or Moody's, the equivalent rating, or in each case, any successor, replacement or equivalent definition as promulgated by S&P, Moody's or other Rating Agency as the case may be. "Joint Venture" means a joint venture, partnership or other similar arrangement, whether in corporate, partnership or other legal form. "Lien" means, with respect to any Property, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such Property, but will not include any partnership, joint venture, shareholder, voting trust or similar governance agreement with respect to Capital Stock in a Subsidiary or Joint Venture. For purposes of the indenture, the Company will be deemed to own subject to a Lien any Property that it has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement relating to such Property. "Non-Recourse" means any Debt or other obligation (or that portion of such Debt or other obligation) that is without recourse to the Company or any property or assets directly owned by the Company (other than a pledge of the equity interests in any Subsidiary of the Company, to the extent recourse to the Company under such pledge is limited to such equity interests). "Property" of any person means all types of real, personal, tangible or mixed property owned by such person whether or not included in the most recent consolidated balance sheet of such person under GAAP. "Rating Agencies" means (1) S&P and (2) Moody's or (3) if S&P or Moody's or both do not make a rating of the notes publicly available, a nationally recognized securities rating agency or agencies, as the case may be, selected by the Company, which will be substituted for S&P, Moody's or both, as the case may be. "Rating Category" means (1) with respect to S&P, any of the following categories: BB, B, CCC, CC, C and D (or equivalent successor categories), (2) with respect to Moody's, any of the following categories: Ba, B, Caa, Ca, C and D (or equivalent successor categories) and (3) the equivalent of any such category of S&P or Moody's used by another Rating Agency. In determining whether the rating of the notes has decreased by one or more gradations, gradations within Rating Categories (+ and -- for S&P, 1, 2 and 3 for Moody's or the equivalent gradations for another Rating Agency) will be taken into account (e.g., with respect to S&P, a decline in a rating from BB+ to BB, as well as from BB- to B+, will constitute a decrease of one gradation). "Rating Decline" is defined to mean the occurrence of the following on, or within 90 days after, the earlier of (1) the occurrence of a Change of Control and (2) the date of public notice of the occurrence of a Change of Control or of the public notice of the intention of the Company to effect a Change of Control (the "Rating Date"), which period will be extended so long as the rating of the notes is under publicly announced consideration for possible downgrading by any of the Rating Agencies: (a) in the event that any series of the notes are rated by either Rating Agency on the Rating Date as Investment Grade, the rating of such notes by both such Rating Agencies will be reduced below Investment Grade, or (b) in the event the notes are rated below Investment Grade by both such Rating Agencies on the Rating Date, the rating of such notes by either Rating Agency will be decreased by one or more gradations (including gradations within Rating Categories as well as between Rating Categories). "Redeemable Stock" means any class or series of Capital Stock of any person that by its terms or otherwise is (1) required to be redeemed prior to the stated maturity of any series of the notes, (2) redeemable at the option of the holder of such class or series of Capital Stock at any time prior to the stated maturity of any series of the notes or (3) convertible into or exchangeable for Capital Stock referred to in clause (1) or (2) above or Debt having a scheduled maturity prior to the stated maturity of any series of the notes, provided that any Capital Stock that would not constitute Redeemable Stock but for provisions thereof giving holders thereof the right to require the Company to purchase or redeem such Capital Stock upon the occurrence of a "change of control" occurring prior to the stated maturity of any 113 series of the notes will not constitute Redeemable Stock if the "change of control" provisions applicable to such Capital Stock are no more favorable to the holders of such Capital Stock than the provisions contained in the covenants described under "Purchase of Notes Upon a Change of Control" above. "Redemption Date" means any date on which the Company redeems all or any portion of the notes in accordance with the terms of the indenture. "Reference Treasury Dealer" means a primary U.S. government securities dealer in New York City appointed by the Company. "Reference Treasury Dealer Quotation" means, with respect to the Reference Treasury Dealer and any Redemption Date, the average, as determined by the Company, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount and quoted in writing to the Company by such Reference Treasury Dealer at 5:00 p.m. on the third business day preceding such Redemption Date). "Significant Subsidiary" means a "significant subsidiary" as defined in Rule 1-02(w) of Regulation S-X under the Securities Act and the Exchange Act, substituting 20 percent for 10 percent each place it appears therein. Unless the context otherwise clearly requires, any reference to a "Significant Subsidiary" is a reference to a Significant Subsidiary of the Company. "Subsidiary" means, with respect to any person including, without limitation, the Company and its Subsidiaries, any corporation or other entity of which such person owns, directly or indirectly, a majority of the Capital Stock or other ownership interests and has ordinary voting power to elect a majority of the board of directors or other persons performing similar functions. "Trade Payables" means, with respect to any person, any accounts payable or any other indebtedness or monetary obligation to trade creditors incurred, created, assumed or Guaranteed by such person or any of its Subsidiaries or Joint Ventures arising in the ordinary course of business. "Treasury Yield" means, with respect to any Redemption Date, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such Redemption Date. "U.S. Government Obligations" means any securities that are (1) direct obligations of the United States for the payment of which its full faith and credit is pledged or (2) obligations of a person controlled or supervised by and acting as an agency or instrumentality of the United States, the payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States, that, in either case are not callable or redeemable at the option of the issuer thereof, and will also include any depository receipt issued by a bank or trust company as custodian with respect to any such U.S. Government Obligations or a specific payment of interest on or principal of any such U.S. Government Obligation held by such custodian for the account of the holder of a depository receipt, provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the U.S. Government Obligation or the specific payment of interest on or principal of the U.S. Government Obligation evidenced by such depository receipt. "Voting Stock" means, with respect to any person, Capital Stock of any class or kind ordinarily having the power to vote for the election of directors (or persons fulfilling similar responsibilities) of such person. GLOBAL NOTES; BOOK-ENTRY SYSTEM The original notes within each series were, and the exchange notes notes within each series will be, issued under a book-entry system in the form of one or more global notes (each, a "Global Note"). Each Global Note with respect to the original notes was, and each Global Note with respect to the exchange notes will be, deposited with, or on behalf of, a depositary, which is The Depository Trust Company, New York, New York (the "Depositary"). The Global Notes with respect to the original notes were, and the Global Notes with respect to the exchange notes will be, registered in the name of the Depositary or its nominee. 114 The notes will not be issued in certificated form and, except under the limited circumstances described below, owners of beneficial interests in the Global Notes will not be entitled to physical delivery of the notes in certificated form. The Global Notes may not be transferred except as a whole by the Depositary to a nominee of the Depositary or by a nominee of the Depositary to the Depositary or another nominee of the Depositary or by the Depositary or any nominee to a successor of the Depositary or a nominee of such successor. The Depositary is a limited-purpose trust company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code, and a "clearing agency" registered pursuant to the provisions of Section 17A of the Exchange Act. The Depositary holds securities that its participants ("Direct Participants") deposit with the Depositary. The Depositary also facilitates the settlement among Direct Participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in Direct Participants' accounts, thereby eliminating the need for physical movement of securities certificates. Direct Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations, including Euroclear Bank as operator of The Euroclear System ("Euroclear") and Clearstream Banking societe anonyme ("Clearstream"). The Depositary is owned by a number of its Direct Participants and by the New York Stock Exchange, Inc., the American Stock Exchange, Inc. and NASD, Inc. Access to the Depositary system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly ("Indirect Participants"). The rules applicable to the Depositary and its Direct and Indirect Participants are on file with the SEC. Purchases of the notes under the Depositary system must be made by or through Direct Participants, which will receive a credit for the notes on the Depositary's records. The ownership interest of each actual purchaser of each note ("Beneficial Owner") is in turn to be recorded on the Direct and Indirect Participants' records. Beneficial Owners will not receive written confirmation from the Depositary of their purchase, but Beneficial Owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which the Beneficial Owner entered into the transaction. Transfers of ownership interests in the notes are to be accomplished by entries made on the books of Direct and Indirect Participants acting on behalf of Beneficial Owners. Beneficial Owners will not receive certificates representing their ownership interests in notes, except in the event that use of the book-entry system for the notes is discontinued. To facilitate subsequent transfers, all notes deposited by Direct Participants with the Depositary will be registered in the name of the Depositary's partnership nominee, Cede & Co. or such other name as may be requested by an authorized representative of the Depositary. The deposit of notes with the Depositary and their registration in the name of Cede & Co. or such other nominee effect no change in beneficial ownership. The Depositary has no knowledge of the actual Beneficial Owners of the notes; the Depositary's records reflect only the identity of the Direct Participants to whose accounts such notes are credited, which may or may not be the Beneficial Owners. The Direct and Indirect Participants will remain responsible for keeping account of their holdings on behalf of their customers. Conveyance of notices and other communications by the Depositary to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time. Neither the Depositary nor Cede & Co. (nor such other nominee of the Depositary) will consent or vote with respect to the notes. Under its usual procedures, the Depositary mails an Omnibus Proxy to the Company as soon as possible after the record date. The Omnibus Proxy assigns Cede & Co.'s consenting or voting rights to those Direct Participants to whose accounts the notes are credited on the record date (identified in a listing attached to the Omnibus Proxy). Principal (and premium, if any) and interest payments on the notes and any redemption payments will be made to Cede & Co. (or such other nominee as may be requested by an authorized representative 115 of the Depositary). The Depositary's practice is to credit Direct Participants' accounts upon the Depositary's receipt of funds and corresponding detail information from the Company or its agent on the payable date in accordance with their respective holdings shown on the Depositary's records. Payments by Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in "street name," and will be the responsibility of such Participant and not of the Depositary, the trustee, or the Company or its agent, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of principal (and premium, if any), interest and any redemption proceeds to Cede & Co. (or such other nominee as may be requested by an authorized representative of the Depositary) is the responsibility of the Company, disbursements of such payments to Direct Participants shall be the responsibility of the Depositary, and disbursement of such payments to the Beneficial Owners shall be the responsibility of Direct and Indirect Participants. The Depositary may discontinue providing its services as securities depositary with respect to the notes at any time by giving reasonable notice to the Company. Under such circumstances, in the event that a successor securities depositary is not obtained, certificated notes are required to be printed and delivered. The Company may decide to discontinue use of the system of book-entry transfers through the Depositary (or a successor securities depositary). In that event, certificated notes will be printed and delivered. The information in this section concerning the Depositary and the Depositary's book-entry system has been obtained from sources that the Company believes to be reliable, but the Company, the initial purchasers and the trustee take no responsibility for the accuracy thereof. A Global Note of any series may not be transferred except as a whole by the Depositary to a nominee or successor of the Depositary or by a nominee of the Depositary to another nominee of the Depositary. A Global Note representing notes of any series is exchangeable, in whole but not in part, for notes of such series in definitive form of like tenor and terms if (1) the Depositary notifies the Company that it is unwilling or unable to continue as depositary for such Global Note or if at any time the Depositary is no longer eligible to be or in good standing as a "clearing agency" registered under the Exchange Act, and in either case, a successor depositary is not appointed by the Company within 120 days of receipt by the Company of such notice or of the Company becoming aware of such ineligibility, (2) while such Global Note is subject to the transfer restrictions described in the indenture, the book-entry interests in such Global Note cease to be eligible for Depositary services because such notes are neither (a) rated in one of the top four categories by a nationally recognized statistical rating organization nor (b) included within a Self-Regulatory Organization system approved by the SEC for the reporting of quotation and trade information of securities eligible for transfer pursuant to Rule 144A under the Securities Act, or (3) the Company in its sole discretion at any time determines not to have such notes represented by a Global Note and notifies the trustee thereof. A Global Note exchangeable pursuant to the preceding sentence shall be exchangeable for notes registered in such names and in such authorized denominations as the Depositary of such Global Note shall direct. If (1) the exchange offer registration statement is not declared effective by the Exchange Effectiveness Deadline, (2) the shelf registration statement is not declared effective by the Shelf Effectiveness Deadline, or (3) after either the exchange offer registration statement or the shelf registration statement is declared effective, such registration statement or the related prospectus thereafter ceases to be effective or usable (subject to certain exceptions) in connection with resales of notes or exchange notes for the period specified and in accordance with the registration rights agreement (each such event referred to in clauses (1) through (3), a "Registration Default"), additional interest will accrue on the notes subject to such Registration Default at a rate of 0.5% from and including the date on which any such Registration Default occurs to but excluding the date on which all such Registration Defaults have ceased to be continuing. In each case, such additional interest is payable in addition to any other interest payable from time to time with respect to the notes and the exchange notes. 116 CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS The following discussion is a summary of the material United States federal income tax consequences relevant to the purchase, ownership and disposition of the notes, and does not purport to be a complete analysis of all potential tax effects. This discussion only deals with persons that hold notes as a capital asset within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended (the "Code"), and that purchased the notes for cash at original issue. This discussion does not address all the United States federal income tax consequences that may be relevant to a holder in light of such holder's particular circumstances or to holders subject to special rules, such as financial institutions, banks, partnerships and other pass-through entities, United States expatriates, controlled foreign corporations, passive foreign investment companies, foreign personal holding companies, insurance companies, dealers in securities or currencies, traders in securities, U.S. Holders (defined below) whose functional currency is not the United States dollar, tax-exempt organizations and persons holding the notes as part of a "straddle," "hedge," "conversion transaction" or other integrated transaction. The discussion is based upon the Code, United States Treasury Regulations issued thereunder, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which are subject to change at any time possibly with retroactive effect. As used herein, "U.S. Holder" means a beneficial owner of the notes who or that is o an individual that is a citizen or resident of the United States; o a corporation or other entity taxable as a corporation created or organized in or under the laws of the United States or a political subdivision thereof; o an estate, the income of which is subject to United States federal income tax regardless of its source; o a trust, if a United States court can exercise primary supervision over the administration of the trust and one or more U.S. persons can control all substantial trust decisions, or, if the trust was in existence on August 20, 1996, and has elected to continue to be treated as a U.S. person; or o a person whose worldwide income or gain is otherwise subject to United States federal income tax on a net income basis. We have not sought and will not seek any rulings from the Internal Revenue Service, (the "IRS") with respect to the matters discussed below. There can be no assurance that the IRS will not take a different position concerning the tax consequences of the purchase, ownership or disposition of the notes or that any such position would not be sustained. PROSPECTIVE INVESTORS SHOULD CONSULT THEIR OWN TAX ADVISORS WITH REGARD TO THE APPLICATION OF THE TAX CONSEQUENCES DISCUSSED BELOW TO THEIR PARTICULAR SITUATIONS AS WELL AS THE APPLICATION OF ANY STATE, LOCAL, FOREIGN OR OTHER TAX LAWS, INCLUDING GIFT AND ESTATE TAX LAWS. U.S. HOLDERS STATED INTEREST A U.S. Holder must generally include stated interest on a note as ordinary income at the time such interest is received or accrued, in accordance with such U.S. Holder's method of accounting for U.S. federal income tax purposes. SALE OR OTHER TAXABLE DISPOSITION OF THE NOTES A U.S. Holder will generally recognize gain or loss on the sale, exchange, redemption, retirement or other taxable disposition of a note equal to the difference between the amount realized upon the disposition and the U.S. Holder's adjusted tax basis in the note. Notwithstanding the foregoing, any amounts realized in connection with any sale, exchange, redemption, retirement or other taxable disposition to the extent attributable to accrued interest not previously included in income will be treated 117 as ordinary interest income. A U.S. Holder's adjusted basis in a note generally will be the U.S. Holder's cost therefor. This gain or loss generally will be a capital gain or loss, and if the U.S. Holder is an individual that has held the note for more than one year, such capital gain will generally be subject to tax at a maximum rate of 20%, or 18% if such holder has held the notes for more than five years. A U.S. Holder's ability to deduct capital losses may be limited. EXCHANGE OFFER The exchange of original notes for exchange notes pursuant to the exchange offer will not constitute a taxable event for U.S. federal income tax purposes. As a result, o a U.S. Holder of notes will not recognize taxable gain or loss as a result of the exchange of original notes for exchange notes pursuant to the exchange offer, o the holding period of the exchange notes will include the holding period of the original notes surrendered in exchange therefor, and o a U.S. Holder's adjusted tax basis in the exchange notes will be the same as such U.S. Holder's adjusted tax basis in the original notes surrendered in exchange therefor. CONTINGENT PAYMENTS In certain circumstances, we may be obligated to pay you amounts in excess of the stated interest and principal payable on the notes. The obligation to make payments of additional interest upon a registration default, and, in certain circumstances, payments upon a change in control, may implicate the provisions of Treasury regulations relating to "contingent payment debt instruments." We intend to take the position that the notes should not be treated as contingent payment debt instruments because of these payments. Assuming such position is respected, a U.S. Holder would be required to include in income the amount of any such payments at the time such payments are received or accrued in accordance with such U.S. Holder's method of accounting for U.S. federal income tax purposes. If the IRS successfully challenged this position, and the notes were treated as contingent payment debt instruments because of such payments, U.S. Holders might, among other things, be required to accrue interest income at higher rates than the stated interest rates on the notes and to treat any gain recognized on the sale or other disposition of a note as ordinary income, subject to tax at the maximum federal rate of 38.6%, rather than as capital gain which may be subject to tax at the maximum federal rate of 20%. The regulations applicable to contingent payment debt instruments have not been the subject of authoritative interpretation and therefore the scope of the regulations is not certain. Purchasers of notes are urged to consult their tax advisors regarding the possible application of the contingent payment debt instrument rules to the notes. INFORMATION REPORTING AND BACKUP WITHHOLDING A U.S. Holder may be subject to a backup withholding tax (currently at a rate of 30% but subject to a gradual reduction to 28% for payments made in 2006 through 2010, after which it will increase to 31%) when such holder receives "reportable payments," including interest and principal payments on the notes or proceeds upon the sale or other disposition of such notes. Certain holders (including, among others, corporations and certain tax-exempt organizations) are generally not subject to backup withholding. A U.S. Holder will be subject to this backup withholding tax if such holder is not otherwise exempt and such holder: o fails to furnish its taxpayer identification number, or TIN, which, for an individual, is ordinarily his or her social security number; o furnishes an incorrect TIN and the payor has received notice thereof; o has failed to properly report payments of interest or dividends and the payor has received notice thereof; or o fails to certify, under penalties of perjury, that it has furnished a correct TIN and that the IRS has not notified the U.S. Holder that it is subject to backup withholding. 118 U.S. Holders should consult their personal tax advisors regarding their qualification for an exemption from backup withholding and the procedures for obtaining such an exemption, if applicable. The backup withholding tax is not an additional tax and taxpayers may use amounts withheld as a credit against their United States federal income tax liability or may claim a refund as long as they timely provide certain information to the IRS. We, our paying agent or other withholding agent generally will report to a U.S. Holder of notes and to the IRS the amount of any reportable payments made in respect of the notes for each calendar year and the amount of tax withheld, if any, with respect to such payments. NON-U.S. HOLDERS The following discussion is limited to the United States federal income tax consequences relevant to a beneficial owner of a note that is not a U.S. Holder (a "Non-U.S. Holder"). INTEREST Subject to the discussion of backup withholding below, interest paid to a Non-U.S. Holder will not be subject to United States federal income or withholding tax, provided that: o such holder does not directly or indirectly, actually or constructively, own 10% or more of the total combined voting power of all classes of our stock entitled to vote; o such holder is not a controlled foreign corporation that is related to us directly or constructively through stock ownership; o such holder is not a bank receiving interest on a loan entered into in the ordinary course of its trade or business; o such interest is not effectively connected with the conduct by the Non-U.S. Holder of a trade or business within the United States; and o we, or our paying agent, receive appropriate documentation establishing that the Non-U.S. Holder is not a U.S. person. A Non-U.S. Holder that does not qualify for exemption from withholding under the preceding paragraph generally will be subject to withholding of United States federal income tax at a 30% rate (or lower applicable treaty rate) on payments of interest on the notes. If interest on the notes is effectively connected with the conduct by a Non-U.S. Holder of a trade or business within the United States, such interest will be subject to United States federal income tax on a net income basis at the rate applicable to U.S. persons generally (and, with respect to corporate holders, may also be subject to a 30% branch profits tax). If interest is subject to United States federal income tax on a net income basis in accordance with these rules, such payments will not be subject to United States withholding tax so long as the Non-U.S. Holder provides us or our paying agent with the appropriate documentation. SALE OR OTHER TAXABLE DISPOSITION OF THE NOTES Subject to the discussion of backup withholding below, any gain realized by a Non-U.S. Holder on the sale, exchange or redemption of a note generally will not be subject to United States federal income tax, unless o such gain is effectively connected with the conduct by such Non-U.S. Holder of a trade or business within the United States, o the Non-U.S. Holder is an individual who is present in the United States for 183 days or more in the taxable year of disposition and certain other conditions are satisfied, or o the Non-U.S. Holder is subject to tax pursuant to the provisions of United States federal income tax law applicable to certain expatriates. 119 INFORMATION REPORTING AND BACKUP WITHHOLDING Backup withholding and information reporting generally will not apply to interest payments made to a Non-U.S. Holder in respect of the notes if such Non-U.S. Holder furnishes us or our paying agent with appropriate documentation of such holder's non-U.S. status. The payment of proceeds from a Non-U.S. Holder's disposition of notes to or through the U.S. office of any broker, domestic or foreign, will be subject to information reporting and possible backup withholding unless such holder certifies as to its non-U.S. status under penalties of perjury or otherwise establishes an exemption, provided that the broker does not have actual knowledge or reason to know that such holder is a U.S. person or that the conditions of an exemption are not, in fact, satisfied. The payment of the proceeds from a Non-U.S. Holder's disposition of a note to or through a non- United States office of either a United States broker or a non- United States broker that is a U.S.-related person will be subject to information reporting, but not backup withholding, unless such broker has documentary evidence in its files that such Non-U.S. Holder is not a U.S. person and the broker has no knowledge to the contrary, or the Non-U.S. Holder establishes an exemption. For this purpose, a "U.S.-related person" is o a controlled foreign corporation for United States federal income tax purposes, o a foreign person 50% or more of whose gross income from all sources for the three-year period ending with the close of its taxable year preceding payment (or for such part of the period that the broker has been in existence) is derived from activities that are effectively connected with the conduct of a United States trade or business, or o a foreign partnership that is either engaged in the conduct of a trade or business in the United States or of which 50% or more of its income or capital interests are held by U.S. persons. Neither information reporting nor backup withholding will apply to a payment of the proceeds of a Non-U.S. Holder's disposition of notes by or through a non-United States office of a non-United States broker that is not a United States-related person. Copies of any information returns filed with the IRS may be made available by the IRS, under the provisions of a specific treaty or agreement, to the taxing authorities of the country in which the Non-U.S. Holder resides. Non-U.S. Holders should consult their own tax advisors regarding the application of withholding and backup withholding in their particular circumstances and the availability of and procedure for obtaining an exemption from withholding and backup withholding under current Treasury Regulations. In this regard, the current Treasury Regulations provide that a certification may not be relied on if we or our agent (or other payor) knows or has reasons to know that the certification may be false. Any amounts withheld under the backup withholding rules from a payment to a Non-U.S. Holder will be allowed as a credit against the holder's United States federal income tax liability or may entitle the holder to a refund, provided the required information is furnished timely to the IRS. 120 PLAN OF DISTRIBUTION Based on existing interpretations of the Securities Act by the staff of the SEC set forth in several no-action letters to third parties, and subject to the immediately following sentence, we believe that the exchange notes that will be issued pursuant to the exchange offer may be offered for resale, resold and otherwise transferred by the holders thereof without further compliance with the registration and prospectus delivery provisions of the Securities Act. However, any purchaser of notes who is an "affiliate" (within the meaning of the Securities Act) of ours or who intends to participate in the exchange offer for the purpose of distributing the exchange notes or a broker-dealer (within the meaning of the Securities Act) that acquired original notes in a transaction other than as part of its market-making or other trading activities and who has arranged or has an understanding with any person to participate in the distribution of the exchange notes: (1) will not be able to rely on the interpretations by the staff of the SEC set forth in the above-mentioned no-action letters; (2) will not be able to tender its original notes in the exchange offer; and (3) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the notes unless such sale or transfer is made pursuant to an exemption from such requirements. Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for original notes where such original notes were acquired as a result of market-marketing activities or other trading activities. We have agreed that, for a period of 120 days after the expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until March 20, 2003, all dealers effecting transactions in the exchange notes may be required to deliver a prospectus. We will not receive any proceeds from any such sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker/dealer and/or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit on any such resale of exchange notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letters of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. For a period of 120 days after the expiration date we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act. 121 NOTICE TO CANADIAN RESIDENTS Any resale of the notes in Canada must be made under applicable securities laws which will vary depending on the relevant jurisdiction, and which may require resales to be made under available statutory exemptions or under a discretionary exemption granted by the applicable Canadian securities regulatory authority. Note holders resident in Canada are advised to seek legal advice prior to any resale of the notes. LEGAL MATTERS Certain legal matters with respect to the exchange notes will be passed upon for us by Willkie Farr & Gallagher, New York, New York. EXPERTS The consolidated balance sheets of MidAmerican Energy Holdings Company (successor to MidAmerican Energy Holdings Company (Predecessor), or MEHC (Predecessor)), and its subsidiaries, which are therein collectively referred to as the Company, as of December 31, 2001 and 2000 for the Company, and the related consolidated statements of operations, stockholders' equity, and cash flows for the year ended December 31, 2001 for the Company, for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor), for the period March 14, 2000 to December 31, 2000 for the Company, and for the year ended December 31, 1999 for MEHC (Predecessor), included in this prospectus and the related financial statement schedules included elsewhere in the registration statement, have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing herein (which report expresses an unqualified opinion and includes an explanatory paragraph referring to the Company's change in its accounting policy for major maintenance, overhaul, and well workover costs), and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing. With respect to the unaudited interim financial information for the periods ended September 30, 2002 and 2001, which is included in this prospectus, Deloitte & Touche LLP have applied limited procedures in accordance with professional standards for a review of such information. However, as stated in their report included in the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 and included herein, they did not audit and they do not express an opinion on that interim financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. Deloitte & Touche LLP are not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited interim financial information because this report is not a "report" or a "part" of the registration statement prepared or certified by an accountant within the meaning of Sections 7 and 11 of the Act. WHERE YOU CAN FIND MORE INFORMATION We file reports and information statements and other information with the SEC. Such reports, proxy and information statements and other information filed by us with the SEC can be inspected and copied at the Public Reference Section of the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, and at the regional offices of the SEC located at Woolworth Building, 233 Broadway, New York, New York 10279 and 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of such material can be obtained from the Public Reference Section of the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549 at prescribed rates. The SEC maintains a Web site that contains reports, proxy and information statements and other materials that are filed through the SEC's Electronic Data Gathering, Analysis, and Retrieval (EDGAR) system. This Web site can be accessed at http://www.sec.gov. We make available free of charge through our internet website at http://www.midamerican.com our annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably practicable after we electronically file with, or furnish it to, the SEC. Any information available on or through our website is not part of this prospectus. 122 INDEX TO FINANCIAL STATEMENTS
PAGE Independent Accountants' Report ........................................................ F-2 Consolidated Balance Sheets as of September 30, 2002 (unaudited) and December 31, 2001 . F-3 Unaudited Consolidated Statements of Operations for the three- and nine-month periods ended September 30, 2002 and 2001 ..................................................... F-4 Unaudited Consolidated Statements of Cash Flows for the nine-month periods ended September 30, 2002 and 2001 ........................................................... F-5 Notes to Unaudited Consolidated Financial Statements ................................... F-6 Independent Auditors' Report ........................................................... F-21 Consolidated Balance Sheets as of December 31, 2001 and 2000 ........................... F-22 Consolidated Statements of Operations for the year ended December 31, 2001 for the Company, for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor), for the period March 14, 2000 to December 31, 2000 for the Company, and for the year ended December 31, 1999 for MEHC (Predecessor) ........................................ F-23 Consolidated Statements of Stockholders' Equity for the year ended December 31, 2001 for the Company, for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor), for the period March 14, 2000 to December 31, 2000 for the Company, and for the year ended December 31, 1999 for MEHC (Predecessor) ........................................ F-24 Consolidated Statements of Cash Flows for the year ended December 31, 2001 for the Company, for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor), for the period March 14, 2000 to December 31, 2000 for the Company, and for the year ended December 31, 1999 for MEHC (Predecessor) ........................................ F-25 Notes to Consolidated Financial Statements ............................................. F-26
F-1 INDEPENDENT ACCOUNTANTS' REPORT Board of Directors and Shareholders MidAmerican Energy Holdings Company Des Moines, Iowa We have reviewed the accompanying consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries (the Company) as of September 30, 2002, and the related consolidated statements of operations for the three-month and nine-month periods ended September 30, 2002 and 2001, and the related consolidated statements of cash flows for the nine-month periods ended September 30, 2002 and 2001. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to such consolidated financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries as of December 31, 2001, and the related consolidated statements of operations, shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated January 17, 2002 (March 27, 2002 as to Notes 20.A. and 21 and August 2, 2002 as to Note 23), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2001, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. DELOITTE & TOUCHE LLP Des Moines, Iowa November 8, 2002 F-2 MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
AS OF ------------------------------- SEPTEMBER 30, DECEMBER 31, 2002 2001 --------------- --------------- (UNAUDITED) ASSETS Current assets: Cash and cash equivalents ....................................................... $ 662,061 $ 386,745 Restricted cash and short-term investments ...................................... 56,466 30,565 Accounts receivable ............................................................. 549,656 310,030 Inventories ..................................................................... 132,153 135,822 Other current assets ............................................................ 187,773 106,124 ----------- ----------- Total current assets .......................................................... 1,588,109 969,286 Property, plant, contracts and equipment, net .................................... 9,168,940 6,537,371 Excess of cost over fair value of net assets acquired, net ....................... 4,223,198 3,638,546 Regulatory assets ................................................................ 538,134 221,120 Other investments ................................................................ 444,183 174,185 Equity investments ............................................................... 274,198 261,432 Deferred charges and other assets ................................................ 747,288 824,712 ----------- ----------- TOTAL ASSETS ..................................................................... $16,984,050 $12,626,652 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY LIABILITIES: Current liabilities: Accounts payable ................................................................ $ 381,983 $ 266,027 Accrued interest ................................................................ 201,082 130,569 Accrued taxes ................................................................... 93,028 88,973 Other accrued liabilities ....................................................... 525,750 308,924 Short-term debt ................................................................. 642,031 256,012 Current portion of long-term debt ............................................... 483,106 317,180 ----------- ----------- Total current liabilities ..................................................... 2,326,980 1,367,685 Other long-term accrued liabilities .............................................. 612,321 537,495 Parent company debt .............................................................. 1,623,178 1,834,498 Subsidiary and project debt ...................................................... 6,388,169 4,754,811 Deferred income taxes ............................................................ 1,297,136 1,284,268 ----------- ----------- TOTAL LIABILITIES ................................................................ 12,247,784 9,778,757 ----------- ----------- Deferred income .................................................................. 82,305 85,917 Minority interest ................................................................ 6,012 44,477 Preferred securities of subsidiaries ............................................. 93,619 121,183 Company-obligated mandatorily redeemable preferred securities of subsidiary trusts .......................................................................... 2,062,815 788,151 Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts .......................................................................... -- 100,000 Commitments and contingencies (Note 12) SHAREHOLDERS' EQUITY: Zero coupon convertible preferred stock -- authorized 50,000 shares, no par value, 41,263 and 34,563 shares issued and outstanding at September 30, 2002, and December 31, 2001, respectively ................................................. -- -- Common stock -- authorized 60,000 shares, no par value, 9,281 shares issued and outstanding ..................................................................... -- -- Additional paid-in capital ....................................................... 1,956,509 1,553,073 Retained earnings ................................................................ 510,766 223,926 Accumulated other comprehensive income (loss) .................................... 24,240 (68,832) ----------- ----------- TOTAL SHAREHOLDERS' EQUITY ....................................................... 2,491,515 1,708,167 ----------- ----------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY ....................................... $16,984,050 $12,626,652 =========== ===========
The accompanying notes are an integral part of these financial statements. F-3 MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS) (UNAUDITED)
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 ------------------------------ ----------------------------- 2002 2001 2002 2001 -------------- ------------- ------------- ------------- REVENUES: Operating revenue ........................... $ 1,238,463 $1,076,786 $3,404,533 $3,756,931 Income on equity investments ................ 10,939 6,332 29,863 23,622 Interest and other income ................... 32,714 223,941 115,348 262,522 ----------- ---------- ---------- ---------- TOTAL REVENUES ............................... 1,282,116 1,307,059 3,549,744 4,043,075 ----------- ---------- ---------- ---------- COSTS AND EXPENSES: Cost of sales ............................... 443,144 472,964 1,283,238 2,010,164 Operating expense ........................... 343,303 293,867 948,913 844,776 Depreciation and amortization ............... 129,362 122,686 386,531 395,253 Interest expense ............................ 168,450 119,809 462,998 362,163 Less interest capitalized ................... (9,152) (19,877) (24,128) (72,010) ----------- ---------- ---------- ---------- TOTAL COSTS AND EXPENSES ..................... 1,075,107 989,449 3,057,552 3,540,346 ----------- ---------- ---------- ---------- Income before provision for income taxes ..... 207,009 317,610 492,192 502,729 Provision for income taxes ................... 26,788 241,873 80,226 296,088 ----------- ---------- ---------- ---------- Income before minority interest .............. 180,221 75,737 411,966 206,641 Minority interest ............................ 45,344 27,796 105,166 79,952 ----------- ---------- ---------- ---------- INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE ..................... 134,877 47,941 306,800 126,689 Cumulative effect of change in accounting principle, net of tax ....................... -- -- -- (4,604) ----------- ---------- ---------- ---------- NET INCOME AVAILABLE TO COMMON AND PREFERRED SHAREHOLDERS ...................... $ 134,877 $ 47,941 $ 306,800 $ 122,085 =========== ========== ========== ==========
The accompanying notes are an integral part of these financial statements. F-4 MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) (UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30 ------------------------------ 2002 2001 --------------- ------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income ............................................................... $ 306,800 $ 122,085 Adjustments to reconcile to net cash flows from operating activities: Cumulative effect of change in accounting principle, net of tax .......... -- 4,604 Gains on disposals ....................................................... (57,480) (221,108) Depreciation and amortization ............................................ 386,531 282,125 Amortization of excess of cost over fair value of net assets acquired .... -- 74,728 Amortization of deferred financing costs and other costs ................. 32,589 15,542 Provision for deferred income taxes ...................................... 40,518 236,901 Undistributed earnings on equity investments ............................. (14,828) (23,622) Changes in other items: Accounts receivable ..................................................... (76,621) 607,287 Other current assets .................................................... 47,493 23,381 Accounts payable and accrued liabilities ................................ (15,193) (389,295) Accrued interest ........................................................ 79,548 78,391 Accrued taxes ........................................................... (43,963) (25,733) Deferred income ......................................................... (2,612) 5,704 ------------ ---------- NET CASH FLOWS FROM OPERATING ACTIVITIES ................................. 682,782 790,990 ------------ ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Acquisition of Kern River, net of cash acquired .......................... (419,724) -- Acquisition of Northern Natural Gas, net of cash acquired ................ (899,249) -- Acquisition of Yorkshire Electricity, net of cash acquired ............... (8,380) (36,860) Proceeds from sale of Northern Supply .................................... -- 377,396 Purchase of convertible preferred securities ............................. (275,000) -- Capital expenditures relating to operating projects ...................... (328,544) (242,337) Construction and other development costs ................................. (450,206) (134,625) Receipt of liquidated damages on construction projects ................... -- 29,648 Proceeds from sale of assets ............................................. 210,767 10,500 Purchase of minority interests ........................................... (33,262) (29,276) Acquisition of realty companies, net of cash acquired .................... (102,699) (32,565) Change in restricted investments ......................................... 16,746 17,924 Change in other assets ................................................... 25,895 (8,502) ------------ ---------- NET CASH FLOWS FROM INVESTING ACTIVITIES ................................. (2,263,656) (48,697) ------------ ---------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from issuance of convertible preferred stock .................... 402,000 -- Proceeds from issuance of trust preferred securities ..................... 1,273,000 -- Net repayment of short-term subsidiary debt .............................. (77,585) (160,288) Net proceeds from short-term parent company debt ......................... 13,500 64,500 Repayment of subsidiary and project debt ................................. (377,644) (278,867) Proceeds from subsidiary and project debt ................................ 780,142 200,000 Redemption of preferred securities of subsidiaries ....................... (127,613) (14,616) Change in restricted investments-debt service ............................ (25,901) (6,585) Other .................................................................... (44,999) (2,105) ------------ ---------- NET CASH FLOWS FROM FINANCING ACTIVITIES ................................. 1,814,900 (197,961) ------------ ---------- Effect of exchange rate changes on cash .................................. 41,290 1,689 ------------ ---------- Net increase in cash and cash equivalents ................................ 275,316 546,021 Cash and cash equivalents at beginning of period ......................... 386,745 38,152 ------------ ---------- Cash and cash equivalents at end of period ............................... $ 662,061 $ 584,173 ============ ========== Interest paid, net of amount capitalized ................................. $ 404,288 $ 222,991 ============ ========== Income taxes paid ........................................................ $ 55,437 $ 43,632 ============ ==========
The accompanying notes are an integral part of these financial statements. F-5 MIDAMERICAN ENERGY HOLDINGS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. GENERAL In the opinion of management of MidAmerican Energy Holdings Company and subsidiaries (the "Company"), the accompanying unaudited consolidated financial statements contain all adjustments (consisting of normal recurring accruals) necessary to present fairly the financial position as of September 30, 2002, and the results of operations for the three months and nine months ended September 30, 2002 and 2001 and the related consolidated statements of cash flows for the nine months ended September 30, 2002 and 2001. The results of operations for the three months and nine months ended September 30, 2002 and 2001 are not necessarily indicative of the results to be expected for the full year. The consolidated financial statements include the accounts of MidAmerican Energy Holdings Company and its wholly and majority owned subsidiaries. Other investments and corporate joint ventures, where the Company has the ability to exercise significant influence, are accounted for under the equity method. Investments where the Company's ability to influence is limited are accounted for under the cost method of accounting. Certain amounts in the 2001 financial statements and supporting note disclosures have been reclassified to conform to the 2002 presentation. Such reclassification did not impact previously reported net income or retained earnings. Although the Company believes that the disclosures are adequate to make the information presented not misleading, it is suggested that these financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company's latest Annual Report on Form 10-K. 2. ACQUISITIONS Kern River On March 27, 2002, the Company closed on a definitive agreement with The Williams Companies, Inc. ("Williams") to acquire Williams" Kern River Gas Transmission Company ("Kern River"), a 926-mile interstate pipeline transporting Rocky Mountain and Canadian natural gas to markets in California, Nevada and Utah. The Kern River pipeline is an important route for the transmission of natural gas from the vast reserves in the Rocky Mountain states to the rapidly growing markets in Utah, Nevada and California. Constructed in 1992, the Kern River pipeline extends from Opal, Wyoming, to the San Joaquin Valley near Bakersfield, California, and has a design capacity of 845 million cubic feet per day. The Company paid $419.7 million, net of cash acquired of $7.7 million and transaction costs and working capital adjustments, for Kern River's gas pipeline business. At the time of the acquisition, Kern River had $505 million of indebtedness, the unamortized portion of which remains outstanding. The acquisition has been accounted for as a purchase business combination. The Company is in the process of completing the allocation of the purchase price to the assets and liabilities acquired. The results of operations for Kern River are included in the Company's results beginning March 27, 2002. The recognition of excess of cost over fair value of net assets acquired resulted from various attributes of Kern River's operations and business in general. These attributes include, but are not limited to: - Opportunities for expansion; - High credit quality shippers contracting with Kern River; - Kern River's strong competitive position; - Exceptional operating track record and state-of-the-art technology; F-6 - Strong demand for gas in the Western markets; and - An ample supply of low-cost gas. In connection with the acquisition of Kern River, the Company issued $323.0 million of 11% Company-obligated mandatorily redeemable preferred securities of subsidiary trust due March 12, 2012 with scheduled principal payments beginning in 2005 and $127.0 million of no par, zero coupon convertible preferred stock to Berkshire Hathaway. Each share of preferred stock is convertible at the option of the holder into one share of the Company's common stock subject to certain adjustments as described in the Company's Amended and Restated Articles of Incorporation. Northern Natural Gas Company On August 16, 2002, the Company closed on a definitive agreement with Dynegy Inc. ("Dynegy") to acquire Dynegy's Northern Natural Gas Company ("Northern Natural Gas"), a 16,600-mile interstate pipeline extending from southwest Texas to the upper Midwest region of the United States. With a design capacity of 4.4 billion cubic feet of natural gas per day, Northern Natural Gas accesses natural gas supply from many of the larger producing regions in North America including the Rocky Mountains, Hugoton, Permian, Anadarko and Western Canadian basins. The system provides transportation and storage services to approximately 70 utility customers and numerous industrial customers in the Upper Midwest. Northern Natural Gas also provides cross-haul and grid transportation between other interstate and intrastate pipelines in Permian, Anadarko, Hugoton and Midwest areas. It operates three natural gas storage facilities and two liquefied natural gas peaking units for a total storage capacity of 59 billion cubic feet and peak delivery capability of over 1.3 billion cubic feet of natural gas per day. The Company paid $899.2 million for Northern Natural Gas, net of cash acquired of $1.4 million and transaction costs and working capital adjustments. At the time of the acquisition, Northern Natural Gas had $950 million of debt outstanding. The acquisition has been accounted for as a purchase business combination. The Company is in the process of completing the working capital negotiations and the allocation of the purchase price to the assets and liabilities acquired. The results of operations for Northern Natural Gas are included in the Company's results beginning August 16, 2002. The recognition of excess of cost over fair value of net assets acquired resulted from various attributes of Northern Natural Gas' operations and business in general. These attributes include, but are not limited to: - High credit quality shippers contracting with Northern Natural Gas; - Northern Natural Gas' strong competitive position; - Strategic location in the high demand Upper Midwest markets; - Flexible access to an ample supply of low-cost gas; - Exceptional operating track record; and - Opportunities for expansion. In connection with the acquisition of Northern Natural Gas, the Company issued $950.0 million of 11% Company-obligated mandatorily redeemable preferred securities of subsidiary trust due August 31, 2011, with scheduled principal payments beginning in 2003, to Berkshire Hathaway. The following pro forma financial information of the Company represents the unaudited pro forma results of operations as if the Kern River and Northern Natural Gas acquisitions, the related financings and the Yorkshire Swap, as described in Note 3 of Notes to Consolidated Financial Statements in the Annual Report on Form 10-K for the year ended December 31, 2001, had occurred at the beginning of each year. These pro forma results have been prepared for comparative purposes only and do not profess to be indicative of the results of operations which would have been achieved had these transactions been completed at the beginning of each year, nor are the results indicative of the Company's future results of operations (in thousands). F-7
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 --------------------------- --------------------------- 2002 2001 2002 2001 ------------- ------------- ------------- ------------- Revenue .................................... $1,204,513 $1,050,104 $3,888,873 $3,849,034 Income before cumulative effect of change in accounting principle ...................... 126,389 71,421 310,359 185,154 Net income available to common and preferred shareholders .............................. 126,389 71,421 310,359 180,550
3. CALENERGY GAS DISPOSAL In May 2002, CalEnergy Gas, an indirect wholly owned subsidiary of the Company, executed the sale of several of its U.K. natural gas assets to Gaz de France for (pounds sterling)137.0 million (approximately $200 million). CalEnergy Gas sold four natural gas-producing fields located in the southern basin of the U.K. North Sea, including Anglia, Johnston, Schooner and Windermere. The transaction also included the sale of rights in four gas fields (in development/construction) and three exploration blocks owned by CalEnergy Gas. As a result of the sale, the Company's nine month results ending September 30, 2002 include pre-tax and after-tax income of $54.3 million and $41.3 million, respectively, which includes a write off of non-deductible goodwill of $49.6 million. The three month results ending September 30, 2002 include $21.1 million in tax benefits related to the sale. 4. PROPERTY, PLANT, CONTRACTS AND EQUIPMENT, NET Property, plant, contracts and equipment, net comprise the following (in thousands):
SEPTEMBER 30, DECEMBER 31, 2002 2001 --------------- --------------- Operating assets: Utility generation, distribution and transmission systems .......... $ 10,102,855 $ 7,574,339 Independent power plants ........................................... 1,406,345 1,402,102 Utility non-operational assets ..................................... 363,910 354,366 Power sales agreements ............................................. 19,185 48,185 Realty company assets .............................................. 73,785 51,150 Other assets ....................................................... 54,197 53,876 ------------ ------------ Total operating assets ............................................. 12,020,277 9,484,018 Less accumulated depreciation and amortization ..................... (3,995,916) (3,650,875) ------------ ------------ Net operating assets ............................................... 8,024,361 5,833,143 Mineral and gas reserves and exploration assets, net ............... 280,722 387,697 Construction in progress: Zinc Recovery Project ............................................. 213,923 163,366 Utility generation, distribution and transmission systems ......... 253,945 149,225 Kern River natural gas pipeline expansion ......................... 389,321 -- Other ............................................................. 6,668 3,940 ------------ ------------ Total .......................................................... $ 9,168,940 $ 6,537,371 ============ ============
Zinc Recovery Project CalEnergy Minerals, LLC, an indirect wholly owned subsidiary of the Company, is constructing the Zinc Recovery Project. The Zinc Recovery Project is designed to have a capacity of approximately 30,000 metric tons per year and is scheduled to commence commercial operations in 2002. Total project costs of the Zinc Recovery Project are expected to be approximately $244 million, net of damages received from Kvaerner, which is being funded by $140.5 million of debt and the balance from funds provided by the parent company. The Zinc Recovery Project has incurred $213.9 million, net of damages, of such costs through September 30, 2002. F-8 Utility generation, distribution and transmission systems Through 2007, MidAmerican Energy plans to develop and construct two electric generating plants in Iowa. MidAmerican Energy expects to invest approximately $1.2 billion in the two plants, including the cost of related transmission facilities and allowance for funds used during construction. The two plants may provide approximately 950 megawatts of generating capacity for MidAmerican Energy depending on management's on-going assessment of needs and related factors. The first project is a 500-megawatt (based on expected accreditation) natural gas-fired combined cycle unit with an estimated cost of $415 million. MidAmerican Energy will own 100% of the plant and operate it. MidAmerican Energy has received a certificate from the Iowa Utilities Board allowing it to construct the plant. Also, on May 29, 2002, the Iowa Utilities Board issued an order that provides the ratemaking principles for the gas-fired plant, thus limiting the regulatory risk of constructing the plant. As a result of that order, MidAmerican Energy is proceeding with the construction of the plant. It is anticipated that the first phase of the project will be completed in 2003, resulting in an additional 310 megawatts of accredited capacity, with the remainder being completed in 2005. Kern River natural gas pipeline expansion On July 17, 2002, Kern River received approval from FERC to construct, own and operate a major expansion to its pipeline system (the "2003 Expansion Project"). The 2003 Expansion Project will loop most of Kern River's existing mainline, construct three new compressor stations and upgrade or modify Kern River's six existing compressor stations. The 2003 Expansion Project, which is expected to be completed and operational by May 2003, will increase Kern River's capacity by approximately 900 MMcf per day. Service will be provided under long-term contracts subject to incremental rates. The estimated cost of the expansion is approximately $1.2 billion. 5. OTHER INVESTMENTS On March 27, 2002, the Company invested $275.0 million in Williams in exchange for shares of 97/8 percent cumulative convertible preferred stock of Williams. Dividends are scheduled to be received quarterly, which commenced July 1, 2002. This investment is accounted for under the cost method. The Company is aware that there have been public announcements that Williams' financial condition has deteriorated as a result of reduced liquidity. Williams' senior unsecured debt obligations are currently rated B1 by Moody's, B by Standard & Poor's and B- by Fitch. The Company has not recorded an impairment on this investment as of September 30, 2002, and is monitoring the situation. In connection with this investment, the Company issued $275.0 million of no par, zero coupon convertible preferred stock to Berkshire Hathaway. Each share of preferred stock is convertible at the option of the holder into one share of the Company's common stock subject to certain adjustments as described in the Company's Amended and Restated Articles of Incorporation. 6. TEESSIDE POWER LIMITED RESTRUCTURING CE Electric UK Funding, an indirect wholly owned subsidiary of the Company, has a 15.4% interest in Teesside Power Limited ("TPL"). TPL owns and operates an 1,875MW combined cycle gas-fired power plant. Shareholders in TPL had previously utilized TPL's taxable losses with an obligation to reimburse TPL later in the project's life. In May 2002, TPL executed a restructuring and stabilization agreement with its lenders. The contract included an agreement between TPL and its shareholders with respect to the waiver of these repayment obligations. In May 2002, CE Electric UK Funding released $35.7 million due to the repayment obligation being waived which is reflected as a current tax benefit in the provision for income taxes. 7. REAL ESTATE COMPANY ACQUISITIONS During 2002, HomeServices separately acquired three real estate companies for an aggregate purchase price of approximately $100 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2001, these real estate companies had combined revenue F-9 of approximately $356 million on 42,000 closed sides representing $13.7 billion of sales volume. Additionally, HomeServices is obligated to pay a maximum earnout of $18.5 million calculated based on 2002 financial performance measures. These purchases were financed using HomeServices' $65 million revolving credit facility and MidAmerican Energy Holdings Company's corporate revolver for $40 million, which was contributed to HomeServices as equity. The Company is in the process of completing the allocation of the purchase price to the assets and liabilities acquired. 8. DEBT ISSUANCES AND REDEMPTIONS On February 8, 2002, MidAmerican Energy issued $400 million of 6.75% notes due in 2031. The proceeds are being used to refinance existing debt and preferred securities and for other corporate purposes. On March 11, 2002, MidAmerican Energy redeemed all $100 million of its 7.98% MidAmerican-obligated preferred securities of subsidiary trust at 100% of the principal amount plus accrued interest. On May 1, 2002, MidAmerican Energy reacquired all $26.7 million of its $7.80 series of preferred securities. The first $13.3 million of preferred securities were redeemed at 100% of the principal amount plus accrued dividends, and the remaining $13.4 million was redeemed at 103.9% of the principal amount plus accrued dividends. On June 21, 2002, Kern River closed on a bank loan facility providing for aggregate loans of up to $875 million to be used for the construction of the Kern River 2003 Expansion Project. The facility, which matures 15 years after the 2003 Expansion Project commences operation, has a variable interest rate which increases over the term of the facility from 1.375% to 4.5% over LIBOR. Kern River has drawn $384.9 million on this facility as of September 30, 2002. 9. ACCOUNTING POLICY CHANGE Effective January 1, 2001, the Company changed its accounting policy regarding major maintenance and repairs for nonregulated gas projects, nonregulated plant overhaul costs and geothermal well rework costs to the direct expense method from the former policy of monthly accruals based on long-term scheduled maintenance plans for the gas projects and deferral and amortization of plant overhaul costs and geothermal well rework costs over the estimated useful lives. The cumulative effect of the change in accounting principle for 2001 was $4.6 million, net of taxes of $.7 million. 10. ACCOUNTING PRONOUNCEMENTS AND REPORTING ISSUES On January 1, 2002, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets," which dictates the accounting for acquired goodwill and other intangible assets. SFAS No. 142 requires that amortization of goodwill and indefinite-lived intangible assets be discontinued and that entities disclose net income for prior periods adjusted to exclude such amortization and related income tax effects, as well as a reconciliation from the originally reported net income to the adjusted net income. The Company's related amortization consists of goodwill amortization and the related income tax effect. Following is a reconciliation of net income as originally reported for the periods ended September 30, 2002 and 2001, to adjusted net income (in thousands):
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 -------------------------- -------------------------- 2002 2001 2002 2001 ------------ ----------- ----------- ------------ Net income as originally reported ......... $ 134,877 $ 47,941 $306,800 $ 122,085 Goodwill amortization ..................... -- 24,739 -- 74,728 Income tax benefit ........................ -- (503) -- (1,504) --------- -------- -------- --------- Net income as adjusted .................... $ 134,877 $ 72,177 $306,800 $ 195,309 ========= ======== ======== =========
In accordance with SFAS No. 142, the Company has determined its reporting units and has completed the initial impairment testing of goodwill primarily using a discounted cash flow methodology. No impairment was indicated as a result of the initial impairment testing. See Note 14 for allocation of goodwill to reporting units. F-10 In August 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143 requires recognition on the balance sheet of legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of such assets. Additionally, at the time an asset retirement obligation (ARO) is recognized, an ARO asset of the same amount is recorded and depreciated. This pronouncement is effective for fiscal years beginning after June 15, 2002. The Company is evaluating the impact that adoption of this standard will have on its consolidated financial statements. In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. The adoption of SFAS No. 144 on January 1, 2002, did not have any impact on the Company's consolidated financial statements. The Emerging Issues Task Force (EITF) recently issued EITF Issue No. 02-3, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under Issues No. 98-10 and 00-17." In accordance with EITF No. 02-3, all gains and losses on energy trading contracts must be reported net on the income statement, effective for reporting periods ending after July 15, 2002, with all prior periods presented being reclassified to a consistent presentation. MidAmerican Energy's nonregulated wholesale gas and electric marketing activities qualify as "energy trading" contracts under the guidance of EITF No. 98-10. In accordance with EITF Issue No. 02-3, effective September 30, 2002, for MidAmerican Energy, all trading revenues are reported net of the cost of such sales. Previously, such amounts were recorded gross. All prior periods have been reclassified to conform to the net presentation. 11. COMPREHENSIVE INCOME The differences from net income to total comprehensive income for the Company are due to foreign currency translation adjustments, unrealized holding gains and losses of marketable securities during the periods, and the effective portion of net gains and losses of derivative instruments classified as cash flow hedges. Total comprehensive income for the nine months ended September 30, 2001, includes a transition loss of $3.3 million related to the initial adoption of SFAS No. 133. Total comprehensive income for the Company is shown in the table below (in thousands).
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30 ENDED SEPTEMBER 30 ------------------------- -------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ------------ Net income ................................. $134,877 $ 47,941 $ 306,800 $ 122,085 Other comprehensive income -- Foreign currency translation .............. 39,437 31,791 120,905 (16,681) Marketable securities, net of tax ......... 332 (7,683) (3,337) (5,816) Cash flow hedges, net of tax .............. (3,694) (3,897) (24,496) 32,598 -------- -------- --------- --------- Total comprehensive income ................. $170,952 $ 68,152 $ 399,872 $ 132,186 ======== ======== ========= =========
12. COMMITMENTS AND CONTINGENCIES A. FINANCIAL CONDITION OF EDISON Southern California Edison Company ("Edison"), a wholly owned subsidiary of Edison International, is a public utility primarily engaged in the business of supplying electric energy to retail customers in Central and Southern California, excluding Los Angeles. Due to reduced liquidity, Edison failed to pay approximately $119 million due under the power purchase agreement with CE Generation affiliates for power delivered in the fourth quarter 2000 and the first quarter 2001. Due to Edison's failure to pay contractual obligations, the CE Generation affiliates had established an allowance for doubtful accounts of approximately $21 million as of December 31, 2001. The final payment of the past due amounts was received from Edison on March 1, 2002. Following the receipt of Edison's payment of past due balances, the CE Generation affiliates released the remaining allowance for doubtful accounts. F-11 B. CASECNAN CONSTRUCTION ARBITRATION On May 7, 1997, CE Casecnan entered into a fixed-price, date certain, turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Construction Contract"). The work under the Construction Contract was conducted by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa., working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. (collectively, the "Contractor"). On November 20, 1999, the Construction Contract was amended to extend the Guaranteed Substantial Completion Date for the Casecnan Project to March 31, 2001. This amendment was approved by the lenders" independent engineer under the Casecnan Indenture. In January 2001, CE Casecnan received a new working schedule from the Contractor that showed a completion date of August 31, 2001. The delay in completion was attributable in part to the collapse in December 2000 of the Casecnan Project's partially completed vertical surge shaft and the need to drill a replacement surge shaft. Upon receipt of the working schedule, CE Casecnan sought and obtained from the lender's independent engineer approval for a revised construction schedule under the Casecnan Indenture. In connection with the revised schedule, MidAmerican Energy Holdings Company agreed to make available up to $11.6 million of additional funds under certain conditions pursuant to a Shareholder Support Letter dated February 8, 2001 (Shareholder Support Letter). MidAmerican Energy Holdings Company has fully satisfied its obligations under the Shareholder Support Letter. The receipt of the new working schedule did not change the Guaranteed Substantial Completion Date under the Construction Contract, and the Contractor was still contractually obligated either to complete the Casecnan Project by March 31, 2001, or to pay liquidated damages for the delay in completion. The Casecnan Project entered into commercial operations on December 11, 2001. In 2002, CE Casecnan has received approximately $6.0 million of liquidated damages from demands made on the demand guarantees posted by Commerzbank on behalf of the Contractor. On February 12, 2001, the Contractor filed a Request for Arbitration with the International Chamber of Commerce seeking an extension of the Guaranteed Substantial Completion Date by up to 153 days through August 31, 2001, resulting from various alleged force majeure events. In its March 20, 2001, Supplement to Request for Arbitration, the Contractor requested compensation for alleged additional costs of approximately $4 million it incurred from the claimed force majeure events to the extent it is unable to recover from its insurer. On April 20, 2001, the Contractor filed a further supplement seeking an additional compensation for damages of approximately $62 million for the alleged force majeure event (and geologic conditions) related to the collapse of the surge shaft. The Contractor has alleged that the circumstances surrounding the placing of the Casecnan Project into commercial operation on December 11, 2001, amounted to a repudiation of the Construction Contract and has filed a claim for unspecified quantum meruit damages. The Contractor also has alleged that the delay liquidated damages clause in the EPC Contract is unenforceable as a penalty. CE Casecnan believes all such allegations and claims are without merit and is vigorously contesting the Contractor's claims. The arbitration is being conducted applying New York law and in accordance with the rules of the International Chamber of Commerce. Although the outcome of the arbitration, as with any litigious proceedings, is difficult to access, CE Casecnan believes it will prevail and receive additional liquidated damages in the arbitration. On June 25, 2001, the arbitration tribunal temporarily enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di Roma in support of the Contractor's obligations to CE Casecnan for delay liquidated damages. On April 26, 2002, CE Casecnan and the Contractor mutually agreed that no demands would be made on the Banca di Roma demand guaranty except pursuant to a final arbitration award. Hearings on the force majeure claims were held in London from July 2 to 14, 2001, and hearings on the Contractor's April 20, 2001, supplement were held from September 24 to October 3, 2001. Further hearings were held from January 21 to February 1, 2002 and from March 14 to 19, 2002. From November 4 to 6, 2002, hearings were held on the Contractor's claim with respect to the alleged unenforceability of the delay liquidated damages clause. On November 7, 2002, the International Chamber of Commerce issued the arbitration tribunal's partial award with respect to the Contractor's force majeure and geologic F-12 conditions claims. The arbitral panel awarded the Contractor 18 days of schedule relief in the aggregate for all of the force majeure events and awarded the Contractor $3.8 million with respect to the cost of the collapsed surge shaft. All of the Contractor's other claims that have been heard by the arbitral tribunal were denied. Further hearings on the Contractor's repudiation and quantum meruit claims are scheduled for January 20 to 23 and 28 to 31, 2003. These claims, and the alleged unenforceability of the delay liquidated damages clause, have not been ruled on by the arbitration tribunal. C. CASECNAN SHAREHOLDER ISSUE Pursuant to the share ownership adjustment mechanism in the Casecnan Shareholder Agreement, which is based upon pro forma financial projections of the Casecnan Project prepared following commencement of commercial operations, the Company, through its indirect wholly owned subsidiary CE Casecnan Ltd., has advised the minority shareholder LaPrairie Group Contractors (International) Ltd. ("LPG"), that the Company's ownership interest in CE Casecnan will increase to 100%. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against, inter alia, CE Casecnan Ltd. and MidAmerican Energy Holdings Company. In the complaint, LPG seeks compensatory and punitive damages for alleged breaches of the Shareholder Agreement and alleged breaches of fiduciary duties allegedly owed by the Company and CE Casecnan Ltd. to LPG. The complaint also seeks injunctive relief against all defendants and a declaratory judgment that LPG is entitled to maintain its 15% interest in Casecnan. The impact, if any, of this litigation on the Company cannot be determined at this time. D. CASECNAN NIA ARBITRATION In August 2002, CE Casecnan commenced arbitration against the National Irrigation Administration ("NIA") in connection with the Casecnan Project by serving it with a Request for Arbitration under International Chamber of Commerce rules (the "Request for Arbitration"). In the Request for Arbitration, CE Casecnan claimed that NIA has breached its obligations under the Casecnan Project Agreement by failing to reimburse CE Casecnan for certain tax payments and by failing to pay the portion of the Water Delivery Fee under the Casecnan Project Agreement attributable to certain tax payments. The Casecnan Project Agreement provides for arbitration in accordance with International Chamber of Commerce rules by a panel of three arbitrators in Singapore. CE Casecnan is awaiting NIA's formal answer to the Request for Arbitration. CE Casecnan intends to vigorously pursue its claims in these proceedings. E. MALITBOG ARBITRATION VGPC and PNOC-EDC have been negotiating with respect to certain disputes concerning the Malitbog energy conversion agreement ("ECA") but have been unable to reach a mutually acceptable resolution. Accordingly, on October 16, 2000, VGPC commenced arbitration against PNOC-EDC by serving it with a Notice of Arbitration and Statement of Claim (the "Notice of Arbitration"). In the Notice of Arbitration, VGPC claimed that PNOC-EDC breached the Malitbog ECA by improperly characterizing certain No Fault Outages as Forced Outage Hours and then deducting them from the total number of hours each month. On December 22, 2000, VGPC filed an Amended Statement of Claim pursuant to which VGPC added a claim that PNOC-EDC breached the Malitbog ECA by refusing to accept VGPC's specified Nominated Capacity for contract years July 25, 1999 to July 25, 2000, and July 25, 2000 to July 25, 2001. A Second Amended Statement of Claim was filed on March 9, 2001, to add the Scheduled Maintenance issue. VGPC is vigorously pursuing its claims in this proceeding. Hearings were conducted from June 24, 2002, to July 5, 2002, in Sydney, Australia, and the Company expects a ruling on these hearings in the fourth quarter of 2002. F. MAHANAGDONG ARBITRATION On September 25, 2002, CE Luzon Geothermal Power Company, Inc. ("CE Luzon"), an indirect majority owned subsidiary of the Company, commenced arbitration against PNOC-EDC by serving it with a F-13 Request for Arbitration (the "Request for Arbitration") under International Chamber of Commerce rules. In the Request for Arbitration, CE Luzon claimed that PNOC-EDC breached the Mahanagdong ECA by refusing to accept CE Luzon's specified Nominated Capacity for contract years July 25, 2001 to July 25, 2002 and July 25, 2002 to July 25, 2003. CE Luzon is awaiting PNOC-EDC's formal answer. CE Luzon intends to vigorously pursue its claims in these proceedings. G. REGULATORY ENVIRONMENT: PHILIPPINES The Philippine Congress has passed the Electric Power Industry Reform Act of 2001, which is aimed at restructuring the Philippine power industry, privatization of the NPC and introduction of a competitive electricity market, among other initiatives. The implementation of the bill may have an impact on the Company's future operations and the industry as a whole, the effect of which is not yet determinable and estimable. In connection with an interagency review of approximately 40 independent power project contracts in the Philippines, the Casecnan Project (along with four other unrelated projects) has reportedly been identified as raising legal and financial questions and, with those projects, has been prioritized for renegotiation. The Company's subsidiaries' Upper Mahiao, Malitbog, and Mahanagdong projects, which, together with the Casecnan Project, collectively the "Philippine Projects", have also reportedly been identified as raising financial questions. No written report has yet been issued with respect to the interagency review, and the timing and nature of steps, if any, that the Philippine Government may take in this regard are not known. To the extent disputes arise under the Philippine Projects' agreements with respect to the Philippines Projects' obligations, rights and remedies thereunder, such disputes will be determined by international arbitration in a neutral forum conducted in accordance with the rules of the International Chamber of Commerce or UNCITRAL, as applicable. Representatives of CE Casecnan Water and Energy Company, Inc. ("CE Casecnan"), a Philippine corporation, together with certain current and former Philippine government officials, also have been requested to appear, and have appeared, before a Philippine Senate committee which has independently raised questions and made allegations with respect to the Casecnan Project's tariff structure and implementation. No further hearings are scheduled at this time. CE Casecnan has and intends to continue to respond to such questions and to vigorously defend the Casecnan Project against any allegations, which may be made. CE Casecnan believes the allegations made with respect to the Casecnan Project to be without merit. H. COOPER LITIGATION On July 23, 1997, Nebraska Public Power District ("NPPD") filed a complaint, in the United States District Court for the District of Nebraska, naming MidAmerican Energy as the defendant and seeking declaratory judgment as to issues under the parties' long-term power purchase agreement for Cooper Nuclear Station ("Cooper") capacity and energy. On July 31, 2002, MidAmerican Energy and NPPD signed an agreement on the restructuring of the power purchase contract for Cooper. Under the terms of the restructured contract, MidAmerican Energy will pay NPPD through December 31, 2004, a scheduled amount per unit for 380 megawatts of the accredited capacity of Cooper and a minimum of approximately 1.2 million megawatt-hours (MWh) in the last five months of 2002 and approximately 2.5 million MWh in each of 2003 and 2004. NPPD also paid MidAmerican Energy $39.1 million on August 1, 2002. In December 2000, MidAmerican Energy ceased contributing decommissioning funds to NPPD and maintained a separate fund for estimated Cooper decommissioning costs. At the date of the contract restructuring, $18.3 million had been accrued and retained by MidAmerican Energy in this separate fund. In conjunction with the power purchase contract restructuring, MidAmerican Energy is recognizing the $39.1 million cash payment and the $18.3 million previously accrued for decommissioning into income based on the estimated energy expected to be received for the remainder of the contract. F-14 Finally, both parties agreed to release each other from any and all claims, past or present, each might have under the power purchase contract prior to being restructured and file to dismiss the litigation currently pending in U.S. District Court. Under the terms of MidAmerican Energy's power purchase contract with NPPD prior to its restructuring, MidAmerican Energy paid NPPD one-half of the fixed and operating costs of Cooper, excluding depreciation but including debt service, and MidAmerican Energy's share of the nuclear fuel cost, including Department of Energy disposal fees, based on energy delivered. In addition, prior to December 2000, MidAmerican Energy contributed toward payment of one-half of Cooper's project decommissioning costs based on an assumed 2004 shutdown of the plant. I. KVAERNER ARBITRATION The Zinc Recovery Project was being constructed by Kvaerner U.S. Inc. ("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering, procure, construct and manage contract (the "Zinc Recovery Project EPC Contract"). On June 14, 2001, CalEnergy Minerals, LLC issued notices of default, termination and demand for payment of damages to Kvaerner under the Zinc Recovery Project EPC Contract due to failure to meet performance obligations. As a result of Kvaerner's failure to pay monetary obligations under the Zinc Recovery Project EPC Contract, CalEnergy Minerals, LLC drew $29.6 million under the EPC Contract Letter of Credit ("LOC") on July 20, 2001, and claimed the retainage and balance of the contract price. The LOC draw, retainage and balance of the contract price have been accounted for as a reduction of the capitalized costs of the project. CalEnergy Minerals, LLC has entered into a time and materials reimbursable engineer, procure and construction management contract with AMEC E&C Services, Inc. to complete the Zinc Recovery Project. On May 23, 2002, following various discussions and legal filings, CalEnergy Minerals, LLC and Kvaerner entered into a Settlement Agreement. Under the terms of the agreement, CalEnergy Minerals, LLC retained the amounts drawn under the LOC, the EPC retainage amounts and the EPC contract balance and will pay to Kvaerner three equal installments of $2.25 million payable in January of 2003, 2004 and 2005. J. PIPELINE LITIGATION In 1998, the United States Department of Justice informed the then current owners of Kern River and Northern Natural Gas 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 such entities and certain of their subsidiaries including Kern River and Northern Natural Gas. Mr. Grynberg has also filed claims against numerous 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, civil penalties, attorneys' fees and costs. On April 9, 1999, the United States Department of Justice announced that it declined to intervene in any of the Grynberg qui tam cases, including the actions filed against Kern River and Northern Natural Gas in the United States District Court for the District of Colorado. On October 21, 1999, the Panel on Multi-District Litigation transferred the Grynberg qui tam cases, including the ones filed against Kern River and Northern Natural Gas, to the United States District Court for the District of Wyoming for pre-trial purposes. Motions to dismiss the complaint, filed by various defendants including Northern Natural Gas and Williams, which was the former owner of Kern River, were denied on May 18, 2001. In connection with the purchase of Kern River from Williams in March 2002, Williams agreed to indemnify us against any liability for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. No such indemnification was obtained in connection with the purchase of Northern Natural Gas in August 2002. We believe that the Grynberg cases filed against Kern River and Northern Natural Gas are without merit and Williams, on behalf of Kern River pursuant to its agreement to indemnify us, and Northern Natural Gas, intends to defend these actions vigorously. On June 8, 2001, a number of interstate pipeline companies, including Kern River and Northern Natural Gas, were named as defendants in a nationwide class action lawsuit which had been pending in the 26th F-15 Judicial District, District Court, Stevens County Kansas, Civil Department against other defendants, generally pipeline and gathering companies, since May 20, 1999. The plaintiffs allege that the 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 November 2001, Kern River and Northern Natural Gas, along with the coordinating defendants, filed a motion to dismiss under Rules 9B and 12B of the Kansas Rules of Civil Procedure. In January 2002, Kern River and Northern Natural Gas and most of the coordinating defendants filed a motion to dismiss for lack of personal jurisdiction. The court has yet to rule on these motions. The plaintiffs filed for certification of the plaintiff class on September 16, 2002. Williams has agreed to indemnify us against any liability associated with Kern River for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. Williams, on behalf of Kern River and other entities, anticipates joining with Northern Natural Gas and other defendants in contesting certification of the plaintiff class. Kern River and Northern Natural Gas believe that this claim is without merit and that Kern River's and Northern Natural Gas' gas measurement techniques have been in accordance with industry standards and its tariff. K. PIPELINE EXPANSION GUARANTEE On July 17, 2002, Kern River received approval from the FERC to construct, own and operate the 2003 Expansion Project. The 2003 Expansion Project will loop most of Kern River's existing mainline, construct three new compressor stations and upgrade or modify Kern River's six existing compressor stations. The 2003 Expansion Project, which is expected to be completed and operational by May 2003, will increase Kern River's capacity by approximately 900mmcf/day. Service will be provided under long-term contracts subject to incremental rates. The estimated cost of the expansion is approximately $1.2 billion, which will be financed with 70% debt and 30% equity, consistent with Kern River's existing capital structure, the application for the FERC approval described above and the limitations contained in the indenture for Kern River's existing secured senior notes. Construction will initially be funded with the proceeds of an $875 million credit facility entered into by Kern River on June 21, 2002, until 70% of the projected capitalized costs of the 2003 Expansion Project has been spent. The final 30% of the capitalized costs of the 2003 Expansion Project will be funded with equity from the Company. The credit facility is structured as a two-year construction facility followed by a term loan with a final maturity 15 years after completion of the 2003 Expansion Project. However, Kern River presently intends to refinance the credit facility through a bond offering or other capital markets transaction following completion of the 2003 Expansion Project. Prior to completion of the 2003 Expansion Project, the credit facility lenders will have limited recourse to Kern River and its assets and cash flow, and will have recourse to the Company's completion guarantee described below. Following completion of the 2003 Expansion Project, until such time as the Kern River credit facility is refinanced, the lenders under the credit facility will share equally and ratably with the existing Kern River senior secured noteholders in all of the collateral pledged to such senior secured noteholders. Pursuant to the Company's completion guarantee, it has guaranteed that "completion" of the 2003 Expansion Project will occur on or prior to the earliest of any abandonment by Kern River of the project, the occurrence of certain other acceleration events and June 30, 2004. The potential acceleration events include any downgrading of the Company's public debt rating to below investment grade by either S&P or Moody's unless a satisfactory substitute guarantor assumes the Company's obligations under the completion guarantee within 60 days after any such downgrade; Berkshire Hathaway ceasing to own at least a majority of the outstanding capital stock of the Company; and certain other customary events of default by the Company. In the completion guarantee, the Company has also agreed to cause capital contributions to be made to Kern River in a minimum aggregate amount of at least $375 million by June 30, 2004 or upon any earlier event of abandonment of the project. For purposes of the Company's completion guarantee, the term "completion" is defined in the Kern River credit agreement to mean satisfaction of a number of conditions, the most significant of which include the requirements that the 2003 Expansion Project be substantially complete and operable and able to permit Kern River to perform its obligations under all of the long-term firm gas transportation service agreements entered into in connection with the 2003 Expansion Project; that the shippers under such agreements shall have begun F-16 to incur the obligation to pay reservation fees thereunder; and that the FERC shall have authorized Kern River to begin collecting rates under its tariff and its shipper agreements; provided that the 2003 Expansion Project shall still be deemed to have been completed if it is less than substantially complete but it demonstrates at least 80% design capacity and Kern River's debt service coverage ratios as defined in its senior secured note indenture are not less than 1:55 to 1:0. There are a number of other conditions to completion, including requirements that all conditions to completion of the expansion contained in Kern River's senior secured note indenture be satisfied and all of Kern River's obligations under its credit agreement then share pari passu in all collateral available to Kern River's senior secured noteholders. The Company's completion guarantee shall terminate upon the earlier of completion of the 2003 Expansion Project or repayment in full of all obligations under the Kern River credit facility. L. MANUFACTURED GAS PLANT The U.S. Environmental Protection Agency ("EPA"), and state environmental agencies have determined that contaminated wastes remaining at decommissioned manufactured gas plant facilities may pose a threat to the public health or the environment if these contaminants are in sufficient quantities and at such concentrations as to warrant remedial action. MidAmerican Energy has evaluated or is evaluating 27 properties that were, at one time, sites of gas manufacturing plants in which it may be a potentially responsible party. The purpose of these evaluations is to determine whether waste materials are present, whether the materials constitute an environmental or health risk, and whether MidAmerican Energy has any responsibility for remedial action. Investigations of the sites are at various stages, and MidAmerican Energy has conducted ten removal actions to date. MidAmerican Energy is continuing to evaluate several of the sites to determine the appropriate site remedies, if any, necessary to obtain site closure from the agencies. MidAmerican Energy estimates the range of possible costs for investigation, remediation and monitoring for the sites discussed above to be $16 million to $30 million. MidAmerican Energy's estimate of the probable cost for these sites as of September 30, 2002, was $18 million. The estimate consists of $1 million for investigation costs, $6 million for remediation costs, $9 million for ground water treatment and monitoring costs and $2 million for closure and administrative costs. This estimate has been recorded as a liability and a regulatory asset for future recovery. MidAmerican Energy projects that these amounts will be paid or incurred over the next 5 years. The estimate of probable remediation costs is established on a site-specific basis. Initially, a determination is made as to whether MidAmerican Energy has potential remedial liability for the site and whether information exists to indicate that contaminated wastes remain at the site. When a potential remedial liability exists, the best estimate of projected site closure costs are accrued. The estimates are evaluated and revised quarterly as appropriate based on additional information obtained during investigation and remedial activities. The estimated recorded liabilities for these properties include incremental direct costs of the remediation effort and oversight by the appropriate regulatory authority, costs for future monitoring at sites and costs of compensation to employees for time expected to be spent directly on the remediation effort. The estimated recorded liability could change materially based on facts and circumstances derived from site investigations, changes in required remedial action and changes in technology relating to remedial alternatives. Insurance recoveries have been received for some of the sites under investigation. Those recoveries are intended to be used principally for accelerated remediation, as specified by the Iowa Utilities Board, and are recorded as a regulatory liability. Additionally, as viable potentially responsible parties are identified, those parties are evaluated for potential contributions, and cost recovery is pursued when appropriate. Although the timing of potential incurred costs and recovery of costs in rates may affect the results of operations in individual periods, management believes that the outcome of these issues will not have a material adverse effect on the Company's financial position, results of operations or cash flows. 13. SUBSEQUENT EVENTS On October 4, 2002, the Company issued $200 million of 4.625% Senior Notes due in 2007 and $500 million of 5.875% Senior Notes due in 2012. The proceeds are being used for general corporate F-17 purposes including to reduce short-term obligations, to make a $150 million equity contribution to Northern Natural Gas, and to make funds available to Kern River for its 2003 Expansion Project. On October 15, 2002, Northern Natural Gas issued $300 million of 5.375% Senior Notes due in 2012. The proceeds, along with the $150 million equity contribution from the Company, were used to refinance a $450 million short-term debt obligation. 14. SEGMENT INFORMATION The Company has identified seven reportable operating segments principally based on management structure: MidAmerican Energy (domestic utility operations), CE Electric UK Funding (foreign utility operations), Kern River and Northern Natural Gas (domestic natural gas pipeline operations), CalEnergy Generation-Domestic, CalEnergy Generation-Foreign (primarily the Philippines), and HomeServices (real estate operations). Information related to the Company's reportable operating segments is shown below (in thousands).
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30 SEPTEMBER 30 ------------------------------ ------------------------------ 2002 2001 2002 2001 -------------- ------------- -------------- ------------- OPERATING REVENUE: MidAmerican Energy ....................... $ 538,696 $ 507,661 $1,582,609 $1,897,792 CE Electric UK Funding ................... 193,360 316,252 596,958 1,222,324 Kern River ............................... 39,867 -- 87,048 -- Northern Natural Gas ..................... 39,098 -- 39,098 -- CalEnergy Generation -- Domestic ......... 13,717 25,592 27,627 32,635 CalEnergy Generation -- Foreign .......... 84,227 48,782 234,686 147,589 HomeServices ............................. 340,692 193,123 855,919 473,457 ---------- ---------- ---------- ---------- Segment operating revenue ................ 1,249,657 1,091,410 3,423,945 3,773,797 Corporate ................................ (11,194) (14,624) (19,412) (16,866) ---------- ---------- ---------- ---------- $1,238,463 $1,076,786 $3,404,533 $3,756,931 ========== ========== ========== ========== INCOME (LOSS) ON EQUITY INVESTMENTS: MidAmerican Energy ....................... $ (4,582) $ 878 $ 1,394 $ 1,595 CalEnergy Generation -- Domestic ......... 12,424 5,454 21,194 22,027 HomeServices ............................. 3,071 -- 6,984 -- ---------- ---------- ---------- ---------- Segment income on equity investments...... 10,913 6,332 29,572 23,622 Corporate ................................ 26 -- 291 -- ---------- ---------- ---------- ---------- $ 10,939 $ 6,332 $ 29,863 $ 23,622 ========== ========== ========== ========== DEPRECIATION AND AMORTIZATION: MidAmerican Energy ....................... $ 66,946 $ 63,017 $ 208,726 $ 217,260 CE Electric UK Funding ................... 28,390 31,219 87,200 97,141 Kern River ............................... 4,900 -- 12,161 -- Northern Natural Gas ..................... 5,755 -- 5,755 -- CalEnergy Generation -- Domestic ......... 2,160 2,058 6,517 3,375 CalEnergy Generation -- Foreign .......... 22,009 16,537 66,273 49,715 HomeServices ............................. 5,722 4,207 18,035 12,618 ---------- ---------- ---------- ---------- Segment depreciation and amortization..... 135,882 117,038 404,667 380,109 Corporate ................................ (6,520) 5,648 (18,136) 15,144 ---------- ---------- ---------- ---------- $ 129,362 $ 122,686 $ 386,531 $ 395,253 ========== ========== ========== ========== INTEREST EXPENSE, NET: MidAmerican Energy ....................... $ 30,220 $ 28,359 $ 89,489 $ 86,789 CE Electric UK Funding ................... 47,819 22,933 136,250 67,308
F-18
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30 SEPTEMBER 30 ------------------------- ---------------------------- 2002 2001 2002 2001 ------------ ---------- ------------- ------------ Kern River ................................. 12,877 -- 22,406 -- Northern Natural Gas ....................... 7,992 -- 7,992 -- CalEnergy Generation -- Domestic ........... 5,005 5,063 15,040 5,900 CalEnergy Generation -- Foreign ............ 16,923 6,584 51,853 22,160 HomeServices ............................... 1,121 822 3,334 2,930 ------ ----- ------ ------ Segment interest expense, net .............. 121,957 63,761 326,364 185,087 Corporate .................................. 37,341 36,171 112,506 105,066 ------- ------ ------- ------- $ 159,298 $ 99,932 $ 438,870 $ 290,153 ========= ======== ========== ========= INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES: MidAmerican Energy ......................... $ 108,577 $ 80,453 $ 218,565 $ 204,348 CE Electric UK Funding ..................... 39,968 98,961 197,223 186,248 Kern River ................................. 16,774 -- 39,387 -- Northern Natural Gas ....................... (1,015) -- (1,015) -- CalEnergy Generation -- Domestic ........... 14,649 22,994 12,983 37,383 CalEnergy Generation -- Foreign ............ 40,208 20,757 103,994 66,330 HomeServices ............................... 26,475 19,077 52,506 31,689 --------- -------- ---------- --------- Segment income before provision for income taxes .............................. 245,636 242,242 623,643 525,998 Corporate .................................. (38,627) 75,368 (131,451) (23,269) --------- -------- ---------- --------- $ 207,009 $317,610 $ 492,192 $ 502,729 ========= ======== ========== ========= PROVISION (BENEFIT) FOR INCOME TAXES: MidAmerican Energy ......................... $ 44,702 $ 36,079 $ 89,705 $ 92,349 CE Electric UK Funding ..................... (9,627) 177,700 5,949 205,407 Kern River ................................. 6,297 -- 15,001 -- Northern Natural Gas ....................... (399) -- (399) -- CalEnergy Generation -- Domestic ........... 844 7,013 (3,318) 5,137 CalEnergy Generation -- Foreign ............ 5,575 4,793 18,256 11,982 HomeServices ............................... 11,131 7,439 21,161 12,051 --------- -------- ---------- --------- Segment provision for income taxes ......... 58,523 233,024 146,355 326,926 Corporate .................................. (31,735) 8,849 (66,129) (30,838) --------- -------- ---------- --------- $ 26,788 $241,873 $ 80,226 $ 296,088 ========= ======== ========== =========
SEPTEMBER 30, DECEMBER 31, 2002 2001 --------------- ------------- IDENTIFIABLE ASSETS: MidAmerican Energy ....................... $ 5,986,212 $ 5,848,035 CE Electric UK Funding ................... 4,526,923 4,340,147 Kern River ............................... 1,342,424 -- Northern Natural Gas ..................... 2,041,842 -- CalEnergy Generation -- Domestic ......... 928,731 870,664 CalEnergy Generation -- Foreign .......... 983,702 950,035 HomeServices ............................. 515,328 322,552 ----------- ----------- Segment identifiable assets .............. 16,325,162 12,331,433 Corporate ................................ 658,888 295,219 ----------- ----------- $16,984,050 $12,626,652 =========== ===========
F-19 The remaining differences from the segment amounts to the consolidated amounts described as "Corporate" relate principally to the corporate functions including administrative costs, corporate cash and related interest income, goodwill amortization in 2001, intersegment eliminations, and fair value and goodwill adjustments relating to acquisitions and disposals. EXCESS OF COST OVER FAIR VALUE OF NET ASSETS ACQUIRED, NET:
NORTHERN CALENERGY MIDAMERICAN CE ELECTRIC NATURAL GENERATION ENERGY UK FUNDING KERN RIVER GAS -- DOMESTIC HOMESERVICES TOTAL ------------- ------------- ------------ ---------- ------------- -------------- ------------- Goodwill at December 31, 2001 ........ $2,148,859 $1,100,489 $ -- $ -- $ 158,708 $ 230,490 $3,638,546 Acquisitions/purchase price accounting adjustments .............. -- 56,626 32,704 379,464 -- 106,054 574,848 Impairment losses ......... -- -- -- -- -- -- -- Goodwill written off related to sale of business unit ............ -- (49,587) -- -- -- -- (49,587) Translation adjustment..... -- 62,262 -- -- 62,262 Other adjustments ......... (1,776) (601) -- -- (324) (170) (2,871) ---------- ---------- -------- -------- --------- --------- ---------- Goodwill at September 30, 2002 ....... $2,147,083 $1,169,189 $ 32,704 $379,464 $ 158,384 $ 336,374 $4,223,198 ========== ========== ======== ======== ========= ========= ==========
F-20 INDEPENDENT AUDITORS' REPORT Board of Directors and Stockholders MidAmerican Energy Holdings Company Des Moines, Iowa We have audited the accompanying consolidated balance sheets of MidAmerican Energy Holdings Company (successor to MidAmerican Energy Holdings Company (Predecessor), referred to as "MEHC (Predecessor)") and subsidiaries (the "Company") as of December 31, 2001 and 2000 for the Company, and the related consolidated statements of operations, stockholders' equity, and cash flows for the year ended December 31, 2001 for the Company, for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor), for the period March 14, 2000 to December 31, 2000 for the Company, and for the year ended December 31, 1999 for MEHC (Predecessor). Our audits also included the financial statement schedules listed in Item 21. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, such consolidated financial statements present fairly, in all material respects, the financial position of MidAmerican Energy Holdings Company and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the above stated periods in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein. As discussed in Note 2 to the consolidated financial statements, in 2001 the Company changed its accounting policy for major maintenance, overhaul and well workover costs. DELOITTE & TOUCHE LLP Des Moines, Iowa January 17, 2002 (March 27, 2002 as to Notes 20.A. and 21 and August 2, 2002 as to Note 23) F-21 MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
AS OF DECEMBER 31, ------------------------------- 2001 2000 -------------- -------------- ASSETS Current Assets: Cash and investments .................................................. $ 386,745 $ 38,152 Restricted cash and short term investments ............................ 30,565 42,129 Accounts receivable ................................................... 332,553 833,757 Inventories ........................................................... 103,078 81,943 Other current assets .................................................. 131,968 96,784 ----------- ----------- Total Current Assets ................................................ 984,909 1,092,765 Property, plant, contracts and equipment, net .......................... 6,527,448 5,348,647 Excess of cost over fair value of net assets acquired, net ............. 3,639,088 3,673,150 Regulatory assets ...................................................... 221,120 240,934 Long-term restricted cash and investments .............................. 24,207 48,747 Nuclear decommissioning trust fund and other marketable securities ..... 160,938 202,227 Equity investments ..................................................... 259,619 246,466 Deferred charges, other investments and other assets ................... 798,004 758,003 ----------- ----------- Total Assets ........................................................ $12,615,333 $11,610,939 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable ...................................................... $ 266,027 $ 586,644 Accrued interest ...................................................... 130,569 107,726 Accrued taxes ......................................................... 88,973 125,645 Other accrued liabilities ............................................. 308,924 250,975 Short-term debt ....................................................... 256,012 261,656 Current portion of long-term debt ..................................... 317,180 438,978 ----------- ----------- Total Current Liabilities ........................................... 1,367,685 1,771,624 Other long-term accrued liabilities .................................... 526,176 976,030 Parent company debt .................................................... 1,834,498 1,829,971 Subsidiary and project debt ............................................ 4,754,811 3,388,696 Deferred income taxes .................................................. 1,284,268 945,028 ----------- ----------- Total Liabilities ................................................... 9,767,438 8,911,349 ----------- ----------- Deferred income ........................................................ 85,917 79,489 Minority interest ...................................................... 44,477 11,491 Company-obligated mandatorily redeemable preferred securities of subsidiary trusts ..................................................... 788,151 786,523 Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts ..................................................... 100,000 100,000 Preferred securities of subsidiaries ................................... 121,183 145,686 Commitments and contingencies (Note 20) Stockholders' Equity: Zero coupon convertible preferred stock -- authorized 50,000 shares, no par value, 34,563 shares outstanding at December 31, 2001 and 2000 .................................................................. -- -- Common stock -- authorized 60,000 no par value; 9,281 shares issued and outstanding at December 31, 2001 and 2000 ......................... -- -- Additional paid in capital ............................................. 1,553,073 1,553,073 Retained earnings ...................................................... 223,926 81,257 Accumulated other comprehensive loss, net .............................. (68,832) (57,929) ----------- ----------- Total Stockholders' Equity ............................................ 1,708,167 1,576,401 ----------- ----------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ............................. $12,615,333 $11,610,939 =========== ===========
The accompanying notes are an integral part of these financial statements. F-22 MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS)
MEHC (PREDECESSOR) ------------------------------- YEAR ENDED MARCH 14, 2000 JANUARY 1, 2000 YEAR ENDED DECEMBER 31, THROUGH THROUGH DECEMBER 31, 2001 DECEMBER 31, 2000 MARCH 13, 2000 1999 -------------- ------------------- ----------------- ------------- REVENUE: Operating revenue ........................... $5,060,605 $4,147,867 $1,087,125 $4,184,546 Interest and other income ................... 96,706 94,882 19,484 143,175 Gains on non-recurring items (Notes 3 and 15) ................................... 179,493 -- -- 138,704 ---------- ---------- ---------- ---------- TOTAL REVENUES ............................... 5,336,804 4,242,749 1,106,609 4,466,425 ---------- ---------- ---------- ---------- COSTS AND EXPENSES: Cost of sales ............................... 2,705,002 2,424,279 605,439 2,199,700 Operating expense ........................... 1,176,422 904,511 219,303 1,001,384 Depreciation and amortization ............... 538,702 383,351 97,278 427,690 Interest expense ............................ 499,263 396,773 101,330 496,578 Less interest capitalized ................... (86,469) (85,369) (15,516) (70,405) Losses on non-recurring items (Notes 3 and 15) ................................... -- -- 7,605 54,409 ---------- ---------- ---------- ---------- TOTAL COSTS AND EXPENSES ..................... 4,832,920 4,023,545 1,015,439 4,109,356 ---------- ---------- ---------- ---------- Income before provision for income taxes ..... 503,884 219,204 91,170 357,069 Provision for income taxes ................... 250,064 53,277 31,008 93,475 ---------- ---------- ---------- ---------- Income before minority interest .............. 253,820 165,927 60,162 263,594 Minority interest ............................ 106,547 84,670 8,850 46,923 ---------- ---------- ---------- ---------- INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE ........................ 147,273 81,257 51,312 216,671 Extraordinary item, net of tax ............... -- -- -- (49,441) Cumulative effect of change in accounting principle, net of tax ....................... (4,604) -- -- -- ---------- ---------- ---------- ---------- NET INCOME AVAILABLE TO COMMON STOCKHOLDERS ................................ $ 142,669 $ 81,257 $ 51,312 $ 167,230 ========== ========== ========== ==========
The accompanying notes are an integral part of these financial statements. F-23 MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE THREE YEARS ENDED DECEMBER 31, 2001 (IN THOUSANDS)
OUTSTANDING ADDITIONAL COMMON COMMON PAID-IN SHARES STOCK CAPITAL ------------- -------- -------------- BALANCE JANUARY 1, 1999 ....................... 59,605 $-- $1,238,690 Net income .................................... -- -- -- Other Comprehensive Income: Foreign currency translation adjustment * -- -- -- Unrealized losses on securities, net of tax of $14....................................... -- -- -- Comprehensive income .......................... Issuance of stock by subsidiary ............... -- -- 9,113 Exercise of stock options and other equity transactions ................................. 238 -- (2,628) Purchase of treasury stock .................... (3,376) -- -- Conversion of TIDES I ......................... 3,477 -- 2,845 Tax benefit from stock plan ................... -- -- 1,059 ------ --- ---------- BALANCE DECEMBER 31, 1999 ..................... 59,944 -- 1,249,079 Net income January 1, 2000 through March 13, 2000 ....................... -- -- -- Net income March 14, 2000 through December 31, 2000 .................... -- -- -- Other Comprehensive Income: Foreign currency translation adjustment * -- -- -- Minimum pension liability adjustment, net of tax of $1,699 ........................ -- -- -- Unrealized losses on securities, net of tax of $1,164......................... -- -- -- Comprehensive income .......................... Exercise of stock options and other equity transactions .................... 13 -- (138) Teton Transaction ............................. (50,676) -- 304,132 ------- --- ---------- BALANCE DECEMBER 31, 2000 ..................... 9,281 -- 1,553,073 Net income .................................... -- -- -- Other Comprehensive Income: Foreign currency translation adjustment * ................................ -- -- -- Fair value adjustment on cash flow hedges, net of tax of $8,143................. -- -- -- Minimum pension liability adjustment, net of tax of $3,448 ........................ -- -- -- Unrealized losses on securities, net of tax of $1,315......................... -- -- -- Comprehensive income .......................... BALANCE DECEMBER 31, 2001 ..................... 9,281 $-- $1,553,073 ======= === ========== ACCUMULATED OTHER COMPREHENSIVE RETAINED INCOME TREASURY EARNINGS (LOSS) STOCK TOTAL ------------- -------------- -------------- ------------- BALANCE JANUARY 1, 1999 ....................... $ 340,496 $ 45 $ (752,178) $ 827,053 Net income .................................... 167,230 -- -- 167,230 Other Comprehensive Income: Foreign currency translation adjustment * -- (12,047) -- (12,047) Unrealized losses on securities, net of tax of $14....................................... -- (27) -- (27) ---------- Comprehensive income .......................... 155,156 Issuance of stock by subsidiary ............... -- -- -- 9,113 Exercise of stock options and other equity transactions ................................. -- -- 7,779 5,151 Purchase of treasury stock .................... -- -- (104,847) (104,847) Conversion of TIDES I ......................... -- -- 99,058 101,903 Tax benefit from stock plan ................... -- -- -- 1,059 ---------- --------- ---------- ---------- BALANCE DECEMBER 31, 1999 ..................... 507,726 (12,029) (750,188) 994,588 Net income January 1, 2000 through March 13, 2000 ....................... 51,312 -- -- 51,312 Net income March 14, 2000 through December 31, 2000 .................... 81,257 -- -- 81,257 Other Comprehensive Income: Foreign currency translation adjustment * -- (82,996) -- (82,996) Minimum pension liability adjustment, net of tax of $1,699 ........................ -- (2,388) -- (2,388) Unrealized losses on securities, net of tax of $1,164......................... -- 2,160 -- 2,160 ---------- Comprehensive income .......................... 49,345 Exercise of stock options and other equity transactions .................... -- -- 418 280 Teton Transaction ............................. (559,038) 37,324 749,770 532,188 ---------- --------- ---------- ---------- BALANCE DECEMBER 31, 2000 ..................... 81,257 (57,929) -- 1,576,401 Net income .................................... 142,669 -- -- 142,669 Other Comprehensive Income: Foreign currency translation adjustment * ................................ -- (22,103) -- (22,103) Fair value adjustment on cash flow hedges, net of tax of $8,143................. -- 18,490 -- 18,490 Minimum pension liability adjustment, net of tax of $3,448 ........................ -- (4,847) -- (4,847) Unrealized losses on securities, net of tax of $1,315......................... -- (2,443) -- (2,443) ---------- Comprehensive income .......................... 131,766 ---------- BALANCE DECEMBER 31, 2001 ..................... $ 223,926 $ (68,832) $ -- $1,708,167 ========== ========= ========== ==========
---------- * Foreign currency translation adjustment has no tax effect The accompanying notes are an integral part of these financial statements. F-24 MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
MARCH 14, 2000 YEAR ENDED THROUGH DECEMBER 31, 2001 DECEMBER 31, 2000 ------------------- ------------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income ............................................... $ 142,669 $ 81,257 Adjustments to reconcile net cash flows from operating activities: Gains on non-recurring items ........................... (179,493) -- Extraordinary item, net of tax ......................... -- -- Cumulative effect of change in accounting principle, net of tax ................................. 4,604 -- Depreciation and amortization .......................... 442,284 303,354 Amortization of excess of cost over fair value of net assets acquired ................................... 96,418 79,997 Amortization of deferred financing and other costs ................................................. 20,529 18,310 Provision for deferred income taxes .................... 152,920 (15,460) Income in excess of distributions on equity investments ........................................... (28,515) (26,607) Changes in other items: Accounts receivable and other current assets .......... 619,827 (316,287) Accounts payable, accrued liabilities, deferred income and other .................................... (424,245) 121,843 ---------- ------------- NET CASH FLOWS FROM OPERATING ACTIVITIES ................. 846,998 246,407 ---------- ------------- CASH FLOWS FROM INVESTING ACTIVITIES: Purchase of Yorkshire Electric, MEHC (Predecessor), and MidAmerican, net of cash acquired ................... (41,670) (2,048,266) Proceeds from sale of Northern Supply and qualified facilities, net of cash disposed ........................ 377,396 -- Proceeds from Indonesia settlement ....................... -- -- Acquisition of realty companies, net of cash acquired..... (40,264) -- Purchase of marketable securities ........................ -- (44,686) Proceeds from sale of marketable securities .............. -- 69,375 Capital expenditures relating to operating projects ...... (398,165) (301,948) Philippine construction .................................. (82,181) (58,531) Acquisition of U.K. gas assets ........................... -- -- Construction and other development costs ................. (96,406) (178,250) Decrease in restricted cash and investments .............. 24,540 157,905 Other .................................................... 18,206 15,241 ---------- ------------- NET CASH FLOWS FROM INVESTING ACTIVITIES ................. (238,544) (2,389,160) ---------- ------------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from issuance of common and preferred stock ................................................... -- 1,428,024 Proceeds from issuance of trust preferred securities ..... -- 454,772 Repayments of parent company debt ........................ -- (4,225) Net proceeds from corporate revolver ..................... 68,500 85,000 Net repayment of subsidiary short term debt .............. (74,144) (88,106) Proceeds from subsidiary and project debt ................ 200,000 262,176 Repayments of subsidiary and project debt ................ (437,372) (234,776) Deferred charges relating to debt financing .............. (2,073) (3,805) Redemption of preferred securities of subsidiaries ....... (24,910) (20,409) Purchase of treasury stock ............................... -- -- Other .................................................... 11,532 198 ---------- ------------- NET CASH FLOWS FROM FINANCING ACTIVITIES ................. (258,467) 1,878,849 ---------- ------------- Effect of exchange rate changes .......................... (1,394) (1,555) ---------- ------------- Net increase (decrease) in cash and cash equivalents...... 348,593 (265,459) Cash and cash equivalents at beginning of period ......... 38,152 303,611 ---------- ------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD ............... $ 386,745 $ 38,152 ========== ============= Supplemental Disclosures: Interest paid, net of amount capitalized ................. $ 389,953 $ 351,532 ========== ============= Income taxes paid ........................................ $ 133,139 $ 94,405 ========== ============= MEHC (PREDECESSOR) --------------------------------- JANUARY 1, 2000 YEAR ENDED THROUGH DECEMBER 31, MARCH 13, 2000 1999 ----------------- --------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income ............................................... $ 51,312 $ 167,230 Adjustments to reconcile net cash flows from operating activities: Gains on non-recurring items ........................... -- (138,704) Extraordinary item, net of tax ......................... -- 49,441 Cumulative effect of change in accounting principle, net of tax ................................. -- -- Depreciation and amortization .......................... 83,097 363,737 Amortization of excess of cost over fair value of net assets acquired ................................... 14,181 63,953 Amortization of deferred financing and other costs ................................................. 4,075 18,181 Provision for deferred income taxes .................... 7,735 (56,590) Income in excess of distributions on equity investments ........................................... (3,459) (22,796) Changes in other items: Accounts receivable and other current assets .......... 440 53,016 Accounts payable, accrued liabilities, deferred income and other .................................... 13,702 57,491 ---------- ------------- NET CASH FLOWS FROM OPERATING ACTIVITIES ................. 171,083 554,959 ---------- ------------- CASH FLOWS FROM INVESTING ACTIVITIES: Purchase of Yorkshire Electric, MEHC (Predecessor), and MidAmerican, net of cash acquired ................... -- (2,501,425) Proceeds from sale of Northern Supply and qualified facilities, net of cash disposed ........................ -- 365,074 Proceeds from Indonesia settlement ....................... -- 290,000 Acquisition of realty companies, net of cash acquired..... -- (36,858) Purchase of marketable securities ........................ (8,251) (92,523) Proceeds from sale of marketable securities .............. 12,562 498,676 Capital expenditures relating to operating projects ...... (44,355) (360,898) Philippine construction .................................. (22,736) (62,059) Acquisition of U.K. gas assets ........................... -- (72,280) Construction and other development costs ................. (56,450) (180,683) Decrease in restricted cash and investments .............. 48,788 199,588 Other .................................................... 15,568 (7,432) ---------- ------------- NET CASH FLOWS FROM INVESTING ACTIVITIES ................. (54,874) (1,960,820) ---------- ------------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from issuance of common and preferred stock ................................................... -- -- Proceeds from issuance of trust preferred securities ..... -- -- Repayments of parent company debt ........................ -- (853,420) Net proceeds from corporate revolver ..................... -- -- Net repayment of subsidiary short term debt .............. (124,761) (136) Proceeds from subsidiary and project debt ................ 6,043 1,394,094 Repayments of subsidiary and project debt ................ (3,135) (331,880) Deferred charges relating to debt financing .............. -- 7,761 Redemption of preferred securities of subsidiaries ....... -- -- Purchase of treasury stock ............................... -- (104,847) Other .................................................... (6,648) 4,303 ---------- ------------- NET CASH FLOWS FROM FINANCING ACTIVITIES ................. (128,501) 115,875 ---------- ------------- Effect of exchange rate changes .......................... (424) 165 ---------- ------------- Net increase (decrease) in cash and cash equivalents...... (12,716) (1,289,821) Cash and cash equivalents at beginning of period ......... 316,327 1,606,148 ---------- ------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD ............... $ 303,611 $ 316,327 ========== ============= Supplemental Disclosures: Interest paid, net of amount capitalized ................. $ 35,057 $ 439,894 ========== ============= Income taxes paid ........................................ $ -- $ 130,875 ========== =============
The accompanying notes are an integral part of these financial statements. F-25 MIDAMERICAN ENERGY HOLDINGS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. BUSINESS MidAmerican Energy Holdings Company and its subsidiaries (the "Company" or "MEHC"), is a United States-based privately owned global energy company with publicly traded fixed income securities that generates, distributes and supplies energy to utilities, government entities, retail customers and other customers located throughout the world. Through its subsidiaries the Company is organized and managed on five separate platforms: MidAmerican Energy, CE Electric UK Funding, CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and HomeServices. On March 14, 2000, the Company and an investor group comprised of Berkshire Hathaway Inc., Walter Scott, Jr., a director of the Company, David L. Sokol, Chairman and Chief Executive Officer of the Company, and Gregory E. Abel, Chief Operating Officer of the Company closed on a definitive agreement and plan of merger whereby the investor group acquired all of the outstanding common stock of the Company (the "Teton Transaction"). As a result of the Teton Transaction, Berkshire Hathaway, Mr. Scott, Mr. Sokol and Mr. Abel own approximately 9.7%, 86%, 3% and 1% of the voting stock respectively. MIDAMERICAN ENERGY MidAmerican Energy Company ("MidAmerican Energy") is a regulated public utility principally engaged in the business of generating, transmitting, distributing and selling electric energy and in distributing, selling and transporting natural gas. MidAmerican Energy distributes electricity at the retail level in Iowa, Illinois and South Dakota. It also distributes natural gas at the retail level in Iowa, Illinois, South Dakota and Nebraska. As of December 31, 2001, MidAmerican Energy had approximately 673,000 retail electric customers and 652,000 retail natural gas customers. In addition to retail sales, MidAmerican Energy sells electric energy and natural gas to other utilities, marketers and municipalities that distribute it to end-use customers. These sales are referred to as sales for resale or off-system sales. It also transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. A substantial portion of MidAmerican Energy's business still operates in a rate-regulated environment and, accordingly, many decisions for obtaining and using resources are evaluated from an electric and gas regulated business perspective. MidAmerican Energy's operations are seasonal in nature with a disproportionate percentage of revenues and earnings historically being earned in the Company's first and third quarters. CE ELECTRIC UK FUNDING The business of CE Electric UK Funding, an indirect wholly owned subsidiary of the Company, consists of Northern Electric plc ("Northern"), an indirect wholly owned subsidiary of the Company, and Yorkshire Power Group Ltd. ("Yorkshire"), an indirect majority owned subsidiary of the Company, and CalEnergy Gas (Holdings) Limited ("CE Gas"), an indirect wholly owned subsidiary of the Company. Northern's and Yorkshire's operations consist primarily of the distribution of electricity and other auxiliary businesses in the United Kingdom. Through September 21, 2001, Northern's operations also included the supply of electricity and natural gas and the related metering business. Northern and Yorkshire receive electricity from the national grid transmission system and distribute it to customers' premises using their network of transformers, switchgear and cables. Substantially all of the customers in their distribution service areas are connected to their network and can only be delivered through their distribution system, thus providing Northern and Yorkshire with distribution volume that is stable from year to year. Northern and Yorkshire charge access fees for the use of the distribution system. The prices for distribution are controlled by a prescribed formula that limits increases (and may require decreases) based upon the rate of inflation in the United Kingdom and other regulatory action. F-26 Northern's supply business was primarily involved in the bulk purchase of electricity, previously through a central pool and from March 27, 2001 on through the New Electricity Trading Agreements ("NETA"), and subsequent resale to individual customers throughout the U.K. The supply business generally is a high volume business that tends to operate at lower profitability levels than the distribution business. Northern also competed to supply gas inside and outside its authorized area. See Note 3. CE Gas is a gas exploration and production company that is focused on developing integrated upstream gas projects. Its "upstream gas" business consists of the exploration, development and production, including transportation and storage, of gas for delivery to a point of sale into either a gas supply market or a power generation facility. CE Gas holds various interests in the southern basin of the United Kingdom sector of the North Sea. Also, CE Gas has been involved in certain gas development and exploration activities relating to a large gas field prospect in Poland, the EP389 concession in the Perth Basin in Australia and the Yolla discovery in the Bass Basin of Australia. CALENERGY GENERATION-DOMESTIC The Company has a 50% ownership interest in CE Generation LLC ("CE Generation") that has interests in ten geothermal plants in the Imperial Valley, California and three natural gas-fired cogeneration plants. For purposes of consistent presentation, plant capacity factors for Vulcan, Hoch (Del Ranch), Turbo, Elmore and Leathers (collectively the "Partnership Projects") are based on capacity amounts of 34, 38, 10, 38, and 38 net MW, respectively, and for Salton Sea I, Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V plants (collectively the "Salton Sea Projects") are based on capacity amounts of 10, 20, 50, 40 and 49 net MW, respectively (the Partnership Projects and the Salton Sea Projects are collectively referred to as the "Imperial Valley Projects"). Plant capacity factors for Saranac, Power Resources and Yuma (collectively the "Gas Plants") are based on capacity amounts of 240, 200, and 50 net MW, respectively. Each plant possesses an operating margin that allows for production in excess of the amount listed above. Utilization of this operating margin is based upon a variety of factors and can be expected to vary between calendar quarters, under normal operating conditions. Due to its 50% ownership interest in CE Generation, the Company accounts for CE Generation as an equity investment. Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned subsidiary of the Company, operates a 537 MW gas-fired power plant in the Quad Cities, Illinois area (the "Cordova Project"). The Cordova Project commenced commercial operations on June 19, 2001. Cordova Energy has entered into a power purchase agreement with a unit of El Paso Energy Corporation ("El Paso") in which El Paso will purchase all of the capacity and energy from the project until December 31, 2019. Cordova Energy has exercised an option under the El Paso Power Purchase Agreement to callback 50% of the project output for sales to others for the contract years ending on or prior to May 14, 2004. Cordova Energy subsequently entered into a power purchase agreement with MidAmerican Energy whereby MidAmerican Energy will purchase 50% of the capacity and energy from the Cordova Project until May 14, 2004. CALENERGY GENERATION-FOREIGN The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively, the "Leyte Projects"), which are geothermal power plants located on the island of Leyte in the Philippines, and the Casecnan Project, a combined irrigation and hydroelectric power generation project located in the central part of the island of Luzon in the Philippines. The Casecnan Project commenced commercial operations on December 11, 2001. For purposes of consistent presentation, capacity amounts for Upper Mahiao, Malitbog, Mahanagdong and Casecnan are 119, 216, 165 and 150 net MW, respectively. Each plant possesses an operating margin that allows for production in excess of the amount listed above. Utilization of this operating margin is based upon a variety of factors and can be expected to vary between calendar quarters, under normal operating conditions. HOMESERVICES HomeServices.Com, Inc. ("HomeServices"), a wholly-owned subsidiary of the Company, is the second largest residential real estate brokerage firm in the United States based on aggregate closed transaction F-27 sides in 2000 for its various brokerage firm operating subsidiaries. Closed transaction sides mean either the buy side or sell side of any closed home purchase and is the standard term used by industry participants and publications to rank real estate brokerage firms. In addition to providing traditional residential real estate brokerage services, HomeServices cross sells to its existing real estate customers preclosing services, such as mortgage origination and title services, including title insurance, title search, escrow and other closing administrative services, assists in securing other preclosing and postclosing services provided by third parties, such as home warranty, home inspection, home security, property and casualty insurance, home maintenance, repair and remodeling and is developing various related e-commerce services. HomeServices currently operates in the following fourteen states: Minnesota, Iowa, California, Arizona, Kansas, Missouri, Kentucky, Nebraska, Wisconsin, Indiana, Maryland, North Dakota, South Dakota and Georgia. HomeServices generally occupies the number one or number two market share position in each of its major markets based on aggregate closed transaction sides for the year ended December 31, 2001. HomeServices' major markets consist of the following metropolitan areas: Minneapolis and St. Paul, Minnesota; Des Moines, Iowa; Los Angeles and San Diego, California; Omaha, Nebraska; Kansas City, Kansas; Louisville, Kentucky; Springfield, Missouri; Tucson, Arizona; Annapolis, Maryland and Atlanta, Georgia. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Subsidiaries which are less than 100% owned but greater than 50% owned are consolidated with a minority interest. Subsidiaries that are 50% owned or less, but where the Company has the ability to exercise significant influence, are accounted for under the equity method of accounting. Investments where the Company's ability to influence is limited are accounted for under the cost method of accounting. All significant inter-enterprise transactions and accounts have been eliminated. The results of operations of the Company include the Company's proportionate share of results of operations of entities acquired from the date of each acquisition for purchase business combinations. CASH EQUIVALENTS, INVESTMENTS, AND RESTRICTED CASH AND INVESTMENTS The Company considers all investment instruments purchased with an original maturity of three months or less to be cash equivalents. Investments other than restricted cash are primarily commercial paper and money market securities. Restricted cash is not considered a cash equivalent. The current restricted cash and short-term investments balance includes commercial paper and money market securities, and is mainly composed of amounts deposited in restricted accounts from which the Company will source its debt service reserve requirements relating to the projects. These funds are restricted by their respective project debt agreements to be used only for the related project. The long-term restricted cash and investments balances are mainly composed of amounts deposited in restricted accounts from which the Company will fund the various projects under construction. The Company's restricted investments are classified as held-to-maturity and are accounted for at their amortized cost basis. The carrying amount of the investments approximates the fair value based on quoted market prices as provided by the financial institution that holds the investments. The Company's nuclear decommissioning trust funds and other marketable securities are classified as available for sale and are accounted for at fair value. INVENTORY Inventory is primarily composed of materials and supplies, coal stocks, gas in storage and fuel oil. Materials and supplies, coal stocks and fuel oil are at average cost and gas in storage is accounted for under the LIFO method. PROPERTY, PLANT, CONTRACTS, EQUIPMENT AND DEPRECIATION The cost of major additions and betterments are capitalized, while replacements, maintenance, and repairs that do not improve or extend the lives of the respective assets are expensed. F-28 Depreciation of the operating power plant costs, net of salvage value, is computed on the straight-line method over the estimated useful lives, between ten and thirty years. Depreciation of furniture, fixtures and equipment that are recorded at cost, is computed on the straight-line method over the estimated useful lives of the related assets, which range from three to ten years. Capitalized costs for gas reserves, other than costs of unevaluated exploration projects and projects awaiting development consent, are depleted using the units of production method. Depletion is calculated based on hydrocarbon reserves of properties in the evaluated pool estimated to be commercially recoverable and include anticipated future development costs in respect of those reserves. Expenditures on major information technology systems are capitalized and depreciated on a straight-line basis over the estimated useful lives of the developed systems that range from three to fifteen years. An allowance for the estimated annual decommissioning costs of the Quad Cities Generating Station ("Quad Cities Station") equal to the level of funding is included in depreciation expense. See Note 20 for additional information regarding decommissioning costs. EXCESS OF COST OVER FAIR VALUE OF NET ASSETS ACQUIRED Total acquisition costs in excess of the fair values assigned to the net assets acquired are amortized using the straight line method over a 25 to 40 year period. IMPAIRMENT OF LONG-LIVED ASSETS The Company reviews long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss would be recognized, based on discounted cash flows or various fair value models, whenever evidence exists that the carrying value is not recoverable. CONTINGENT LIABILITIES The Company is subject to the possibility of various loss contingencies arising in the ordinary course of business. Management considers the likelihood of the loss or impairment of an asset or the incurrence of a liability as well as our ability to reasonably estimate the amount of loss in determining loss contingencies. An estimated loss contingency is accrued when it is probable that a liability has been incurred or an asset has been impaired and the amount of loss can be reasonably estimated. The Company regularly evaluates current information available to determine whether such accruals should be adjusted. REVENUE RECOGNITION Revenues are recorded based upon services rendered and electricity, gas and steam delivered, distributed or supplied to the end of the period. Where there is an over recovery of distribution business revenues against the maximum regulated amount, revenues are deferred equivalent to the over recovered amount. The deferred amount is deducted from revenue and included in other liabilities. Where there is an under recovery, no anticipation of any potential future recovery is made. The Company also records unbilled revenues representing the estimated amounts customers will be billed for services rendered between the meter reading dates in a particular month and the end of that month. Accrued unbilled revenues are included in accounts receivable on the consolidated balance sheets. CAPITALIZATION OF INTEREST AND DEFERRED FINANCING COSTS Prior to the commencement of operations, interest is capitalized on the costs of the construction projects and resource development to the extent incurred. Capitalized interest and other deferred charges are amortized over the lives of the related assets. Deferred financing costs are amortized over the term of the related financing using the effective interest method. F-29 DEFERRED INCOME TAXES The Company recognizes deferred tax assets and liabilities based on the difference between the financial statement and tax basis of assets and liabilities using estimated tax rates in effect for the year in which the differences are expected to reverse. The Company does not intend to repatriate earnings of foreign subsidiaries in the foreseeable future. As a result, deferred United States income taxes are not provided for retained earnings of international subsidiaries and corporate joint ventures unless the earnings are intended to be remitted. FINANCIAL INSTRUMENTS The Company currently utilizes or had previously utilized swap agreements and forward purchase agreements to manage market risks and reduce its exposure resulting from fluctuation in interest rates, foreign currency exchange rates and electric and gas prices. For interest rate swap agreements, the net cash amounts paid or received on the agreements are accrued and recognized as an adjustment to interest expense. Gains and losses related to gas forward contracts are deferred and included in the measurement of the related gas purchases. These instruments are either exchange traded or with counterparties of high credit quality; therefore, the risk of nonperformance by the counterparties is considered to be negligible. FOREIGN CURRENCY TRANSLATION AND TRANSACTIONS For the Company's foreign operations whose functional currency is not the U.S. dollar, the assets and liabilities are translated into U.S. dollars at current exchange rates. Resulting translation adjustments are reflected as accumulated other comprehensive income (loss) in stockholders' equity. Revenues and expenses are translated at average exchange rates for the year. Transaction gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency, except those transactions which operate as a hedge of an identifiable foreign currency commitment or as a hedge of a foreign currency investment position, are included in the results of operations as incurred. RECLASSIFICATION Certain amounts in the fiscal 2000 and 1999 consolidated financial statements and supporting note disclosures have been reclassified to conform to the fiscal 2001 presentation. Such reclassification did not impact previously reported net income or retained earnings. USE OF ESTIMATES The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. ACCOUNTING FOR LONG-TERM POWER PURCHASE CONTRACT Under a long-term power purchase contract with Nebraska Public Power District ("NPPD"), expiring in 2004, MidAmerican Energy purchases one-half of the output of the 778-megawatt Cooper Nuclear Station ("Cooper"). The consolidated balance sheets include a liability for MidAmerican Energy's fixed obligation to pay 50% of NPPD's Nuclear Facility Revenue Bonds and other fixed liabilities. A like amount representing MidAmerican Energy's right to purchase power is shown as an asset. Cooper capital improvement costs prior to 1997, including carrying costs, were deferred in accordance with then applicable rate regulation and are being amortized and recovered in rates over either a five-year period or the remaining term of the power purchase contract. Beginning July 11, 1997, the Iowa portion of capital improvement costs is recovered currently from customers and is expensed as incurred. For jurisdictions other than Iowa, MidAmerican Energy began charging Cooper capital improvement costs to expense as incurred in January 1997. F-30 The fuel cost portion of the power purchase contract is included in cost of sales. All other costs MidAmerican Energy incurs in relation to its long-term power purchase contract with NPPD are included in operating expense. ACCOUNTING PRINCIPLE CHANGE Effective January 1, 2001, the Company has changed its accounting policy regarding major maintenance and repairs for nonregulated gas projects, nonregulated plant overhaul costs and geothermal well rework costs to the direct expense method from the former policy of monthly accruals based on long-term scheduled maintenance plans for the gas projects and deferral and amortization of plant overhaul costs and geothermal well rework costs over the estimated useful lives. The cumulative effect of the change in accounting principle was $4.6 million, net of taxes of $.7 million. If the Company had adopted the policy as of January 1, 2000, income before extraordinary item and cumulative effect of change in accounting principle would have been $6.3 million lower in 2000 on a proforma basis. ACCOUNTING FOR DERIVATIVES The Company is exposed to market risk, including changes in the market price of certain commodities and interest rates. To manage the price volatility relating to these exposures, the Company enters into various financial derivative instruments. Senior management provides the overall direction, structure, conduct and control of the Company's risk management activities, including the use of financial derivative instruments, authorization and communication of risk management policies and procedures, strategic hedging program guidelines, appropriate market and credit risk limits, and appropriate systems for recording, monitoring and reporting the results of transactional and risk management activities. The Company uses hedge accounting for derivative instruments pertaining to its natural gas purchasing, wholesale electricity activities, financing activities and preferred stock investing operations. On January 1, 2001, the Company adopted Statement of Financial Accounting Standards Nos. 133 and 138 (SFAS Nos. 133/138) pertaining to the accounting for derivative instruments and hedging activities. SFAS Nos. 133/138 requires an entity to recognize all of its derivatives as either assets or liabilities in its statement of financial position and measure those instruments at fair value. If the conditions specified in SFAS Nos. 133/138 are met, those instruments may be designated as hedges. Changes in the value of hedge instruments would not impact earnings, except to the extent that the instrument is not perfectly effective as a hedge. At January 1, 2001, the Company recognized $44.9 million and $38.0 million of energy-related assets and liabilities, respectively, as being subject to fair value accounting pursuant to SFAS Nos. 133/138, all of which are accounted for as hedges. Additionally, on January 1, 2001, the Company's portfolio of preferred stock investments was transferred from the available for sale category to the trading category, as permitted by SFAS No. 133. Initial adoption of SFAS Nos. 133/138 did not have a material impact on the results of operations for the Company. NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the FASB issued SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets" which establish accounting and reporting for business combinations. SFAS No. 141 requires all business combinations entered into subsequent to June 30, 2001, to be accounted for using the purchase method of accounting. SFAS No. 142 provides that goodwill and other intangible assets with indefinite lives will not be amortized but tested for impairment on an annual basis. SFAS No. 142 is effective for the Company beginning January 1, 2002. Under the current method of assessing goodwill for impairment, which uses an undiscounted cash flow approach, no material impairment existed at December 31, 2001. For 2002, the Company will begin to test goodwill for impairment under the new rules, applying a fair-value-based approach. The Company is in the process of quantifying the anticipated impact on its financial condition and results of operations of adopting the provisions of SFAS No. 142, which could be significant. The historical impact of not amortizing goodwill would have been to increase net income for the years ended December 31, 2001, 2000 and 1999 by $94.4 million, $92.4 million and $62.3 million, respectively. However, impairment reviews may result in future periodic write-downs. F-31 In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations", which addresses the accounting for legal obligations associated with the retirement of tangible, long-lived assets, and the associated asset retirement costs. This pronouncement is effective for years beginning after June 15, 2002. The Company is evaluating the impact that adoption of this standard will have on its financial statements. In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. This pronouncement is effective for years beginning after December 15, 2001. The Company is evaluating the impact that adoption of this standard will have on its financial statements, but does not believe it will have a material impact on its financial statements. 3. ACQUISITIONS/DISPOSITIONS YORKSHIRE SWAP On September 21, 2001, CE Electric UK Ltd., an indirect wholly owned subsidiary of the Company, and Innogy Holdings, plc executed an agreement to exchange Northern's electricity and gas supply and metering assets for Innogy's 94.75% interest in Yorkshire's electricity distribution business. Northern's supply business was initially valued at approximately $430 million ( (pounds sterling)295 million), including working capital of approximately $53 million ( (pounds sterling)37 million). 94.75% of Yorkshire's distribution business was initially valued at approximately $395 million ( (pounds sterling)271 million), including working capital of approximately $48 million ( (pounds sterling)33 million). The net cash received by Northern for the exchange was approximately $35 million ( (pounds sterling)24 million). Working capital is subject to adjustment and is currently under review. The disposition of Northern's supply business created a pre-tax non-recurring gain of $196.7 million and an after-tax gain of $10.8 million. Included in the carrying value of the Northern supply business was $504.4 million of goodwill allocated based on the relative fair values of the Northern supply business. In connection with the sale of the Northern supply business, management intends to sell the associated Northern retail business. The Company paid $37.4 million, net of cash acquired of $362.8 million and transaction costs, for 94.75% of the Yorkshire electricity distribution business and related indebtedness. The acquisition has been accounted for as a purchase business combination. The results of operations for Yorkshire are included in the Company's results beginning September 21, 2001. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions). Cash .......................................................... $ 362.8 Property, plant and equipment ................................. 1,262.7 Excess of cost over fair value of net assets acquired ......... 523.6 Other assets .................................................. 11.6 ---------- Total assets acquired ..................................... 2,160.7 ---------- Current liabilities ........................................... ( 34.1) Long-term debt ................................................ (1,503.3) Deferred income taxes ......................................... ( 175.8) Minority interest ............................................. ( 40.7) Other liabilities ............................................. ( 6.6) ---------- Total liabilities assumed ................................. (1,760.5) ---------- Net assets acquired ........................................... $ 400.2 ==========
TETON TRANSACTION On October 24, 1999, the Company and an investor group comprised of Berkshire Hathaway, Walter Scott, Jr., and David L. Sokol, executed a definitive agreement and plan of merger whereby the investor F-32 group would acquire all of the outstanding common stock of the Company for $35.05 per share in cash, representing a total purchase price of approximately $2.2 billion, including transaction costs (the "Teton Transaction"). The Teton Transaction closed on March 14, 2000 and Berkshire Hathaway invested approximately $1.24 billion in common stock and convertible preferred stock and approximately $455 million in 11% nontransferable trust preferred securities due March 14, 2010. Mr. Scott, Mr. Sokol and Gregory E. Abel, Chief Operating Officer of the Company, contributed cash and current securities of the Company having a value of approximately $310 million. The remaining purchase price was funded with the Company's cash. Berkshire Hathaway owns approximately 9.7% of the voting stock, Mr. Scott owns approximately 86% of the voting stock, Mr. Sokol owns approximately 3% of the voting stock and Mr. Abel owns approximately 1% of the voting stock. The merger has been accounted for as a purchase business combination. The purchase price has been allocated to assets acquired and liabilities assumed. The Company recorded goodwill of approximately $1.2 billion that is being amortized using the straight-line method over a 40-year period. The Company incurred approximately $7.6 million and $6.7 million of non-recurring costs in 2000 and 1999 respectively, related to the Teton Transaction, which were expensed. Unaudited pro forma combined revenue, income before cumulative effect of change in accounting principle and net income of the Company and MEHC (Predecessor) for the years ended December 31, 2001 and 2000, as if the Yorkshire swap and the Teton Transaction had occurred at the beginning of each year after giving effect to pro forma adjustments related to the acquisitions, including the sale of the Northern Supply business and the issuance of the 11% trust preferred securities, were $4,401.0 million, $149.1 million and $144.5 million, respectively, compared to $4,084.0 million, $113.3 million and $113.3 million, respectively. HOMESERVICES On October 18, 1999, the Company closed on its initial public offering of 3.25 million shares of common stock of HomeServices at $15 per share. HomeServices sold 2.19 million newly issued shares and the Company, the selling stockholder, sold 1.06 million of its HomeServices shares in the offering. The offering reduced the Company's ownership in HomeServices to approximately 65%. On April 14, 2000, the Company purchased 500,000 shares of HomeServices' common stock for $4.2 million, increasing the Company's ownership percentage to approximately 70%. In October 2000, HomeServices repurchased 1.7 million shares of treasury stock for $17.9 million. This transaction increased the Company's ownership percentage to approximately 83%. On August 27, 2001, the Company commenced a tender offer to purchase the remaining outstanding shares of common stock of HomeServices for a cash purchase price of $17 per share. On September 25, 2001, the Company announced that it had successfully completed the tender offer for all outstanding shares of the common stock of HomeServices for $29.3 million. As a result, the Company owns 100% of the outstanding HomeServices common stock, although options entitling employees to purchase HomeServices common stock remain outstanding. F-33 4. PROPERTY, PLANT, CONTRACTS AND EQUIPMENT, NET Property, plant, contracts and equipment, net comprise the following at December 31 (in thousands):
2001 2000 --------------- --------------- Operating assets: Utility generation and distribution system ............... $ 7,574,339 $ 6,132,867 Independent power plants ................................. 1,398,179 694,615 Utility non-operational assets ........................... 354,366 344,576 Power sales agreements ................................... 48,185 82,231 Realty company assets .................................... 51,150 37,936 Other assets ............................................. 47,863 53,590 ------------ ------------ Total operating assets ................................... 9,474,082 7,345,815 Less accumulated depreciation and amortization ........... (3,650,862) (3,300,237) ------------ ------------ Net operating assets ..................................... 5,823,220 4,045,578 Mineral and gas reserves and exploration assets, net ..... 387,697 378,495 Construction in progress: Zinc recovery project ................................... 163,366 165,585 Utility generation and distribution system .............. 149,225 143,261 Casecnan ................................................ -- 387,274 Cordova ................................................. -- 224,514 Other ................................................... 3,940 3,940 ------------ ------------ Total .................................................... $ 6,527,448 $ 5,348,647 ============ ============
ZINC RECOVERY PROJECT The Company owns the rights to proprietary processes for the extraction of minerals from elements in solution in the geothermal brine and fluids utilized at its Imperial Valley plants. A pilot plant has successfully produced commercial quality zinc at the Company's Imperial Valley Projects. CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the Company, is constructing the Zinc Recovery Project which will recover zinc from the geothermal brine (the "Zinc Recovery Project"). Facilities are being installed near the Imperial Valley Project's sites to extract a zinc chloride solution from the geothermal brine through an ion exchange process. This solution will be transported to a central processing plant where zinc ingots will be produced through solvent extraction, electrowinning and casting processes. The Zinc Recovery Project is designed to have a capacity of approximately 30,000 metric tons per year and is scheduled to commence commercial operations in 2002. In September 1999, CalEnergy Minerals LLC entered into a sales agreement whereby all zinc produced by the Zinc Recovery Project will be sold to Cominco, Ltd. The initial term of the agreement expires in December 2005. The Zinc Recovery Project was being constructed by Kvaerner U.S. Inc. ("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering, procure, construct and manage contract (the "Zinc Recovery Project EPC Contract"). On June 14, 2001, CalEnergy Minerals LLC issued notices of default, termination and demand for payment of damages to Kvaerner under the Zinc Recovery Project EPC Contract due to failure to meet performance obligations. As a result of Kvaerner's failure to pay monetary obligations under the Zinc Recovery Project EPC Contract, CalEnergy Minerals LLC drew $29.6 million under the EPC Contract Letter of Credit on July 20, 2001. CalEnergy Minerals LLC has entered into a time and materials reimbursable engineer, procure and construction management contract with AMEC E&C Services, Inc. to complete the Zinc Recovery Project. On July 11, 2001, Kvaerner filed an Amended Demand For Arbitration against CalEnergy Minerals LLC characterizing the nature of the dispute as concerns regarding change orders and performance penalties. Kvaerner did not state the amount of its claim. On August 7, 2001, CalEnergy Minerals LLC filed an Answering Statement and Counterclaim against Kvaerner. CalEnergy Minerals LLC denied all material allegations in Kvaerner's Amended Demand for F-34 Arbitration, and asserted a counterclaim against Kvaerner for breach of contract and specific performance. CalEnergy Minerals LLC alleged that its total estimated damage for Kvaerner's breach of contract are in excess of approximately $60 million; however, CalEnergy Minerals LLC has offset approximately $42.5 million of these damages by exercising its rights under the EPC Contract to claim the retainage and by drawing on a letter of credit. Therefore, CalEnergy Minerals LLC has asked for a judgment in excess of approximately $20 million. The arbitration is scheduled for June 2002. 5. EQUITY INVESTMENT IN CE GENERATION Due to the sale of 50% of its interests in CE Generation, the Company has accounted for CE Generation as an equity investment beginning March 3, 1999. The equity investment in CE Generation at December 31, 2001 and 2000 was approximately $233.6 million and $220.0 million, respectively. The following is summarized financial information for CE Generation as of and for the years ended December 31 (in thousands):
2001 2000 1999 ------------ ------------ ----------- Revenues ........................................... $ 565,838 $ 510,796 $340,683 Income before extraordinary item and cumulative effect of change in accounting principle .......... 74,194 73,535 61,970 Net income ......................................... 58,808 73,535 44,492 Current assets ..................................... 211,635 188,234 Total assets ....................................... 1,932,119 1,984,445 Current liabilities ................................ 155,808 138,751 Long-term debt, including current portion .......... 1,096,256 1,163,729 Total liabilities .................................. 1,404,910 1,477,066
6. SHORT-TERM DEBT Short-term debt comprises the following at December 31 (in thousands):
2001 2000 ----------- ---------- Corporate revolving credit facilities ........... $153,500 $ 85,000 MidAmerican Energy short-term debt .............. 91,780 81,600 HomeServices revolving credit facility .......... 9,000 10,000 Other ........................................... 1,732 85,056 -------- -------- $256,012 $261,656 ======== ========
CORPORATE REVOLVING CREDIT FACILITIES The Company has available $400 million in revolving credit facilities with $150 million expiring in June 2002 and $250 million expiring in June 2003. The facilities are unsecured and are available to fund working capital requirements and finance future business expansion opportunities. The facilities carry a variable interest rate based on LIBOR and ranging from 2.8125% to 8.5% in 2001 (weighted average interest rate of 2.93% at December 31, 2001). MIDAMERICAN ENERGY SHORT-TERM DEBT MidAmerican Energy has authority from the Federal Energy Regulatory Commission ("FERC") to issue short-term debt in the form of commercial paper and bank notes aggregating $500 million. As of December 31, 2001, MidAmerican Energy had in place a $370.4 million revolving credit facility that supports its $250 million commercial paper program and its variable rate pollution control revenue obligations. In addition, MidAmerican Energy has a $5 million line of credit. As of December 31, 2001, commercial paper and bank notes totaled $89.4 million for MidAmerican Energy. F-35 MHC Inc., an indirect wholly owned subsidiary of the Company, has a $4.0 million line of credit under which $2.4 million was outstanding at December 31, 2001. The commercial paper, bank notes and outstanding line of credit have a weighted average interest rate of 1.9% at December 31, 2001. HOMESERVICES REVOLVING CREDIT FACILITIES HomeServices has available a $65 million senior secured revolving credit facility of which HomeServices had drawn down approximately $9 million as of December 31, 2001. This credit agreement has a variable interest rate at either the prime lending rate or LIBOR plus a fixed spread of 1.25% to 2.50% that varies based on HomeServices' cash flow leverage ratio, as defined in the agreement. As of December 31, 2001, the blended average interest rate on the senior secured revolving credit facility borrowings was 3.20%. 7. PARENT COMPANY DEBT Parent company debt is unsecured senior obligations of the Company and comprises the following at December 31 (in thousands):
2001 2000 -------------- -------------- 7.63% Senior Notes due 2007 ............... $ 350,000 $ 350,000 6.96% Senior Notes due 2003 ............... 215,000 215,000 7.23% Senior Notes due 2005 ............... 260,000 260,000 7.52% Senior Notes due 2008 ............... 450,000 450,000 8.48% Senior Notes due 2028 ............... 475,000 475,000 7.52% Senior Notes due 2008 ............... 101,680 101,888 Fair value adjustments and other .......... (17,182) (21,917) ---------- ---------- $1,834,498 $1,829,971 ========== ==========
Interest on the 7.63% Senior Notes is payable semiannually on April 15 and October 15 of each year. Interest on the remaining parent company debt is payable semiannually on March 15 and September 15 of each year. 8. SUBSIDIARY AND PROJECT DEBT Each of the Company's direct or indirect subsidiaries is organized as a legal entity separate and apart from the Company and its other subsidiaries. Pursuant to separate project financing agreements, the assets of each subsidiary are pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should not be assumed that any asset of any such subsidiary will be available to satisfy the obligations of the Company or any of its other such subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to the Company or affiliates thereof. "Subsidiaries" means all of the Company's direct or indirect subsidiaries (1) owning interests in CE Electric UK Funding, MidAmerican Funding, HomeServices, CE Generation, or the Imperial Valley, Saranac, Power Resources, Mahanagdong, Malitbog, Upper Mahiao, Casecnan, and Cordova projects or (2) owning interests in the subsidiaries that own interests in the foregoing subsidiaries or projects. F-36 Project loans held by subsidiaries and projects comprise the following at December 31 (in thousands):
2001 2000 ------------- -------------- MidAmerican Funding, LLC Senior Notes and Bonds .......... $ 700,000 $ 700,000 MidAmerican Energy Mortgage Bonds ........................ 340,570 340,570 MidAmerican Energy Pollution Control Bonds ............... 157,185 158,625 MidAmerican Energy Notes ................................. 322,240 422,240 CE Electric UK Funding Eurobonds ......................... 291,643 299,580 CE Electric UK Funding Company Senior Notes and Sterling Bonds .......................................... 646,500 653,750 Yorkshire Electric Debt .................................. 1,491,597 -- CE Gas Loan .............................................. 70,180 73,162 Casecnan Notes and Bonds ................................. 320,138 346,439 Philippine Term Loans .................................... 313,221 392,625 Cordova Funding Senior Secured Bonds ..................... 225,000 225,000 Salton Sea Bonds ......................................... 139,896 140,528 MidAmerican Capital 8.52% Notes .......................... 23,333 46,667 HomeServices 7.12% Senior Notes and Other ................ 36,780 37,607 Other, including fair value adjustments .................. (6,292) (9,119) ---------- ---------- $5,071,991 $3,827,674 ========== ==========
MIDAMERICAN FUNDING, LLC SENIOR NOTES AND BONDS On March 11, 1999, MidAmerican Funding, LLC, a wholly owned subsidiary of the Company, issued $200 million of 5.85% Senior Secured Notes due in 2001, $175 million of 6.339% Senior Secured Notes due in 2009, and $325 million of 6.927% Senior Secured Bonds due in 2029. The proceeds from the offering were used to complete the MidAmerican acquisition in 1999. On March 1, 2001 MidAmerican Funding, LLC retired $200 million of 5.85% Senior Secured Notes due 2001. On March 19, 2001 MidAmerican Funding, LLC issued $200 million of 6.75% Senior Secured Notes due March 1, 2011. MIDAMERICAN ENERGY MORTGAGE BONDS, POLLUTION CONTROL BONDS AND NOTES The components of MidAmerican Energy's Mortgage Bonds, Pollution Control Bonds and Notes at December 31 are as follows (in thousands):
2001 2000 ----------- ----------- Mortgage bonds: 7.125% Series, due 2003 ......... $100,000 $100,000 7.70% Series, due 2004 .......... 55,630 55,630 7% Series, due 2005 ............. 90,500 90,500 7.375% Series, due 2008 ......... 75,000 75,000 7.45% Series, due 2023 .......... 6,940 6,940 6.95% Series, due 2025 .......... 12,500 12,500 -------- -------- $340,570 $340,570 ======== ========
F-37
2001 2000 ----------- ----------- Pollution control revenue obligations: 5.75% Series, due periodically through 2003 ........................ $ 5,760 $ 7,200 5.95% Series, due 2023 (secured by general mortgage bonds) ......... 29,030 29,030 6.7% Series, due 2003 .............................................. 1,000 1,000 6.1% Series, due 2007 .............................................. 1,000 1,000 Variable rate series - Due 2016 and 2017, 1.77% and 4.56% respectively .................. 37,600 37,600 Due 2023 (secured by general mortgage bond, 1.77% and 4.56%, respectively) ........................................ 28,295 28,295 Due 2023, 1.77% and 4.56% respectively ........................... 6,850 6,850 Due 2024, 1.77% and 4.56% respectively ........................... 34,900 34,900 Due 2025, 1.77% and 4.56% respectively ........................... 12,750 12,750 -------- -------- $157,185 $158,625 ======== ======== Notes: 8.75% Series, due 2002 ............................................. $ 240 $ 240 7.375% Series, due 2002 ............................................ 162,000 162,000 6.5% Series, due 2001 .............................................. -- 100,000 6.375% Series, due 2006 ............................................ 160,000 160,000 -------- -------- $322,240 $422,240 ======== ========
CE ELECTRIC UK FUNDING EUROBONDS The balances at December 31, 2001 and 2000 consists of the following (in thousands):
2001 2000 ----------- ----------- 8.625% Bearer bonds due 2005 .......... $145,879 $149,865 8.875% Bearer bonds due 2020 .......... 145,764 149,715 -------- -------- $291,643 $299,580 ======== ========
CE ELECTRIC UK FUNDING COMPANY SENIOR NOTES AND STERLING BONDS The balances at December 31 are comprised of the following (in thousands):
2001 2000 ----------- ----------- 6.853% Senior Notes due 2004 ........... $124,613 $124,503 6.995% Senior Notes due 2007 ........... 235,937 235,804 7.25% Sterling Bonds due 2022 .......... 285,950 293,443 -------- -------- $646,500 $653,750 ======== ========
The CE Electric UK Funding Company Senior Notes and Sterling Bonds prohibit distributions to any of its stockholders unless certain financial ratios are met by the CE Electric UK Funding Company or the long-term debt rating falls below a prescribed level. F-38 YORKSHIRE ELECTRIC DEBT In connection with the Yorkshire/Northern supply swap on September 21, 2001, the Company assumed approximately $1.5 billion in debt. The balance at December 31, 2001 is comprised of the following (in thousands):
2001 ------------ 9.250% Eurobond due 2020 .................. $ 383,576 7.250% Eurobond due 2028 .................. 311,427 Variable rate Trust Securities due 2020 (5.19% at December 31, 2001) ............. 235,313 8.080% Trust Securities due 2038 .......... 261,082 6.496% Yankee Bonds due 2008 .............. 300,199 ---------- $1,491,597 ==========
The Yorkshire Electric Debt prohibits distributions to any of its stockholders unless certain financial ratios are met by Yorkshire or the long-term debt rating falls below a prescribed level. CE GAS LOAN CE Gas borrowed $70.2 million and $73.2 million on a (pounds sterling)70 million revolving facility at December 31, 2001 and 2000, respectively. The amount carries a variable interest rate based on LIBOR (4.87% at December 31, 2001). The revolving facility had utilized (pounds sterling)48.3 million and (pounds sterling)49.0 million at December 31, 2001 and 2000, respectively. CASECNAN NOTES AND BONDS On November 27, 1995 CE Casecnan issued $371.5 million of notes and bonds to finance the construction of the Casecnan Project. The balances at December 31 consist of the following (in thousands):
2001 2000 ----------- ----------- Senior Secured Floating Rate Notes (FRNs) due in 2002 ............................................. $ 23,638 $ 49,939 11.45% Senior Secured Series A Notes due in 2005 ......... 125,000 125,000 11.95% Senior Secured Series B Bonds due in 2010 ......... 171,500 171,500 -------- -------- $320,138 $346,439 ======== ========
The Company held $3.0 million and $6.3 million of the FRNs at December 31, 2001 and 2000, respectively. The Casecnan Notes and Bonds are subject to redemption at the Company's option as provided for in the Trust Indenture. The Casecnan Notes and Bonds are also subject to mandatory redemption based on certain conditions. PHILIPPINE TERM LOANS The Overseas Private Investment Corporation ("OPIC") provided term loan financing for the Company's Malitbog geothermal power project of $46.8 million that was fixed at an interest rate of 9.176%. A syndicate of international commercial banks is providing term loan financing of $84.4 million at a variable interest rate based on LIBOR (4.295% at December 31, 2001). The loans have scheduled repayments through June 2005. Export-Import Bank of the United States ("Ex-Im Bank") provided term loan financing for the Company's Upper Mahiao geothermal power project of $121.3 million at a fixed interest rate of 5.95%. United Coconut Planters Bank of the Philippines is providing term loan financing of $8.3 million at a variable interest rate based on LIBOR (5.130% at December 31, 2001). The loans have scheduled repayments through June 2006. F-39 Ex-Im Bank provided term loan financing for the Company's Mahanagdong geothermal power project of $154.6 million at a fixed rate of 6.92%. OPIC is providing term loan financing of $34.3 million at a fixed interest rate of 7.6%. The loans have scheduled repayments through June 2007. CORDOVA FUNDING SENIOR SECURED BONDS On September 10, 1999 Cordova Funding Corporation ("Cordova Funding"), a wholly owned subsidiary of the Company, closed the $225 million aggregate principal amount financing for the construction of the Cordova Project. The proceeds were loaned to Cordova Energy and comprise the following (in thousands):
SERIES ISSUE DATE DUE DATE INTEREST RATE AMOUNT ------------------------------------------ -------------------- ---------- --------------- ---------- Series A-1 Senior Secured Bonds .......... September 10, 1999 2019 8.64% $ 93,515 Series A-2 Senior Secured Bonds .......... December 15, 1999 2019 8.79% 31,309 Series A-3 Senior Secured Bonds .......... March 15, 2000 2020 9.07% 29,300 Series A-4 Senior Secured Bonds .......... June 15, 2000 2020 8.82% 58,121 Series A-5 Senior Secured Bonds .......... September 15, 2000 2020 8.48% 12,755 -------- Total .................................... $225,000 ========
MidAmerican Energy Holdings Company has guaranteed a specified portion of the scheduled debt service on the Cordova Funding Senior Secured Bonds equal to $37 million. SALTON SEA BONDS Salton Sea Funding Corporation, an indirect wholly owned subsidiary of CE Generation, had a debt balance of $520.3 million at December 31, 2001. CalEnergy Minerals LLC is one of several guarantors of the Salton Sea Funding Corporation's debt. As a result of a note allocation agreement, CalEnergy Minerals LLC is primarily responsible for $139.9 million of the 7.475% Senior Secured Series F Bonds due November 30, 2018. MidAmerican Energy Holdings Company has guaranteed a specified portion of the scheduled debt service on the Series F Bonds equal to this current principal amount of $139.9 million and associated interest. ANNUAL REPAYMENTS OF SUBSIDIARY AND PROJECT DEBT The annual repayments of the subsidiary and project debt for the years beginning January 1, 2002 and thereafter are as follows (in thousands):
MIDAMERICAN MIDAMERICAN FUNDING, MIDAMERICAN ENERGY MIDAMERICAN CE ELECTRIC LLC SENIOR ENERGY POLLUTION ENERGY AND HOME SALTON UK NOTES AND MORTGAGE CONTROL CAPITAL SERVICES NOTES SEA FUNDING BONDS BONDS BONDS NOTES AND OTHER BONDS EUROBONDS ------------- ------------- ------------ ------------- ---------------- ---------- ------------ 2002 ........... $ -- $ -- $ 1,440 $185,573 $ 706 $ 2,108 $ -- 2003 ........... -- 100,000 5,320 -- 583 1,405 -- 2004 ........... -- 55,630 -- -- 5,133 1,757 -- 2005 ........... -- 90,500 -- -- 5,048 1,756 145,879 2006 ........... -- -- -- 160,000 5,036 1,827 -- Thereafter ..... 700,000 94,440 150,425 -- 20,274 131,043 145,764 -------- -------- -------- -------- -------- -------- -------- $700,000 $340,570 $157,185 $345,573 $ 36,780 $139,896 $291,643 ======== ======== ======== ======== ======== ======== ========
F-40
CE ELECTRIC UK CORDOVA FUNDING COMPANY FUNDING SENIOR NOTES CASECNAN PHILIPPINE SENIOR AND STERLING YORKSHIRE CE NOTES AND TERM SECURED BONDS ELECTRIC DEBT GAS LOAN BONDS LOANS BONDS TOTAL ----------------- --------------- ---------- ----------- ------------ ------------ ------------ 2002 ............... $ -- $ -- $ 25,642 $ 32,214 $ 68,259 $ 1,238 $ 317,180 2003 ............... -- -- 13,050 41,467 72,148 9,000 242,973 2004 ............... 124,613 -- 16,897 49,360 67,148 8,100 328,638 2005 ............... -- -- 14,455 54,752 63,034 7,875 383,299 2006 ............... -- -- 136 36,015 30,037 4,500 237,551 Thereafter ......... 521,887 1,491,597 -- 106,330 12,595 194,287 3,568,642 --------- ---------- -------- --------- --------- --------- ---------- $ 646,500 $1,491,597 $ 70,180 $ 320,138 $ 313,221 $ 225,000 $5,078,283 ========= ========== ======== ========= ========= ========= ==========
9. INCOME TAXES Provision for (benefit from) income taxes was comprised of the following (in thousands):
MEHC (PREDECESSOR) ----------------------------------- MARCH 14, 2000 JANUARY 1, 2000 YEAR ENDED THROUGH THROUGH YEAR ENDED DECEMBER 31, 2001 DECEMBER 31, 2000 MARCH 13, 2000 DECEMBER 31, 1999 ------------------- ------------------- ---------------- ------------------ Current: State ........... $ 2,669 $ 10,527 $ (1,886) $ 7,337 Federal ......... 51,025 17,387 9,147 128,839 Foreign ......... 43,450 40,823 16,012 13,889 --------- --------- -------- --------- 97,144 68,737 23,273 150,065 --------- --------- -------- --------- Deferred: State ........... 22,095 (1,933) 834 1,791 Federal ......... (36,441) (32,469) 1,854 (75,510) Foreign ......... 167,266 18,942 5,047 17,129 --------- --------- -------- --------- 152,920 (15,460) 7,735 (56,590) --------- --------- -------- --------- Total ............ $ 250,064 $ 53,277 $ 31,008 $ 93,475 ========= ========= ======== =========
A reconciliation of the federal statutory tax rate to the effective tax rate applicable to income before provision for income taxes follows:
MEHC (PREDECESSOR) ------------------------------- YEAR ENDED MARCH 14, 2000 JANUARY 1, 2000 YEAR ENDED DECEMBER 31, THROUGH THROUGH DECEMBER 31, 2001 DECEMBER 31, 2000 MARCH 13, 2000 1999 -------------- ------------------- ----------------- ------------- Federal statutory rate ................................ 35.0% 35.0% 35.0% 35.0% Investment and energy tax credits ..................... (1.0) ( 2.3) ( .7) ( 1.8) State taxes, net of federal tax effect ................ 3.2 2.6 ( .8) 1.7 Goodwill amortization ................................. 5.9 12.1 5.9 5.5 Dividends on preferred securities of subsidiary trusts* .............................................. (6.1) (11.1) (2.8) ( 3.8) Tax effect of foreign income .......................... (2.5) ( 5.8) (5.0) .3 Non-recurring items on CE Electric UK Funding, net of tax effect of foreign income ......... 19.2 -- -- -- Non-recurring items on Indonesia ...................... -- -- -- (11.0) Dividends received deduction .......................... (2.6) ( 6.8) (1.0) ( 3.7) Other items, net ...................................... (1.5) .6 3.4 3.9 ---- ----- ---- ----- Effective tax rate .................................... 49.6% 24.3% 34.0% 26.1% ==== ===== ==== =====
---------- * Dividends on preferred securities of subsidiary trusts are included in minority interest. F-41 Deferred tax liabilities (assets) are comprised of the following at December 31 (in thousands):
2001 2000 ------------- ------------- Property, plant, contracts and equipment .................... $1,245,140 $ 866,678 Income taxes recoverable through future rates ............... 185,222 186,427 Fuel cost recoveries ........................................ 20,272 14,598 Reacquired debt ............................................. 7,544 10,256 ---------- ---------- 1,458,178 1,077,959 ---------- ---------- Nuclear reserve and decommissioning ......................... (17,898) (20,690) Deferred income ............................................. (24,732) (8,883) Deferred contract costs ..................................... (65,145) (51,703) Revenue sharing accruals .................................... (24,769) (3,742) Accruals not currently deductible for tax purposes .......... (35,221) (40,563) Other ....................................................... (6,145) (7,350) ---------- ---------- (173,910) (132,931) ---------- ---------- Net deferred income taxes ................................... $1,284,268 $ 945,028 ========== ==========
10. COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUSTS The Company has organized special purpose Delaware business trusts (collectively, the "Trusts") pursuant to their respective amended and restated declarations of trusts (collectively, the "Declarations"). The Company, through these Trusts, issued Company-obligated mandatorily redeemable preferred securities (collectively, the "Trust Securities") as follows (in thousands):
ORIGINAL CARRYING VALUE CARRYING VALUE ISSUE DECEMBER 31, DECEMBER 31, CONVERSION ISSUER ISSUE DATE RATE AMOUNT 2001 2000 RATE ------------------------------------- ------------------- ---------- ---------- ---------------- --------------- ----------- CalEnergy Capital Trust II .......... February 26, 1997 6.25% $180,000 $ 155,584 $ 156,084 1.1655 CalEnergy Capital Trust III ......... August 12, 1997 6.50% 270,000 269,984 269,984 1.047 MidAmerican Capital Trust I (issued to Berkshire) .............. March 14, 2000 11.00% 454,772 454,772 454,772 N/A Fair value adjustment ............... (92,189) (94,317) --------- --------- $ 788,151 $ 786,523 ========= =========
During 2001 and 2000, CalEnergy Capital Trust II redeemed 10,000 and 477,000 shares, respectively, of preferred securities at an aggregate cost of approximately $.4 million and $19.5 million, respectively. The Company owns all of the common securities of the Trusts. The Trust Securities have a liquidation preference of fifty dollars each and represent undivided beneficial ownership interests in each of the Trusts. The assets of the Trusts consist solely of the Company's Subordinated Debentures due February 25, 2012, September 1, 2027, and March 14, 2010, respectively, in outstanding aggregate principal amounts of approximately $155.5 million, $270 million and $454.8 million, respectively (collectively, the "Junior Debentures") issued pursuant to their respective indentures. The indentures include agreements by the Company to pay expenses and obligations incurred by the Trusts. Prior to the Teton Transaction, each Trust Security issued by CalEnergy Capital Trust II and III with a par value of $50 was convertible at the option of the holder at any time into shares of the Company's common stock based on the conversion rate. As a result of the Teton Transaction, in lieu of shares of the Company's common stock, holders of Trust Securities will receive $35.05 for each share of common stock it would have been entitled to receive on conversion. Distributions on the Trust Securities (and Junior Debentures) are cumulative, accrue from the date of initial issuance and are payable quarterly in arrears. The Junior Debentures are subordinated in right of payment to all senior indebtedness of the Company and the Junior Debentures are subject to certain covenants, events of default and optional and mandatory redemption provisions, all as described in the Junior Debenture indentures. F-42 Pursuant to Preferred Securities Guarantee Agreements (collectively, the "Guarantees"), between the Company and a preferred guarantee trustee, the Company has agreed irrevocably to pay to the holders of the Trust Securities, to the extent that the Trustee has funds available to make such payments, quarterly distributions, redemption payments and liquidation payments on the Trust Securities. Considered together, the undertakings contained in the Declarations, Junior Debentures, Indentures and Guarantees constitute full and unconditional guarantees by the Company of the Trusts' obligations under the Trust Securities. 11. SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST In December 1996, MidAmerican Energy Financing I, a wholly owned statutory business trust of MidAmerican Energy, issued 4,000,000 shares of 7.98% Series MidAmerican Energy-obligated mandatorily redeemable preferred securities. The sole assets of MidAmerican Energy Financing are $103.1 million of MidAmerican Energy 7.98% Series A Debentures due 2045 (the "Debentures"). There is a full and unconditional guarantee by MidAmerican Energy of MidAmerican Energy Financing's obligations under the preferred securities. MidAmerican Energy has the right to defer payments of interest on the Debentures by extending the interest payment period for up to 20 consecutive quarters. If interest payments on the Debentures are deferred, distributions on the preferred securities will also be deferred. During any deferral, distributions will continue to accrue with interest thereon, and MidAmerican Energy may not declare or pay any dividend or other distribution on, or redeem or purchase, any of its capital stock. If the Debentures, or a portion thereof, are redeemed, MidAmerican Energy Financing must redeem a like amount of the preferred securities. If a termination of MidAmerican Energy Financing occurs, MidAmerican Energy Financing will distribute to the holders of the preferred securities a like amount of the Debentures unless such a distribution is determined not to be practicable. If a determination is made, the holders of the preferred securities will be entitled to receive, out of the assets of MidAmerican Energy Financing after satisfaction of its liabilities, a liquidation amount of $25 for each preferred security held plus accrued and unpaid distributions. See Note 21. 12. PREFERRED STOCK In connection with the Teton Transaction, the Company issued 34.6 million shares of no par, zero coupon convertible preferred stock valued at $1,211.4 million. Each share of preferred stock is convertible at the option of the holder into one share of the Company's common stock subject to certain adjustments as described in the Company's Amended and Restated Articles of Incorporation 13. STOCK OPTIONS The Company had various stock option plans under which shares were reserved for grant as incentive or non-qualified stock options, as determined by the Board of Directors. The plans allowed options to be granted at 85% of their fair market value of the common stock at the date of grant. Generally, options were issued at 100% of fair market value of the common stock at the date of grant. Options granted under the 1996 plan became exercisable over a period of two to five years and expired if not exercised within ten years from the date of grant or, in some instances, a lesser term. As a result of the Teton Transaction, the majority of the options were cashed out at $35.05 per share. The remaining options of 2,145,000 were reissued under the new MidAmerican Energy Holdings Company and an additional 703,329 options were issued. The old options are fully vested and the additional options vest monthly over three years. The options are exercisable until the end of the term on March 14, 2008 at exercise prices ranging from $15.94 to $35.05 per share. 14. FAIR VALUE OF FINANCIAL INSTRUMENTS The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Although F-43 management uses its best judgment in estimating the fair value of these financial instruments, there are inherent limitations in any estimation technique. Therefore, the fair value estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a current transaction. The methods and assumptions used to estimate fair value are as follows: Short-term debt -- Due to the short-term nature of the short-term debt, the fair value approximates the carrying value. Debt instruments -- The fair value of all debt issues listed on exchanges has been estimated based on the quoted market prices. The Company is unable to estimate a fair value for the Philippine term loans as there are no quoted market prices available. Other financial instruments -- All other financial instruments of a material nature are short-term and the fair value approximates the carrying amount.
2001 2000 --------------------------- -------------------------- ESTIMATED ESTIMATED PRINCIPAL FAIR PRINCIPAL FAIR AMOUNT VALUE AMOUNT VALUE ------------ ------------ ----------- ------------ (IN THOUSANDS) 7.63% Senior Notes ................................. $ 350,000 $ 362,425 $ 350,000 $ 360,115 6.96% Senior Notes ................................. 215,000 222,676 215,000 216,570 7.23% Senior Notes ................................. 260,000 268,684 260,000 264,004 7.52% Senior Notes ................................. 450,000 455,085 450,000 459,090 8.48% Senior Notes ................................. 475,000 478,325 475,000 507,918 7.52% Senior Notes ................................. 101,680 102,130 101,888 102,020 MidAmerican Funding, LLC Senior Notes and Bonds ............................................. 700,000 667,402 700,000 657,300 MidAmerican Energy Mortgage Bonds .................. 340,570 356,087 340,570 345,692 MidAmerican Energy Pollution Control Bonds ......... 157,185 157,672 158,625 158,914 MidAmerican Energy Notes ........................... 322,240 329,573 422,240 420,496 MidAmerican Capital Notes .......................... 23,333 23,849 46,667 46,464 HomeServices Senior Notes and Other ................ 36,780 31,143 37,607 34,094 Salton Sea Bonds ................................... 139,896 121,290 140,528 116,947 CE Electric UK Funding Eurobonds ................... 291,643 346,115 299,580 357,456 CE Electric UK Funding Company Senior Notes and Sterling Bonds .......................... 646,500 702,643 653,750 694,031 Yorkshire Electric Debt ............................ 1,491,597 1,482,870 -- -- Casecnan Notes and Bonds ........................... 320,138 291,517 346,439 319,056 Cordova Funding Senior Secured Bonds ............... 225,000 227,442 225,000 224,018 CE Gas Loan ........................................ 70,180 70,180 73,162 73,162 Company-obligated preferred securities of subsidiary trusts ................................. 880,340 801,722 880,840 769,605 Subsidiary-obligated preferred securities of subsidiary trusts ................................. 100,000 99,640 100,000 98,752 Preferred Securities of Subsidiaries ............... 121,183 107,893 145,686 131,255
INTEREST RATE RISK At December 31, 2001, the Company had fixed-rate long-term debt, Company-obligated mandatorily redeemable preferred securities of subsidiary trusts, and subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts of $7,678.0 million in principal amount and having a fair value of $7,808.2 million. These instruments are fixed-rate and therefore do not expose the Company to the risk of earnings loss due to changes in market interest rates. However, the fair value of these instruments would decrease by approximately $355.7 million if interest rates were to increase by 10% from their levels F-44 at December 31, 2001. In general, such a decrease in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity. At December 31, 2001, the Company had floating-rate obligations of $281.4 million that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. These obligations are not hedged. If the floating rates were to increase by 10% from December 31, 2001 levels, the Company's consolidated interest expense for unhedged floating-rate obligations would increase by approximately $75,000 each month in which such increase continued based upon December 31, 2001 principal balances. F-45 The amortized cost, gross unrealized gain and losses and estimated fair value of investments in debt and equity securities at December 31 are as follows (in thousands):
2001 ------------------------------------------------------ AMORTIZED UNREALIZED UNREALIZED FAIR COST GAINS LOSSES VALUE ----------- ------------ ------------ ---------- Available-for-sale: Equity securities ................... $ 53,663 $24,444 $ (3,144) $ 74,963 Municipal bonds ..................... 27,842 1,315 (92) 29,065 U. S. Government securities ......... 26,725 1,910 (19) 28,616 Corporate securities ................ 18,682 812 (23) 19,471 Cash equivalents .................... 7,120 -- -- 7,120 -------- ------- -------- -------- $134,032 $28,481 $ (3,278) $159,235 ======== ======= ======== ======== Held-to-Maturity: Debt Securities ..................... $ 2,074 $ -- $ -- $ 2,074 U.S. Treasury Strips ................ 1,090 85 -- 1,175 Agency Obligations .................. 611 -- (22) 589 -------- ------- -------- -------- $ 3,775 $ 85 $ (22) $ 3,838 ======== ======= ======== ========
2000 ------------------------------------------------------- AMORTIZED UNREALIZED UNREALIZED FAIR COST GAINS LOSSES VALUE ----------- ------------ ------------ ----------- Available-for-sale: Equity securities ................... $ 83,509 $34,110 $ (7,115) $110,504 Municipal bonds ..................... 27,758 1,071 (175) 28,654 U. S. Government securities ......... 26,284 1,163 -- 27,447 Corporate securities ................ 25,737 48 (1,027) 24,758 Cash equivalents .................... 11,150 -- -- 11,150 -------- ------- -------- -------- $174,438 $36,392 $ (8,317) $202,513 ======== ======= ======== ======== Held-to-Maturity: Debt Securities ..................... $ 2,077 $ -- $ -- $ 2,077 U.S. Treasury Strips ................ 677 80 -- 757 Agency Obligations .................. 571 -- (53) 518 -------- ------- -------- -------- $ 3,325 $ 80 $ (53) $ 3,352 ======== ======= ======== ========
At December 31, 2001, the debt securities held by the Company had the following maturities (in thousands):
AVAILABLE FOR SALE HELD TO MATURITY ----------------------- ---------------------- AMORTIZED FAIR AMORTIZED FAIR COST VALUE COST VALUE ----------- --------- ----------- -------- Within 1 year .............. $ 3,269 $ 3,332 $ 3 $ 3 1 through 5 years .......... 28,851 30,706 2,323 2,357 5 through 10 years ......... 10,733 11,578 1,449 1,478 Over 10 years .............. 30,396 31,536 -- --
F-46 The proceeds and gross realized gains and losses on the disposition of available-for-sale and held-to-maturity investments are shown in the following table (in thousands). Realized gains and losses are determined by specific identification.
MEHC (PREDECESSOR) ----------------------------------- MARCH 14, 2000 JANUARY 1, 2000 YEAR ENDED THROUGH THROUGH YEAR ENDED DECEMBER 31, 2001 DECEMBER 31, 2000 MARCH 13, 2001 DECEMBER 31, 1999 ------------------- ------------------- ---------------- ------------------ Proceeds from sales ........... $ 68,333 $ 93,531 $ 22,588 $617,262 Gross realized gains .......... 2,676 6,464 1,560 97,545 Gross realized losses ......... (7,314) (10,585) (2,556) (6,437)
15. NON-RECURRING ITEMS TEESSIDE In December 2001, the Company recorded a non-recurring charge of $20.7 million representing an asset valuation impairment charge under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets," relating to the Company's 15.4% interest in Teesside Power Ltd. ("Teesside"). Teesside owns and operates an 1,875 MW combined cycle gas-fired power plant. Enron Corp. ("Enron"), through its subsidiaries, owned a 42.5% interest, operated the plant, and purchased 668MW of capacity. Enron's subsidiary, who owns and operates Teesside, is now in administration and administrators have been appointed to run its business and are attempting to find a buyer. As a result of Enron's subsidiary being in administration, Teesside is in discussion with its lenders over restructuring of the (pounds sterling)650 million debt still outstanding. It is anticipated that there will be no further dividends arising from the investment in Teesside and subsequently, the Company has determined the investment in Teesside to be of negligible value. TELEPHONE FLAT SALE On October 16, 2001, the Company closed on a transaction that transferred all properties and rights of the Telephone Flat Project, a geothermal development project in northern California to Calpine Corp. The Company recorded a pre-tax gain of $20.7 million and an after-tax gain of $12.2 million on the sale of the Telephone Flat Project. WESTERN STATES SALE On June 30, 2001, the Company closed on a transaction in which the Company sold Western States Geothermal, an indirect wholly owned subsidiary of the Company, to Ormat. The Company recorded a pre-tax gain of $9.8 million and an after-tax gain of $6.4 million on the sale of Western States Geothermal. QUALIFIED FACILITIES DISPOSITIONS On February 26, 1999, the Company closed the sale of all of its indirect ownership interests in the Coso Joint Ventures ("Coso") to Caithness Energy LLC ("Caithness") for $205 million in cash. On March 3, 1999, the Company closed the sale of 50% of its ownership interests in CE Generation to an affiliate of El Paso Energy Corporation for an aggregate consideration of approximately $245 million in cash, $6.5 million in contingent payments and $23.5 million in equity commitments. The sales of the qualified facilities resulted in a net non-recurring pre-tax gain of $20.2 million and an after-tax gain of approximately $12.4 million. MCLEOD On May 18, 1999, the Company announced the sale of approximately 6.74 million shares of McLeodUSA ("McLeod") Class A common stock, through a secondary offering by McLeod, at $55.625 per share. Proceeds from the sale were approximately $375 million, with a resulting pre-tax gain to the Company of approximately $78.2 million, and an after-tax gain of approximately $47.1 million. F-47 INDONESIA On December 2, 1994, former subsidiaries of the Company, Himpurna California Energy Ltd. ("HCE") and Patuha Power, Ltd. ("PPL", together with HCE, the "Indonesian Subsidiaries") executed separate joint operation contracts for the development of geothermal steam fields and geothermal power facilities located in Central Java in Indonesia. In 1997 and 1998 a series of Indonesian government decrees and other actions created significant uncertainty as to whether the Indonesian government would honor their contractual obligations to the Indonesian Subsidiaries. In 1997, the Company recorded a non-recurring charge of $87 million representing an asset valuation impairment charge under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets," relating to the Company's assets in Indonesia. The charge of $87 million represented the amount by which the carrying amount of such assets exceeded the estimated fair value of the assets determined by discounting the expected future net cash flows of the Indonesia projects. The Company carried political risk insurance on its investment in HCE and PPL through OPIC, an agency of the U.S. Government, as well as through private market insurers. On November 18, 1999, the Company transferred the Indonesian Subsidiaries to OPIC and received payment from OPIC and the private market insurers totaling $290 million under its political risk insurance policies, reflecting the return of its equity investment less policy deductibles. Due primarily to the timing of the receipt of proceeds, the Company recorded a pre-tax gain of approximately $40.3 million on the insurance proceeds and an additional tax benefit of $17.7 million for an after-tax gain of $58.0 million. On September 13, 2001, the Company transferred shares of Bali Energy Ltd., an indirect wholly owned Indonesian subsidiary of the Company, to PT Tenaga Burni Bali. The Company recorded a pre-tax gain of $10.4 million and an after-tax gain of $6.5 million on the transfer of the shares. 16. ACCOUNTING FOR DERIVATIVES INTEREST RATE RISK MidAmerican Energy has entered into a two-year, $162 million fixed-to-floating interest rate swap agreement in conjunction with its $162 million, 7.375% series of medium-term notes due August 1, 2002. The floating rate of the swap is based on a three-month LIBOR rate and the effective interest rate after the swap was 4.46% in 2001. As of December 31, 2001, the fair value of this swap was $9.1 million. CURRENCY EXCHANGE RATE RISK CE Electric UK Funding entered into certain currency rate swap agreements for the CE Electric UK Funding Company Senior Notes with two large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in Sterling. For the $125 million of 6.853% Senior Notes, the agreements extend until December 30, 2004 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.744%. For the $237 million of 6.995% Senior Notes, the agreements extend until December 30, 2007 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.737%. The estimated fair value of these swap agreements at December 31, 2001 is approximately $44.8 million based on quotes from the counterparty to these instruments and represents the estimated amount that the Company would expect to receive if these agreements were terminated. It is the Company's intention to hold these swap agreements to maturity. Yorkshire entered into certain currency rate swap agreements for the Trust Securities and the Yankee Bonds with five large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in Sterling. For the $255 million of Trust Securities, the agreements extend until June 30, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 9.4758% to 9.715%. For the $300 million of Yankee Bonds, the agreements extend until February 25, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 7.3175% to 7.345%. The estimated fair value of these swap agreements at December 31, 2001 is approximately $8.4 million based on quotes from the counterparty to these instruments and represents the estimated amount that the Company would expect to receive if these agreements were terminated. It is the Company's intention to hold these swap agreements to maturity. F-48 A decrease of 10% in the December 31, 2001 rate of exchange of Sterling to dollars would increase the amount received if these swap agreements were terminated by approximately $106.4 million. ENERGY COMMODITY PRICE RISK Under the current regulatory framework, MidAmerican Energy is allowed to recover in revenues the cost of gas sold from all of its regulated gas customers through a purchased gas adjustment clause. Because the majority of MidAmerican Energy's firm natural gas supply contracts contain pricing provisions based on a daily or monthly market index, MidAmerican Energy's regulated gas customers, although ensured of the availability of gas supplies, retain the risk associated with market price volatility. MidAmerican Energy enters into natural gas futures and swap agreements to mitigate a portion of the market risk retained by its regulated gas customers through the purchased gas adjustment clause. These financial derivative activities are recorded as hedge accounting transactions, with net amounts exchanged or accrued under swap agreements and realized gains or loses on futures contracts included in the cost of gas sold and recovered in revenues from regulated gas customers. MidAmerican Energy also derives revenues from nonregulated sales of natural gas. Pricing provisions are individually negotiated with these customers and may include fixed prices or prices based on a daily or monthly market index. MidAmerican Energy enters into natural gas futures and swap agreements to offset the financial impact of variations in natural gas commodity prices for physical delivery to nonregulated customers. These financial derivative activities are also recorded as hedge accounting transactions. MidAmerican Energy uses natural gas derivative instruments for trading purposes pursuant to EITF 98-10 under strict value-at-risk guidelines outlined by senior management. Derivative instruments held for trading purposes are recorded at fair value and any unrealized gains or losses are reported in earnings. Trading revenues and costs are reported gross on the consolidated statements of operations. MidAmerican Energy is exposed to variations in the price of fuel for generation and the price of purchased power in its Iowa jurisdiction comprising 89% of 2001 electric operating revenues. Fuel price risk is mitigated through forward contracts. Under typical operating conditions, MidAmerican Energy has sufficient generation to supply its retail electric needs. A loss of such generation at a time of high market prices could subject MidAmerican Energy to losses on its energy sales. MidAmerican Energy uses electricity forward contracts to hedge anticipated sales of wholesale electric power. MidAmerican Energy and its customers are exposed to the effect of variations in weather conditions on sales and purchased, respectively, of electricity and natural gas. For the 2001-2002 heating season, MidAmerican Energy entered into several degree-day swaps to offset a portion of the financial impact of those variations on MidAmerican Energy and its customers. MidAmerican Energy had the following financial derivative instruments for its natural gas and electric operations as of December 31: F-49 MidAmerican Energy derivative instruments used for other than trading purposes --
2001 2000 ----------------------- ------------------- Natural Gas Futures Contracts -- NYMEX: Net Contract Volumes -- Long (Short) ......... (600,000) MMBtu 1,460,000 MMBtu Unrealized Gain, in thousands ................ $ 40 $ 7,554 Weighted Average Settlement Price ............ $ (6.77) $ 9.42 Natural Gas Swap Contracts: Contract Volumes -- Pay Fixed ................ 7,853,052 MMBtu 13,496,239 MMBtu Contract Volumes -- Receive Fixed ............ 900,000 MMBtu 10,610,741 MMBtu Unrealized Gain (Loss), in thousands ......... $(7,643) $ 8,055 Weighted Average Pay Fixed Price ............. $ (0.97) $ 0.89 Weighted Average Receive Fixed Price ......... $ 0.04 $ (0.37) Natural Gas Options: Contract Volumes -- Long ..................... 2,300,000 MMBtu 1,790,280 MMBtu Unrealized Gain (Loss), in thousands ......... $(1,212) $ 953 Degree Day Swap Contracts: Contract Volumes -- Long ..................... 20,000 $/Degree day -- $/Degree Day Unrealized Gain (Loss), in thousands ......... $(3,486) $ -- Electric Forward Contracts: Contract Volumes -- (Short) .................. (728,800) MWh (139,200) MWh Unrealized Gain (Loss), in thousands ......... $ 6,313 $(4,731)
A $1.00 decrease in underlying natural gas prices would decrease unrealized gains on the futures contracts held at December 31, 2001, by approximately $0.6 million and would decrease unrealized losses on the above swap contracts by approximately $7.0 million. A $5.00 increase in underlying electricity prices would decrease unrealized gains on the forward contracts held at December 31, 2001, by approximately $3.6 million. The weighted average maturity for all derivative instruments used for hedging purposes is under one year. Unrealized gains and losses on cash flow hedges of future transactions are recorded in other comprehensive income. Only hedges that are highly effective in offsetting the risk of variability in future cash flows are accounted for in this manner. Future transactions include purchases of gas for resale to regulated and nonregulated customers, purchases of gas for storage, and purchases and sales of wholesale electric energy. When the associated hedged future transaction occurs or if a hedging relationship is no longer appropriate, the unrealized gains and losses are reversed from other comprehensive income and recognized in net income. Realized gains on cash flow hedges are recorded in either cost of sales or operating revenues, depending upon the nature of the physical transaction being hedged. For 2001, a net loss of $408,000 and a net gain of $36,000, representing the ineffectiveness of cash flow hedges, are reflected in cost of sales. During the twelve months beginning January 1, 2002, it is anticipated that $3.4 million of the $3.5 million after-tax, net unrealized gains on cash flow hedges presently recorded as accumulated other comprehensive income will be realized and recorded in earnings. MidAmerican Energy has hedged a portion of its exposure to the variability of cash flows for future transactions through December 2003. Unrealized gains and losses on fair value hedges are recognized in income as either operating revenues or cost of sales depending upon the nature of the item being hedged. Purchase and sales commitments hedged by fair value hedges are recorded at fair value, with the changes in values also recognized in income and substantially offsetting the impact of the hedges on earnings. For 2001, a net pre-tax gain of $18,000, representing the ineffectiveness of fair value hedges, is included in operating revenues. F-50 MidAmerican Energy derivative instruments used for trading purposes --
2001 2000 -------------------- ------------------- Natural Gas Futures Contracts -- NYMEX: Net Contract Volumes -- (Short) .............. 120,000 MMBtu (20,000) MMBtu Unrealized (Loss), in thousands .............. $ (224) $ (79) Weighted Average Settlement Price ............ $ 1.69 $(15.92) Natural Gas Swap Contracts: Contract Volumes -- Pay Fixed ................ 17,519,581 MMBtu 1,000,000 MMBtu Contract Volumes -- Receive Fixed ............ 17,850,372 MMBtu 1,010,000 MMBtu Unrealized Gain (Loss), in thousands ......... $2,045 $ (261) Weighted Average Pay Fixed Price ............. $(0.99) $ 0.92 Weighted Average Receive Fixed Price ......... $ 1.09 $ (1.17)
A change in underlying natural gas prices would not materially affect unrealized losses on the above future and swap contracts. 17. SECURITIZATION OF ACCOUNTS RECEIVABLE In December 1998, CE Electric UK Funding entered into a revolving receivable purchase agreement with Kitty Hawk Funding Corporation ("Kitty Hawk"), an unaffiliated special purpose entity established to purchase accounts receivable. In October 2000, the facility was transferred to Mont Blanc Capital Corp, administered by ING Barings, which allowed CE Electric UK Funding to sell all of its rights, title and interest in the majority of its billed electricity accounts receivable and to borrow against its unbilled electricity accounts receivable. In March 1999, CE Electric UK Funding received $161 million in cash associated with the agreement. In connection with the Northern Supply/Yorkshire swap on September 21, 2001, CE Electric UK Funding repaid the outstanding balance of this purchase agreement and ended their arrangement with Mont Blanc Capital Corp. CE Electric UK Funding does not have any amounts outstanding at December 31, 2001. In 1997, MidAmerican Energy entered into a revolving agreement, which expires in October 2002, to sell all of its right, title and interest in the majority of its billed accounts receivable to MidAmerican Energy Funding Corporation, a special purpose entity established to purchase accounts receivable from MidAmerican Energy. MidAmerican Energy Funding Corporation in turn sells receivable interests to outside investors. In consideration of the sale, MidAmerican Energy received cash and a subordinated note, bearing interest at 8%, from MidAmerican Energy Funding Corporation. As of December 31, 2001, the revolving cash balance was $44 million, down $26 million from December 31, 2000, and the amount outstanding under the subordinated note was $28.7 million. The agreement is structured as a true sale under which the creditors or MidAmerican Energy Funding Corporation will be entitled to be satisfied out of the assets of MidAmerican Energy Funding Corporation prior to any value being returned to MidAmerican Energy or its creditors. Therefore, the accounts receivable sold are not reflected on the consolidated balance sheets. At December 31, 2001, $71.5 million of accounts receivable, net of reserves, was sold under the agreement. 18. REGULATORY MATTERS CE ELECTRIC UK FUNDING Most revenue of each Distribution License Holder ("DLH") is controlled by a distribution price control formula. The current formula requires that regulated distribution income per unit is increased or decreased each year by RPI-Xd where the Retail Price Index ("RPI") reflects the average of the 12-month inflation rates recorded for each month in the previous July to December period. The distribution price control formula also reflects an adjustment factor ("Xd") which was established by the regulatory body, the Office of Gas and Electricity Markets ("Ofgem"), at the last price control review (and continues to be set) at 3%. The formula also takes account of the changes in system electrical losses, the number of F-51 customers connected and the voltage at which customers receive the units of electricity distributed. This formula determines the maximum average price per unit of electricity distributed (in pence per kilowatt hour) which a DLH is entitled to charge. The distribution price control formula permits DLHs to receive additional revenues due to increased distribution of units and a predetermined increase in customer numbers. The price control does not seek to constrain the profits of a DLH from year to year. It is a control on revenue that operates independently of most of the DLH's costs. During the lifetime of the price control, additional cost savings therefore contribute directly to profit. MIDAMERICAN ENERGY In 1997, pursuant to a rate proceeding before the Iowa Utilities Board ("IUB"), MidAmerican Energy, the Office of Consumer Advocate and other parties entered into a pricing plan settlement agreement establishing MidAmerican Energy's Iowa retail electric rates. That settlement agreement expired on December 31, 2000. On March 14, 2001, the Office of the Consumer Advocate filed a petition with the IUB to reduce Iowa retail electric rates by approximately $77 million annually. On June 11, 2001, MidAmerican Energy responded to that petition by filing a request with the IUB to increase MidAmerican Energy's Iowa retail electric rates by $51 million annually. On December 21, 2001, the IUB approved a settlement agreement that freezes the rates in effect on December 31, 2000, through December 31, 2005, and, with modifications, reinstates the revenue sharing provisions of the 1997 pricing plan settlement agreement. Under the 2001 settlement agreement, an amount equal to 50% of revenues associated with returns on equity between 12% and 14%, and 83.33% of revenues associated with returns on equity above 14%, in each year will be recorded as a regulatory liability to be used to offset a portion of the cost of future generating plant investments. An amount equal to the regulatory liability will be recorded as depreciation expense. As of December 31, 2001, MidAmerican Energy has recorded a $47.1 million regulatory liability that is reflected in other long-term accrued liabilities on the consolidated balance sheet. Under an Illinois restructuring law enacted in 1997, a sharing mechanism is in place for MidAmerican Energy's Illinois regulated retail electric operations whereby earnings above a computed threshold will be shared equally between customers and shareholders. A two-year average return on common equity greater than a two-year average benchmark will trigger an equal sharing of earnings on the excess. MidAmerican Energy's computed level of return on common equity is based on a rolling two-year average of the 30-year Treasury bond rates plus a premium of 5.50% for 1998 and 1999 and a premium of 8.5% for 200 through 2004. The two-year average above which sharing must occur for 2001 was 14.33%. The law allows MidAmerican Energy to mitigate the sharing of earnings above the threshold return on common equity through accelerated recovery of regulatory assets. On September 21, 2001, MidAmerican Energy filed a petition with the South Dakota Public Utilities Commission ("SDPUC") to increase its South Dakota natural gas rates. On February 20, 2002, the SDPUC approved a settlement agreement allowing increased rates of $3.1 million annually. On October 19, 2001, MidAmerican Energy filed a petition with the Illinois Commerce Commission to increase its Illinois natural gas rates by $3.2 million annually. A final decision on the petition is required within eleven months of the date of filing. On March 15, 2002, MidAmerican Energy made a filing with the IUB requesting an increase in rates of approximately $26.6 million for its Iowa retail natural gas customers. As part of the filing, MidAmerican Energy requested an interim rate increase of approximately $20.4 million annually. The IUB may adjust the requested interim amount and delay its implementation for up to ninety days. MidAmerican Energy expects the final rates, which may differ from the requested amount, to be implemented in the fourth quarter. 19. PENSION COMMITMENTS UNITED KINGDOM OPERATIONS CE Electric UK Funding participates in the Electricity Supply Pension Scheme, which provides pension and other related defined benefits, based on final pensionable pay, to substantially all employees throughout the Electricity Supply Industry in the United Kingdom. F-52 The actuarial computation for December 31, 2001, 2000 and 1999 assumed interest rates of 5.75%, 6.0% and 6.0% respectively, an expected return on plan assets of 7.0%, 6.5% and 6.5%, respectively, and annual compensation increases of 2.5%, 3.0% and 3.0%, respectively, over the remaining service lives of employees covered under the plan. Amounts funded to the pension are primarily invested in equity and fixed income securities. The following table details the funded status and the amount recognized in the Company's consolidated balance sheets for CE Electric UK Funding's plan as of December 31, 2001 and 2000 (in thousands):
2001 2000 ------------- ------------ Change in benefit obligation: Benefit obligation at beginning of year .................... $ 951,553 $ 940,600 Service cost ............................................... 7,854 8,660 Interest cost .............................................. 51,926 50,765 Participant contributions .................................. 5,236 4,927 Benefits paid .............................................. (49,453) (49,272) FAS 88 curtailment ......................................... 7,127 6,570 Northern Supply/Yorkshire swap net effect .................. 44,216 -- Experience gain and change of assumptions .................. (44,381) (10,697) ---------- ---------- Benefit obligation at end of the year ...................... 974,078 951,553 ---------- ---------- Change in plan assets: Fair value of plan assets at beginning of the year ......... 1,166,111 1,283,600 Actual return on plan assets ............................... (98,799) (73,741) Net asset transfer resulting from Northern Supply/Yorkshire Swap .................................... 46,980 -- Employer contributions ..................................... 582 597 Participant contributions .................................. 5,236 4,927 Benefits paid .............................................. (49,453) (49,272) ---------- ---------- Fair value of plan assets at end of the year ............... 1,070,657 1,166,111 ---------- ---------- Funded status .............................................. 96,579 214,558 Unrecognized net loss ...................................... (196,648) (77,193) ---------- ---------- Prepaid benefit cost ....................................... $ 293,227 $ 291,751 ========== ==========
Net periodic pension cost (benefit) for CE Electric UK Funding's plan for 2001, 2000 and 1999 included the following components (in thousands):
MEHC (PREDECESSOR) ----------------------------- MARCH 14, 2000 JANUARY 1, 2000 THROUGH THROUGH 2001 DECEMBER 31, 2000 MARCH 31, 2000 1999 ------------ ------------------- ---------------- ------------ Service cost -- benefits earned during the period..... $ 7,854 $ 6,933 $ 1,727 $ 10,200 Interest cost on projected benefit obligation ........ 51,926 40,640 10,125 48,500 Expected return on plan assets ....................... (78,979) (50,800) (12,657) (59,500) Curtailment loss ..................................... 7,127 5,260 1,310 38,300 --------- --------- --------- --------- Net periodic pension (benefit) cost .................. $ (12,072) $ 2,033 $ 505 $ 37,500 ========= ========= ========= =========
As a result of the distribution price reviews in 1999, CE Electric UK Funding implemented a review of staffing requirements primarily in its distribution business. Following discussions with the trade unions, CE Electric UK Funding put in place a workforce reduction program. In 1999, the Company recorded a non-recurring pre-tax loss of approximately $47.7 million that included a pension curtailment of $38.3 million. In 2000, the pension curtailment related to this workforce reduction program was $6.6 million. The curtailment loss in 2001 of $7.1 million is a result of the Northern Supply/Yorkshire swap. F-53 DOMESTIC OPERATIONS The Company has primarily noncontributory cash balance defined benefit pension plans covering substantially all domestic employees. Benefit obligations under the plans are based on participants' compensation, years of service and age at retirement. Funding is based upon the actuarially determined costs of the plans and the requirements of the Internal Revenue Code and the Employee Retirement Income Security Act. The Company has been allowed to recover pension costs related to its employees in rates. MidAmerican Energy currently provides certain postretirement health care and life insurance benefits for retired employees. Under the plans, substantially all of MidAmerican Energy's employees may become eligible for these benefits if they reach retirement age while working for MidAmerican Energy. However, MidAmerican Energy retains the right to change these benefits anytime at its discretion. MidAmerican Energy expenses postretirement benefit costs on an accrual basis and includes provisions for such costs in rates. In 1999, the noncontributory cash balance defined benefit pension plans, the noncontributory, nonqualified supplemental executive retirement plan, and the postretirement plans were amended to include participants from the Company. Prior to the amendment, these plans included only employees and participants of MidAmerican Energy. This inclusion increased the benefit obligation by $14.8 million for the pension and nonqualified supplemental retirement plans and $2.8 million for the postretirement plans. MidAmerican Energy also maintains noncontributory, nonqualified supplemental executive retirement plans for active and retired participants. During 2000, MidAmerican Energy adopted a market-related valuation of its pension assets for purposes of calculating net periodic pension costs. This change conforms MidAmerican Energy's accounting practices for pension costs to that of the Company. Net periodic pension, supplemental retirement and postretirement benefit costs included the following components for the Company:
MEHC (PREDECESSOR) ----------------------------------- MARCH 14, 2000 JANUARY 1, 2000 YEAR ENDED THROUGH THROUGH YEAR ENDED DECEMBER 31, 2001 DECEMBER 31, 2000 MARCH 13, 2000 DECEMBER 31, 1999 ------------------- ------------------- ---------------- ------------------ PENSION COST Service cost .................. $ 18,114 $ 13,014 $ 3,242 $ 9,854 Interest cost ................. 33,027 28,329 7,058 25,505 Expected return on plan assets (36,326) (38,532) (9,600) (37,392) Amortization of net transition obligation ................... (2,591) (2,074) (517) -- Amortization of prior service cost ......................... 2,729 2,310 575 -- Amortization of prior year gain (3,894) (3,297) (822) -- Curtailment loss .............. -- -- -- 4,270 --------- --------- -------- --------- Net periodic pension cost (benefit) .................... $ 11,059 $ (250) $ (64) $ 2,237 ========= ========= ======== =========
F-54
MEHC (PREDECESSOR) ----------------------------------- MARCH 14, 2000 JANUARY 1, 2000 YEAR ENDED THROUGH THROUGH YEAR ENDED DECEMBER 31, 2001 DECEMBER 31, 2000 MARCH 13, 2000 DECEMBER 31, 1999 ------------------- ------------------- ---------------- ------------------ POSTRETIREMENT COST Service cost ....................... $ 4,357 $ 2,089 $ 520 $ 2,478 Interest cost ...................... 10,418 6,688 1,666 6,423 Expected return on plan assets ..... (4,032) (3,947) (984) (3,540) Amortization of net transition obligation ........................ 4,110 3,290 820 -- Amortization of prior service cost .............................. 425 340 85 -- Amortization of prior year (gain) loss ....................... 332 (699) (174) -- -------- -------- ------ -------- Net periodic pension cost .......... $ 15,610 $ 7,761 $1,933 $ 5,361 ======== ======== ====== ========
The pension plan assets are in external trusts and are comprised of corporate equity securities, United States government debt, corporate bonds and insurance contracts. The postretirement benefit plans assets are in external trusts and are comprised primarily of corporate equity securities, corporate bonds, money market investment accounts and municipal bonds. Although the supplemental executive retirement plans had no plan assets as of December 31, 2001, MidAmerican Energy has Rabbi trusts which hold corporate-owned life insurance and other investments to provide funding for the future cash requirements. Because these plans are nonqualified, the fair value of these assets is not included in the following table. The fair value of the Rabbi trust investments was $50.4 million and $44.7 million at December 31, 2001 and 2000, respectively. During 1999 certain participants in the supplemental executive retirement plan left MidAmerican Energy reducing the future service of active employees by 28%. As a result, a curtailment loss of $5.3 million was recognized by the Company in 1999. Additionally, termination benefits provided to the participants, totaling $3.5 million, were expensed by MidAmerican Energy during 1999. The projected benefit obligation and accumulated benefit obligation for the supplemental executive retirement plans were $91.2 million and $88.2 million, respectively, as of December 31, 2001 and $82.7 million and $77.5 million, respectively, as of December 31, 2000. The following table presents a reconciliation of the beginning and ending balances of the benefit obligation, fair value of plan assets and the funded status of MidAmerican Energy's plans to the net amounts recognized in the consolidated balance sheet as of December 31 (dollars in thousands): F-55
2001 2001 2000 2000 PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS ------------ ---------------- ------------ --------------- Reconciliation of benefit obligation: Benefit obligation at beginning of year ............. $ 472,349 $ 131,822 $ 447,170 $ 107,744 Service cost ........................................ 18,114 4,357 16,256 2,609 Interest cost ....................................... 33,027 10,418 35,387 8,354 Participant contributions ........................... -- 3,059 74 2,395 Plan amendments ..................................... 652 -- (132) -- Actuarial (gain) loss ............................... 17,333 57,101 6,007 20,589 Benefits paid ....................................... (23,267) (11,840) (32,413) (9,869) --------- ---------- ---------- --------- Benefit obligation at end of year .................. 518,208 194,917 472,349 131,822 --------- ---------- ---------- --------- Reconciliation of the fair value of plan assets: Fair value of plan assets at beginning of year ...... 555,208 75,090 605,059 72,622 Employer contributions .............................. 4,576 16,022 4,355 10,543 Participant contributions ........................... -- 3,059 74 2,395 Actual return on plan assets ........................ (20,627) (1,202) (21,867) (601) Benefits paid ....................................... (23,267) (11,840) (32,413) (9,869) --------- ---------- ---------- --------- Fair value of plan assets at end of year ........... 515,890 81,129 555,208 75,090 --------- ---------- ---------- --------- Funded status ....................................... (2,318) (113,788) 82,859 (56,732) Unrecognized net (gain) loss ........................ (52,244) 63,328 (130,423) 1,326 Unrecognized prior service cost ..................... 22,885 4,264 24,962 4,689 Unrecognized net transition obligation (asset) ...... (5,974) 45,212 (8,566) 49,322 --------- ---------- ---------- --------- Net amount recognized in the consolidated balance sheet .................................... $ (37,651) $ (984) $ (31,168) $ (1,395) ========= ========== ========== ========= Amounts recognized in the consolidated balance sheet consist of: Prepaid benefit cost ................................ $ 15,381 $ 1,493 $ 16,773 $ 1,493 Accrued benefit liability ........................... (88,210) (2,477) (77,538) (2,888) Intangible asset .................................... 22,796 -- 25,510 -- Accumulated other comprehensive income .............. 12,382 -- 4,087 -- --------- ---------- ---------- --------- Net amount recognized .............................. $ (37,651) $ (984) $ (31,168) $ (1,395) ========= ========== ========== =========
PENSION AND POSTRETIREMENT ASSUMPTIONS --------------------------------------------- MEHC (PREDECESSOR) ------------------- 2001 2000 1999 ---------- ---------- ------------------- Assumptions used were: Discount rate .............................................. 6.50% 7.00% 7.75% Rate of increase in compensation levels .................... 5.00% 5.00% 5.00% Weighted average expected long-term rate of return on assets 7.00% 9.00% 9.00%
For purposes of calculating the postretirement benefit obligation, it is assumed health care costs for all covered individuals will increase by 11.25% in 2002 and that the rate of increase thereafter will decrease to an ultimate rate of 5.25% by the year 2006. If the assumed health care trend rates used to measure the expected cost of benefits covered by the plans were increased by 1.0%, the total service and interest cost for 2001 would increase by $3.0 million, and the postretirement benefit obligation at December 31, 2001, would increase by $30.6 million. If the assumed health care trend rates were to decrease by 1.0%, the total service and interest cost for 2001 would decrease by $2.3 million and the postretirement benefit obligation at December 31, 2001, would decrease by $24.2 million. F-56 20. COMMITMENTS AND CONTINGENCIES A. FINANCIAL CONDITION OF EDISON Southern California Edison Company ("Edison"), a wholly-owned subsidiary of Edison International, is a public utility primarily engaged in the business of supplying electric energy to retail customers in Central and Southern California, excluding Los Angeles. The Company is aware that there have been public announcements that Edison's financial condition has deteriorated as a result of reduced liquidity. Following Edison's recent financing, Edison's senior unsecured debt obligations were upgraded to Ba3 by Moody's and BB by S&P. Edison failed to pay approximately $119 million due under the power purchase agreement with CE Generation affiliates for power delivered in November and December 2000 and January, February and March 2001, although the Power Purchase Agreements provide for billing and payment on a schedule where payments would have normally been received in early January, February, March, April and May 2001. On February 21, 2001, the Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) filed a lawsuit against Edison in California's Imperial County Superior Court seeking a court order requiring Edison to make the required payments under the Power Purchase Agreements. The lawsuit also requested, among other things, that the court order permit the Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) to suspend deliveries of power to Edison and to permit the Imperial Valley Projects to sell such power to other purchasers in California. On March 22, 2001, the Imperial County Superior Court granted the Imperial Valley Projects' (excluding the Salton Sea V and Turbo Projects) Motion for Summary Adjudication and a Declaratory Judgment ordering that: 1) under the Power Purchase Agreements, the Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) have the right to temporarily suspend deliveries of capacity and energy to Edison, 2) such Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) are entitled to resell the energy and capacity to other purchasers and 3) the interim suspension of deliveries to Edison shall not in any respect result in the modifications or termination of the Power Purchase Agreements, and the Power Purchase Agreements shall in all respects continue in full force and effect other than the temporary suspension of deliveries to Edison. As a result of the March 22, 2001 Declaratory Judgment, the Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) suspended deliveries of energy to Edison and entered into a transaction agreement with El Paso Merchant Energy, L.P. ("EPME") in which the Imperial Valley Projects' (excluding the Salton Sea V and Turbo Projects) available power was sold to EPME based on percentages of the Dow Jones SP-15 Index. On June 18, 2001 the Superior Court prospectively vacated its order authorizing the Imperial Valley Projects' (excluding the Salton Sea V and Turbo Projects) right to resell power pursuant to the Declaratory Judgment. On June 20, 2001, the Imperial Valley Projects (excluding Salton Sea Unit V and CE Turbo) entered into Agreements Addressing Renewable Energy Pricing and Payment Issues with Edison ("Settlement Agreements") and, as a result, resumed power sales to Edison on June 22, 2001. The Settlement Agreements required that Edison make an initial payment to repay the past due balances under the Power Purchase Agreements (the "stipulated amounts"). The initial payment of approximately $11.6 million, which represented 10% of the stipulated amounts, was received June 22, 2001. On October 2, 2001, the California Public Utilities Commission announced an agreement with Edison that allowed Edison to recover in retail electric rates its past due obligations. On November 30, 2001, the Settlement Agreements were amended to reflect when Edison would be required to make the final payment on past due amounts. On March 1, 2002, Edison obtained $1.8 billion in secured financing that, when combined with cash on hand, enabled Edison to pay off its past due debts. The final payment of approximately $104.6 million, representing the remaining stipulated amounts, was received March 1, 2002. In addition to these payments, Edison was required to make monthly interest payments calculated at a rate of 7% per annum on the outstanding stipulated amounts. The amended Settlement Agreements provide a revised energy pricing structure, whereby Edison elects to pay the Imperial Valley Projects a fixed energy price in lieu F-57 of the Commission-approved Avoided Cost of Energy Methodology under the Power Purchase Agreements. The fixed energy price is 3.25 cents/kWh from December 2001 through April 30, 2002 and 5.37 cents/kWh commencing May 1, 2002 for a five year period. Following the five year period, the energy payments revert back to the Commission-approved Avoided Cost of Energy Methodology under the Power Purchase Agreements. Estimates of Edison's future Avoided Cost of Energy vary substantially from year to year. As a result of Edison's failure to make the payments due under the Power Purchase Agreements and the downgrades of Edison's credit rating, Moody's downgraded the ratings for the Salton Sea Funding Corporation (the "Funding Corporation") Securities to Caa2 (negative outlook) and S&P downgraded the ratings for the Funding Corporation Securities to BBB- and placed the Securities on "credit watch negative." Moody's downgraded the ratings for the CE Generation Securities to B1 from Baa3 (review for possible downgrade). Following the execution of the Settlement Agreements, Moody's placed the Salton Sea Funding and CE Generation securities on "credit watch positive." The Funding Corporation Securities are currently rated Ba3 by Moody's and BBB- by S&P. CE Generation Securities are currently Ba2 by Moody's and BBB- by S&P. B. CASECNAN The Casecnan Project was initially being constructed pursuant to a fixed-price, date-certain, turnkey construction contract (the "Hanbo Contract") on a joint and several basis by Hanbo Corporation ("Hanbo") and Hanbo Engineering and Construction Co., Ltd. ("HECC"), both of which are South Korean corporations. As of May 7, 1997, the Company terminated the Hanbo Contract due to defaults by Hanbo and HECC including the insolvency of both companies. On the same date, the Company entered into a new fixed-price, date certain, turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Replacement Contract"). The work under the Replacement Contract is being conducted by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa., working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. (collectively, the "Contractor"). On November 20, 1999, the Replacement Contract was amended to extend the Guaranteed Substantial Completion Date for the Casecnan Project to March 31, 2001. This amendment was approved by the lender's independent engineer under the Casecnan Indenture. On February 12, 2001, the Contractor filed a Request for Arbitration with the International Chamber of Commerce seeking an extension of the Guaranteed Substantial Completion Date by up to 153 days through August 31, 2001 resulting from various alleged force majeure events. In a March 20, 2001 Supplement to Request for Arbitration, the Contractor also seeks compensation for alleged additional costs of approximately $4 million it incurred from the claimed force majeure events to the extent it is unable to recover from its insurer. On April 20, 2001, the Contractor filed a further supplement seeking an additional approximately $62 million in damages for the alleged force majeure event (and geologic conditions) related to the collapse of the surge shaft. The Contractor alleged that the circumstances surrounding the placing of the Casecnan Project into commercial operation on December 11, 2001 amounted to a termination of the Replacement Contract and filed a claim for unspecified quantum meruit damages. CE Casecnan believes such allegations and claims are without merit and is vigorously defending the Contractor's claims. The arbitration is being conducted applying New York law and pursuant to the rules of the International Chamber of Commerce. On June 25, 2001, the arbitration tribunal temporarily enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di Roma in support of the Contractor's obligations to CE Casecnan for delay liquidated damages. Hearings on the force majeure claims were held in London from July 2 to 14, 2001, and hearings on the Contractor's April 20, 2001 supplement were held in London from September 24 to October 3, 2001. Further hearings were held from January 2 to February 1, 2002 and additional hearings were held from March 14 to 19, 2002. As of December 31, 2001 the Company has received approximately $6.0 million of liquidated damages from demands made or the demand guarantees posted by Commerzbank on behalf of the Contractor. F-58 Although the outcome of the arbitration is difficult to assess, CE Casecnan believes it will prevail and receive substantial additional liquidated damages in the arbitration. Under the Project Agreement, if NIA is able to accept delivery of water into the Pantabangan Reservoir and NPC has completed the Project's related transmission line, the Company is liable to pay NIA $5,500 per day for each day of delay in completion of the Casecnan Project beyond July 27, 2000, increasing to $13,500 per day for each day of delay in completion beyond November 27, 2000. NIA completed the installation of the transmission line on August 13, 2001. Accordingly, the Company accrued $1.6 million liquidated damages payable to NIA for 120 days of delay. The Company's ability to make payments on any of its existing and future obligations is dependent on NIA's and the Republic of the Philippines' performance of their obligations under the Project Agreement and the Performance Undertaking, respectively. Except to the extent expressly provided for in the Shareholder Support Letters, no shareholders, partners or affiliates of the Company, including MidAmerican, and no directors, officers or employees of the Company will guarantee or be in any way liable for payment of the Company's obligations. As a result, payment of the Company's obligations depends upon the availability of sufficient revenues from the Company's business after the payment of operating expenses. C. DECOMMISSIONING COSTS Expected decommissioning costs for Quad Cities Station and Cooper have been developed based on site-specific decommissioning studies that include decontamination, dismantling, site restoration, dry fuel storage cost and assumed shutdown dates. In Illinois, Cooper nuclear decommissioning costs are recovered through a rate rider on customer billings that permits annual adjustments. Quad Cities Station and Cooper decommissioning costs are reflected as base rates in Iowa tariffs. MidAmerican Energy's share of expected decommissioning costs for Quad Cities Station, in 2001 dollars, is $278 million. MidAmerican Energy has established external trusts for the investment of funds for decommissioning the Quad Cities Station. The total accrued balance as of December 31, 2001, was $158.3 million and is included in other long-term accrued liabilities, and a like amount is reflected in Investments and represents the fair value of the assets held in the trusts. MidAmerican Energy's depreciation expense included costs for Quad Cities Station nuclear decommissioning of $8.3 million, $8.3 million, and $10.4 million for 2001, 2000 and 1999, respectively. The provision charged to depreciation expense is equal to the funding that is being collected in rates. The decommissioning funding component of MidAmerican Energy's Illinois and Iowa tariffs assumes decommissioning costs, related to the Quad Cities Station, will escalate at an annual rate of 4.5% and the assumed annual return on funds in the trust is 6.9%. Realized income (loss), net of investment fees, on the assets in the trust fund was $(0.6) million, $1.9 million and $1.9 million for 2001, 2000 and 1999, respectively. MidAmerican Energy's contribution toward payment of Cooper's projected decommissioning costs have been based on the NPPD decommissioning funding plan for Cooper. Total expected decommissioning costs for Cooper, in 2001 dollars, are $577 million. For purposes of developing a decommissioning funding plan for Cooper, the NPPD assumes that decommissioning costs will escalate at an annual rate of 4.0%. Although Cooper's operating license expires in 2014, the funding plan assumes decommissioning will start in 2004, the anticipated plant shutdown date. As of December 31, 2001, total funds set aside in the internal and external accounts for Cooper decommissioning that are maintained by the NPPD were $291.3 million. In addition, the funding plan for Cooper also assumes various funds and reserves currently held to satisfy the NPPD bond resolution requirements will be available for plant decommissioning, which is to begin with the assumed plant shutdown in September 2004. The funding schedule assumes a long-term return on funds in the trust of 6.75% annually. Certain funds will be required to be invested on a short-term basis when decommissioning begins and are assumed to earn at a rate of 4.0% annually. Earnings from the internal account and external trust fund, which are recognized by the NPPD as the owner of the plant, are tax exempt and serve to reduce future funding requirements. F-59 Beginning in December 2000, MidAmerican Energy ceased contributing to the accounts maintained by NPPD and began contributing funds to a separate MidAmerican Energy bank account based on the NPPD decommissioning funding plan for Cooper. A liability equal to the amount of funds contributed, plus the earnings on those funds, is reflected in other long-term accrued liabilities on the consolidated balance sheets. MidAmerican Energy records expense equal to the funds contributed to the separate account plus investment fees paid to the NPPD for funds in the accounts they maintain. MidAmerican Energy's expense for Cooper decommissioning was $11.6 million, $11.5 million and $11.3 million for the years 2001, 2000 and 1999, respectively, and is included in other operating expenses. MidAmerican Energy is currently involved in litigation with NPPD in part related to the determination of MidAmerican Energy's obligation, if any, for costs of decommissioning Cooper. Refer to Note (20)(E) for a discussion of the proceedings. D. NUCLEAR INSURANCE MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station and Cooper through a combination of insurance purchased by NPPD (the owner and operator of Cooper) and Exelon Generation Company, LLC (the operator and joint owner of Quad Cities Station), insurance purchased directly by MidAmerican Energy, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988. The general types of coverage are: nuclear liability, property coverage and nuclear worker liability. NPPD and Exelon Generation each purchase nuclear liability insurance for Cooper and Quad Cities Station, respectively, in the maximum available amount of $200 million. In accordance with the Price-Anderson Amendments Act of 1988, excess liability protection above the amount is provided by a mandatory industry-wide program under which the licensees of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the United States. Currently, MidAmerican Energy's aggregate maximum potential share of an assessment for Cooper and Quad Cities Station combined is $88.1 million per incident, payable in installments not to exceed $10 million annually. The property coverage provides for property damage, stabilization and decontamination of the facility, disposal of the decontaminated material and premature decommissioning. For Quad Cities Station, Exelon Generation purchases primary and excess property insurance protection for the combined interests in Quad Cities Station, with coverage limits totaling $2.1 billion. For Cooper, MidAmerican Energy and NPPD separately purchase primary and excess property insurance protection for their respective obligations, with coverage limits of $1.375 billion each. This structure provides that both MidAmerican Energy and NPPD are covered for their respective 50% obligation in the event of a loss totaling up to $2.75 billion. MidAmerican Energy also directly purchases extra expense/business interruption coverage for its share of replacement power and/or other extra expenses in the event of a covered accidental outage at Cooper or Quad Cities Station. The coverages purchased directly by MidAmerican Energy, and the property coverages purchased by Exelon Generation, which includes the interests of MidAmerican Energy, are underwritten by an industry mutual insurance company and contain provisions for retrospective premium assessments should two or more full policy-limit losses occur in one policy year. Currently, the maximum retrospective amounts that could be assessed against MidAmerican Energy from industry mutual policies for its obligations associated with Cooper and Quad Cities Station combined, total $20.5 million. The master nuclear worker liability coverage, which is purchased by NPPD and Exelon Generation for Cooper and Quad Cities Station, respectively, is an industry-wide guaranteed-cost policy with an aggregate limit of $200 million for the nuclear industry as a whole, which is in effect to cover tort claims in nuclear-related industries. E. COOPER LITIGATION On July 23, 1997, the Nebraska Public Power District ("NPPD") filed a complaint, in the United States District Court for the District of Nebraska, naming MidAmerican Energy as the defendant and seeking F-60 declaratory judgment as to three issues under the parties' long-term power purchase agreement for Cooper capacity and energy. More specifically, the NPPD sought a declaratory judgment in the following respects: (1) that MidAmerican Energy is obligated to pay 50% of all costs and expenses associated with decommissioning Cooper, and that in the event NPPD continues to operate Cooper after expiration of the power purchase agreement (September 2004), MidAmerican Energy is not entitled to reimbursement of any decommissioning funds it has paid to date or will pay in the future; (2) that the current method of allocating transition costs as a part of the decommissioning cost is proper under the power purchase agreement; and (3) that the current method of investing decommissioning funds is proper under the power purchase agreement. MidAmerican Energy filed its answer and counterclaims. The counterclaims filed by MidAmerican Energy are generally as follows: (1) that MidAmerican Energy has no duty under the power purchase agreement to reimburse or pay 50% of the decommissioning costs unless conditions to reimbursement occur; (2) that the term "monthly power costs" as defined in the power purchase agreement does not include costs and expenses associated with decommissioning the plant; (3) that NPPD violated MidAmerican Energy's directions for application of payments; (4) that transition costs are not included in any decommissioning costs and are not any kind of costs that MidAmerican Energy is obligated to pay; (5) that NPPD has the duty to repay all amounts that MidAmerican Energy has prefunded for decommissioning in the event the Nebraska Public Power District operates the plant after the term of the power purchase agreement; (6) that NPPD is equitably estopped from continuing to operate the plant after the term of the power purchase agreement so long as NPPD does not repay all amounts MidAmerican Energy has prefunded for estimated decommissioning costs together with other amounts in certain funds and accounts and for so long as NPPD fails to provide MidAmerican Energy with certain requested accountings and information; (7) that certain funds, accounts, and reserves are excessive and are required to be paid to MidAmerican Energy or credited to MidAmerican Energy's pre-2004 monthly power costs; (8) that MidAmerican Energy has no duty to pay for nuclear fuel, operations and maintenance projects or capital improvements that have useful lives after the term of the power purchase agreement; (9) that NPPD has mismanaged the plant in numerous described transactions resulting in damage to MidAmerican Energy; (10) that NPPD has breached its contractual and other duties to MidAmerican Energy by not joining certain litigation and by failing to credit or agree to credit MidAmerican Energy with any recovery for low-level radioactive waste; and (11) that NPPD has breached its duty to MidAmerican Energy in making investments of decommissioning funds; On October 6, 1999, the court rendered summary judgment for NPPD on the above-mentioned issue concerning liability for decommissioning (issue one in the first paragraph above) and the related contingent counterclaims filed by MidAmerican Energy (issues one and two in the second paragraph above). The court referred all remaining issues in the case to mediation, and cancelled the November 1999 trial date. F-61 MidAmerican Energy appealed the court's summary judgment ruling. On December 12, 2000, the United States Court of Appeals for the Eighth Circuit reversed the ruling of the district court and granted summary judgment in favor of MidAmerican Energy on issues one and five in the second paragraph above. Additionally, it remanded the case for trial on all other claims and counterclaims. Since the remand to the District Court from the Eighth Circuit Court of Appeals, NPPD has been granted permission, over MidAmerican Energy's objections, to file a second amended complaint. The second amended complaint asserts that even though the Eighth Circuit Court of Appeals held that MidAmerican Energy has no liability under the power purchase agreement to reimburse or pay NPPD a 50% share of decommissioning costs unless certain conditions occur, MidAmerican Energy has unconditional liability for a 50% share based on agreements other than the power purchase agreement as originally written. NPPD's post-remand contentions - all strongly disputed by MEC - are that MidAmerican Energy has unconditional liability for a 50% share of decommissioning based on any of the following alternative theories: (i) the parties without written amendment either modified the power purchase agreement or made a separate agreement that imposes unconditional liability on MidAmerican Energy for decommissioning costs; (ii) absent unconditional liability for a 50% share of decommissioning costs, MidAmerican Energy would be unjustly enriched; (iii) MidAmerican Energy has unconditional liability for a 50% share of decommissioning costs based on promissory estoppel; or (iv) NPPD is entitled to have the power purchase agreement reformed to provide that MidAmerican Energy has unconditional liability for a 50% share of decommissioning costs. In response to NPPD's second amended complaint, MidAmerican Energy filed its first amended answer and third amended counterclaims containing denials, several affirmative defenses, and the counterclaims summarized above. In the course of discovery, NPPD has contended that MidAmerican Energy has some responsibility for some costs of storage of spent fuel resulting from the operation of the plant during the term of the power purchase agreement. MidAmerican Energy disputes this. MidAmerican Energy recently filed a mandamus petition with Eighth Circuit Court of Appeals seeking an order of that court directing the District Court not to permit NPPD to pursue the above alternative theories at trial, since the above alternative theories appear to be contrary to the December 12, 2000 Eighth Circuit Court of Appeals decision. If such relief is not granted, MidAmerican Energy will strongly dispute at trial these contentions and theories put forth by NPPD. Trial in these matters has been recently rescheduled to being on September 9, 2002. F. COAL AND NATURAL GAS CONTRACT COMMITMENTS MidAmerican Energy has supply and related transportation contracts for its fossil fueled generating stations. The contracts, with expiration dates ranging from 2002 to 2007, require minimum payments of $80.3 million, $70.6 million, $36.2 million, $34.0 million and $2.6 million for the years 2002 through 2006, respectively, and $2.6 million for the total of the years thereafter. MidAmerican Energy expects to supplement these coal contracts with additional contracts and spot market purchases to fulfill its future fossil fuel needs. MidAmerican Energy has contracts with various companies to purchase electric capacity. The contracts, with expiration dates ranging from 2002 to 2011, require minimum payments of $27.0 million, $30.5 million, $15.3 million, $2.9 million and $2.2 million for the years 2002 through 2006, respectively, and $11.0 million for the total of the years thereafter. MidAmerican Energy has various natural gas supply and transportation contracts for its gas operations. The minimum commitments under these contracts are $56.6 million, $41.3 million, $13.4 million, $13.2 million and $13.0 million for the years 2002 through 2006, respectively, and $26.7 million for the total of the years thereafter. 21. SUBSEQUENT EVENTS Debt issuance On February 8, 2002, MidAmerican Energy issued $400 million of 6.75% medium-term notes due in 2031. The proceeds will be used to refinance existing debt and preferred securities and for other corporate purposes. On March 11, 2002, MidAmerican Energy redeemed its MidAmerican-obligated mandatorily redeemable preferred securities of subsidiary trust at 100% of the principal amount plus accrued interest. F-62 Prudential California Acquisition In February 2002, HomeServices completed its purchase of a majority interest in Prudential California Realty. The cash purchase price of Prudential California Realty was approximately $74 million, with an option to purchase the remaining interests. Additionally, HomeServices is obligated to pay a maximum earnout of $18.5 million calculated based on certain 2002 financial performance measures. The purchase price was financed using the Company's corporate revolver for $40 million which was contributed to HomeServices as equity and the remaining funds were borrowed from available credit under the HomeServices's $65 million revolving credit facility. It is anticipated that the borrowings in connection with this acquisition will be repaid from HomeServices generated funds. The acquisition will be accounted for by the purchase method of accounting, and the Company is in the process of completing the allocation of the purchase price to the assets acquired and liabilities assumed. Kern River Acquisition On March 7, 2002, the Company reached a definitive agreement with The Williams Companies, Inc. ("Williams") to acquire Williams' Kern River Gas Transmission Company, a 926-mile interstate pipeline transporting Rocky Mountain and Canadian natural gas to markets in California, Nevada and Utah. The purchase price was $956 million, including $506 million of assumed debt. As part of the agreement, the Company will continue the planned expansion of the Kern River system, a project that will more than double the pipeline's capacity with expected capital expenditures of approximately $1.2 billion. The purchase was completed on March 27, 2002. The Kern River pipeline is an important route for the transmission of natural gas from the vast reserves in the Rocky Mountain states to the rapidly growing markets in Utah, Nevada and California. Constructed in 1992, Kern River extends 926 miles from Opal, Wyoming, to the San Joaquin Valley near Bakersfield, California, and has a design capacity of 835 million cubic feet per day. In August 2001, Williams filed with FERC to more than double the capacity on the Kern River system by adding approximately 900 million cubic feet per day of additional capacity from Wyoming to California and markets in between. Upon completion of the expansion project in May 2003, Kern River will be capable of transporting 1.7 billion cubic feet of natural gas per day. When converted to electricity, that is enough energy to power approximately 10 million homes. In connection with the acquisition of Kern River, the Company issued $323 million of Trust Preferred Securities and $127 million of convertible preferred stock to Berkshire Hathaway. In addition to the acquisition of Kern River, the Company also announced its investment of $275 million in Williams, in exchange for shares of 97/8 percent cumulative convertible preferred stock of Williams. In connection with this investment, the Company issued $275 million of convertible preferred stock to Berkshire Hathaway. 22. SEGMENT INFORMATION: The Company has identified five reportable operating segments principally based on management structure: CalEnergy Generation -- Domestic, CalEnergy Generation -- Foreign (primarily the Philippines), MidAmerican Energy (domestic utility operations), CE Electric UK Funding (foreign utility operations) and HomeServices (real estate operations). Information related to the Company's reportable operating segments are shown below (in thousands). F-63
MEHC (PREDECESSOR) ----------------------------------- MARCH 14, 2000 JANUARY 1, 2000 YEAR ENDED THROUGH THROUGH YEAR ENDED DECEMBER 31, 2001 DECEMBER 31, 2000 MARCH 13, 2000 DECEMBER 31, 1999 ------------------- ------------------- ---------------- ------------------ REVENUE: (1) CalEnergy Generation -- Domestic $ 75,541 $ 40,031 $ 4,520 $ 105,869 CalEnergy Generation -- Foreign ..... 207,386 156,504 42,726 210,571 MidAmerican Energy .................. 2,795,838 2,132,273 491,636 1,525,157 CE Electric UK Funding .............. 1,458,979 1,517,539 499,017 2,098,976 HomeServices ........................ 644,741 405,805 66,880 357,728 ---------- ---------- ---------- ---------- Segment revenue ..................... 5,182,485 4,252,152 1,104,779 4,298,301 Corporate/other ..................... (25,174) (9,403) 1,830 29,420 ---------- ---------- ---------- ---------- $5,157,311 $4,242,749 $1,106,609 $4,327,721 ========== ========== ========== ========== DEPRECIATION AND AMORTIZATION: CalEnergy Generation -- Domestic $ 5,439 $ 2,183 $ 250 $ 14,478 CalEnergy Generation -- Foreign ..... 66,315 52,685 13,514 66,063 MidAmerican Energy .................. 286,590 184,955 45,184 182,638 CE Electric UK Funding .............. 125,564 108,637 31,964 137,963 HomeServices ........................ 17,201 8,695 2,891 7,772 ---------- ---------- ---------- ---------- Segment depreciation ................ 501,109 357,155 93,803 408,914 Corporate/other ..................... 37,593 26,196 3,475 18,776 ---------- ---------- ---------- ---------- $ 538,702 $ 383,351 $ 97,278 $ 427,690 ========== ========== ========== ========== INTEREST EXPENSE, NET: CalEnergy Generation -- Domestic $ 10,835 $ 1,829 $ 793 $ 17,851 CalEnergy Generation -- Foreign ..... 30,875 34,458 9,713 58,322 MidAmerican Energy .................. 113,980 94,425 24,579 100,046 CE Electric UK Funding .............. 112,308 74,335 21,189 96,759 HomeServices ........................ 3,884 2,328 785 3,228 ---------- ---------- ---------- ---------- Segment interest expense, net ....... 271,882 207,375 57,059 276,206 Corporate/other ..................... 140,912 104,029 28,755 149,967 ---------- ---------- ---------- ---------- $ 412,794 $ 311,404 $ 85,814 $ 426,173 ========== ========== ========== ========== INCOME BEFORE PROVISIONS FOR INCOME TAXES: (1) CalEnergy Generation -- Domestic $ 44,335 $ 30,697 $ 2,877 $ 49,095 CalEnergy Generation -- Foreign ..... 89,542 49,787 15,976 68,105 MidAmerican Energy .................. 210,733 181,797 63,315 151,555 CE Electric UK Funding .............. 159,850 83,108 58,673 152,126 HomeServices ........................ 42,945 31,015 (4,929) 16,613 ---------- ---------- ---------- ---------- Segment income ...................... 547,405 376,404 135,912 437,494 Corporate/other ..................... (223,014) (157,200) (37,137) (164,720) ---------- ---------- ---------- ---------- $ 324,391 $ 219,204 $ 98,775 $ 272,774 ========== ========== ========== ==========
F-64
MEHC (PREDECESSOR) ----------------------------------- MARCH 14, 2000 JANUARY 1, 2000 YEAR ENDED THROUGH THROUGH YEAR ENDED DECEMBER 31, 2001 DECEMBER 31, 2000 MARCH 13, 2000 DECEMBER 31, 1999 ------------------- ------------------- ---------------- ------------------ PROVISIONS FOR INCOME TAXES: (1) CalEnergy Generation -- Domestic $ (689) $ (1,929) $ (8) $ 6,347 CalEnergy Generation -- Foreign ..... 27,962 29,194 373 33,912 MidAmerican Energy .................. 95,490 77,450 27,943 64,936 CE Electric UK Funding .............. 47,866 30,065 18,761 59,183 HomeServices ........................ 15,953 12,300 (1,992) 7,193 ---------- --------- --------- --------- Segment income ...................... 186,582 147,080 45,077 171,571 Corporate/other ..................... (100,314) (93,803) (14,069) (80,835) ---------- --------- --------- --------- $ 86,268 $ 53,277 $ 31,008 $ 90,736 ========== ========= ========= ========= CAPITAL EXPENDITURES: CalEnergy Generation -- Domestic $ 52,940 $ 151,289 $ 53,011 $ 145,255 CalEnergy Generation -- Foreign ..... 83,954 87,781 22,263 95,552 MidAmerican Energy .................. 252,615 194,045 23,977 194,216 CE Electric UK Funding .............. 176,464 95,806 22,210 231,634 HomeServices ........................ 9,878 6,996 2,052 9,143 ---------- --------- --------- --------- Segment capital expenditures ........ 575,851 535,917 123,513 675,800 Corporate/other ..................... 901 2,812 28 120 ---------- --------- --------- --------- $ 576,752 $ 538,729 $ 123,541 $ 675,920 ========== ========= ========= =========
---------- (1) Before non-recurring items
AS OF DECEMBER 31, MEHC (PREDECESSOR) ------------------------------ AS OF DECEMBER 31, 2001 2000 1999 ------------- -------------- ------------------- TOTAL ASSETS: CalEnergy Generation -- Domestic ......... $ 725,716 $ 663,125 $ 538,598 CalEnergy Generation -- Foreign .......... 925,825 965,913 1,115,661 MidAmerican Energy ....................... 5,023,584 5,324,921 5,072,788 CE Electric UK Funding ................... 3,973,457 2,414,394 2,953,288 HomeServices ............................. 226,588 169,470 166,658 ----------- ----------- ----------- Segment assets ........................... 10,875,170 9,537,823 $ 9,846,993 =========== Corporate/other .......................... 1,740,163 2,073,116 ----------- ----------- $12,615,333 $11,610,939 =========== =========== LONG-LIVED ASSETS: CalEnergy Generation -- Domestic ......... $ 441,603 $ 434,523 $ 222,357 CalEnergy Generation -- Foreign .......... 802,092 790,077 809,506 MidAmerican .............................. 4,050,285 4,079,250 3,995,763 CE Electric UK Funding ................... 3,302,560 1,884,951 2,438,877 HomeServices ............................. 165,689 125,894 129,649 ----------- ----------- ----------- Segment long-lived assets ................ 8,762,229 7,314,695 $ 7,596,152 =========== Corporate ................................ 1,404,307 1,707,102 ----------- ----------- $10,166,536 $ 9,021,797 =========== ===========
The remaining differences from the segment amounts to the consolidated amounts described as "Corporate" relate principally to the corporate functions including administrative costs, corporate cash and related interest income, intersegment eliminations, unallocated goodwill and fair value adjustments relating to acquisitions. F-65 23. EXCESS OF COST OVER FAIR VALUE OF NET ASSETS ACQUIRED: On January 1, 2002, the Company adopted Statement of Financial Accounting Standards ("SFAS ") No. 142, "Goodwill and Other Intangible Assets," which establishes the accounting for acquired goodwill and other intangible assets. SFAS No. 142 requires that amortization of goodwill and indefinite-lived intangible assets be discontinued and that entities disclose net income for prior periods adjusted to exclude such amortization and related income tax effects, as well as a reconciliation from the originally reported net income to the adjusted net income. The Company's related amortization consists of goodwill amortization and the related income tax effect. Following is a reconciliation of net income as originally reported for the year ended December 31, 2001, the period March 14, 2000 through December 31, 2000, the period January 1, 2000 through March 13, 2000, and the year ended December 31, 1999,to adjusted net income (in thousands):
MEHC (PREDECESSOR) --------------------------- MARCH 14, JANUARY 1, 2000 2000 YEAR ENDED THROUGH THROUGH YEAR ENDED DECEMBER 31, DECEMBER 31, MARCH 13, DECEMBER 31, 2001 2000 2000 1999 -------------- -------------- ----------- ------------- Net income as originally reported ......... $142,669 $ 81,257 $51,312 $167,230 Goodwill amortization ..................... 96,418 79,997 14,181 63,953 Income tax benefit ........................ (2,018) (1,433) (352) (1,685) -------- -------- ------- -------- Net income as adjusted .................... $237,069 $159,821 $65,141 $229,498 ======== ======== ======= ========
F-66 DEALER PROSPECTUS DELIVERY OBLIGATION Until March 20, 2003, all dealers that effect transactions in these securities, whether or not participating in the offering, may be required to deliver a prospectus. This is in addition to the dealer's obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions. [GRAPHIC OMITTED] All tendered original notes, executed letters of transmittal, and other related documents should be directed to the exchange agent. Requests for assistance and for additional copies of this prospectus, the letter of transmittal and other related documents should be directed to the exchange agent. EXCHANGE AGENT: THE BANK OF NEW YORK By Facsimile: (212) 298-1915 Confirm by telephone: (212) 815-5920 By Mail, Hand or Courier: The Bank of New York Corporate Trust Department Reorganization Unit 101 Barclay Street Floor 7 East New York, New York 10286 PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS. Insofar as indemnification for liabilities arising under the Securities Act may be permitted to the Registrant's directors and officers pursuant to the following provisions or otherwise, the Registrant has been advised that, although the validity and scope of the governing statute have not been tested in court, in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In addition, indemnification may be limited by state securities laws. Sections 490.850 through 490.858 of the Iowa Business Corporation Act (the "IBCA") permit corporations organized thereunder to indemnify directors, officers, employees and agents against liability under certain circumstances. Section 490.851 of the IBCA provides that a corporation may indemnify its officers and directors if (i) the person acted in good faith, and (ii) the person reasonably believed, in the case of conduct in the person's official capacity with the corporation, that the conduct was in the corporation's best interests, and in all other cases, that the person's conduct was at least not opposed to the corporation's best interests, and (iii) in the case of any criminal proceeding, the person had no reasonable cause to believe the person's conduct was unlawful. The Registrant's Amended and Restated Articles of Incorporation and Bylaws provide that the Registrant shall indemnify, to the fullest extent permitted by the IBCA, its directors, officers, employees and agents, (2) any person serving as the legal representative of a director, officer, employee or agent, and (3) any person who is or was serving at the request of the Registrant as director, officer or employee of another corporation, joint venture, partnership, trust or other venture. Such indemnification is provided by the Registrant to such persons for all reasonable expenses, liability and loss incurred in connection with any civil, criminal, administrative or investigative proceeding, formal or informal, to which the person is, or is threatened to be made a party, whether the basis of such proceeding is alleged action in an official capacity or any other capacity while serving as director, officer, or employee. The Registrant's Amended and Restated Articles of Incorporation and Bylaws provides that if the proceeding for which indemnification is sought is by or in the right of the Registrant, indemnification may be made only for reasonable expenses and may not be made in any proceeding in which the person is adjudged liable to the Registrant. Further, any such person may not be indemnified in any proceeding that charges improper personal benefit to the person in which the person is adjudged to be liable. The Registrant's Amended and Restated Articles of Incorporation and Bylaws allow the Registrant to maintain liability insurance to protect itself and any director, officer, employee, or agent against any expense, liability or loss whether or not the Registrant would have the power to indemnify such person against such incurred expense, liability, or loss. The Registrant has also entered into indemnification agreements with certain directors and officers, and expects to enter into similar agreements with future directors and officers, to further assure such persons' indemnification as permitted by Iowa law. The rights to indemnification conferred on any person by the Registrant's Amended and Restated Articles of Incorporation and Bylaws are not exclusive of any right which any person may have or acquire under any statute, provision of the Registrant's Amended and Restated Articles of Incorporation, Bylaws, agreement, or vote of shareholders or disinterested directors. II-1 ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. (a) Exhibits
EXHIBIT NO. DESCRIPTION ------------- -------------------------------------------------------------------------------------------- 3.1 Amended and Restated Articles of Incorporation of the Company effective March 6, 2002. (incorporated by reference to Exhibit 3.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001). 3.2 Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 4.1 Indenture, dated as of October 4, 2002, by and between the Company and The Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012.* 4.2 First Supplemental Indenture, dated as of October 4, 2002, by and between the Company and The Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012.* 4.3 Registration Rights Agreement, dated as of October 1, 2002, by and between the Company and Credit Suisse First Boston (as Representative for the Initial Purchasers).* 4.4 Indenture for the 6 1/4% Convertible Junior Subordinated Debentures due 2012, dated as of February 26, 1997, between the Company, as issuer, and the Bank of New York, as Trustee (incorporated by reference to Exhibit 10.129 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 4.5 Indenture, dated as of October 15, 1997, among the Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K dated October 23, 1997). 4.6 Form of First Supplemental Indenture for the 7.63% Senior Notes in the principal amount of $350,000,000 due 2007, dated as of October 28, 1997, among the Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K dated October 23, 1997). 4.7 Form of Second Supplemental Indenture for the 6.96% Senior Notes in the principal amount of $215,000,000 due 2003, 7.23% Senior Notes in the principal amount of $260,000,000 due 2005, 7.52% Senior Notes in the principal amount of $450,000,000 due 2008, and 8.48% Senior Notes in the principal amount of $475,000,000 due 2028, dated as of September 22, 1998 between the Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K dated September 17, 1998.) 4.8 Form of Third Supplemental Indenture for the 7.52% Senior Notes in the principal amount of $100,000,000 due 2008, dated as of November 13, 1998, between the Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to the Company's Current Report on Form 8-K dated November 10, 1998). 4.9 Indenture, dated as of March 14, 2000, among the Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.9 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 4.10 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 14, 2000 (incorporated by reference to Exhibit 4.10 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999).
II-2
EXHIBIT NO. DESCRIPTION ------------- ---------------------------------------------------------------------------------------- 4.11 Indenture, dated as of March 12, 2002 between the Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.11 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001). 4.12 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 7, 2002 (incorporated by reference to Exhibit 4.12 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001). 4.13 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 12, 2002 (incorporated by reference to Exhibit 4.13 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001). 4.14 Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of August 16, 2002.* 4.15 Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of March 12, 2002.* 4.16 Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of March 14, 2000.* 4.17 Indenture, dated as of August 16, 2002 between the Company and the Bank of New York, as Trustee.* 4.18 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of August 16, 2002.* 4.19 Shareholders Agreement dated as of March 14, 2000.* 5.1 Opinion of Willkie Farr & Gallagher.** 8.1 Opinion of Willkie Farr & Gallagher with respect to certain tax matters.** 10.1 Employment Agreement between the Company and David L. Sokol, dated May 10, 1999 (incorporated by reference to Exhibit 10.1 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 10.2 Amendment No. 1 to the Amended and Restated Employment Agreement between the Company and David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.2 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 10.3 Non-Qualified Stock Options Agreements of David L. Sokol dated March 14, 2000.* 10.4 Amended and Restated Employment Agreement between the Company and Gregory E. Abel, dated May 10, 1999 (incorporated by reference to Exhibit 10.3 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 10.5 Non-Qualified Stock Options Agreements of Gregory E. Abel dated March 14, 2000.* 10.6 Employment Agreement between the Company and Patrick J. Goodman, dated April 21, 1999 (incorporated by reference to Exhibit 10.5 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 10.7 MidAmerican Energy Holdings Company Long Term Incentive Partnership Plan.*
II-3
EXHIBIT NO. DESCRIPTION ------------- --------------------------------------------------------------------------------------------- 10.8 125 MW Power Plant--Upper Mahiao Agreement dated September 6, 1993 between PNOC-Energy Development Corporation and Ormat, Inc. as amended by the First Amendment to 125 MW Power Plant Upper Mahiao Agreement dated as of January 28, 1994, the Letter Agreement dated February 10, 1994, the Letter Agreement dated February 18, 1994 and the Fourth Amendment to 125 MW Power Plant--Upper Mahiao Agreement dated as of March 7, 1994 (incorporated by reference to Exhibit 10.95 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.9 Credit Agreement dated April 8, 1994 among CE Cebu Geothermal Power Company, Inc., the Banks thereto, Credit Suisse as Agent (incorporated by reference to Exhibit 10.96 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.10 Credit Agreement dated as of April 8, 1994 between CE Cebu Geothermal Power Company, Inc., Export-Import Bank of the United States (incorporated by reference to Exhibit 10.97 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.11 Pledge Agreement among CE Philippines Ltd, Ormat-Cebu Ltd., Credit Suisse as Collateral Agent and CE Cebu Geothermal Power Company, Inc. dated as of April 8, 1994 (incorporated by reference to Exhibit 10.98 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.12 Overseas Private Investment Corporation Contract of Insurance dated April 8, 1994 between the Overseas Private Investment Corporation and the Company through its subsidiaries CE International Ltd., CE Philippines Ltd., and Ormat-Cebu Ltd. (incorporated by reference to Exhibit 10.99 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.13 180 MW Power Plant--Mahanagdong Agreement dated September 18, 1993 between PNOC-Energy Development Corporation and CE Philippines Ltd. and the Company, as amended by the First Amendment to Mahanagdong Agreement dated June 22, 1994, the Letter Agreement dated July 12, 1994, the Letter Agreement dated July 29, 1994, and the Fourth Amendment to Mahanagdong Agreement dated March 3, 1995 (incorporated by reference to Exhibit 10.100 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.14 Credit Agreement dated as of June 30, 1994 among CE Luzon Geothermal Power Company, Inc., American Pacific Finance Company, the Lenders party thereto, and Bank of America National Trust and Savings Association as Administrative Agent (incorporated by reference to Exhibit 10.101 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.15 Credit Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power Company, Inc. and Export-Import Bank of the United States (incorporated by reference to Exhibit 10.102 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.16 Finance Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power Company, Inc. and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.103 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
II-4
EXHIBIT NO. DESCRIPTION ------------- ----------------------------------------------------------------------------------------- 10.17 Pledge Agreement dated as of June 30, 1994 among CE Mahanagdong Ltd., Kiewit Energy International (Bermuda) Ltd., Bank of America National Trust and Savings Association as Collateral Agent and CE Luzon Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.104 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.18 Overseas Private Investment Corporation Contract of Insurance dated July 29, 1994 between Overseas Private Investment Corporation and the Company, CE International Ltd., CE Mahanagdong Ltd. and American Pacific Finance Company and Amendment No. 1 dated August 3, 1994 (incorporated by reference to Exhibit 10.105 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.19 231 MW Power Plant--Malitbog Agreement dated September 10, 1993 between PNOC- Energy Development Corporation and Magma Power Company and the First and Second Amendments thereto dated December 8, 1993 and March 10, 1994, respectively (incorporated by reference to Exhibit 10.106 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.20 Credit Agreement dated as of November 10, 1994 among Visayas Power Capital Corporation, the Banks parties thereto and Credit Suisse Bank Agent (incorporated by reference to Exhibit 10.107 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.21 Finance Agreement dated as of November 10, 1994 between Visayas Geothermal Power Company and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.108 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.22 Pledge and Security Agreement dated as of November 10, 1994 among Broad Street Contract Services, Inc., Magma Power Company, Magma Netherlands B.V. and Credit Suisse as Bank Agent (incorporated by reference to Exhibit 10.109 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.23 Overseas Private Investment Corporation Contract of Insurance dated December 21, 1994 between Overseas Private Investment Corporation and Magma Netherlands, B.V. (incorporated by reference to Exhibit 10.110 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.24 Agreement as to Certain Common Representations, Warranties, Covenants and Other Terms, dated November 10, 1994 between Visayas Geothermal Power Company, Visayas Power Capital Corporation, Credit Suisse, as Bank Agent, Overseas Private Investment Corporation and the Banks named therein (incorporated by reference to Exhibit 10.111 to the Company's 1994 Annual Report on Form 10-K for the year ended December 31, 1993). 10.25 Trust Indenture dated as of November 27, 1995 between the CE Casecnan Water and Energy Company, Inc. and Chemical Trust Company of California (incorporated by reference to Exhibit 4.1 to CE Casecnan Water and Energy Company, Inc.'s Registration Statement on Form S-4 dated January 25, 1996). 10.26 Amended and Restated Casecnan Project Agreement between the National Irrigation Administration and CE Casecnan Water and Energy Company Inc. dated June 26, 1995 (incorporated by reference to Exhibit 10.1 to CE Casecnan Water and Energy Company, Inc.'s Registration Statement on Form S-4 dated January 25, 1996).
II-5
EXHIBIT NO. DESCRIPTION ------------- -------------------------------------------------------------------------------------------- 10.27 Term Loan and Revolving Facility Agreement, dated as of October 28, 1996, among CE Electric UK Holdings, CE Electric UK plc and Credit Suisse (incorporated by reference to Exhibit 10.130 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.28 Indenture and First Supplemental Indenture, dated March 11, 1999, between MidAmerican Funding LLC and IBJ Whitehall Bank & Trust Company and the First Supplement thereto relating to the $700 million Senior Notes and Bonds (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). 10.29 General Mortgage Indenture and Deed of Trust dated as of January 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-1 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654). 10.30 First Supplemental Indenture dated as of January 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-2 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654). 10.31 Second Supplemental Indenture dated as of January 15, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-3 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654). 10.32 Third Supplemental Indenture dated as of May 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4.4 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654). 10.33 Fourth Supplemental Indenture dated as of October 1, 1994, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.5 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654). 10.34 Fifth Supplemental Indenture dated as of November 1, 1994, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.6 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654). 10.35 Sixth Supplemental Indenture dated as of July 1, 1995, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.15 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 1995, Commission File No. 1-11505). 10.36 Indenture of Mortgage and Deed of Trust, dated as of March 1, 1947 (incorporated by reference to Exhibit 7B filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 2-6922). 10.37 Sixth Supplemental Indenture dated as of July 1, 1967 (incorporated by reference to Exhibit 2.08 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 2-28806). 10.38 Twentieth Supplemental Indenture dated as of May 1, 1982 (incorporated by reference to Exhibit 4.B.23 to the Iowa-Illinois Gas and Electric Company Quarterly Report on Form 10-Q for the period ended June 30, 1982, Commission File No. 1-3573).
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EXHIBIT NO. DESCRIPTION ------------- -------------------------------------------------------------------------------------------- 10.39 Resignation and Appointment of successor Individual Trustee (incorporated by reference to Exhibit 4.B.30 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 33-39211). 10.40 Twenty-Eighth Supplemental Indenture dated as of May 15, 1992 (incorporated by reference to Exhibit 4.31.B to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated May 21, 1992, Commission File No. 1-3573). 10.41 Twenty-Ninth Supplemental Indenture dated as of March 15, 1993 (incorporated by reference to Exhibit 4.32.A to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated March 24, 1993, Commission File No. 1-3573). 10.42 Thirtieth Supplemental Indenture dated as of October 1, 1993 (incorporated by reference to Exhibit 4.34.A to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated October 7, 1993, Commission File No. 1-3573). 10.43 Thirty-First Supplemental Indenture dated as of July 1, 1995, between Iowa-Illinois Gas and Electric Company and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.16 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended dated December 31, 1995, Commission File No. 1-11505). 10.44 Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 4-C-2 filed by Iowa Power Inc. as part of Registration Statement No. 2-27681). 10.45 Amendments Nos. 1 and 2 to Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District (incorporated by reference to Exhibit 4-C-2a filed by Iowa Power Inc. as part of Registration Statement No. 2-35624). 10.46 Amendment No. 3 dated August 31, 1970, to the Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 5-C-2-b filed by Iowa Power Inc. as part of Registration Statement No. 2-42191). 10.47 Amendment No. 4 dated March 28, 1974, to the Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 5-C-2-c filed by Iowa Power Inc. as part of Registration Statement No. 2-51540). 10.48 Amendment No. 5 dated September 2, 1997, to the Power Sales Contract between MidAmerican Energy Company and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 10.2 to the former MidAmerican Energy Holdings Company and MidAmerican Energy Company respective Quarterly Reports on the combined Form 10-Q for the quarter ended September 30, 1997, Commission File Nos. 333-90553 and 1-11505, respectively). 10.49 Amendment No. 6 dated July 31, 2002, to the Power Sales Contract between MidAmerican Energy Company and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 10.1 to the MidAmerican Funding, LLC and MidAmerican Energy Company respective Quarterly Reports on the combined Form 10-Q for the quarter ended June 20, 2002, Commission File Nos. 1-12459 and 1-11505, respectively). 10.50 CalEnergy Company, Inc. Voluntary Deferred Compensation Plan effective December 1, 1997, First Amendment dated as of August 17, 1999 and Second Amendment effective March 2000.*
II-7
EXHIBIT NO. DESCRIPTION ------------- --------------------------------------------------------------------------------------------- 10.51 MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan.* 10.52 MidAmerican Energy Company First Amended and Restated Supplemental Retirement Plan for Designated Officers dated as of May 10, 1999.* 10.53 MidAmerican Energy Company Restated Executive Deferred Compensation Plan (incorporated by reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 10.54 MidAmerican Energy Holdings Company Restated Deferred Compensation Plan--Board of Directors (incorporated by reference to Exhibit 10 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999). 10.55 MidAmerican Energy Company Combined Midwest Resources/Iowa Resources Restated Deferred Compensation Plan--Board of Directors (incorporated by reference to Exhibit 10.63 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 10.56 Midwest Resources Inc. Supplemental Retirement Plan (formerly the Midwest Energy Company Supplemental Retirement Plan (incorporated by reference to Exhibit 10.10 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654). 10.57 Amendment No. 1 to the Midwest Resources Inc. Supplemental Retirement Plan (incorporated by reference to Exhibit 10.24 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654). 10.58 Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan for Designated Officers, as amended as of July 28, 1994 (incorporated by reference to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-3573). 10.59 Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Designated Officers, as amended as of July 1, 1993 (incorporated by reference to Exhibit 10.K.2 to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-3573). 10.60 Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Key Employees, dated as of April 26, 1991 (incorporated by reference to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1991, Commission File No. 1-3573). 10.61 Iowa-Illinois Gas and Electric Company Board of Directors' Compensation Deferral Plan (incorporated by reference to Exhibit 10.K.4 to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-3573). 10.62 Iowa Utilities Board Settlement Agreement among MidAmerican Energy Company, Office of Consumer Advocate, Iowa Energy Consumers, Aluminum Company of America, Deere & Company, Cargill Inc., U.S. Gypsum Company, Interstate Power Company and IES Utilities, Inc. (incorporated by reference to Exhibit 10.16 to the MidAmerican Funding, LLC and MidAmerican Energy Company respective Annual Reports on the combined Form 10-K for the year ended December 31, 2000, Commission File Nos. 333-90553 and 1-11505, respectively). 10.63 Share Sale Agreement among NPower Yorkshire Limited, Innogy Holdings plc, CE Electric UK plc and Northern Electric plc dated as of August 6, 2001.*
II-8
EXHIBIT NO. DESCRIPTION ------------- ------------------------------------------------------------------------------------------ 10.64 Purchase Agreement among The Williams Companies, Inc., Williams Gas Pipeline Company, LLC, Williams Western Pipeline Company LLC, Kern River Acquisition, LLC and the Company, KR Holding, LLC, KR Acquisition 1, LLC and KR Acquisition 2, LLC, dated as of March 7, 2002 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated March 28, 2002). 10.65 Stock Purchase Agreement among The Williams Companies, Inc., MEHC Investment, Inc. and the Company dated as of March 7, 2002 (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated March 28, 2002). 10.66 Completion Guarantee given by the Company to Union Bank of California, Administrative Agent, dated as of June 21, 2002 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated June 27, 2002). 10.67 Purchase and Sale Agreement between Dynegy Inc., NNGC Holding Company, Inc. and the Company, dated as of July 28, 2002 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated July 30, 2002). 12.1 Statement regarding Computation of Earnings to Fixed Charges.* 15.1 Awareness Letter of Independent Accountants.** 21.1 Subsidiaries of the Registrant.** 23.1 Consent of Willkie Farr & Gallagher (included in their opinions filed as Exhibits 5.1 and Exhibit 8.1).** 23.2 Consent of Deloitte & Touche LLP.** 24.1 Powers of Attorney.* 25.1 Statement on Form T-1 of Eligibility of Trustee relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012.* 99.1 Form of Letter of Transmittal relating to the 4.625% Senior Notes due 2007.* 99.2 Form of Notice of Guaranteed Delivery relating to the 4.625% Senior Notes due 2007.* 99.3 Form of Letter to Clients relating to the 4.625% Senior Notes due 2007.* 99.4 Form of Letter to Nominees relating to the 4.625% Senior Notes due 2007.* 99.5 Form of Letter of Transmittal relating to the 5.875% Senior Notes due 2012.* 99.6 Form of Notice of Guaranteed Delivery relating to the 5.875% Senior Notes due 2012.* 99.7 Form of Letter to Clients relating to the 5.875% Senior Notes due 2012.* 99.8 Form of Letter to Nominees relating to the 5.875% Senior Notes due 2012.*
(b) Financial Statement Schedules Schedule I--Condensed Financial Statements (MidAmerican Energy Holdings Company only) Schedule II--Consolidated Valuation and Qualifying Accounts ---------- * Previously filed. ** Filed herewith. II-9 ITEM 22. UNDERTAKINGS. The undersigned registrant hereby undertakes that, for the purposes of determining any liability under the Securities Act, each filing of the registrant's annual report pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan's annual report pursuant to Section 15(d) of the Exchange Act) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant, pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by any such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether or not such indemnification is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue. The undersigned registrant hereby undertakes that: (1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective. (2) For purposes of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. The undersigned registrant hereby undertakes to respond to requests for information that is incorporated by reference into the prospectus pursuant to Item 4, 10(b), 11 or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request. The undersigned registrant hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective. II-10 SIGNATURES Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Des Moines, State of Iowa, on the 20th day of December, 2002. MIDAMERICAN ENERGY HOLDINGS COMPANY By: /s/ Douglas L. Anderson -------------------------------- Douglas L. Anderson Senior Vice President and General Counsel POWER OF ATTORNEY The undersigned officers and directors of MidAmerican Energy Holdings Company hereby severally constitute and appoint Douglas L. Anderson and Paul J. Leighton, and each of them, attorneys-in-fact for the undersigned, in any and all capacities, with the power of substitution, to sign any amendments to this registration statement (including post-effective amendments) and any subsequent registration statement for the same offering which may be filed under Rule 462(b) under the Securities Act of 1933, as amended, and to file the same with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully and to all interests and purposes as he might or could do in person, hereby ratifying and confirming all that each said attorney-in-fact, or his substitute or substitutes, may do or cause to be done by virtue thereof. Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons, in the capacities and on the dates indicated.
SIGNATURE TITLE DATE -------------------------------- -------------------------------- ------------------ * Chairman of the Board of December 20, 2002 ----------------------------- Directors, Chief Executive David L. Sokol Officer and Director (principal executive officer) * Senior Vice President and December 20, 2002 ----------------------------- Chief Financial Officer Patrick J. Goodman (principal financial and accounting officer) * Director December 20, 2002 ----------------------------- Gregory E. Abel
II-11
SIGNATURE TITLE DATE -------------------------------- ---------- ------------------ * Director December 20, 2002 ----------------------------- Edgar D. Aronson * Director December 20, 2002 ----------------------------- John K. Boyer * Director December 20, 2002 ----------------------------- Stanley J. Bright * Director December 20, 2002 ----------------------------- Warren E. Buffett * Director December 20, 2002 ----------------------------- Marc D. Hamburg * Director December 20, 2002 ----------------------------- Richard R. Jaros * Director December 20, 2002 ----------------------------- W. David Scott * Director December 20, 2002 ----------------------------- Walter Scott, Jr.
Douglas L. Anderson, by signing his name below, signs this document on behalf of each of the above-named persons specified by an asterisk (*) pursuant to a power of attorney duly executed by such persons, filed with the Securities and Exchange Commission in the Registrant's Registration Statement on Form S-4 on December 6, 2002. /s/ Douglas L. Anderson ----------------------------- Douglas L. Anderson Attorney-in-fact II-12 MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I PARENT COMPANY ONLY CONDENSED BALANCE SHEETS As of December 31, 2001 and 2000 (In thousands)
2001 2000 -------------- -------------- ASSETS Current Assets: Cash and cash equivalents ............................................. $ 2,524 $ 8,223 ---------- ---------- Total current assets ................................................. 2,524 8,223 Investments in and advances to subsidiaries and joint ventures ......... 3,432,528 3,125,487 Equipment, net ......................................................... 17,605 17,228 Excess of cost over fair value of net assets acquired, net ............. 1,211,814 1,216,550 Deferred charges and other assets ...................................... 129,501 127,966 ---------- ---------- Total Assets ........................................................... $4,793,972 $4,495,454 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable and other accrued liabilities ........................ $ 68,445 $ 54,073 Short term debt ....................................................... 153,500 85,000 ---------- ---------- Total current liabilities ............................................ 221,945 139,073 Non-current liabilities ................................................ 6,480 6,435 Notes payable -- affiliate ............................................. 197,153 122,177 Parent company debt .................................................... 1,834,498 1,829,971 ---------- ---------- Total liabilities ..................................................... 2,260,076 2,097,656 ---------- ---------- Deferred income ........................................................ 37,578 34,874 Company-obligated mandatorily redeemable preferred securities of subsidiary trusts ..................................................... 788,151 786,523 Stockholders' Equity: Zero coupon convertible preferred stock -- authorized 50,000 shares, no par value, 34,563 shares issued and outstanding at December 31, 2001 and 2000 ......................................................... -- -- Common stock -- authorized 60,000 shares, no par value; 9,281 shares issued and outstanding at December 31, 2001 and 2000 .................. -- -- Additional paid in capital ............................................. 1,553,073 1,553,073 Retained earnings ...................................................... 223,926 81,257 Accumulated other comprehensive loss, net .............................. (68,832) (57,929) ---------- ---------- Total stockholders' equity ............................................. 1,708,167 1,576,401 ---------- ---------- Total Liabilities and Stockholders' Equity ............................. $4,793,972 $4,495,454 ========== ==========
The notes to the consolidated financial statements of MidAmerican Energy Holdings Company are an integral part of this financial statement schedule. S-1 MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I PARENT COMPANY ONLY CONDENSED STATEMENTS OF OPERATIONS For the three years ended December 31, 2001 (In thousands)
2001 2000 1999 ----------- ----------- ----------- Revenue: Equity in undistributed earnings of subsidiary companies and joint ventures ....................................... $608,896 $390,194 $ 166,428 Cash dividends and distributions from subsidiary companies and joint ventures ............................. 87,625 96,342 345,430 Interest and other income ................................. 2,248 13,818 34,002 -------- -------- --------- Total revenues ........................................... 698,769 500,354 545,860 -------- -------- --------- Expenses: General and administration ................................ 41,078 45,089 39,174 Depreciation and amortization ............................. 31,537 25,716 1,088 Interest, net of capitalized interest ..................... 148,680 141,891 163,589 -------- -------- --------- Total expenses ........................................... 221,295 212,696 203,851 -------- -------- --------- Income before provision for income taxes .................. 477,474 287,658 342,009 Provision for income taxes ................................ 250,064 84,285 93,475 -------- -------- --------- Income before minority interest ........................... 227,410 203,373 248,534 Minority interest ......................................... 80,137 70,804 31,863 -------- -------- --------- Income before extraordinary items and cumulative effect of change in accounting principle ........................ 147,273 132,569 216,671 Extraordinary items, net of tax ........................... -- -- (49,441) Cumulative effect of change in accounting principle, net of tax ...................................................... (4,604) -- -- -------- -------- --------- Net income available to common stockholders ............... $142,669 $132,569 $ 167,230 ======== ======== =========
The notes to the consolidated financial statements of MidAmerican Energy Holdings Company are an integral part of this financial statement schedule. S-2 MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I PARENT COMPANY ONLY CONDENSED STATEMENTS OF CASH FLOWS For the three years ended December 31, 2001 (In thousands)
2001 2000 1999 --------------- --------------- --------------- Cash flows from operating activities .......................... $ (272,906) $ (299,862) $ (261,276) ----------- ------------ ------------ Cash flows from investing activities: Decrease (increase) in advances to and investments in subsidiaries and joint ventures .............................. 204,118 143,052 (53,215) Acquisition of MEHC (Predecessor) ............................. -- (2,048,266) -- Other ......................................................... (5,297) 28,458 (4,390) ----------- ------------ ------------ Cash flows from investing activities .......................... 198,821 (1,876,756) (57,605) ----------- ------------ ------------ Cash flows from financing activities: Proceeds from issuance of common and preferred stock .......... -- 1,428,024 -- Proceeds from issuance of trust preferred securities .......... -- 454,772 -- Repayments of parent company debt ............................. (32) -- (853,420) Net proceeds from revolver .................................... 68,500 85,000 -- Purchase of treasury stock .................................... -- -- (104,847) Other ......................................................... (82) (23,893) (4,208) ----------- ------------ ------------ Cash flows from financing activities .......................... 68,386 1,943,903 (962,475) ----------- ------------ ------------ Net increase (decrease) in cash and cash equivalents .......... (5,699) (232,715) (1,281,356) Cash and cash equivalents at beginning of period .............. 8,223 240,938 1,522,294 ----------- ------------ ------------ Cash and cash equivalents at end of period .................... $ 2,524 $ 8,223 $ 240,938 ----------- ------------ ------------ Supplemental disclosures: Interest paid (net of amount capitalized) ..................... $ 148,999 $ 144,147 $ 180,274 =========== ============ ============ Income taxes paid ............................................. $ 133,139 $ 94,405 $ 130,875 =========== ============ ============
The notes to the consolidated financial statements of MidAmerican Energy Holdings Company are an integral part of this financial statement schedule. S-3 SCHEDULE II MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE THREE YEARS ENDED DECEMBER 31, 2001 (IN THOUSANDS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E ----------------------------------------------- ------------ ---------------------- ------------- ----------- ADDITIONS BALANCE AT ---------------------- BALANCE AT BEGINNING CHARGED OTHER END DESCRIPTION OF YEAR TO INCOME ACCOUNTS DEDUCTIONS OF YEAR ----------------------------------------------- ------------ ----------- ---------- ------------- ----------- Reserves Deducted From Assets To Which They Apply: Reserve for uncollectible accounts receivable: Year ended 2001 ............................ $ 32,685 $ 17,061 $ -- $ (42,427) $ 7,319 ======== ======== ====== ========= ======= Year ended 2000 ............................ $ 18,666 $ 40,024 $ -- $ (26,005) $32,685 ======== ======== ====== ========= ======= Year ended 1999 ............................ $ 11,994 $ 14,483 $ -- $ (7,811) $18,666 ======== ======== ====== ========= ======= Reserves Not Deducted From Assets (1): Year ended 2001 ............................ $ 25,063 $ 5,046 $ -- $ (16,478) $13,631 ======== ======== ====== ========= ======= Year ended 2000 ............................ $ 17,696 $ 10,832 $ -- $ (3,465) $25,063 ======== ======== ====== ========= ======= Year ended 1999 ............................ $ 5,660 $ 15,112 $2,148 $ (5,224) $17,696 ======== ======== ====== ========= =======
---------- (1) Reserves not deducted from assets include estimated liabilities for losses retained by MHC Inc. for workers compensation, public liability and property damage claims. The notes to the consolidated financial statements of MidAmerican Energy Holdings Company are an integral part of this financial statement schedule. S-4 EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION ------------- ------------------------------------------------------------------------------------ 3.1 Amended and Restated Articles of Incorporation of the Company effective March 6, 2002. (incorporated by reference to Exhibit 3.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001). 3.2 Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 4.1 Indenture, dated as of October 4, 2002, by and between the Company and The Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012.* 4.2 First Supplemental Indenture, dated as of October 4, 2002, by and between the Company and The Bank of New York, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012.* 4.3 Registration Rights Agreement, dated as of October 1, 2002, by and between the Company and Credit Suisse First Boston (as Representative for the Initial Purchasers).* 4.4 Indenture for the 6 1/4% Convertible Junior Subordinated Debentures due 2012, dated as of February 26, 1997, between the Company, as issuer, and the Bank of New York, as Trustee (incorporated by reference to Exhibit 10.129 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 4.5 Indenture, dated as of October 15, 1997, among the Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K dated October 23, 1997). 4.6 Form of First Supplemental Indenture for the 7.63% Senior Notes in the principal amount of $350,000,000 due 2007, dated as of October 28, 1997, among the Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K dated October 23, 1997). 4.7 Form of Second Supplemental Indenture for the 6.96% Senior Notes in the principal amount of $215,000,000 due 2003, 7.23% Senior Notes in the principal amount of $260,000,000 due 2005, 7.52% Senior Notes in the principal amount of $450,000,000 due 2008, and 8.48% Senior Notes in the principal amount of $475,000,000 due 2028, dated as of September 22, 1998 between the Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K dated September 17, 1998.) 4.8 Form of Third Supplemental Indenture for the 7.52% Senior Notes in the principal amount of $100,000,000 due 2008, dated as of November 13, 1998, between the Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to the Company's Current Report on Form 8-K dated November 10, 1998). 4.9 Indenture, dated as of March 14, 2000, among the Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.9 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999).
EXHIBIT NO. DESCRIPTION ------------- ---------------------------------------------------------------------------------- 4.10 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 14, 2000 (incorporated by reference to Exhibit 4.10 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 4.11 Indenture, dated as of March 12, 2002 between the Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.11 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001). 4.12 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 7, 2002 (incorporated by reference to Exhibit 4.12 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001). 4.13 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 12, 2002 (incorporated by reference to Exhibit 4.13 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001). 4.14 Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of August 16, 2002.* 4.15 Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of March 12, 2002.* 4.16 Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of March 14, 2000.* 4.17 Indenture, dated as of August 16, 2002 between the Company and the Bank of New York, as Trustee.* 4.18 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of August 16, 2002.* 4.19 Shareholders Agreement dated as of March 14, 2000.* 5.1 Opinion of Willkie Farr & Gallagher.** 8.1 Opinion of Willkie Farr & Gallagher with respect to certain tax matters.** 10.1 Employment Agreement between the Company and David L. Sokol, dated May 10, 1999 (incorporated by reference to Exhibit 10.1 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 10.2 Amendment No. 1 to the Amended and Restated Employment Agreement between the Company and David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.2 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 10.3 Non-Qualified Stock Options Agreements of David L. Sokol dated March 14, 2000.* 10.4 Amended and Restated Employment Agreement between the Company and Gregory E. Abel, dated May 10, 1999 (incorporated by reference to Exhibit 10.3 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 10.5 Non-Qualified Stock Options Agreements of Gregory E. Abel dated March 14, 2000.* 10.6 Employment Agreement between the Company and Patrick J. Goodman, dated April 21, 1999 (incorporated by reference to Exhibit 10.5 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999).
EXHIBIT NO. DESCRIPTION ------------- ---------------------------------------------------------------------------------- 10.7 MidAmerican Energy Holdings Company Long Term Incentive Partnership Plan.* 10.8 125 MW Power Plant--Upper Mahiao Agreement dated September 6, 1993 between PNOC-Energy Development Corporation and Ormat, Inc. as amended by the First Amendment to 125 MW Power Plant Upper Mahiao Agreement dated as of January 28, 1994, the Letter Agreement dated February 10, 1994, the Letter Agreement dated February 18, 1994 and the Fourth Amendment to 125 MW Power Plant--Upper Mahiao Agreement dated as of March 7, 1994 (incorporated by reference to Exhibit 10.95 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.9 Credit Agreement dated April 8, 1994 among CE Cebu Geothermal Power Company, Inc., the Banks thereto, Credit Suisse as Agent (incorporated by reference to Exhibit 10.96 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.10 Credit Agreement dated as of April 8, 1994 between CE Cebu Geothermal Power Company, Inc., Export-Import Bank of the United States (incorporated by reference to Exhibit 10.97 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.11 Pledge Agreement among CE Philippines Ltd, Ormat-Cebu Ltd., Credit Suisse as Collateral Agent and CE Cebu Geothermal Power Company, Inc. dated as of April 8, 1994 (incorporated by reference to Exhibit 10.98 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.12 Overseas Private Investment Corporation Contract of Insurance dated April 8, 1994 between the Overseas Private Investment Corporation and the Company through its subsidiaries CE International Ltd., CE Philippines Ltd., and Ormat- Cebu Ltd. (incorporated by reference to Exhibit 10.99 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.13 180 MW Power Plant--Mahanagdong Agreement dated September 18, 1993 between PNOC-Energy Development Corporation and CE Philippines Ltd. and the Company, as amended by the First Amendment to Mahanagdong Agreement dated June 22, 1994, the Letter Agreement dated July 12, 1994, the Letter Agreement dated July 29, 1994, and the Fourth Amendment to Mahanagdong Agreement dated March 3, 1995 (incorporated by reference to Exhibit 10.100 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.14 Credit Agreement dated as of June 30, 1994 among CE Luzon Geothermal Power Company, Inc., American Pacific Finance Company, the Lenders party thereto, and Bank of America National Trust and Savings Association as Administrative Agent (incorporated by reference to Exhibit 10.101 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.15 Credit Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power Company, Inc. and Export-Import Bank of the United States (incorporated by reference to Exhibit 10.102 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.16 Finance Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power Company, Inc. and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.103 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
EXHIBIT NO. DESCRIPTION ------------- ---------------------------------------------------------------------------------- 10.17 Pledge Agreement dated as of June 30, 1994 among CE Mahanagdong Ltd., Kiewit Energy International (Bermuda) Ltd., Bank of America National Trust and Savings Association as Collateral Agent and CE Luzon Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.104 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.18 Overseas Private Investment Corporation Contract of Insurance dated July 29, 1994 between Overseas Private Investment Corporation and the Company, CE International Ltd., CE Mahanagdong Ltd. and American Pacific Finance Company and Amendment No. 1 dated August 3, 1994 (incorporated by reference to Exhibit 10.105 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.19 231 MW Power Plant--Malitbog Agreement dated September 10, 1993 between PNOC-Energy Development Corporation and Magma Power Company and the First and Second Amendments thereto dated December 8, 1993 and March 10, 1994, respectively (incorporated by reference to Exhibit 10.106 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.20 Credit Agreement dated as of November 10, 1994 among Visayas Power Capital Corporation, the Banks parties thereto and Credit Suisse Bank Agent (incorporated by reference to Exhibit 10.107 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.21 Finance Agreement dated as of November 10, 1994 between Visayas Geothermal Power Company and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.108 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.22 Pledge and Security Agreement dated as of November 10, 1994 among Broad Street Contract Services, Inc., Magma Power Company, Magma Netherlands B.V. and Credit Suisse as Bank Agent (incorporated by reference to Exhibit 10.109 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.23 Overseas Private Investment Corporation Contract of Insurance dated December 21, 1994 between Overseas Private Investment Corporation and Magma Netherlands, B.V. (incorporated by reference to Exhibit 10.110 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.24 Agreement as to Certain Common Representations, Warranties, Covenants and Other Terms, dated November 10, 1994 between Visayas Geothermal Power Company, Visayas Power Capital Corporation, Credit Suisse, as Bank Agent, Overseas Private Investment Corporation and the Banks named therein (incorporated by reference to Exhibit 10.111 to the Company's 1994 Annual Report on Form 10-K for the year ended December 31, 1993). 10.25 Trust Indenture dated as of November 27, 1995 between the CE Casecnan Water and Energy Company, Inc. and Chemical Trust Company of California (incorporated by reference to Exhibit 4.1 to CE Casecnan Water and Energy Company, Inc.'s Registration Statement on Form S-4 dated January 25, 1996).
EXHIBIT NO. DESCRIPTION ------------- ---------------------------------------------------------------------------------- 10.26 Amended and Restated Casecnan Project Agreement between the National Irrigation Administration and CE Casecnan Water and Energy Company Inc. dated June 26, 1995 (incorporated by reference to Exhibit 10.1 to CE Casecnan Water and Energy Company, Inc.'s Registration Statement on Form S-4 dated January 25, 1996). 10.27 Term Loan and Revolving Facility Agreement, dated as of October 28, 1996, among CE Electric UK Holdings, CE Electric UK plc and Credit Suisse (incorporated by reference to Exhibit 10.130 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.28 Indenture and First Supplemental Indenture, dated March 11, 1999, between MidAmerican Funding LLC and IBJ Whitehall Bank & Trust Company and the First Supplement thereto relating to the $700 million Senior Notes and Bonds (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). 10.29 General Mortgage Indenture and Deed of Trust dated as of January 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-1 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654). 10.30 First Supplemental Indenture dated as of January 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-2 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654). 10.31 Second Supplemental Indenture dated as of January 15, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-3 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654). 10.32 Third Supplemental Indenture dated as of May 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4.4 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654). 10.33 Fourth Supplemental Indenture dated as of October 1, 1994, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.5 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654). 10.34 Fifth Supplemental Indenture dated as of November 1, 1994, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.6 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654). 10.35 Sixth Supplemental Indenture dated as of July 1, 1995, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.15 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 1995, Commission File No. 1-11505).
EXHIBIT NO. DESCRIPTION ------------- ------------------------------------------------------------------------------------- 10.36 Indenture of Mortgage and Deed of Trust, dated as of March 1, 1947 (incorporated by reference to Exhibit 7B filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 2-6922). 10.37 Sixth Supplemental Indenture dated as of July 1, 1967 (incorporated by reference to Exhibit 2.08 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 2-28806). 10.38 Twentieth Supplemental Indenture dated as of May 1, 1982 (incorporated by reference to Exhibit 4.B.23 to the Iowa-Illinois Gas and Electric Company Quarterly Report on Form 10-Q for the period ended June 30, 1982, Commission File No. 1-3573). 10.39 Resignation and Appointment of successor Individual Trustee (incorporated by reference to Exhibit 4.B.30 filed by Iowa-Illinois Gas and Electric Company as part of Commission File No. 33-39211). 10.40 Twenty-Eighth Supplemental Indenture dated as of May 15, 1992 (incorporated by reference to Exhibit 4.31.B to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated May 21, 1992, Commission File No. 1-3573). 10.41 Twenty-Ninth Supplemental Indenture dated as of March 15, 1993 (incorporated by reference to Exhibit 4.32.A to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated March 24, 1993, Commission File No. 1-3573). 10.42 Thirtieth Supplemental Indenture dated as of October 1, 1993 (incorporated by reference to Exhibit 4.34.A to the Iowa-Illinois Gas and Electric Company Current Report on Form 8-K dated October 7, 1993, Commission File No. 1-3573). 10.43 Thirty-First Supplemental Indenture dated as of July 1, 1995, between Iowa-Illinois Gas and Electric Company and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.16 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended dated December 31, 1995, Commission File No. 1-11505). 10.44 Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 4-C-2 filed by Iowa Power Inc. as part of Registration Statement No. 2-27681). 10.45 Amendments Nos. 1 and 2 to Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District (incorporated by reference to Exhibit 4-C-2a filed by Iowa Power Inc. as part of Registration Statement No. 2-35624). 10.46 Amendment No. 3 dated August 31, 1970, to the Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 5-C-2-b filed by Iowa Power Inc. as part of Registration Statement No. 2-42191). 10.47 Amendment No. 4 dated March 28, 1974, to the Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 5-C-2-c filed by Iowa Power Inc. as part of Registration Statement No. 2-51540).
EXHIBIT NO. DESCRIPTION ------------- ------------------------------------------------------------------------------------- 10.48 Amendment No. 5 dated September 2, 1997, to the Power Sales Contract between MidAmerican Energy Company and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 10.2 to the former MidAmerican Energy Holdings Company and MidAmerican Energy Company respective Quarterly Reports on the combined Form 10-Q for the quarter ended September 30, 1997, Commission File Nos. 333-90553 and 1-11505, respectively). 10.49 Amendment No. 6 dated July 31, 2002, to the Power Sales Contract between MidAmerican Energy Company and Nebraska Public Power District, dated September 22, 1967 (incorporated by reference to Exhibit 10.1 to the MidAmerican Funding, LLC and MidAmerican Energy Company respective Quarterly Reports on the combined Form 10-Q for the quarter ended June 20, 2002, Commission File Nos. 1-12459 and 1-11505, respectively). 10.50 CalEnergy Company, Inc. Voluntary Deferred Compensation Plan effective December 1, 1997, First Amendment dated as of August 17, 1999 and Second Amendment effective March 2000.* 10.51 MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan.* 10.52 MidAmerican Energy Company First Amended and Restated Supplemental Retirement Plan for Designated Officers dated as of May 10, 1999.* 10.53 MidAmerican Energy Company Restated Executive Deferred Compensation Plan (incorporated by reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 10.54 MidAmerican Energy Holdings Company Restated Deferred Compensation Plan-- Board of Directors (incorporated by reference to Exhibit 10 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999). 10.55 MidAmerican Energy Company Combined Midwest Resources/Iowa Resources Restated Deferred Compensation Plan--Board of Directors (incorporated by reference to Exhibit 10.63 to the Company's Annual Report on Form 10-K/A for the year ended December 31, 1999). 10.56 Midwest Resources Inc. Supplemental Retirement Plan (formerly the Midwest Energy Company Supplemental Retirement Plan (incorporated by reference to Exhibit 10.10 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654). 10.57 Amendment No. 1 to the Midwest Resources Inc. Supplemental Retirement Plan (incorporated by reference to Exhibit 10.24 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654). 10.58 Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan for Designated Officers, as amended as of July 28, 1994 (incorporated by reference to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-3573). 10.59 Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Designated Officers, as amended as of July 1, 1993 (incorporated by reference to Exhibit 10.K.2 to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-3573).
EXHIBIT NO. DESCRIPTION ------------- -------------------------------------------------------------------------------------- 10.60 Iowa-Illinois Gas and Electric Company Compensation Deferral Plan for Key Employees, dated as of April 26, 1991 (incorporated by reference to the Iowa- Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1991, Commission File No. 1-3573). 10.61 Iowa-Illinois Gas and Electric Company Board of Directors' Compensation Deferral Plan (incorporated by reference to Exhibit 10.K.4 to the Iowa-Illinois Gas and Electric Company Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-3573). 10.62 Iowa Utilities Board Settlement Agreement among MidAmerican Energy Company, Office of Consumer Advocate, Iowa Energy Consumers, Aluminum Company of America, Deere & Company, Cargill Inc., U.S. Gypsum Company, Interstate Power Company and IES Utilities, Inc. (incorporated by reference to Exhibit 10.16 to the MidAmerican Funding, LLC and MidAmerican Energy Company respective Annual Reports on the combined Form 10-K for the year ended December 31, 2000, Commission File Nos. 333-90553 and 1-11505, respectively). 10.63 Share Sale Agreement among NPower Yorkshire Limited, Innogy Holdings plc, CE Electric UK plc and Northern Electric plc dated as of August 6, 2001.* 10.64 Purchase Agreement among The Williams Companies, Inc., Williams Gas Pipeline Company, LLC, Williams Western Pipeline Company LLC, Kern River Acquisition, LLC and the Company, KR Holding, LLC, KR Acquisition 1, LLC and KR Acquisition 2, LLC, dated as of March 7, 2002 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated March 28, 2002). 10.65 Stock Purchase Agreement among The Williams Companies, Inc., MEHC Investment, Inc. and the Company dated as of March 7, 2002 (incorporated by reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated March 28, 2002). 10.66 Completion Guarantee given by the Company to Union Bank of California, Administrative Agent, dated as of June 21, 2002 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated June 27, 2002). 10.67 Purchase and Sale Agreement between Dynegy Inc., NNGC Holding Company, Inc. and the Company, dated as of July 28, 2002 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated July 30, 2002). 12.1 Statement regarding Computation of Earnings to Fixed Charges.* 15.1 Awareness Letter of Independent Accountants.** 21.1 Subsidiaries of the Registrant.** 23.1 Consent of Willkie Farr & Gallagher (included in their opinions filed as Exhibits 5.1 and Exhibit 8.1).** 23.2 Consent of Deloitte & Touche LLP.** 24.1 Powers of Attorney.* 25.1 Statement on Form T-1 of Eligibility of Trustee relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012.* 99.1 Form of Letter of Transmittal relating to the 4.625% Senior Notes due 2007.*
EXHIBIT NO. DESCRIPTION ------------- ------------------------------------------------------------------------------ 99.2 Form of Notice of Guaranteed Delivery relating to the 4.625% Senior Notes due 2007.* 99.3 Form of Letter to Clients relating to the 4.625% Senior Notes due 2007.* 99.4 Form of Letter to Nominees relating to the 4.625% Senior Notes due 2007.* 99.5 Form of Letter of Transmittal relating to the 5.875% Senior Notes due 2012.* 99.6 Form of Notice of Guaranteed Delivery relating to the 5.875% Senior Notes due 2012.* 99.7 Form of Letter to Clients relating to the 5.875% Senior Notes due 2012.* 99.8 Form of Letter to Nominees relating to the 5.875% Senior Notes due 2012.*
---------- * Previously filed. ** Filed herewith.